29 April 2025

Star Energy Group plc (AIM: STAR)

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

Full year results for the year ended 31 December 2024

Commenting today, Ross Glover, Chief Executive Officer, said:

"I am very pleased to be presenting my first annual results as Chief Executive Officer of Star Energy. Our strategic aim is to be a profitable energy business generating strong cashflows from our oil and gas assets whilst progressing growth opportunities in the geothermal sector. By focusing on maximising profitability from our oil and gas activities, we ensure long-term sustainability and can successfully navigate a volatile oil price environment, which is increasingly important in today's uncertain geopolitical climate. We have maintained strong production across our fields and made good progress in reducing costs, with substantial general and administrative savings projected for 2025.

Investing in our producing assets provides a robust financial foundation for future growth, and I am confident that geothermal energy presents a significant growth opportunity in both the UK and Europe. Successful project development will create material incremental asset value and can deliver strong returns for shareholders. We recognise that it will take time to bring our geothermal projects to production and are committed to rigorously assessing project commerciality in order to allocate capital based on strict criteria for achievement of milestones and creation of value. This approach will enable us to build a portfolio of profitable projects over time."

Financial Performance

* Adjusted EBITDA, Net Debt (borrowings less cash and cash equivalents excluding capitalised fees) and Underlying Operating Profit are used by the Group, alongside IFRS measures for both internal performance analysis and to help shareholders, lenders and other users of the Annual Report to better understand the Group's performance in the period in comparison to previous periods and to industry peers

Corporate & Financial Highlights

·      Successfully secured a €25 million financing facility provided by Kommunalkredit Austria AG which, while primarily supporting the development of our geothermal energy sector, also enables continued investment in the oil and gas business utilising existing cash flows

·      Cash at 31 December 2024 was £4.7 million, excluding restricted cash, and Star Energy had drawn £12.2 million under its loan facility. Restricted cash was £4.3 million and relates to the cash backing of performance bonds for licence commitments of the Company's Croatian subsidiary relating to the Sječe and Pčelić exploration licences

·      Increased our stake in our Croatian subsidiary post year end, from 51% to 71%, allowing us to control the development of this initiative until appropriate value inflection points are achieved

·      Exchanged contracts for the sale of non-core land for £6.3 million in November 2024 with proceeds received in April 2025

·      Hedging in place for 400bbl/d for H1 2025 and H2 2025 with swaps at an average price of $79.8/bbl and $73.0/bbl, respectively

·      Energy Profits Levy of £1.0 million paid in February 2025 based on the taxable profits for the year ended 31 December 2023. The Company estimates a charge of £2.1 million for 2024

 Operational Highlights

·      Net production, in line with guidance averaging 1,989 boepd in 2024 (2023: 2,100), with uptime across the portfolio remaining strong over the year

·      Continued to optimise oil production from our existing wells through selective investment in short cycle developments which deliver quick payback

·      DeGolyer & MacNaughton updated CPR  values 2P NPV10 at $188 million (2023: $235 million). The decrease in reserves value is due to a development project moving out of the reserves category due to project prioritisation

·      Work has begun on the Singleton gas-to-wire project which will deliver c.74 boe/d, utilising gas which is currently being flared. The project, which satisfies the regulatory requirements for the facility, now has planning consent and a secured grid connection. Procurement for long lead items is underway, with a first export of electricity from the site expected late 2025

·      Ernestinovo licence commitments have been fulfilled and the acquisition of magnetotelluric data across the Sjece and Pcelic geothermal licence blocks in Croatia is complete, with the incorporation of this data into the geological models underway.  Work is ongoing on the technical analysis to rank the optimal sequencing of their commercial development

·      Seismic data was acquired and analysed for the Salisbury NHS Foundation Trust project, and pre-applications have been submitted for planning and permitting for both Salisbury and the Wythenshawe Hospital projects

Outlook

·      We anticipate net production of c.2,000 boepd and operating costs of c.$40/boe (assuming an average exchange rate of £1:$1.27) in 2025

