Final Results & Notice of AGM

12 May 2026

Jersey Oil and Gas plc

("Jersey Oil & Gas", "JOG" or the "Company")

Final Results for the Year Ended 31 December 2025

& Notice of Annual General Meeting

Jersey Oil & Gas (AIM: JOG), an independent upstream oil and gas company ‎focused on the UK Continental Shelf region of the North Sea, is pleased to announce its audited financial results for the year ended 31 December 2025 and the date of its forthcoming Annual General Meeting ("AGM").

Following the significant progress that has been made by the Company towards monetising the Greater Buchan Area ("GBA"), the last year has frustratingly seen momentum slowing as a result of the Government's consultations on the future regulatory and fiscal direction of the UK North Sea. Despite this, the Company remains well positioned as one of the leading UK listed small-cap oil and gas companies, with a high-quality development portfolio and the funding to deliver on its organic growth plans.

Buchan Development

The potential for the Buchan Horst ("Buchan") development to drive long term shareholder value is well understood and securing sanction for this project represents a huge opportunity. While the end of the Government consultations in late 2025 helped provide additional clarity on the framework within which future investment decisions can be assessed, it is clear that the industry as a whole is still digesting the outcomes. Positive conclusions in respect of the protracted environmental and regulatory approval processes for the North Sea's "Jackdaw" and "Rosebank" developments will inevitably help inform the optimal route forward for subsequent UK projects like Buchan. Obtaining clarity from these processes and the likelihood of an earlier than planned implementation of the "Oil and Gas Price Mechanism", the replacement regime for the Energy Profits Levy, will help influence the timeline and steps for taking the Buchan project towards sanction.

Although various headwinds have buffeted the industry, the core strengths of our business remain unchanged:

§ Material resource base: With estimated gross resources of over 100 million barrels of oil equivalent ("MMboe") in the Greater Buchan Area ("GBA"), underpinned by a carried 20% working interest in the Buchan development, the Company has the potential to generate substantial cash flow from its portfolio

§ "Hub and spoke" development plan: Unlocking the resource base involves the installation of a central processing facility for the area, with initial production from Buchan to be followed by the tieback of the other GBA feeder fields

§ Fully funded: The farm-out transactions completed with NEO Next+ ("NEO") and Serica Energy ("Serica") provide the funding for the Company's 20% investment in the Buchan development, along with several milestone cash payments - to date this has totalled over $25 million in cash and capital expenditure carry payments

§ Strong industry partners: NEO and Serica are major, well-financed, UK North Sea oil and gas operators that provide strength and expertise to a high-quality joint venture partnership

§ Financial resilience: The Company continues to prudently manage the financial position of the business and maintain its resilience to the delayed sanction of the Buchan development, which has resulted from the regulatory and fiscal headwinds the industry has faced

The Buchan joint venture is continuing to screen and consider additional potential development solutions that have arisen as a result of the inevitable delay in investment decision-making caused by the Government consultations.

Strategic Focus

The Company's vision is centred on successfully growing the business in a smart and sustainable way, developing important domestic energy resources and creating value for all stakeholders. The organisation is "right sized" for the stage and scale of its current activities and maintains a nimble approach to advancing its key strategic objectives.

JOG remains sharply focused on unlocking the organic value of the GBA, combined with utilisation of its existing UK tax allowances of over $100 million through the pursuit of accretive asset acquisitions that bring cash flow, diversity and quality investment opportunities into the portfolio. Such opportunities are thoroughly assessed in terms of their potential strategic fit, being mindful of the quality and unencumbered strengths of the existing portfolio.

Outlook

The Company is well positioned to continue pursuing its core objective of fully monetising the value of its GBA interests. With total year-end cash reserves of £11 million, no debt and a current cash run rate of under £1.5 million per annum, the business is financially secure and funded for execution of the Buchan development programme. This backdrop provides an attractive springboard from which to realise the full potential and ambitions of the business for delivering long-term shareholder value.

Annual General Meeting

The Company also announces that its 2025 Annual Report and Financial Statements together with the AGM Notice and associated Form of Proxy are now available on the Company's website (www.jerseyoilandgas.com) and will be posted today to those shareholders who have elected to receive hardcopy shareholder communications from the Company.

