Half-year Results

Star Energy announces its unaudited interim results for the six months to 30 June 2025.

Commenting today Ross Glover, Chief Executive Officer, said:

"We welcome the UK government's recent recognition of domestic energy's strategic value, as reflected in policy priorities aimed at reducing reliance on imported fossil fuels, enhancing energy security, and creating new green jobs and economic growth. The mission of Great British Energy similarly champions clean, secure, home-grown energy as a catalyst for job creation and energy independence. Our strategy is closely aligned with these objectives: we manage our oil and gas assets responsibly and efficiently, while reinvesting operating cashflows into making our oil and gas business more resilient and maturing our geothermal opportunities.

However, the operating environment remains challenging. Our core oil and gas operations-critical to funding the Group-are under increasing strain from the Energy Profits Levy, which has elevated the headline upstream tax rate to 78%. This, combined with a more complex and costly regulatory environment, creates substantial barriers just as the UK's dependence on energy imports remains pronounced. In the first quarter of 2025, the country's net energy imports underscored the urgent need to prioritise and support domestic supply.

Despite these headwinds, we remain committed to developing a robust UK geothermal business and are lobbying the Government to provide consistent and practical policy and regulatory support. With this support, the potential is considerable: geothermal energy offers secure, low-carbon, and price-stable heat at scale. We aim to be a highly active player in the energy transition and are well-positioned to be so.

Promoting genuinely home-grown energy is essential-not only for strengthening the UK's energy security, but also for supporting skilled employment, generating tax receipts for the government, and fostering regional and national growth. This opportunity is of strategic importance both to the country and to Star Energy, and we are dedicated to realising its potential. Our approach is disciplined and measured. We are focused on operational excellence in our oil and gas business, making selective investments where returns are compelling, and steadily advancing our geothermal development pipeline in the UK and Croatia and generating value for shareholders"

Results Summary

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

Corporate & Financial Summary

• Cash balances as at 30 June 2025 were £4.3 million (31 December 2024: £4.7 million) and net debt reduced to £2.7 million (31 December 2024: £7.5 million). £8.7 million (€10.2 million) remains undrawn under our Finance facility which can be used to fund a portion of the Singleton Gas-to-wire project and our geothermal activities.
• Adjusted EBITDA was £4.5 million. Lower commodity prices, a weaker US dollar, and lower production impacted oil revenues. However, the savings of £1.6 million that we have generated in administrative costs and reduced expenditure on our Croatian geothermal licences has partially offset this.
• Operating cash flow before working capital movements increased to £4.8 million (H1 2024: £4.4 million). Reduced cashflows from oil sales net of hedges were more than offset by a reduction in administrative expenses, geothermal expenditure and other expenses.
• We received £6.3 million of proceeds from the sale of our Holybourne site.
• We invested £2.0 million in our oil and gas assets in the period including on our Singleton gas-to-wire project and on smaller projects across our sites to enhance production and optimise operations. Net cash capex for FY 2025 is expected to be £8.4 million, primarily relating to our conventional assets.
• We recognised a gain of £1.3 million on our commodity and foreign exchange hedges, of which £0.5 million was realised in the period. We have hedged 152,800 bbls with swaps for H2 2025 and Q1 2026 at an average price of $72.9/bbl and have additionally created some downside protection for 237,800 bbls with a three-way put/call options for H2 2025 and for 20261. We have also put in place USD/GBP foreign exchange hedges for $0.5 million/month at a rate of $1.227/£1 for the remainder of 2025.
• The Group had ring fence tax losses of £249 million at 30 June 2025.

1 A summary of our commodity hedges is shown on our June 2025 AGM trading update on our website

Operational Summary

• Net production averaged 1,894 boe/d in H1 2025 (H1 2024: 2,012 boe/d). Full year production is expected to be c.2,000 boe/d, in line with our previous guidance.
• Work on our Singleton gas-to-wire project has started, and we have entered into contracts for the procurement of two generators and the connection to the grid. Planning permission was received for the cable installation in July. We have been informed by the distribution network operator that energisation of the grid connection will not be completed in 2025. Accordingly, whilst we are working with the operator to expedite this, we expect the project's scheduled launch to be delayed into 2026.
• We are continuing the development of our UK geothermal pipeline and are working with both public and private entities to expand this. During the first half, we announced the following:

o MoU signed with the University of Southampton and Bring Energy to decarbonise the existing Southampton District Heat Network and explore the provision of geothermal heat to the University; and

o MoU signed with Veolia on the decarbonisation of heat supply to new and existing customers. We will work together on decarbonising district heating schemes, commercial buildings, hospitals, campuses and industrial processes.

• We have completed the detailed feasibility studies for our projects at the Wythenshawe Hospital and Salisbury District Hospital, both of which confirm the presence of viable geothermal reservoirs.
• We continue to mature our Croatia geothermal portfolio by establishing the exploitation field within the Ernestinovo licence and preparing the conceptual field development plan to be submitted to the Croatian Ministry of Economy. Following the acquisition of magnetotelluric data on both Sječe and Pčelić exploration licences, we are undertaking a technical de-risking of the licences to enable a phased development of the portfolio.

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

Our core oil and gas business continues to be the source of all revenue for the group. We have made good progress on optimising our existing producing assets with a focus on profitability. The revenue generated from this business enables us to further enhance and optimise operations whilst building a growth story in geothermal in the UK and in Croatia. It should be noted that despite the UK demand for oil and gas remaining strong and the government's own projections demonstrating strong demand to 2050 and beyond, the operating environment in the UK is hostile. The regulatory burden grows with increased costs, often resulting in little to no real world environmental improvements and increased delays, in particular with the Environment Agency, where the processing time for environmental permits regularly exceeds a year. Planning for growth is made more difficult due to the fiscal burden on the industry with an effective 78% tax rate, even at depressed oil prices, meaning that investment in both the oil and gas business as well as our geothermal businesses is curtailed. The Energy Profits Levy (EPL), in particular, is a significant handbrake on us developing our geothermal projects, the type of project that the government should be promoting. We have been able to partly offset inflationary impacts on operating costs and higher workover costs by savings elsewhere, whilst maintaining our strong Health and Safety (HSE) record. We have also achieved substantial reductions in our administrative costs.