·      2025 forecast capital expenditure is c.£10.0 million. This includes £5.8 million on the Singleton gas-to-wire project which is forecast to come online in late 2025 with production of 74 boe/d. Star Energy also plans to invest £1.7 million on quick returning incremental projects and the balance on regulatory improvements, site resilience and projects to reduce operating costs going forward

·      Holybourne sale proceeds of £6.3 million will be used to repay Facility A of our Kommunalkredit loan which is due on 30 June 2025

·      Good progress on G&A costs reduction expected to generate savings of c.£1.5 million in 2025

·      Data analysis continuing to further derisk our Croatian portfolio

·      Seeking strategic partnerships in the UK to advance our pipeline

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

Marie Dransfield, Technical Director of Star Energy Group plc, and a qualified person as defined in the Guidance Note for Mining, Oil and Gas Companies, June 2009 as updated 21 July 2019, of the London Stock Exchange, has reviewed and approved the technical information contained in this announcement. Mrs Dransfield has 19 years' oil and gas exploration and production experience.

For further information please contact:

Chairman's statement

I am pleased with the progress we have made on our strategic aims during the year despite an increasingly challenging political and regulatory environment. Our focus remains on being a responsible operator of our oil and gas assets, managing these for maximum value and rightsizing to maintain profitability, whilst continuing to contribute to the delivery of the UK's domestic energy security.

At a time of increasing international uncertainties, where the value of energy security is important, 100% of our production comes from the UK onshore and is consumed in the UK. We focus on maintaining consistent volumes of production and investing our capital to create value for shareholders now and over the longer term. We are keen to capitalise on our undoubted skills in onshore oil and gas operations to develop growth opportunities as these arise in geothermal power and heating, both in the UK and Croatia.

Our long experience of successful and environmentally responsible onshore oil and gas development and operation, together with a substantial skillset in this area is readily transferable to geothermal. We have established expertise in navigating the regulatory and planning environment and have very experienced commercial, subsurface and operating teams. We calibrate our initiatives to match the readiness  of our counterparties and customers. Our expertise has been supplemented through the acquisition of A14 Energy in 2023, where the Croatian team provide significant in-country expertise. We have the technical and operational capability to de-risk projects, creating natural monetisation points that offer flexibility to retain or farm down assets for early value realisation.

We have strengthened our balance sheet through securing a €25 million debt facility with Kommunalkredit AG which, while primarily funding geothermal growth, also allows us to reinvest cashflows in our oil and gas assets. The sale of a non-core asset for £6.3 million which completed in 2025, was an important step in realising value from our existing assets. However, improving our resilience in an uncertain commodity price environment is critical and we have already made good progress on this, realising significant savings in our cost base as we go into 2025.

Generating strong cashflows from our existing operations is important in creating value for shareholders. We have continued to operate in a safe and environmentally friendly manner and achieved a strong safety performance for the year. The safety of our staff and that of the communities we work in is of paramount importance and will always be front and centre as we look to streamline our operations and drive down costs. Our existing operations provide a solid platform for maximising profits in our conventional oil business and provide the professional and capital resources as new energy opportunities materialise.

In a UK context, the decarbonisation of heat utilising the geothermal resource beneath our feet can deliver a sustainable, low carbon and on demand energy source. Approximately half of energy consumed in the UK is ultimately used in the creation of heat. The development of a geothermal sector would provide baseload heat. It could help make Britain the clean energy superpower promoted by the government and boost economic growth whilst helping the country achieve its legally binding net zero targets. With our extensive UK onshore expertise, transferable skills and subsurface database, we are in a strong position to deliver low carbon heat energy for the country provided that the government is able to use its convening and co-ordinating powers to help deliver executable projects in a timely fashion.

In Croatia, we have advanced our geothermal projects with further data acquisition and interpretation across all three licences. Geothermal activity in the country is increasing rapidly, and Croatia is emerging as a European hotspot for the sector. A supportive regulatory regime and government backing provide a solid foundation for the development of our existing licences and further expansion. Growing investor interest underlines the potential, and our increased stake in the Croatian subsidiary post year end, from 51% to 71%, allows us to control the development of this initiative until appropriate value inflection points are achieved.

