Interim Results

THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION FOR THE PURPOSES OF ARTICLE 7 OF REGULATION 2014/596/EU WHICH IS PART OF DOMESTIC UK LAW PURSUANT TO THE MARKET ABUSE (AMENDMENT) (EU EXIT) REGULATIONS (SI 2019/310) (UK MAR). UPON THE PUBLICATION OF THIS ANNOUNCEMENT, THIS INSIDE INFORMATION (AS DEFINED IN UK MAR) IS NOW CONSIDERED TO BE IN THE PUBLIC DOMAIN.

15 September 2026

Kistos Holdings plc

("Kistos", the "Company", or the "Group")

Interim results for the six months to 30 June 2026

London, 15 September 2026 - Kistos Holdings plc (LSE: KIST), an independent energy company focused on generating value across the upstream and midstream markets, today announces its unaudited interim results for the six months ended 30 June 2026. The results are included below and copies are available at www.kistosplc.com.

Financial Highlights

·      Pro-forma EBITDA^2,3 was approximately $205 million including a $51 million contribution from Blocks 3&4 and Block 9, Oman, and reflecting the full benefit of strong commodity prices with the Group fully unhedged.

·      Cash and near cash⁴ of $259 million which includes $128 million of unrestricted cash, $95 million in escrow for Oman acquisition and a $36 million near cash Norwegian tax rebate expected to be received in December 2026.

·      Adjusted net debt² at period end: $23 million (30 June 2025: $86 million).

6 months ended 30 June 2026

1. Total production rate includes gas, oil and natural gas liquids and is rounded to nearest 100 barrels of oil equivalent per day, with sales and production volumes converted to estimated barrels of oil equivalent (boe) using the conversion factors set out in Appendix C to the Interim Financial Statements.

2. Non-IFRS measure. See note 2.2.1 to the Interim Financial Statements for definition and reconciliation to the nearest equivalent IFRS measure.

3. Pro forma numbers are defined as Group results as if the Oman Block 3&4 and Block 9 acquisitions had completed on 1 January 2026, based on draft financial information provided by the seller.

4. Cash and near cash is non-IFRS measure.

Andrew Austin, Executive Chairman of Kistos, commented:

"We generated significant cash in the first half of 2026, supported by strong operational performance across our asset portfolio, keeping us on track to meet our full-year pro forma production guidance of 19,000 - 21,000 boepd. With the Group fully unhedged, we captured the full benefit of strong prices during the period. The sanctioning of the Balder Next New Wells project in June 2026 marks an important milestone for Kistos, delivering a reserves replacement ratio of 120% across our existing asset base and further strengthening our 2P reserves base, which - together with our new interests in Oman - has more than doubled over the past year.

We remain focused on realising organic growth opportunities across our assets, including further development of the Balder area and, following the transition of operatorship of the Greater Laggan Area to Serica Energy, the potential to extract near-term value from infill drilling and further third-party tiebacks to the Shetland Gas Plant, alongside the enhanced terms recently secured under Block 9 EPSA in Oman.

Kistos remains disciplined in its approach to growth. We continue to see a range of value-accretive M&A opportunities across our core geographies, and we believe our track record and ability to execute transactions make us an attractive counterparty. As we evaluate opportunities across the value chain, we remain centred on maintaining financial strength and operational reliability."

Dr Richard Benmore, Non-Executive Director of Kistos, with a Bachelor's, Master's and PhD in Geosciences and who has been involved in the energy industry for more than 40 years, has read and approved the disclosure in this announcement.

The Company's internal estimates of resources contained in this announcement were prepared in accordance with the Petroleum Resource Management System guidelines endorsed by the Society of Petroleum Engineers, World Petroleum Congress, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers.

Enquiries

https://www.kistosplc.com

Kistos Holdings plc - 2026 Interim Report

Highlights

The first half of 2026 was a period of continued operational delivery and portfolio growth for Kistos, with production rates in line with guidance across the portfolio and the Group fully unhedged, capturing the full benefit of strong commodity prices in revenue and cash generation. Further investment in the Balder area in Norway, including the sanctioning of the Balder Next New Wells project, delivered a reserves replacement ratio of 120% across the Group's existing asset base during the period. In Oman, completion of Blocks 3&4 occurred on the 14 September 2026, with Block 9 expected to complete in H2 2026. Kistos also refinanced its outstanding bonds, moving the debt from Kistos Energy (Norway) AS up to the Kistos Holdings plc level and extending the Group's debt maturity profile. The Group reiterates full-year pro forma production guidance of 19,000 - 21,000 boepd.