We are working hard on executing on our long-term growth strategy to develop a geothermal energy business of scale. However, we are ensuring that expenditure on this division is limited to activities where we can see a clear line of sight to value creation. The future development of this sector is reliant on businesses such as ours, with decades of highly relevant development and operational skills derived from our oil and gas business. As such, much of the work to progress our geothermal business is carried out by our existing team, leveraging their oil and gas skillset.

The UK geothermal sector is underdeveloped, but the demand drivers, being heat decarbonisation, energy security, and long-term predictable pricing, are all intensifying. Our pipeline of private and public sector projects is growing, and we are working with credible partners such as the NHS, Veolia, and Bring Energy to mature that pipeline. Despite the growing demand for a utility scale distributed decarbonised heat solutions, something that only geothermal can satisfy, the government's focus on energy remains around electrification and on wind and solar in particular. Whilst many within government recognise the benefits, there remains no organised framework within which geothermal projects are promoted and developed.

If the UK wants secure, price-stable, low-carbon heat at scale, we need to treat geothermal like core infrastructure. A recently released report1, commissioned by the Department for Energy Security and Net Zero, identifies life cycle cost savings of as much as 75% or more, between the First of a Kind projects (FOAK) and the later-stage "N'th of a Kind" projects (NOAK).

To get there, we need to 'prime the pump' in the same way that solar and offshore wind received vociferous government backing in the early days. Our ask of government is simple:

• Consult on and implement a National Geothermal Strategy, including targets for geothermal development and use, aligned with National System Energy Operator (NESO) and heat network zoning policy;
• Create and implement compelling non-financial and financial investment incentives for geothermal, including by making geothermal a focus for investment by GB Energy and the National Wealth Fund; and
• Department for Energy Security and Net Zero 2025: UK Geothermal Review and Cost Estimations
• Dedicate additional cross-departmental policy-making resource and attention to geothermal - including by establishing formal structures within Government, involving industry experts, to develop policy recommendations.

In Croatia, we benefit from a supportive regulatory and investment climate for geothermal as well as a suitable geology for the generation of electricity. Whilst the regulatory system operates very efficiently, Croatian Government delays to European Union approval of a new premium tariff for geothermal is holding back investment across the sector. Despite this, we are finalising technical de-risking of our licences to enable phased development. The Croatian market provides access to scalable energy opportunities within a jurisdiction that actively supports and encourages clean energy investment.

We are uniquely positioned to deliver value from cash-generative UK oil and gas operations, while building a diversified energy business that can thrive in multiple market scenarios. Our geothermal activities are not a pivot away from hydrocarbons; rather they are a logical, deployment of our core strengths in subsurface, permitting, and infrastructure development into a growth area.

Production Operations

Net production for the period averaged 1,894 boe/d (H1 2024: 2,012 boe/d). Whilst well uptime was generally good across the portfolio, production deferrals were due to unplanned outages on larger producing wells and grid upgrades in the East Midlands, undertaken by the District Network Operator, taking longer than scheduled. Due to the combination of low oil prices, increased regulatory costs and the penal tax rate, certain wells that we would have otherwise brought back into production have remained temporarily shut-in as it did not make economic sense to bring them back online. In spite of planned summer shutdowns, production has recovered in July and August with August production at 1,976 boe/d.

The rolling programme of well optimisation and stimulation continues. We are offsetting the natural declines in our fields by investing in quick returning projects generally deploying small amounts of capital to optimise specific wells.

Development Projects

Work has begun on our Singleton gas-to-wire project which will deliver c.75 boe/d utilising gas which is currently being flared and meet the HSE requirements for the continued operation of the site. The project now has planning consent and a secured grid connection. Work on the project has started and we have entered into contracts for the procurement of two generators and the connection to the grid. Planning permission was received for the cable installation in July. We have been informed by the distribution network operator that energisation of the grid connection will not be completed in 2025. Whilst we are working with the operator to expedite this. we expect the project go live date to be delayed into 2026.

Reserves and resources

CPR

In February 2025, Star Energy announced the publication of the full and final results of the Competent Person's Report (CPR) by DeGolyer & MacNaughton (D&M), a leading international reserves and resources auditor.

The report comprised an independent evaluation of Star Energy's conventional oil and gas interests as of 31 December 2024. The full report can be found here: https://www.starenergygroupplc.com/investors/reports-publications-presentations.

Net Reserves & Contingent Resources as at 31 December 2024 (MMboe)

*Oil price assumption of c.$72/bbl for 5 years, then inflated at 2-3% p.a. from 2029 to 2054

**The production in the reserves movement table incorporates production at the following sites: Albury, Beckingham, Bletchingley, Bothamsall, Cold Hanworth, Corringham, East Glentworth, Egmanton, Glentworth, Goodworth, Horndean, Long Clawson, Palmers Wood, Scampton North, Singleton, Stockbridge and Welton.

The report values our conventional assets at $188 million (2023: $235 million) on a 2P NPV10 basis.

Licence Rationalisation

We have rationalised our portfolio of exploration licences, relinquishing early-stage exploration and shale licences whilst retaining a core exploration acreage adjacent to our existing operations in the East Midlands. This exploration acreage not only holds conventional oil and gas prospects but also overlies a nationally significant shale gas resource. Seismic data, well data and widespread detailed surface constraints mapping shows that this acreage is geologically significantly more structurally simple than other UK shale basins and offers far fewer surface constraints.