The Company will hold its AGM in respect of its financial year ended 31 December 2025 on 9 June 2026 at 11.00 a.m. at the offices of Strand Hanson Limited, 26 Mount Row, London W1K 3SQ.

Andrew Benitz, Chief Executive Officer of JOG, commented:

"The message is beginning to land; as long as demand persists, the UK cannot sustain a strategy that relies on importing oil and gas while discouraging domestic North Sea production. The agreement on a more rational fiscal mechanism for taxing North Sea oil and gas production during periods of exceptionally high prices is a welcome and important step forward. However, delaying its introduction to 2030 will come too late for many in the basin. We believe that the straightforward step, which we understand the Government is actively considering, of bringing this mechanism forward would help reopen the UK North Sea and represent a major step towards unlocking the significant investment potential that our Buchan redevelopment project has to offer."

Enquiries:

- Ends -

Notes to Editors:

Jersey Oil & Gas (AIM: JOG) is a UK energy company focused on creating shareholder value through the development of oil and gas assets and the execution of accretive transactions. 

The Company has a focused asset portfolio centred on developing homegrown North Sea resources that support the UK's energy requirements as it transitions towards net zero. JOG holds a 20% interest in each of licences P2498 (Blocks 20/5a, 20/5e and 21/1a) and P2170 (Blocks 20/5b and 21/1d) located in the UK Central North Sea and referred to as the "Greater Buchan Area" ("GBA"). Licence P2498 contains the Buchan Horst ("Buchan") oil field and J2 oil discovery and licence P2170 contains the Verbier oil discovery.

JOG's strategy is focused on unlocking the organic value of its GBA assets, combined with the pursuit of potential asset acquisitions that bring cash flow, diversity and quality investment opportunities into the portfolio. The Company's Board and Executive team have a wealth of experience in managing and growing publicly listed energy companies and a strong track-record of value creation in the UK North Sea's oil and gas sector.

Forward-Looking Statements

This announcement may contain certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with an oil and gas business. Whilst the Company believes the expectations reflected herein to be reasonable in light of the information available to it at this time, the actual outcome may be materially different owing to factors beyond the Company's control or otherwise within the Company's control but where, for example, the Company decides on a change of plan or strategy.

The information contained within this announcement is deemed by the Company to constitute inside information as stipulated under the Market Abuse Regulation (EU) No. 596/2014 as it forms part of United Kingdom domestic law by virtue of the European Union (Withdrawal) Act 2018, as amended by virtue of the Market Abuse (Amendment) (EU Exit) Regulations 2019.

CHAIRMAN & CHIEF EXECUTIVE OFFICER'S REPORT

Following the significant progress made by the Company since being awarded the Buchan Horst ("Buchan") licence, 2025 was marked by a slowing in momentum as a result of Government consultations on the future regulatory and fiscal direction of the UK North Sea that were taking place during the year. 

Having established the enviable position of owning a material interest in one of the largest remaining oil development projects on the UK Continental Shelf, via a joint venture with high-quality partners and an expenditure carry for the investment programme, it was regrettable that uncertainty and delays on the optimal way forward arose from the actions of Government policy making.

While the outcome of the consultations was ultimately published by the Government in late 2025, it is apparent that there remains uncertainty in the industry regarding long term investment decisions. This is driven by both the continuing absence of approval for the Adura-operated "Jackdaw" and "Rosebank" projects (Adura is the company formed through the combination of the UK businesses of Shell and Equinor) and potential oscillations by the UK Treasury around an earlier than stated end to the Energy Profits Levy. Obtaining clarity on these matters naturally influences decisions on the Buchan project and the appropriate route to project sanction.

Buchan Development Solution

Prior to the launch of the Government's regulatory and fiscal consultations in 2024, the plan for securing joint venture sanction and regulatory approval for the development of the Buchan field was well established and the draft Field Development Plan ("FDP") and associated Environmental Impact Assessment ("EIA") had been submitted to the regulatory authorities.