In Norway, net production from the Balder area was 8,500 boepd (H1 2025: 2,800 boepd). The contribution from three new production wells on the Balder Phase V project, together with high production efficiency of 94% across the Jotun FPSO, Balder FPU and Ringhorne Platform, contributed to stable production. Start-up of the remaining two wells in Balder Phase V was completed in July 2026. Drilling of the Balder Phase VI trilateral well is under way targeting around 1.5 MMboe (net). First oil from Balder Phase VI is scheduled for December 2026. In June 2026, the Balder Next New Wells project was sanctioned to drill and complete seven wells for tie-back to Jotun FPSO from the southern Balder field area targeting around 8.6 MMboe (net). Start up of the Balder Next project is expected by the end of 2027, maintaining high production levels at Jotun FPSO beyond 2030.

In the UK, net production from the Greater Laggan Area ("GLA") was 2,100 boepd (H1 2025: 2,500 boepd). Uptime of 95% was achieved due to exceptionally low unplanned downtime in the period, coupled with a short pit stop completed in May. The Victory field continued to produce through the Shetland Gas Plant ("SGP"), providing a substantial unit opex benefit to GLA partners and utilising spare capacity in the SGP.

Serica Energy plc ("Serica") acquired Prax Upstream Limited (formerly Hurricane Energy Plc) following the administration of Prax's parent company, and completed the acquisition of TotalEnergies' remaining 40% operated interest in the west of Shetland assets on 26 March 2026. Serica is now the operator of the GLA and SGP.

Our Gas Storage business continued to deliver strong operational performance during the period, maintaining 98% availability. Physical import and export activity was lower than the prior period as a result of development and expansion activities to return the Hole House site to service, which reduced the requirement for import and export campaigns. Exported gas volumes during the period were 67.0 million therms (H1 2025: 107.2 million therms). Storage income for the period was $9.1 million, with the Hole House return to service funded by third-party financing under a profit share agreement.

In the Netherlands, net production from Q10-A was 1,200 boepd (H1 2025: 900 boepd), increasing on the prior period due to high uptime of the TAQA-operated P15-D platform. Planning for cessation of production (CoP) by year-end 2027 continued, with a rig contract for well P&A and a lift vessel to undertake platform jacket removal executed for a commencement window in 2028.

In Oman, both Blocks 3&4 and Block 9 have an effective date of 1 January 2025. Following receipt of the Royal Decree, completion of Blocks 3&4 occurred on the 14 September 2026, with completion of Block 9 expected in H2 2026 on a different timeline owing to its EPSA framework. Following the amendment to the Block 9 EPSA with Oman's Ministry of Energy and Minerals, effective 1 July 2026, the Group expects the enhanced terms to support production and future reserves growth. On a pro forma basis, the Oman interests contributed $51 million of EBITDA in the period.

Following the sanctioning of Balder Next New Wells, pro forma 2P reserves stood at 49.2 MMboe at the period end, with 2C resources estimated at a further 52.4 MMboe (Company estimates).

Key financial and operational data for the period is set out below, with further detail in the Financial Review.

1. Total production rate includes gas, oil and natural gas liquids and is rounded to nearest 100 barrels of oil equivalent per day, with sales and production volumes converted to estimated barrels of oil equivalent (boe) using the conversion factors set out in Appendix C to the Interim Financial Statements.

2. Non-IFRS measure. Refer to Appendix B and note 2.2.1 to the Interim Financial Statements for definition and reconciliation to the nearest equivalent IFRS measure.

3. Pro forma numbers are defined as Group results as if the Oman Block 3&4 and Block 9 acquisitions had completed on 1 January 2026, based on draft results provided by the seller.

Outlook

In Norway, following completion of Balder Phase V drilling, the COSL Pioneer has commenced drilling the single Balder Phase VI trilateral well, with first oil scheduled for December 2026. The King well, drilled from the Ringhorne platform, started up in August 2026.

The sanctioned Balder Next New Wells project carries a breakeven of approximately $30 per boe and a projected rate of return in excess of 35%. The drilling of these seven new wells will commence following the completion of the Balder Phase VI well and will also utilise the COSL Pioneer for a multi-year rig programme. Start-up is expected by the end of 2027, and the project is key to utilising the spare capacity at the Jotun FPSO. Alongside this programme, there has been continued progress on the FPSO debottlenecking project, which will increase processing capacity and operational flexibility ahead of the planned removal of the Balder FPU in 2028.

In the UK, the addition of Victory field volumes through the Shetland Gas Plant is expected to continue delivering significant unit opex reduction for the Greater Laggan Area partners through H2 2026. Following the operatorship transition to Serica, the joint venture continues to mature potential infill drilling and additional third-party tie-backs to the Shetland Gas Plant. At our Gas Storage business, well work associated with the Hole House return to service project is expected to continue into the autumn of 2026, ahead of a second rig campaign in 2027.