During 2024, we also re-organised and simplified our operating licence structure and we have seen the results of this in 2025 with reduced costs and a lower administrative burden.

Geothermal Development

UK Projects

We have completed the detailed feasibility study for our project at Salisbury District Hospital. This included the reprocessing of 700km of legacy 2D seismic data, the acquisition of four new seismic lines and the development of an extensive geological model at the hospital site. The study confirmed the presence of a viable geothermal reservoir. In parallel, pre application for planning and regulators consents have been completed and a conceptual well design developed. This work has concluded with a commercial assessment on the project and we have provided indicative heads of terms for supply of that heat to the hospital under a long-term thermal purchase agreement (TPA).

We completed the detailed feasibility study for our Wythenshawe Hospital project. This included reprocessing of seismic, pre applications, conceptual well designs and commercial assessment. The study identified two viable geothermal targets and we provided indicative terms for supply from both under long-term TPA. We expect to commence the planning and permitting phase of the project in Q4. A seismic acquisition programme for the project is currently under design and will be executed in the next phase.

Croatia Projects

Following the acquisition of the Ernestinovo licence in August 2023, the exploration licence commitment was satisfied in March 2024. The exploitation field within the Ernestinovo licence has been established and the conceptual field development plan is being compiled to be submitted to the Croatian Ministry of Economy with the aim of progressing the licence to its exploitation phase in Q1 2026.

The Sjece and Pcelic licences were awarded in October 2023. Magnetotelluric data on both Sječe and Pčelić exploration licences have been acquired and a technical de-risking of the licences is being undertaken to enable phased development. All our Croatian licences are in areas where substantial offset data sets are available from previous conventional oil and gas drilling activities.

Alongside this, our technical teams are at an advanced stage of consolidating all existing and new data for each of our three licences in Croatia. This analysis will allow us to bring the development plans for each licence up to date and will inform our next steps and the optimal sequencing for the commercial development of the licences. Preliminary conclusions point to good prospects within our Croatian portfolio, with high temperatures recorded in existing wells comparable with other Croatian geothermal reservoirs and the potential is also supported by results from nearby drilling and testing of similar (geological and depth-wise) geothermal well at Podravska Slatina by the Energia Naturalis (ENNA) Group. Acquisition and interpretation of Magnetotelluric data has aided definition of the extent of the geothermal deposits and, together with additional subsurface interpretations, a number of potential well targets in all licenses have been identified. The analysis and ranking of these targets are currently underway, and we expect to complete this work by year end. Following this, work will then progress to mature these opportunities and develop well proposals and drilling programs.

Financial review

Income Statement

The Group generated revenue of £18.3 million in the first six months of 2025 from sales of 339,635 barrels of oil and 4,129 Mwh of electricity. (H1 2024: revenue of £23.2 million from sales of 355,800 barrels of oil, 3,644 Mwh of electricity and 171,542 therms of gas). The reduction in revenues was primarily driven by lower oil prices and a weaker US dollar, with Brent prices averaging $71.7/bbl in H1 2025 compared to $84.1/bbl during H1 2024 and the USD/GBP rate averaging $1.31/£1 compared to $1.27/£1 in H1 2024.

Adjusted EBITDA for H1 2025 was £4.5 million (H1 2024: £6.5 million), of which £5.5 million (H1 2024: £8.9 million) related to our oil and gas operations and £(1.0) million (H1 2024: £(2.4) million) related to geothermal activities.

The loss after tax from continuing activities was £4.1 million (H1 2024: £2.5 million) and the main factors explaining the movements between H1 2025 and H1 2024 were as follows:

• Revenues reduced to £18.3 million (H1 2024: £23.2 million) primarily reflecting lower oil prices and a weaker US dollar. Sales volumes also reduced from 1,995 boe/d to 1,901 boe/d, reflecting the cessation of gas sales from our Albury facility and planned downtime for workovers at a number of sites;
• Depletion, depreciation and amortisation (DD&A) increased to £3.6 million (H1 2024: £2.9 million) as a result of a reduction in the Group's estimated proven and probable reserves as at 1 January 2025 as noted in our 2024 Annual Report;
• We saw a small increase in operating costs to £10.8 million (H1 2024: £10.4 million) mainly due to an increase in workover activity, but have been able to offset inflationary increases through savings in a number of areas;
• We generated material savings in administrative expenses which reduced to £2.5 million (H1 2024: £4.1 million). £0.8 million of savings were realised through a cost cutting exercise with the lower cost base continuing into the future. The balance of the savings related to non-recurring costs in 2024 relating to the refinancing of the Group's borrowings and other corporate projects;
• Research and non-capitalised development costs were £0.3 million (H1 2024: £1.8 million). Higher expenditure in H1 2024 reflected the cost of re-entering and testing a well on the Ernestinovo licence to fulfil the licence commitments;
• We completed the sale of our Holybourne site in the period which resulted in a net gain on disposal of £4.5 million. H1 2024 included a charge of £2.0 million in connection with preparing the Holybourne site for sale;
• No significant write off of exploration and evaluation assets in the current period; H1 2024 included the write off of exploration and evaluation assets of £1.8 million mainly as a result of relinquishing the PEDL 235 (Godley Bridge) licence;
• H1 2024 included the impairment of development costs relating to the Stoke-on-Trent geothermal project. No such impairment charge recognised in the current period;
• We recognised a gain of £0.5 million from the write-off of contingent consideration payable relating to the acquisition of GT Energy UK Limited (H1 2024: £2.3 million) as the related milestones will not be achieved. The full amount of contingent consideration related to the acquisition has now been extinguished;
• We recognised a gain of £1.0 million on our oil hedging programme (H1 2024: loss of £0.1 million);
• Net finance costs increased to £3.0 million (H1 2024: £2.4 million) mainly due to increase in foreign exchange loss arising from movements in USD/GBP and Euro/GBP exchange rates; and
• A tax charge of £8.4 million (H1 2024: tax credit of £1.7 million) was recognised in the period. The charge included current taxes of £0.5 million relating to the estimated EPL charge on profits for the period, and a deferred tax charge of £8.0 million due to lower forecast oil prices and an extension of the EPL regime leading to a reduction in the amount of recognised tax losses.