In 2024, we appointed Ross Glover as CEO,  who brings a depth of experience in both oil and gas and renewable energy development. Ross has been with Star since 2017 and was previously COO. We thank the previous CEO,  Chris Hopkinson, for his contribution to the development of the Company and we wish him all the best for the future.

On behalf of the Board, I would like to thank everyone in the business for their commitment and professionalism. It is the combination of a proven track record of strong operational performance, resilience and adaptability that keep the business moving forward.

Outlook

Recent times have amply demonstrated that energy is a strategic resource and the basic building block for a modern economy looking for growth. The current geopolitical climate and its impact on oil prices reinforces the importance of resilience in a volatile commodity price environment. As the largest onshore oil and gas company in the UK, Star has an important role to play. The energy transition is underway, and we are at the forefront of the challenges and opportunities that this evolution brings. However, the approach must be managed wisely as hydrocarbons currently continue to provide the world with some 80% of our daily energy supply (much of it imported into the UK). The Company will accordingly continue to maximise its own cashflows from its existing energy portfolio. We will invest in our conventional business to maintain production levels. It is important to recognise the continuing role of fossil fuels in providing for UK energy needs during the transition to a low carbon economy and developing indigenous, locally produced resources is a critical part of the UK's future energy security. We continue to play our part in delivering that.

Operating review

We continue to operate in a safe and environmentally sensitive manner, which is a fundamental principle guiding all our activities and decisions. Our focus on maximising profitability from our oil and gas activities is crucial for long-term sustainability and enables us to successfully navigate a volatile oil price environment. We plan to capitalise on government backing, an investor-friendly regulatory framework, and increased investor interest in Croatia, presenting a unique opportunity for expansion and progression of our geothermal projects in this region. In the UK, we are advancing geothermal energy to take advantage of the government's renewable energy aspirations, proceeding cautiously until a clearer investment framework is established.

Oil and gas

The Company's focus is on optimising the net profitability of the fields from which it produces. In this context, predictability of production (across its mature portfolio of operations) is also important. Well uptime remained strong across the year with net production for the year averaging 1,989 boepd (2023: 2,100 boepd). Good results from a rolling programme of well optimisation and stimulation activities yielded additional production at a number of sites. However, as expected, we saw a reduction in production from our Albury field (c. 80 boe/d) due to a decline in gas pressure resulting in the cessation of gas exports.

We continue to offset decline rates through the execution of low cost incremental production projects with short pay-back times, and have increased the efficiency of our well service operations thereby achieving better uptimes across our sites. We have made progress in reducing operating costs in certain areas, from £24.1 million in 2023 to £22.3 million, however, more work needs to be done and this will be a focus as we go forward. We are still seeing the impact of the regulatory burden but are working with regulators to address those costs and/or duplication of effort which do not contribute to our high standards as an environmentally responsible operator. We upgraded pipelines and the processing centre at our Gainsborough site which will result in lower operating costs going forward. However, a step-change in operating costs is dependent on optimising the operational portfolio, including full field abandonment at less productive sites. Work has started on this and, following the full impairment of our shale assets in 2023, we have started to rationalise our portfolio of exploration licences, relinquishing early-stage exploration and shale licences whilst retaining core exploration acreage adjacent to our existing operations in the East Midlands. Five wells have been abandoned at our non-operated Doe Green and Irlam sites, with site restoration work planned for 2025. Alongside this, we have re-organised and simplified our operating licence structure. This re-organisation will lead to reduced costs and a lower administrative burden going forward.

We have also made good headway in reducing our G&A costs with a target to achieve annual savings of c.£1.5 million with effect from 2025. We will continue to maximise cashflows from our oil and gas business and secure an income stream that is resilient in a volatile commodity price environment.

Work has begun on the Singleton gas-to-wire project which will deliver c.74 boe/d, utilising gas which is currently being flared. The project, which satisfies the regulatory requirements for the facility, now has planning consent and a secured grid connection. Procurement for long lead items is underway, with a first export of electricity from the site expected in late 2025. We have permitted projects at Glentworth (200boepd), Corringham (100boepd) and Bletchingley (6MW gas-to-wire), however, progress on these is subject to finding a farm-in partner.