In the Netherlands, production from Q10-A is expected to remain steady through H2 2026, supported by continued strong uptime across the producing wells. Decommissioning contracts have been signed for removal of the platform jacket and a well plug and abandonment campaign starting in 2028. The Group continues to work closely with the P15 operator to reduce opex and identify decommissioning cost synergies across P15 HUB producers.

In Oman, completion of the Block 9 acquisition is expected in H2 2026, as previously guided, its different timeline reflecting the EPSA framework.

Financial Review

Unaudited results for the six months ended 30 June 2026

Financial results are prepared in accordance with IFRS, unless otherwise noted below:

1 Total production rate includes gas, oil and natural gas liquids and is rounded to the nearest 100 barrels of oil equivalent per day. Sales and production volumes are converted to estimated boe using the conversion factors in Appendix C to the Interim Financial Statements.

2. Non-IFRS measure. Refer to the definition within the glossary.

3. Non-IFRS measure. Refer to the definition within the glossary and reconciliation in Appendix B2.

4. Non-IFRS measure. Refer to the definition within the glossary and reconciliation in note 2.2.1.

5. Non-IFRS measure. Refer to the definition within the glossary and reconciliation in Appendix B1.

Financial commentary:

·      Revenue: $211.9 million (H1 2025: $87.9 million), reflecting higher production rates in Norway following FPSO start-up as well as strong commodity prices.

·      EBITDA: $154.0 million (H1 2025: $23.7 million). On a pro forma basis EBITDA ¹ was approximately $205 million, with the increase driven by higher production volumes and commodity prices.

·      Unit opex: $17/boe (H1 2025: $42/boe), reflecting higher production rates and cost savings in GLA following the Victory tie-back to SGP, which reduced GLA's share of SGP operating costs.

·      Capital Expenditure: $53.9 million (H1 2025: $69.8 million), almost entirely allocated to the Balder Phase V, Phase VI and Balder Next New Wells in Norway.

·      Adjusted Net Debt: $23 million at period end (30 June 2025: $86 million) prior to the acquisition of Blocks 3&4 and Block 9 Oman. The face value of the Group's bond debt at 30 June 2026 was $584 million, comprising the $300 million USD-denominated bonds issued by Kistos Holdings plc and $284 million of existing bonds issued by the Group's Norwegian subsidiary, which was subsequently repaid on the 9 July 2026. The refinancing was completed through the issue of a new $300 million senior secured bond at par, carrying a coupon of 9.875% over a four-year term, with the proceeds used to repay the Group's existing outstanding debt and increase financial flexibility. Adjusted net debt also reflects $20 million drawn under the Group's credit facility during the period, which was repaid in August 2026.

·      Tax: The net accounting tax charge for the period was $66.5 million, reflecting profits taxed at 78% in the UK and Norway and 50% in the Netherlands, partially offset by deferred tax movements and capital allowances in Norway. Cash tax payments totalled $19.7 million (H1 2025: $23.8 million). The current tax liability as at 30 June 2026 was $142.2 million (31 December 2025: $90.9 million). This includes $54 million (2025: $55 million) of uncertain tax position in respect of the Solidarity Contribution Tax, for which the Group believes there is a strong argument that the relevant Dutch subsidiary Kistos NL2 BV is out of scope (see note 6.2.3).

·      Cash and Restricted Funds: $523 million, comprising unrestricted cash and cash equivalent of $128 million per the balance sheet and restricted funds of $395 million, principally the net proceeds of the new bond and the $95 million deposit held in escrow for the Oman acquisition. The $280 million first tranche was released from the escrow account in July 2026 on waiver of the Royal Decree condition precedents for Blocks 3&4.

·      Cash and Near Cash²: $259 million, comprising the unrestricted cash, $95 million held in escrow for the Oman acquisition and the $36 million Norwegian tax receivable expected in December 2026.

1. Pro forma EBITDA is defined as Group results as if the Oman Block 3&4 and Block 9 acquisitions had completed on 1 January 2026, based on draft results provided by the seller.

2. Cash and near cash is non-IFRS measure.

Principal Risks and Uncertainties

Kistos identifies, assesses and manages the risks critical to its success. The Directors do not believe that the principal risks and uncertainties have changed since the publication of Kistos Holdings plc's 2025 Annual Report dated 26 June 2026. There are a number of potential risks and uncertainties that could have a material impact on the Group's performance over the remaining six months of the financial year and could cause actual results to differ materially from expected and historical results. A detailed explanation of the risks summarised below can be found in the section headed "Principal Risks and Risk Management" on page 24 of the Kistos Holdings plc 2025 Annual Report dated 26 June 2026, which is available at www.kistosplc.com.