Cash Flow

Net cash generated from operations before working capital movements and tax increased to £4.8 million for the period (H1 2024: £4.4 million) as the impact of reduced cash outflows from lower administrative expenses, research and non-capitalised geothermal development costs and other expenses in the period more than offset the impact of reduced cash inflows from a decline in revenues.

The Group invested £2.0 million across its asset base during the period (H1 2024: £3.0 million) primarily on the Singleton gas-to-wire project as well as a number of other projects carried out to increase production from existing wells and to offset field declines. The Group received £6.3 million from the sale of the Holybourne site in the period.

The Group repaid £5.6 million (€6.7 million) to fully settle facility A of its loan facility in line with its contractual maturity date (H1 2024: drawdown of £6.1 million (€7.1 million) under the loan facility and repayment of £5.5 million ($7.0 million) to fully settle the RBL facility with the Bank of Montreal). Interest paid during the period was £0.7 million (H1 2024: £0.2 million). Repayments made in respect of lease obligations were £1.2 million (H1 2024: £0.6 million).

The Group paid £1.0 million in settlement of its EPL liability for the 2023 tax year.

Cash and cash equivalents were £4.3 million at the end of the period (31 December 2024: £4.7 million).

Balance Sheet

The Group had net assets of £38.5 million at 30 June 2025 (31 December 2024: £42.6 million).

Property, plant and equipment reduced by £3.3 million due to a DD&A charge of £3.0 million, disposals of £1.9 million and a reduction in value of decommissioning assets of £0.3 million, partially offset by capital expenditure of £2.0 million.

The deferred tax asset reduced by £8.0 million mainly due to a change in forecast utilisation of available tax losses and impact of extension of the period of EPL.

Derivative financial assets increased by £0.8 million due to an unrealised gain on hedges.

Trade and other receivables reduced by £1.7 million mainly due to a decrease in trade receivables of £0.9 million and the settlement of a convertible loan note of £0.4 million by the minority shareholder in A14 Energy Limited. Trade and other payables reduced by £2.1 million mainly due to the timing of expenditure.

The Group's borrowings reduced by £5.2 million as we repaid facility A in June 2025. Lease liabilities reduced by £0.7 million due to the timing of payments and right-of-use assets reduced by £0.4 million. The provision for decommissioning increased by £0.7 million due to the unwinding of discount by £1.3 million, partially offset by utilisation of £0.3 million and a reassessment of provision of £0.3 million.

Non-IFRS Measures

The Group uses non-IFRS measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. The non-IFRS measures include net debt, adjusted EBITDA and underlying cash operating costs. These non-IFRS measures are used by the Group, alongside IFRS measures, for both internal performance analysis and to help shareholders, lenders and other users of the Interim Report to better understand the Group's performance in the period in comparison to previous periods and to industry peers.

Net Debt

Net debt, being borrowings excluding capitalised fees less cash and cash equivalents, decreased from the end of the previous year to £2.7 million at 30 June 2025 (31 December 2024: £7.5 million; 30 June 2024: £1.9 million). The Group's definition of net debt does not include the Group's lease liabilities.

Adjusted EBITDA

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

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

Principal risks and uncertainties

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

The principal risks for the Group remain as previously detailed on pages 22-23 of the 2024 Annual Report and Accounts and can be summarised as:

• Political risk such as change in Government or the effect of local or national referendums which can result in changes to the regulatory or fiscal regime;
• Strategy, and its execution, fails to meet shareholder expectations;
• Climate change risks that causes changes to laws, regulations, policies, obligations and social attitudes relating to the transition to a lower carbon economy which could have a cost impact or reduced demand for hydrocarbons for the Group and could impact our Strategy;
• Risk of reduction in appetite for low carbon heat solutions;
• Cyber security risk that gives exposure to a serious cyber-attack which could affect the confidentiality of data, the availability of critical business information and cause disruption to our operations;
• Planning, environmental, licensing and other permitting risks associated with operations and in particular, with drilling and production operations;
• Oil or gas production, as no guarantee can be given that they can be produced in the anticipated quantities from any or all of the Group's assets or that oil or gas can be delivered economically;
• Risk of delays in project delivery, higher cost of project delivery and lower than forecast output of projects delivered;
• Failure to achieve targeted geothermal production rates;
• Loss of key staff;
• Pandemic that impacts the ability to operate the business effectively;
• Oil market price risk through variations in the wholesale price in the context of the production from oil fields it owns and operates;
• Electricity market price risk through variations in the wholesale price in the context of its future production volumes;
• Exchange rate risk through its major source of revenue being priced in US$ and its borrowings being priced in Euros while most of the Group's operating and G&A costs are denominated in UK pounds sterling;
• Liquidity risk; and
• Capital risk resulting from its capital structure, including operating within the covenants of its finance facility.

Going concern

The Group continues to closely monitor and manage its liquidity risks. Cash flow forecasts for the Group are prepared on a monthly basis based on, inter alia, the Group's production and expenditure forecasts, management's best estimate of future oil prices and foreign exchange rates and the Group's available loan facility. Sensitivities are run to reflect different scenarios including, but not limited to, possible reductions in commodity prices, fluctuations in exchange rates and reductions in forecast oil production rates.