Geothermal Energy

We see exciting opportunities for growth in our geothermal business, both in the UK and Croatia. The International Energy Agency's report on geothermal energy in December 2024 recognised the huge potential for geothermal energy and concluded that, if geothermal can follow in the footsteps of innovation success stories such as solar PV, wind, EVs and batteries, it can become a cornerstone of tomorrow's electricity and heat systems as a dispatchable and clean source of energy.

Croatia

In Croatia, there is now significant activity in the geothermal sector, with over 100MW of geothermal power capacity projected to come online in 2028. Confirming its commitment to the sector, the Croatian government is drilling four geothermal exploration wells in 2025. This, along with a clear regulatory framework, has seen the emergence of the Pannonian Basin, in which our licences are located, as a key European geothermal hotspot. Our increased stake in A14 Energy Limited provides us with greater flexibility in our plans to accelerate the development of our Croatian assets and, when appropriate value inflection points have been achieved to introduce other partners. The increased interest does not expose us to material additional costs in the short to medium term due to the existing carry arrangements.

We have fulfilled our exploration obligations on our Ernestinovo licence and have established the exploitation field on the licence. A field development plan is under preparation and we expect to submit this shortly. We have completed the acquisition of magnetotelluric data across our Sjece and Pcelic licences. This data will delineate the reservoir and allow us to update our estimates of reservoir size. All our Croatian licences are in areas where substantial offset data sets are available from previous conventional oil and gas drilling activities. Our technical teams are at an advanced stage of consolidating all existing and new data for each of our three licences. 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 licences' commercial development. Preliminary conclusions point to good prospects within our Croatian portfolio, with high temperatures recorded in existing wells comparable with other Croatian geothermal reservoirs.

UK

In the UK, we have been successful in obtaining grant funding to progress our NHS projects. We continue to work in partnership with the Salisbury and Manchester NHS hospital trusts to decarbonise their operations and provide a reliable long-term source of heat. We are also pleased to be working with Bring Energy to explore the further integration of geothermal energy into Southampton's city-centre heat network where we will leverage our geothermal expertise to assess the potential for supplying heat to the existing network as well as exploring the development of a new geothermal supplied heat network to serve the northern part of the city.

The UK has legally binding net zero by 2050 targets, with interim carbon budgets set under the Climate Change Act 2008. Heating accounts for c.37% of all UK emissions and decarbonisation of the public sector is a key element of this. To date, UK government policy of decarbonising heat has had an emphasis on electrification, however, electrification alone is not a sufficient solution given electricity generation capacity is significantly less than will be required, and generating the additional capacity will involve material upgrades to the national grid. The next 12 months will be an important opportunity for the UK Government to demonstrate its commitment towards the decarbonisation of heat and, in particular, geothermal energy as an important tool in achieving its net zero ambitions. Geothermal energy can provide a solution to the UK's heat decarbonisation goals and we are well placed to take advantage of this significant opportunity.

Seismic data acquisition was completed in September 2024 for the Salisbury NHS Foundation Trust project. Processing and interpretation of the data acquired was completed by year end. We are preparing a planning application for submission in 2025.

In Manchester, at the Wythenshawe Hospital project, reprocessing and interpretation of legacy data is complete. Further seismic data will be acquired in Q4 2025, with the survey design largely completed.

As disclosed in note 6, the Stoke-on-Trent geothermal project in its original form is no longer progressing and we have therefore impaired the development costs of £4.3 million. As a result of its cancellation, £2.3 million of the related contingent consideration provision was released in the period.

Financial Review

Our focus for 2024 has been on strengthening our balance sheet, improving the resilience of our oil and gas business in the light of volatile commodity prices and positioning the Group for growth in the geothermal sector. We secured a €25 million debt facility (provided by Kommunalkredit Austria AG (Kommunalkredit)) which, while primarily supporting the development of our geothermal energy business, also enables continued investment in the oil and gas business utilising existing cash flows. We also exchanged contracts for the sale of non-core land and the proceeds of £6.3 million were received in April 2025. We commenced a cost reduction initiative in our G&A costs and forecast material savings for 2025.