The key headline risks relate to the following:

·      Political

·      Growth of business and reserves base

·      Climate change and energy transition

·      Cyber security

·      Joint venture activity

·      HSE and compliance

·      Hydrocarbon production and operational performance

·      Project delivery

·      Retention of key personnel

·      Commodity price

·      Liquidity

·      Decommissioning costs and timing

·      Taxation

Our Environmental, Social and Governance Ambitions

As the global energy mix evolves, natural gas and oil remain essential to meeting current and near-term demand, particularly given the pace at which renewable capacity can realistically scale. In the short term, there is unlikely to be sufficient renewable energy to fully meet demand, so continued development and extraction of oil and gas support the global security of supply in the meantime. Emissions intensity is one of several factors considered in evaluating future projects, alongside commercial and operational criteria.

In the Netherlands, our Scope 1 emissions levels (from our operated asset) remain minimal, supported by the solar panels and wind turbines that power the Q10-A platform, with a Scope 1 emissions intensity level below 0.01 kg CO2e/boe in H1 2026.

Across the Q10-A platform in the Netherlands, as well as our non-operated offshore interests in the GLA (14 kg CO2e/boe) and on the Norwegian Continental Shelf (NCS) (15.5 kg CO2e/boe), the Group's Scope 1 and Scope 2 emissions intensity ratios remain well below the North Sea average (estimated by the North Sea Transition Authority (NSTA) to be 24 kg CO2/boe for 2024). They also continue to be significantly lower than the average CO₂ emissions intensity associated with the import of liquefied natural gas (LNG), which the NSTA estimates to be on average three and a half times higher than the North Sea average. The Scope 1 + 2 emissions intensity ratio for Kistos' non-operated onshore interests in Oman stood at an average of 42.1 kg CO2e/boe, with continued efforts by the operator to reduce flaring at Blocks 3&4.

Our UK Gas Storage assets do not consume gas on site, but they do emit small quantities of emissions associated with natural gas venting as part of the safety systems for process equipment, whilst we also report on diesel consumed by site vehicles and the emissions associated with the imported electricity which powers our compressors. During the period, a total of 1,426 tonnes of CO₂ equivalent Scope 1 + 2 emissions were recorded, the majority of which was attributed to the venting of natural gas which was required during the well work operations to bring Hole House back to service.

In the six months to 30 June 2026, our working interest share of total Scope 1 and 2 emissions (including Oman) was estimated at 111,085 tonnes of CO₂ equivalent (CO₂e), an increase on the comparable period in 2025 as a result of the inclusion of the Jotun FPSO for a full period, higher emissions associated with the Victory field producing into the SGP, and the inclusion of the Oman assets.

The Group remains committed to maintaining a safe working environment. We are pleased to report that no lost-time injuries (LTIs) were recorded during the reporting period across our operated assets and Gas Storage business.

Cautionary Statement About Forward-Looking Statements

This half-year results announcement contains certain forward-looking statements. All statements other than historical facts are forward-looking statements. Examples of forward-looking statements include those regarding the Group's strategy, plans, objectives or future operating or financial performance, reserve and resource estimates, commodity demand and trends in commodity prices, growth opportunities, and any assumptions underlying or relating to any of the foregoing. Words such as 'intend', 'aim', 'project', 'anticipate', 'estimate', 'plan', 'believe', 'expect', 'may', 'should', 'will', 'continue' and similar expressions identify forward-looking statements. Forward-looking statements involve known and unknown risks, uncertainties, assumptions and other factors that are beyond the Group's control. Given these risks, uncertainties and assumptions, actual results could differ materially from any future results expressed or implied by these forward-looking statements, which speak only at the date of this report. Important factors that could cause actual results to differ from those in the forward-looking   statements include: global economic conditions, demand, supply and prices for oil, gas and other long-term commodity price assumptions (as they materially affect the timing and feasibility of future projects and developments), trends in the oil and gas sector and conditions of the international markets, the effect of currency exchange rates on commodity prices and operating costs, the availability and costs associated with production inputs and labour, operating or technical difficulties in connection with production or development activities, employee relations, litigation, and actions and activities of governmental authorities, including changes in laws, regulations or taxation. Except as required by applicable law, rule or regulation, the Group does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Past performance cannot be relied on as a guide to future performance.

Interim Financial Statements (unaudited)

Condensed consolidated income statement

Condensed consolidated statement of other comprehensive income

Condensed consolidated balance sheet

Condensed consolidated statement of changes in equity

Condensed consolidated cash flow statement

Notes to the interim condensed consolidated financial statements

Section 1 General information and basis of preparation

1.1 General information

These condensed consolidated financial statements for the six-month period ended 30 June 2026 have been prepared in accordance with IAS 34 Interim Financial Reporting and AIM Rule 18. These condensed consolidated financial statements, along with the management report above, represent a 'half-yearly report' as referred to in the AIM Rules. Accordingly, they do not include all the information required for a full annual financial report. These condensed consolidated financial statements are unaudited and do not constitute statutory accounts as defined in section 434 of the Companies Act 2006 and should be read in conjunction with the 2025 Annual Report and Accounts. Interim period results are not necessarily indicative of results of operations or cash flows for an annual period. The condensed consolidated financial statements have not been subject to review or audit by independent auditors; therefore, all figures are unaudited.