The current geopolitical climate and uncertain global economic outlook has reduced crude oil prices in the first half of 2025, with volatility in oil prices and foreign exchange rates likely to continue.

The focus of the Group in 2025 has been to strengthen our balance sheet and improve our resilience to oil price volatility. We have generated positive operating cashflows in H1 2025 as a result of stable production and a continued effort to minimise operating costs. We have also carried out a reorganisation in 2024 resulting in a material reduction in general and administrative costs in 2025. Our €25 million finance facility, of which €10.2 million remains undrawn, and the sale of non-core land with the proceeds of £6.3 million being received in April 2025, further improve our liquidity position.

However, the ability of the Group to operate as a going concern is dependent upon the continued availability of future cash flows and the availability of the monies drawn under its loan facility, which is dependent on the Group not breaching the facility's covenants. To mitigate these risks, the Group benefits from its hedging policy with 152,800 barrels hedged for the second half of 2025 and first quarter of 2026 using swaps at an average price of $72.9/bbl. We have additionally created some downside protection for 237,800 bbls with a three-way put/call options for H2 2025 and for 2026. We have also put in place USD/GBP foreign exchange hedges for $0.5 million/month at a rate of $1.227/£1 for the remainder of 2025

The Group's base case cash flow forecast was run with average oil prices of $66/bbl until the end of H1 2026, $68/bbl for H2 2026, $70/bbl for Q1 2027, and foreign exchange rates of an average $1.35/£1 for the remainder of 2025, $1.33/£1 for 2026, and $1.30/£ for Q1 2027. In this base case scenario, our forecasts show that the Group will have sufficient financial headroom to meet the applicable financial covenants for the 12 months from the date of approval of the financial statements.

Management has also prepared a "severe but plausible" downside case, which reflects the possible impact of global economic uncertainties resulting in the oil price dropping to $60/bbl in Q4 2025 and $62/bbl in 2026, before recovering to $65/bbl by Q1 2027. In this downside case management has assumed foreign exchange rates of an average $1.35/£1 for the remainder of the going concern period. Our downside case also included a reduction in production of 5% throughout the going concern period. In the event of a downside scenario, management could take mitigating actions including delaying capital expenditure and reducing costs, in order to remain within the Group's financial covenants over the remaining facility period, should such actions be necessary. All such mitigating actions are within management's control. In this downside scenario including mitigating actions, our forecast shows that the Group will have sufficient financial headroom to meet its financial covenants for the 12 months from the date of approval of the financial statements. Management remain focused on maintaining a strong balance sheet and funding to support our strategy.

Statement of Directors' responsibilities

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

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

By order of the Board,

Ross Glover

Chief Executive Officer

Condensed Interim Consolidated Income Statement

Other comprehensive income for the period/year:

Items that may be reclassified subsequently to profit or loss:

* See note 17 for explanation of reclassification of this balance.

Condensed Interim Consolidated Balance Sheet

* The foreign currency translation reserve includes an amount of £3,799 thousand (31 December 2024: £3,799 thousand, 30 June 2024: £3,799 thousand) relating to exchange gains and losses on translation of net assets and results, and intercompany balances, which formed part of the net investment of the Group, in respect of subsidiaries which previously operated with a functional currency other than UK pound sterling.

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 and its subsidiaries (the Group) for the six months ended 30 June 2025, which are unaudited, were authorised for issue in accordance with a resolution of the Directors on 16 September 2025. Star Energy Group plc is a public limited company incorporated in the United Kingdom and registered in England and Wales and listed on the Alternative Investment Market (AIM). The Group's principal activities are exploring for, appraising, developing and producing oil and gas and developing geothermal projects.

2 Accounting policies

Basis of preparation

These unaudited condensed interim consolidated financial statements for the six months ended 30 June 2025 have been prepared in accordance with UK-adopted International Accounting Standard 34, 'Interim Financial Reporting' ("IAS 34") and the AIM Rules for Companies. The unaudited condensed interim consolidated financial statements should be read in conjunction with the consolidated financial statements for the year ended 31 December 2024. The annual financial statements of Star Energy Group plc are prepared in accordance with UK-adopted International Accounting Standards.

The financial information contained in this document does not constitute statutory accounts as defined by Section 434 of the Companies Act 2006 (England & Wales). The financial information as at 31 December 2024 is based on the statutory accounts for the year ended 31 December 2024. A copy of the statutory accounts for that year, has been delivered to the Registrar of Companies and is available on the Company's website at www.starenergygroupplc.com. The auditors' report in accordance with Chapter 3 Part 16 of the Companies Act 2006 in relation to those accounts was unqualified, did not draw attention to any matters by way of emphasis and did not contain a statement under section 498(2) or (3) of the Companies Act 2006.

The accounting policies adopted are consistent with those of the previous financial year and corresponding interim reporting period, except for the adoption of the new and amended standards and interpretations discussed below. Prior period numbers have been reclassified, where necessary, to conform to the current period presentation.

Going concern

The Group continues to closely monitor and manage its liquidity risks. Cash flow forecasts for the Group are prepared on a monthly basis based on, inter alia, the Group's production and expenditure forecasts, management's best estimate of future oil prices and foreign exchange rates and the Group's available loan facility. Sensitivities are run to reflect different scenarios including, but not limited to, possible reductions in commodity prices, fluctuations in exchange rates and reductions in forecast oil production rates.

The current geopolitical climate and uncertain global economic outlook has reduced crude oil prices in the first half of 2025, with volatility in oil prices and foreign exchange rates likely to continue.

The focus of the Group in 2025 has been to strengthen our balance sheet and improve our resilience to oil price volatility. We have generated positive operating cashflows in H1 2025 as a result of stable production and a continued effort to minimise operating costs. We have also carried out a reorganisation in 2024 resulting in a material reduction in general and administrative costs in 2025. Our €25 million finance facility, of which €10.2 million remains undrawn, and the sale of non-core land with the proceeds of £6.3 million being received in April 2025, further improve our liquidity position.