Production for the year averaged 1,989 boepd (2023: 2,100 boepd),  in line with our production guidance. Brent oil prices remained stable until September when they came under pressure as a result of geopolitical tensions and concerns about demand. The average Brent price was $81/bbl in 2024 compared to $83/bbl in 2023.  Sterling  strengthened during the year with average GBP/USD rates of £1:$1.28 in 2024 compared to £1:$1.25 in 2023, negatively impacting our revenues which are mainly denominated in USD.

Revenues for the year were £43.7 million compared to £49.5 million in 2023, a reduction of £5.8 million reflecting lower commodity prices, particularly for gas and electricity, foreign exchange movements and lower volumes. The Group generated a net oil price hedging gain of £0.7 million for the year compared to a loss of £0.03 million in 2023. Other cost of sales decreased from £24.1 million in 2023 to £22.3 million in 2024 as reductions from cost savings,  lower production and processing fewer third-party barrels more than offset inflationary increases. Underlying operating costs (which exclude third party oil but include costs relating to leases capitalised under IFRS 16) were £32.8 ($42.0) per boe for the year (2023: £32.4 ($40.3) per boe).

Adjusted EBITDA was £11.1 million (2023: £16.1 million) and the underlying operating profit was £5.9 million (2023: £9.1 million), with the variance resulting primarily from a reduction in revenues.

* Includes depreciation charge recorded in administrative expenses

Restricted cash was £4.3 million (€5.2 million) which provides cash backing for the performance guarantees issued in relation to geothermal licence commitments in Croatia.

Income Statement

The Group recognised revenues of £43.7 million for the year (2023: £49.5 million). Oil revenue was £42.0 million compared to £44.8 million in 2023, reflecting lower prices and volumes and a stronger USD to GBP exchange rate. The average pre-hedge realised price for the year was $76.9/bbl (2023: $79.0/bbl). Gas revenues reduced to £0.2 million (2023: £ 1.9 million) due to lower gas prices and the permanent shut-in of gas-to-grid production at our Albury site. Electricity revenues declined by £0.6 million, primarily due to lower prices. Revenues relating to the sale of third-party oil also declined from £1.2 million to £0.3 million with the reduction relating mainly to lower volumes being processed in the year.

A gain of £0.7 million was recognised on oil hedges during the year (2023: loss of £0.03 million) with 201,400 bbls of fixed oil price contracts at an average price of $78.6/bbl (2023: 120,000 bbls at an average price of $88.1/bbl).

Cost of sales for the year were £28.8 million (2023: £32.3 million) including DD&A of £6.5 million (2023: £8.2 million), and other costs of sales of £22.3 million (2023: £24.1 million). Other costs of sales decreased by £1.8 million compared to 2023 mainly due to reduction in staff costs, lower workover and maintenance activity following the investment in our fields in 2023 and a reduction in third-party volumes being processed.  The DD&A charge has decreased by £1.7 million mainly due to an increase in the proven and probable reserves as at 1 January 2024 as compared to 1 January 2023 and due to lower production volumes in the year.

Adjusted EBITDA in the year was £11.1 million (2023: £16.1 million). The gross profit for the year was £14.9 million (2023: £17.1 million). 

Administrative costs remained largely consistent with prior year at £7.4 million (2023: £7.3 million). The increase in costs in the year due to redundancy payments, lower allocation to capital projects and inflationary increases was partially offset by a reduction in legal and professional costs, lower share-based payment charges and savings from cost reduction measures.

Research and non-capitalised development costs were £2.0 million (2023: £2.0 million), of which £1.6 million (2023: £1.6 million) related to our operations in Croatia, primarily for the re-entry and testing of a well on the Ernestinovo licence. These are early-stage costs which do not meet the criteria for capitalisation as development costs under IAS 38 Intangible Assets. The remainder of the costs mainly related to UK geothermal business development costs and expenditure on the NHS Trust geothermal projects, net of any grants received.