These condensed consolidated financial statements were authorised for issue by Kistos Holdings plc's Board of Directors on 15 September 2026.

1.2 Going concern

These condensed consolidated financial statements have been prepared in accordance with the going concern basis of accounting. The forecasts and projections made in adopting the going concern basis take into account forecasts of commodity prices, production rates, operating and general and administrative (G&A) expenditure, committed and sanctioned capital expenditure, and the timing and quantum of future tax payments. To assess the Group's ability to continue as a going concern, management evaluated cash flow forecasts for the period to September 2027 (the going concern period) by preparing a base case forecast and various combined downside sensitivities. The base case assumed the following:

·      Q10-A production in line with latest internal forecasts.

·      Production from the GLA, Oman and Balder/Ringhorne in line with latest available operator forecasts.

·      Committed and contracted capital expenditure only in line with currently approved budgets.

·      A tax rebate of approximately $37 million (including interest) received in December 2026.

·      Obligations under Decommissioning Security Agreements (DSAs) for the GLA fields are satisfied at least in part by the issuance of surety bonds during the period covered by the going concern assessment.

·      Commodity prices based on forward curves prevailing at the date of assessment (being an average of 144p/therm, €58/MWh and $84/bbl across the going concern period).

The base case forecast indicated that the Group would be able to maintain sufficient liquidity to meet its bond covenant requirement (minimum liquidity of $15 million) and day-to-day operations across the going concern period.

As part of the assessment, reasonably plausible scenarios were also prepared and analysed. These include: 

·      a reduction to the oil and gas price assumptions based on recent price volatility;

·      a reduction to forecast production rates based on reasonably plausible changes to technical assumptions and sensitivities to extending the impact of planned maintenance shut-ins; and

·      an assumption that the 2027 DSA for the GLA fields, has to be to be partially covered in cash.

The outcome of applying one or more of these reasonably plausible downside scenarios against the base case supported the going concern conclusion.

These condensed consolidated financial statements do not include any adjustments that may result from the outcome of these uncertainties.

1.3 Material accounting policies

The Interim Financial Statements have been prepared in accordance with the accounting policies adopted in the Group's annual financial statements for the year ended 31 December 2025.

There are no accounting pronouncements which have become effective from 1 January 2026 that have a significant impact on the Group's interim condensed consolidated financial statements.

In preparing these condensed consolidated financial statements, management has made judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expense. Actual results may differ from these estimates. 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 that applied to the audited annual financial statements at 31 December 2025. The only exception is the estimate of income tax liabilities, which is determined in this half-yearly report using the estimated average annual effective income tax rate applied to the pre-tax income of the interim period.

1.4 Foreign currencies and translation

Items included in the financial statements of each of the Group's entities are measured using the currency of the primary economic environment in which each entity operates (the functional currency). Transactions in currencies other than the functional currency are translated to the entity's functional currency at the foreign exchange rates at the date of the transactions.

Foreign exchange gains and losses resulting from the settlement of monetary assets and liabilities denominated in foreign currencies are recognised in the income statement. All UK-incorporated entities in the Group, including Kistos Holdings plc, have a functional currency of pounds Sterling (GBP). All Dutch-incorporated entities have a functional currency of euros (EUR). Norwegian-incorporated entities have a functional currency of Norwegian Krone (NOK).

The results and balance sheet of all the Group entities that have a functional currency different from the presentation currency were translated into the presentation currency as follows:

·      Assets and liabilities for each balance sheet presented were translated at the closing rate at the date of that balance sheet (except for certain items in equity which are translated at the historical rate);

·      Income and expenditure and cash flows were translated at average exchange rates for the periods; and

·      The effects of translating the Group's financial results and financial positions into USD were recognised within 'Other comprehensive income' and against the foreign currency translation reserve (within 'Other reserves' on the balance sheet).

1.5 Significant events in the current period

The financial position and performance of the Group were affected by the following events and transactions during the six months ended 30 June 2026:

·      The Group has successfully priced a $300 million issue of senior secured bonds at par with a maturity of four years and a coupon of 9.875% per annum.

·      Cash outflows of $19.7 million in respect of tax liabilities.

Section 2 Oil and gas operations

2.1 Revenue

2.2 Segmental information

The performance of the Group is monitored by the Executive Directors (comprising the Executive Chairman, Chief Executive Officer and Chief Financial Officer) who consider the business from both a product and a geographic perspective.