However, the ability of the Group to operate as a going concern is dependent upon the continued availability of future cash flows and the availability of the monies drawn under its loan facility, which is dependent on the Group not breaching the facility's covenants. To mitigate these risks, the Group benefits from its hedging policy with 152,800 barrels hedged for the second half of 2025 and first quarter of 2026 using swaps at an average price of $72.9/bbl. We have additionally created some downside protection for 237,800 bbls with a three-way put/call options for H2 2025 and for 2026. We have also put in place USD/GBP foreign exchange hedges for $0.5 million/month at a rate of $1.227/£1 for the remainder of 2025

The Group's base case cash flow forecast was run with average oil prices of $66/bbl until the end of H1 2026, $68/bbl for H2 2026, $70/bbl for Q1 2027, and foreign exchange rates of an average $1.35/£1 for the remainder of 2025, $1.33/£1 for 2026, and $1.30/£ for Q1 2027. In this base case scenario, our forecasts show that the Group will have sufficient financial headroom to meet the applicable financial covenants for the 12 months from the date of approval of the financial statements.

Management has also prepared a "severe but plausible" downside case, which reflects the possible impact of global economic uncertainties resulting in the oil price dropping to $60/bbl in Q4 2025 and $62/bbl in 2026, before recovering to $65/bbl by Q1 2027. In this downside case management has assumed foreign exchange rates of an average $1.35/£1 for the remainder of the going concern period. Our downside case also included a reduction in production of 5% throughout the going concern period. In the event of a downside scenario, management could take mitigating actions including delaying capital expenditure and reducing costs, in order to remain within the Group's financial covenants over the remaining facility period, should such actions be necessary. All such mitigating actions are within management's control. In this downside scenario including mitigating actions, our forecast shows that the Group will have sufficient financial headroom to meet its financial covenants for the 12 months from the date of approval of the financial statements. Management remain focused on maintaining a strong balance sheet and funding to support our strategy.

New and amended standards and interpretations

During the period, the Group adopted the following new and amended IFRSs for the first time for their reporting period commencing 1 January 2025:

The above amendment to IAS 21 did not have a material impact on the financial statements of the Group. There are no other standards that are not yet effective and that would be expected to have a material impact on the entity in the current or future reporting periods, with the exception of IFRS 18 Presentation and Disclosure in Financial Statements which was issued on 9 April 2024, effective for periods beginning on or after 1 January 2027. We are in the process of assessing the impact of this newly issued standard on our future financial statements.

Estimates and judgements

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

In preparing these unaudited condensed interim consolidated financial statements, the significant judgements made by management in applying the Group's accounting policies and the key sources of estimation uncertainty were the same as those applied to the consolidated financial statements for the year ended 31 December 2024.

Financial risk management

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

The unaudited condensed interim consolidated financial statements do not include financial risk management information and disclosures required in the annual financial statements; accordingly, the unaudited condensed interim consolidated financial statements should be read in conjunction with the Group's annual financial statements as at 31 December 2024.

3 Basis of consolidation

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

4 Revenue

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

6 Tax on profit/(loss) on ordinary activities

The Group calculates the period income tax expense using the UK corporation tax rate that would be applicable to expected total annual earnings for the 12 months ending 31 December 2025. The majority of the Group's profits are generated by "ring-fence" business which attract UK corporation tax and supplementary charges at a combined average rate of 40% (six months ended 30 June 2024: 40%), in addition to the Energy Profit Levy (EPL) with a rate of 38% for the period (six months ended 30 June 2024: 35%). The tax charge for the period comprises deferred tax charge of £8.0 million (six month ended 30 June 2024: deferred tax credit of £3.4 million) principally due to reduction in the amount of recognised tax losses due to lower forecast oil prices and an extension of the EPL regime, and a current tax charge of £0.5 million in respect of the EPL (six months ended 30 June 2024: £1.7 million).

The major components of income tax expense in the unaudited condensed interim consolidated income statement are:

A deferred tax asset of £23.1 million (30 June 2024: £40.6 million, 31 December 2024: £31.1 million) has been recognised in respect of tax losses and other temporary differences where the Directors believe that it is probable that these assets will be recovered based on estimated taxable profit forecasts.

Corporation tax payable of £2.6 million (30 June 2024: £2.8 million, 31 December 2024: £3.1 million) has been recognised in respect of the EPL. Tax paid in the period was £1.0 million (30 June 2024: £nil, 31 December 2024: £nil).

The Group has gross total tax losses and similar attributes carried forward of £367.6 million (30 June 2024: £361.6 million, 31 December 2024: £367.8 million). Deferred tax assets have been recognised in respect of tax losses and other temporary differences where the Directors believe it is probable that these assets will be recovered based on a five-year profit forecast or to the extent that there are offsetting deferred tax liabilities. Such recognised tax losses include £75.0 million (30 June 2024: £104.8 million, 31 December 2024: £85.0 million) of ringfence corporation tax losses which will be recovered at 30% of future taxable profits, £63.0 million (30 June 2024: £90.4 million, 31 December 2024: £70.2 million) of supplementary charge tax losses which will be recovered at 10% of future taxable profits, £3.5 million (30 June 2024: £4.8 million, 31 December 2024: £4.1 million) of losses arising under the EPL regime which will be recovered at 38% of future taxable profits and £3.2 million (30 June 2024: £4.6 million, 31 December 2024: £3.2 million) of non-ringfence corporation tax losses which will be recovered at 25% of future taxable profits.