An impairment of development costs of £4.3 million (2023: £nil million) was recognised related to the Stoke-on-Trent geothermal project following the decision by SSE to change the focus of the project towards an 'Energy from Waste' project. The majority of the Stoke-on-Trent development costs arose as part of the GT Energy UK Limited acquisition. However, a significant portion of the consideration was based on achieving various milestones on that project and as a result of its cancellation, £2.3 million (2023: £nil million) of this contingent consideration provision was released.

Other expenses of £2.0 million (2023: £nil million) were incurred in the year in connection with preparing our Holybourne Oil Terminal site for sale. We exchanged contracts for the sale of the site in November 2024 with completion in April 2025.

Exploration and evaluation assets impaired of £1.9 million mainly represent costs incurred on PEDL 235 (Godley Bridge) where we decided not to renew that licence (2023: £0.5 million impairment of costs relating to our oil and gas assets where there was no further development prospect and trailing costs on previously impaired unconventional licences).

Net finance costs were £4.8 million (2023: £4.4 million) including interest and fees on borrowings of £1.1 million (2023: £1.2 million) and costs related to the performance guarantees issued in relation to licence commitments in Croatia of £0.4 million (2023: £0.1 million). Finance costs also included the unwinding of the discount on the decommissioning provision of £2.5 million (2023: £2.6 million) and interest charge on lease liabilities of £0.7 million (2023: £0.7 million). Net foreign exchange losses during the year were £0.1 million (2023: gain of £0.2 million) mainly arising from our Croatian operations.

A net tax charge of £8.1 million (2023: £8.3 million) was recognised during the year, mainly due to the reduction in the deferred tax asset relating to tax losses reflecting the decrease in the oil and gas reserves forecast (£6.1 million) and a current tax charge arising as a result of the Energy Profits Levy (£2.0 million).

Cash Flow

Net cash generated from operating activities for the year was £2.3 million (2023: £17.2 million). The reduction was primarily due to the decrease in cash inflows from revenue of £6.6 million, an increase in the cash outflows from operating costs, administrative expenses, including non-recurring legal and professional costs, and research and non-capitalised development costs of £8.6 million, partially offset by reduction in abandonment spend of £0.5 million.

The Group invested £5.7 million across its asset base during the year (2023: £8.5 million) primarily comprising of upgrades and a pipeline replacement at our Gainsborough site, optimisation projects across our portfolio to offset declines, rationalisation and decommissioning at our Holybourne site and general improvements across our fields.

The Group completed the refinancing of its borrowing facility during the year and secured a €25.0 million facility with Kommunalkredit Austria AG. Drawdowns were made primarily to repay the remaining balance under the reserves based lending (RBL) facility with BMO Capital Markets (BMO) of £5.5 million (€ 6.7 million), to provide cash backing for the performance guarantees issued in relation to licence commitments in Croatia of £4.3 million (€5.2 million) and to fund geothermal activity during the year. The amount drawn at the end of the year was £12.2 million (€14.8 million).  Net debt at the end of the year was £7.5 million (2023: £1.6 million). In addition, the Group held £4.3 million (€5.2 million) of restricted cash in relation to the Croatian performance bonds.

Facility arrangement and other fees were £0.6 million and we paid loan interest of £0.5 million (2023: £0.8 million).

Balance Sheet

Net assets reduced by £12.3 million to £42.6 million at 31 December 2024 (2023: £54.9 million), primarily due to a reduction in the intangible assets, property, plant and equipment, deferred tax asset and trade and other receivables and an increase in borrowings (net of restricted cash) and corporation tax payable, partially offset by a reduction in provisions and trade and other payables.

Intangible assets reduced by £6.1 million due to the recognition of impairment charges of £4.3 million relating to the Stoke-on-Trent geothermal project and the impairment of exploration costs of £1.9 million primarily relating to the Godley Bridge licence as explained above.

Property, plant and equipment reduced by £3.3 million during the year to £70.7 million. The value of decommissioning assets reduced by £2.8 million as a result of management's reassessment of the decommissioning provision. Capital expenditure incurred in the year was £4.8 million and we recognised a DD&A charge of £5.3 million.