2.2.1 EBITDA

The Executive Directors use EBITDA as a measure of profit and loss to assess the performance of the operating segments. EBITDA is a non-IFRS measure, which management believe is a useful metric as it provides additional information on performance and trends. EBITDA is not defined in IFRS or other accounting standards, and therefore may not be comparable with similarly described or defined measures reported by other companies. It is not intended to be a substitute for, or superior to, any nearest equivalent IFRS measure.

EBITDA excludes the effects of significant items of income and expenditure that may have an impact on the quality of earnings such as impairment charges, other non-cash charges such as depreciation and share-based payment expense, transaction costs, changes in contingent consideration relating to business acquisitions and development expenditure.

A reconciliation of EBITDA by segment to profit before tax, the nearest equivalent IFRS measure, is presented below.

2.3 Property, plant and equipment

2.4 Intangible assets and goodwill

Exploration and evaluation assets include the exploration licence portfolio acquired as part of the exploration prospects in Norway and GLA Acquisition.

2.5 Abandonment provision

Abandonment provisions primarily include:

·      In the Netherlands, the Group's share of the estimated costs is based on abandoning the producing Q10-A wells, decommissioning the associated infrastructure and the plugging and abandoning of the currently suspended Q11-B well. The removal and restoration of certain onshore pipelines and corresponding land from historic assets was completed in 2025, and no obligations remain. Abandonment of the producing wells and infrastructure is expected to take place between two and four years from the balance sheet date, with the wells being a single campaign in 2028 and the infrastructure following thereafter, with a most likely date of 2029.

·      In the UK Production segment, the Group's share of the estimated costs relates to plugging and abandoning the producing and suspended Laggan, Tormore, Edradour and Glenlivet wells, removal of the associated subsea infrastructure, and demolition of the Shetland Gas Plant (SGP) and restoration of the land upon which the plant is constructed. Abandonment is expected to take place between four and 13 years from the balance sheet date, subject to production and commodity price forecasts and level of use of the SGP by third parties.

·      In Norway, the provisions cover plugging and abandonment of drilled wells on the Ringhorne platform and those that are tied back to the Balder and Jotun vessels, as well as the               removal of the Balder floating production unit (FPU), Jotun floating production, storage and offloading unit (FPSO) and Ringhorne platform. Abandonment is expected to take place within two to three years in the case of the Balder FPU and certain wells, while the remaining assets are expected to be abandoned after the mid- to late-2040s.

·      In the UK Storage segment, the key work required for decommissioning is the rebrining of gas storage caverns, and return to the freeholder and removal of the plant assets. Abandonment is expected to take place in approximately 20 years' time, including Hole House after the final investment decision taken in September 2025 to proceed with returning the facility to service.

Abandonment provisions are initially estimated in nominal terms, based on management's assessment of publicly available economic forecasts and determined using inflation rates of 2.0% to 2.30% and a discount rate of 2.5% to 5.2%.

Group has in issue $88 million of surety bonds and an amount of $13 million held in a separate bank account (restricted funds) as at 30 June 2026 to cover its obligations under DSAs for the GLA and Q10A fields and infrastructure. The amount  of the bonds required is reassessed each year, changing in line with estimated post-tax cash flows from the assets, revisions to the abandonment cost, inflation rates, discount rates and other inputs defined in the DSAs.

During the period, the Group made a payment of $12.7 million (post-tax) to Vår Energi, together with $4.7 million of accrued interest, satisfying its obligation to deposit a decommissioning security amount with the operator in respect of the Balder and Ringhorne fields produced via the Jotun FPSO. This amount will be repaid to the Group upon final decommissioning of the fields.

2.6 Joint arrangements and licence interests

As at the balance sheet date, the Group has the following interests in joint arrangements that management has assessed as being joint operations.

The operator of the licences held by Kistos Energy Limited was TotalEnergies E&P UK Limited until 26 March 2026, when Serica Energy (UK) Limited became operator. The operator of the licences held by Kistos Energy (Norway) AS is Vår Energi ASA.

Except where otherwise noted, the interest and status of licences is the same as at the end of the prior period.

The Group's interests in Oman - a 20% working interest in Blocks 3 & 4 and a 5% working interest in Block 9, both non-operated - are not included in the table below, neither acquisition having completed as at 30 June 2026.

¹ Following successful appeal against non-renewal (decision received in July 2023), the licence was re-awarded to Kistos retroactively from 30 June 2022.

² Licence P1453 is split into the portion including and excluding the Benriach area.

³Licence 027 comprises Balder and Ringhorne Øst fields. Kistos' share of the Ringhorne Øst unit is 7.4%.