7 Other income/expense

Other income of £4.5 million primarily relates to gain on sale of the land at the decommissioned Holybourne processing facility. The site was sold for a cash consideration of £6.3 million in April 2025. Other expense of £2.0 million in the period to 30 June 2024 related to costs incurred in connection with the sale.

8 Earnings per share (EPS)

Basic EPS amounts are based on the loss for the period after taxation attributable to the ordinary equity holders of the Parent Company of £3.9 million and the weighted average number of ordinary shares outstanding during the period of 132.1 million.

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

As at 30 June 2025, there are 6.3 million potentially dilutive employee share options. These were not included in the calculation at 30 June 2025, as their conversion to ordinary shares would have decreased the loss per share.

9 Intangible assets

Exploration and evaluation assets

Exploration costs impaired in the period to 30 June 2025 were £0.03 million (6 months to 30 June 2024: £1.8 million, year ended 31 December 2024: £1.9 million) representing costs of early-stage oil and gas projects where it was assessed that there was no further development prospect.

The Group has £4.0 million (six months ended 30 June 2024: £4.0 million, year ended 31 December 2024: £4.0 million) of capitalised exploration expenditure which relates to our oil and gas assets including PL 240.

Management assessed the remaining capitalised exploration expenditure for indications of impairment under IFRS 6 Exploration for and Evaluation of Mineral Resources and did not identify any factors indicating an impairment.

Goodwill

The Group has identified four Cash Generating Units (CGUs) within our geothermal business, whereby technical, economic and/or contractual features create underlying interdependence in the cash flows. These CGUs correspond to the three licences (Ernestinovo, Sječe and Pčelić) and the UK geothermal business. The carrying amount of goodwill arose on the acquisition of an interest in A14 Energy Limited ("A14 Energy") in 2023 and is allocated to the following CGUs:

The Group tests goodwill for impairment annually or more frequently if there are indications that goodwill might be impaired. At 30 June 2025, management reviewed the carrying value of the Sječe and Pčelić licence CGUs and assessed them for impairment. The recoverable amount calculated was higher than the carrying value, hence no impairment charge was recognised against the goodwill allocated to these CGUs .

Development costs

The carrying amount of development costs is split between CGUs as follows:

The costs allocated to the UK geothermal business CGU primarily relate to the design and development of deep geothermal heat projects in the United Kingdom and was recognised as part of the acquisition of GT Energy UK Limited in 2020.

The costs associated with the Ernestinovo licence relate to the fair value of assets acquired as part of the A14 Energy acquisition. The costs relate to the value of the licence award and work performed up to the acquisition date in progressing with the re-entry of an existing well on the Ernestinovo exploration licence.

The Group tests intangible assets not yet ready for use for impairment annually or more frequently if there are indications that the asset might be impaired. At 30 June 2025, management reviewed the carrying value of the Ernestinovo licence CGU and assessed it for impairment. The recoverable amount calculated was higher than the carrying value of the CGU, hence no impairment charge was recognised against capitalised development cost or allocated goodwill.

10 Property, plant and equipment

Impairment of Oil and Gas Assets

Period ended 30 June 2025

Cash Generating Units (CGUs) for impairment purposes are the group of fields whereby technical, economic and/or contractual features create underlying interdependence in the cash flows. The Group has identified the three main producing CGUs as: North, South, and Scotland. At each balance sheet date, the Group assesses its CGUs for impairment whenever events or changes in circumstances indicate that the carrying amount of the CGU may not be recoverable. If any such indication exists, the Group makes an estimate of the asset's recoverable amount. An impairment assessment was performed for all three CGUs at the balance sheet date as a result of identification of impairment indicators, mainly due to reduction in oil prices, adverse foreign exchange rate movements and unfavourable changes in the Energy Profits Levy regime in the period. An impairment indicator was noted for the Scotland CGU given the delay in finalisation of the potential sale of the underlying site.

• Group's estimate of proved plus probable reserves at the balance sheet date
• Oil price (Brent): $65/bbl for the years 2025-2029 and $75/bbl thereafter
• USD/GBP foreign exchange rate: Range of $1.36:£1.00 - $1.30:£1.00
• Post-tax discount rate: 8.5%

Outcome of impairment reviews:

The 30 June 2025 impairment assessment resulted in a recoverable amount greater than the carrying amount by £0.03 million in the South CGU (recoverable amount of £25.7 million) and £1.2 million in the North CGU (recoverable amount of £29.9 million). At the Scotland CGU, no impairment charge was recognised, with the recoverable amount of £0.3 million assessed to approximate the carrying value of the CGU (which includes the carrying value of the associated decommissioning liability).

Sensitivity of changes in assumption:

The principal assumptions in the discounted cashflow methodology are future production, estimated Brent prices, the USD/GBP long-term foreign exchange rate, and the discount rate. The impact on the recoverable amount that would result from changes to the key assumptions at 30 June 2025 are shown below:

11 Financial Instruments - fair value disclosure

• 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 oil. The hedges are valued by comparing the fixed prices of the trades with prevailing market forward prices (or end of day prices) and the difference multiplied by the traded volumes. These results are discounted to provide a fair value.

Foreign exchange contracts

The fair value of foreign exchange contracts was provided by counterparties with whom the trades have been entered into and is based on the difference between the contracted forward rate and the forward rate at the balance sheet date multiplied by the amount of foreign currency hedged, which is then discounted to provide the fair value.

Fair value of other financial assets and financial liabilities

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

12 Provisions

Decommissioning provision

The Group spent £0.3 million on decommissioning activities during the period (six months ended 30 June 2024: £0.7 million; year ended 31 December 2024: £1.1 million).