The provision for decommissioning costs decreased by £1.5 million (2023: £0.4 million) mainly as a result of abandonment activity undertaken during the year (£1.1 million), a reassessment of the remaining provision, primarily due to a change in the discount rate (£2.9 million) and the annual unwinding of the discount on the provision (£2.5 million). The provision for contingent consideration reduced by £2.3 million following the cancellation of the Stoke-on-Trent project as explained above.

Trade and other payables reduced by £4.2 million as a result of timing of activity on capital and abandonment projects. In addition, the balance at the end of the previous year included accruals in relation to costs associated with refinancing, well re-entry activity on the Ernestinovo licence in Croatia and a liability related to the award of the Sječe and Pčelić Croatian geothermal exploration licences. No similar balances were included in the accruals and other creditor balance at the end of the current year. Trade and other receivables reduced by £0.7 million mainly due to the decrease in receivables from joint venture partners.

The deferred tax asset reduced by £6.1 million from £37.2 million at 31 December 2023 to £31.1 million at 31 December 2024 mainly due to a change in forecast utilisation of available tax losses.

The Group recognised a current tax liability of £3.1 million at 31 December 2024 relating to the Energy Profits Levy charge for the years ended 2023 and 2024 (2023: £1.1 million).

The derivative asset of £0.4 million (2023: £nil) represents the fair values of the open commodity price hedges provided by counterparties with whom the trades have been entered into.

Going Concern

The Group continues to closely monitor and manage its liquidity. 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 the impact of an increase in trade tariffs on the global economy has reduced crude oil prices in the first quarter of 2025, with volatility in oil prices and foreign exchange rates likely to continue whilst countries seek to negotiate trade agreements with the US.

The focus of the Group in 2024 has been to strengthen our balance sheet and improve our resilience to oil price volatility. We have generated strong operating cashflows in 2024 as a result of stable production and a continued effort to minimise operating costs. We have also carried out a reorganisation resulting in a material reduction in general and administrative costs going into 2025. The €25 million finance facility agreed with Kommunakkredit, and the sale of non-core land with the proceeds of £6.3 million being received in April 2025, further improves 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 146,200 barrels hedged for 2025 using swaps at an average price of $75/bbl.

The Group's base case cash flow forecast was run with average oil prices of $65/bbl for the remainder of 2025 and $70/bbl for 2026, foreign exchange rates of an average $1.31/£1 for the remainder of 2025 and $1.28/£1 for 2026. In this base case scenario, our forecasts show that the Group will have sufficient liquidity as well as 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 $55/bbl in Q2 2025 before recovering to $58/bbl in Q3 and Q4 2025, and to an average of $62/bbl in 2026. In this downside case management has assumed foreign exchange rates of an average $1.33/£1 for the remainder of 2025 and $1.33/£1 for 2026. Our downside case also includes a reduction in production of 5% throughout the going concern period. In the event of a downside scenario, management has the ability to drawdown further under the loan facility as well as to take mitigating actions including delaying capital expenditure and reducing costs, in order to maintain liquidity and 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 liquidity as well as sufficient 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.

Based on the analysis above, the Directors have a reasonable expectation that the Group has adequate resources to continue as a going concern for at least the next twelve months from the date of the approval of the Group financial statements and have concluded it is appropriate to adopt the going concern basis of accounting in the preparation of the financial statements.

Frances Ward

Chief Financial Officer

Non-IFRS Measures

The Group uses non-IFRS measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. The non-IFRS measures include net debt, adjusted EBITDA and underlying operating profit.

These non-IFRS measures are used by the Group, alongside IFRS measures, for both internal performance analysis and to help shareholders, lenders and other users of the Annual Report to better understand the Group's performance in the period in comparison to previous periods and to industry peers.

Net debt is defined as borrowings excluding capitalised fees less cash and cash equivalents and does not include the Group's lease liabilities or restricted cash.

Adjusted EBITDA and underlying operating profit includes adjustments in relation to non-cash items such as share-based payment charges and unrealised gain/ loss on hedges.

Lease costs for the period which have been capitalised under IFRS 16 have been added to underlying operating costs and deducted in the calculation of adjusted EBITDA.