Section 3 Income statement

3.1 Earnings per share       

3.2 Net finance income/(costs)

Section 4 Working capital

4.1 Cash and cash equivalents and restricted funds

As at 30 June 2026, the cash and cash equivalents balance was $128.1 million (2025: $117.3 million).

As at 30 June 2026, restricted funds consisted of $395.4 million (2025: $47.3 million) held in designated bank accounts.

Restricted funds comprise the net proceeds of the bond issued in May 2026. The net proceeds of the $280 million tranche were released from escrow in July 2026 following the waiver of certain conditions precedent under the bond documents, while the additional $20 million tranche remains in escrow pending completion of the Block 9 acquisition in Oman. Restricted funds also include a deposit held in escrow pending completion of the acquisition in Oman, cash held in escrow to secure letters of credit issued in respect of surety bonds and other amounts held for operational requirements.

4.2 Trade and other receivables

Accrued income represents amounts due in respect of hydrocarbon sales and gas storage capacity revenue that had not been invoiced at the balance sheet date. All hydrocarbon sales accrued income had been invoiced and collected in full within one month of the corresponding reporting date. Certain amounts relating to gas storage capacity revenue are contractually due to be collected in the second quarter of 2027.

Other receivables and cash overcalls represent balances due from our operator in Norway, reflecting funding provided in advance of costs on the ongoing drilling campaign. A significant portion of these overcalls has been billed, with the remainder held in accruals, and the corresponding amounts are reflected within the respective trade payables and accruals items (note 4.3).

4.3 Trade payables and accruals

Trade payables are unsecured and generally paid within 30 days. Accrued expenses are also unsecured and represent estimates of expenses incurred but where no invoice has yet been received, and amounts accrued by joint operators but not yet billed. The carrying value of trade payables and other accrued expenses are considered to be fair value given their short-term nature.

4.4 Other liabilities            

During the period, the Group drew down $20 million under its credit facility. The amount was repaid in full in August 2026.

Section 5 Capital and debt

5.1 Bond debt

The Group has in issue bond debt as follows:

(a)   Borrowing facilities

1. Interest payable wholly in kind via issuance of new bonds.

2. Interest payable partly in cash (4.5%) and partly in kind via issuance of new bonds (5.25%).

3. Interest payable in cash.

4. The face value of the bonds at 30 June 2026 is before the impact of rollover of certain existing bondholders who elected to roll over their bonds into the new bond issue.

(b)   Carrying amounts

On 1 May 2026, the Group successfully priced senior secured bonds issued by the Company with a principal amount of $300 million and a maturity of four years. The bonds bear interest at a fixed coupon rate of 9.875% per annum, payable semi-annually in arrears. The net proceeds from the $280 million tranche were released from escrow in July 2026 following waiver of certain conditions precedent under the bond documents. An additional $20 million tranche remains in the escrow until the completion of the Block 9 Oman acquisition. The net proceeds from the bonds were used primarily to repay in full the existing Norwegian bonds.

Included within the new bond is $8.1 million issued to existing bondholders who elected to roll over their existing bonds into the new bond issue. The corresponding carrying amount of the existing bonds has been derecognised.

5.1.1 Financial covenants

The new bonds are subject to (i) a minimum Liquidity covenant of the higher of $15.0 million and 5% of the Group's gross interest-bearing debt, and (ii) a maximum Leverage Ratio of 2.25:1, tested quarterly; the Group was in compliance with both covenants as at 30 June 2026.

The minimum liquidity covenant of $10 million applicable to the KENO01 and KENO02 bonds from 1 January 2024 until first oil from the Jotun FPSO has ceased to apply. This covenant was released with effect from 19 October 2025, following the Balder Ringhorne licences achieving 90 consecutive days of oil production at an average daily production rate of 75,000 barrels of oil per day.

Section 6 Tax

6.1 Tax charge for period  

6.2  Current tax

6.2.1 Current tax receivable

The current tax receivable of $36 million in Norway relates wholly to tax losses incurred in 2025 in Norway and is expected to be received in cash by the Group in December 2026. The receivable accrues repayment interest from 1 January 2026 at the applicable statutory rate, currently 4.0%. The current tax receivable also includes $15 million of refundable State Profit Share in the Netherlands arising from losses incurred in 2025, partially offset by profits from 2022, which is expected to be received in June 2027.        

6.2.2 Current tax payable

The Group has current tax liabilities by segment as follows:

All current tax liabilities relate to taxation of oil and gas activities and are anticipated to be settled within one year of the balance sheet date, except $54 million relating to the Solidarity Contribution Tax (note 6.2.3) in the Netherlands, for which the timing of settlement is uncertain.

Late or underpaid tax accrues interest at a rate of at least 6.25% in the UK and 6.5% in the Netherlands. No provision was taken for short Solidarity Contribution Tax due to uncertain tax positions.   