Provision has been made for the discounted future cost of abandoning wells and restoring sites to a condition acceptable to the relevant authorities. This is expected to take place between 1 to 30 years from period end (30 June 2024: 1 to 29 years; 31 December 2024: 1 to 31 years). The provisions are based on the Group's internal estimate as at 30 June 2025. Assumptions are based on our cumulative experience from decommissioning wells which management believes is a reasonable basis upon which to estimate the future liability. The estimates are based on a planned programme of abandonments but also include a provision to be spent in 2026-2029 on preparing for the abandonment campaign, abandoning wells and restoring sites which for regulatory, integrity or other reasons fall outside the planned campaign. The estimates are reviewed regularly to take account of any material changes to the assumptions. Actual decommissioning costs will ultimately depend upon future costs for decommissioning which will reflect market conditions and regulations at that time. Furthermore, the timing of decommissioning is uncertain and is likely to depend on when the fields cease to produce at economically viable rates. This, in turn, will depend on factors such as future oil prices, which are inherently uncertain.

The Group applies an inflation adjustment to the current cost estimates and discounts the resulting cash flows using a risk free discount rate. The provision estimate reflects a higher inflation percentage in the range of 2.5% - 3% in the near term for the period 2025 - 2026 and incorporates the long-term UK target inflation rate of 2% for the years 2027 and beyond.

A risk free rate range of 3.0% to 6.7% is used in the calculation of the provision as at 30 June 2025 (30 June 2024: Risk free rate range of 3.0% to 5.8%, 31 December 2024: Risk free rate range of 3.0% to 6.3%).

Management performed sensitivity analysis to assess the impact of changes to the risk free rate on the Group's decommissioning provision balance. A 0.5% decrease in the risk free rate assumption would result in an increase in the decommissioning provision by £4.4 million. Management also performed sensitivity analysis to assess the impact of changes to the undiscounted future cost of abandoning wells and restoring sites on the Group's decommissioning provision balance. A 10% increase in the undiscounted future cost would result in an increase in the decommissioning provision by £6.4 million.

Contingent consideration

The carrying value of contingent consideration at the beginning of the period related to the acquisition of GT Energy UK Limited (GT Energy), which was payable in shares and was dependent on the timing of a business development milestone being achieved. At the balance sheet date, management has assessed that it is highly unlikely that the milestone will be met within the timelines specified in the GT Energy share purchase agreement and, as a result, the provision for contingent consideration has been released in full in the period ended 30 June 2025.

13 Cash and cash equivalents and other financial assets

Borrowings

On 9 April 2024, the Group secured a €25.0 million finance facility with Kommunalkredit Austria AG (Kommunalkredit). The facility comprises of a facility A which was used to fund the repayment of the outstanding balance on the reserves based loan (RBL) facility, carried a fixed interest rate of 9.4% and was fully repaid on its contractual maturity date of 30 June 2025, and a facility B which primarily provides funding for the Group's geothermal development activities, carries an interest rate of Euribor + 6% and has a five-year term with repayments commencing on 30 June 2026.

• Loan Life Cover Ratio ("LLCR") of greater than or equal to 1.25:1.
• Proved and developed reserves value to Net Debt ratio of greater than or equal to 2.50:1.

We complied with all the covenants applicable at the balance sheet date.

Collateral against borrowing

14 Share capital

15 Acquisition of non-controlling interest

On 3 January 2025, the Group acquired a further 20% interest in the issued share capital of its subsidiary A14 Energy from the minority shareholder Peninsula International PTE Limited. As a result, the Group's shareholding in A14 Energy increased from 51% to 71%. The acquisition of the additional shareholding was completed by conversion of the loan notes held by the Group.

Unaudited 6 months ended 30 June 2025 £000

Decrease in equity attributable to owners of the Company comprised of a decrease in retained earnings of £431 thousand and an increase in foreign currency translation reserve of £3 thousand.

16 Operating Segments

An operating segment is a component of the Group that engages in a business activity from which it may earn revenues and incur expenses, including revenues and expenses that relate to transactions with any of the Group's other components. All operating segments operating results are reviewed regularly to make decisions about resources to be allocated to the Segment and to assess its performance by the Chief Operating Decision Maker, which for the Group is the Board of Directors. Segment results include items directly attributable to a segment as well as those that can be allocated on a reasonable basis. Unallocated items comprise mainly corporate assets and head office expenses.

Unaudited at 30 June 2025

* See note 17 for explanation of reclassification of this balance.

The Group has two geographical areas of operation being the UK and Croatia. All Group revenues are derived in the UK. There is a total of £8.1 million (30 June 2024: £3.8; 31 December 2024: £7.5 million) of non-current assets relating to operations in Croatia, with the remainder of the Group's non-current assets relating to operations in the UK.

17 Reclassification

Change in fair value of contingent consideration of £2.3 million for the period ended 30 June 2024 has been reclassified and presented after operating profit/(loss) to align with the presentation treatment adopted in the audited consolidated financial statements of the Group for the year ended 31 December 2024. This has resulted in operating loss of the Group for the period ended 30 June 2024 increasing by a corresponding amount with no impact on profit/(loss) before tax.

Glossary

£ The lawful currency of the United Kingdom

$/USD The lawful currency of the United States of America

€ The lawful currency of the European Union

1P Low estimate of commercially recoverable reserves

2P Best estimate of commercially recoverable reserves

3P High estimate of commercially recoverable reserves

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

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

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

AIM AIM market of the London Stock Exchange

Bbl(s)/d Barrel(s) of oil per day

Bcf billions of standard cubic feet of gas

boepd Barrels of oil equivalent per day

bopd Barrels of oil per day

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

GIIP Gas initially in place

m Million

Mbbl Thousands of barrels

MMboe Millions of barrels of oil equivalent

MMscfd Millions of standard cubic feet per day

PEDL United Kingdom petroleum exploration and development licence

PL Production licence

Tcf Trillions of standard cubic feet of gas

UK United Kingdom