6.2.3 Uncertain tax positions

In October 2022, EU member states adopted Council Regulation (EU) 1854/2022, requiring a Solidarity Contribution Tax on companies in the oil, gas, coal and refinery sectors. The Dutch implementation applies a retrospective 33% tax on 2022 "surplus profits" (taxable profit exceeding 120% of the average of the four preceding years), and captures companies deriving at least 75% of turnover from oil and gas production, coal mining, or petroleum/coke oven refining.

The Group considers there is a reasonable argument that Kistos NL2 B.V. falls outside the scope of the tax, as less than 75% of its turnover under Dutch GAAP was derived from these activities. The Group is also aware that the tax, including its retrospective application, is subject to legal challenge by other parties and certain EU member states, though it is not itself a party to these challenges.

Applying IFRIC 23, Uncertainty over Income Tax Treatments, and having regard to the absence of any audit or collection precedent, the Directors have maintained a provision of $54 million (2025: $55 million) within the current tax charge, representing the single most likely amount payable. The Group filed its return by the May 2024 deadline on a nil-liability basis, consistent with the position above, and as at the date of approval of these financial statements had received no correspondence from the Belastingdienst on the matter.

Should the Belastingdienst rule adversely and find the Group grossly negligent or guilty of wilful misconduct in filing a nil return, material fines or penalties could apply, together with late payment interest (currently 6.5%) accruing from 31 May 2024 to the date of final payment.

Section 7 Other disclosures

7.1 Contingencies

7.1.1 Contingent liabilities relating to Tulip Oil acquisition

As part of the acquisition of Tulip Oil in 2021, the following contingent payments could be made to the vendor should certain events occur and/or milestones be achieved:

·      Up to a maximum of €75 million relating to Vlieland Oil (now Orion), triggered at FID and payable upon first hydrocarbons based on the net reserves at time of sanction; and

·      Up to a maximum of €75 million relating to M10a and M11, triggered at FID and payable upon first gas, based on $3/boe of sanctioned reserves.

Based on management's current assessments and status of the projects and developments above, the contingent considerations above remain unrecognised on the balance sheet.

7.2 Subsequent events

Following the successful pricing of the $300 million bonds during the period, the condition relating to completion of the Blocks 3 & 4 acquisition, and therefore the requirement for receipt of the Royal Decree, was waived. As a result, approximately $280 million of proceeds from the first tranche was released from the escrow account in July 2026 and used in full to redeem the existing Norwegian bonds, with the remaining $20 million expected to be released on completion of Block 9. With the Royal Decree now received, completion of Blocks 3&4 occurred on the 14 September 2026.

Appendix A: Glossary

Appendix B: Non-IFRS Measures

Management believes that certain non-IFRS measures (also referred to as 'alternative performance measures') are useful metrics as they provide additional useful information on performance and trends. These measures are primarily used by management for internal performance analysis, are not defined in IFRS or other GAAPs and therefore may not be comparable with similarly described or defined measures reported by other companies. They are not intended to be a substitute for, or superior to, IFRS measures. Definitions and reconciliations to the nearest equivalent IFRS measure are presented below.

B1: Adjusted net (debt)/cash

Adjusted net (debt)/cash is a measure that management believes is useful as it provides an indicator of the Group's overall liquidity.     It is defined as cash and cash equivalents and restricted funds, prepayment for a new acquisition and current tax receivables less the face value of interest-bearing debt(being the bonds in note 5.1 and the credit facility in note 4.4), excluding the Hybrid Bond which, in management's view, represents contingent consideration rather than bond debt due to the payment triggers associated with it.

B2: Adjusted Cost of Sales and unit opex

Adjusted Cost of Sales (previously called Adjusted operating costs) represents the production and operating expenses attributable to the Group's three Production segments. These costs are adjusted to reflect inventory accounting movements specifically, operating costs capitalised into liquids inventory when produced and only expensed to the income statement upon sale of the related product. Additionally, operating costs from the UK Storage segment are excluded, as they do not relate to the production of hydrocarbons for sale.

Unit opex is Adjusted Cost of Sales divided by barrels of oil equivalent produced for the same period.

Appendix C: Conversion factors

37.3 scf of gas in 1 Nm³ of gas

5,561 scf of gas in 1 boe

149.2 Nm³ of gas in 1 boe

1.7 MWh of gas in 1 boe

34.12 therms of gas in 1 MWh of gas

7 MT of natural gas liquids in 1 boe

28 tonnes of CO₂ equivalent in one tonne of natural gas (CH₄)

Exact conversions of volumes of gas to barrels of oil equivalent (boe), volume of gas to energy (therms or MWh) and volumes of natural gas liquids to boe is dependent on the calorific value of gas and exact composition of natural gas liquids and therefore can change on a daily basis, and may be different to those conversion factors used by other companies