The development plan centred on the acquisition and redeployment of the "Western Isles" floating production, storage and offloading vessel ("FPSO") as a production processing facility located over the field, with up to five gas-lifted production wells, supported by two water injection wells, connected via subsea infrastructure to the vessel. With processing of the hydrocarbons produced from the field taking place offshore, the oil would be exported directly to market via shuttle tankers and gas via a pipeline connection to nearby infrastructure.

The agreement to acquire the Western Isles FPSO was ultimately terminated by Dana Petroleum after it reached its longstop date in March 2025. Despite significant work being undertaken to satisfy the conditions precedent in the agreement and enable handover of the vessel to the Buchan operator, the ability to extend the agreement was inevitably hindered by the absence of a clear timeline to achieving FDP approval given the uncertainty shrouding potential North Sea investment activities resulting from the Government consultations. Nevertheless, the passage of time caused by the consultations means that other potential production solutions have now arisen and warrant further screening and consideration to verify the optimal development plan. The Western Isles FPSO remains available for re-use and as such represents one of several options for Buchan and additional development engineering activities to assess alternatives is part of the work programme being completed during 2026.

Fiscal Regime Changes

Given the results of the Government's fiscal consultations, the optimal development timeline is inevitably influenced by the planned switch in the tax regime between the application of the EPL and its planned replacement, the Oil and Gas Price Mechanism ("OGPM"). The Government announced in late 2025 that the EPL would continue to apply in its current form until 1 April 2030, implying a marginal tax rate of 78% for the industry. In contrast, the OGPM will replace the EPL with a revenue-based model for calculating windfall profits, that levies a 35% tax only on the revenues generated above applicable commodity threshold prices (in addition to the corporate and supplementary tax rate of 40%).

Under the OGPM two independent threshold price points will be set annually, one for oil (in dollars per barrel) and one for gas (in pence per therm). The thresholds in financial year 2026-27 have been set at $90/bbl for oil and 90p/therm for gas - they will be adjusted annually in line with CPI inflation and are projected to be around $98/bbl and 98p/therm by 2030. When in effect, the OGPM restores the tax rate to the 40% headline rate in the permanent regime, with the OGPM only applying to oil and/or gas revenues in the event the respective commodity price is unusually high.

While clarity on the long-term fiscal regime was a positive step forward and was on the whole, welcomed by our industry, the delay in implementing the OGPM was not helpful for providing the confidence boost required to achieve the goal of reigniting major North Sea investment programmes. However, in the Chancellor's Spring Statement and subsequent engagement with the industry, which took place just days prior to the start of the war in Iran and the rapid escalation in energy prices, there was a growing expectation that the Government was on the cusp of bringing forward the end date for the EPL to late 2027. While this change was by no means certain, the growing strength of belief in the industry that it may happen has served to continue the period of fiscal uncertainty. We urge the Government to effect an early move to the application of the OGPM before the infrastructure serving the North Sea is lost, thereby removing the economic opportunity for further major investments in the basin.

Environmental Approvals

Achieving regulatory approval for the Buchan development plan requires confirmation from OPRED of no objections to the EIA for the project. This is the key regulatory pre-cursor to approval by the North Sea Transition Authority ("NSTA").

Upon reconfirmation of the development plan, an addendum to the existing Buchan EIA will be required. Based on the results of the environmental consultation, the assessment will need to be expanded to consider the impact of combustion of the produced hydrocarbons, "Scope 3" emissions, from the project. While the consultation provided clarity on this, the associated guidance issued by the Offshore Petroleum Regulator for the Environment and Decommissioning ("OPRED") inevitably requires some interpretation as to how this is achieved. Additional work has been completed on this to establish a robust methodology for calculating Scope 3 emissions and setting out the significance of these in the context of UK national and international emissions targets. However, it is expected that the ultimate guide for the information that will need to be presented on the project will be evidenced in the submissions made for the Jackdaw and Rosebank developments in the UK. Both of these projects have submitted revised EIAs that incorporate an assessment of Scope 3 emissions and these have recently undergone a public consultation process. OPRED subsequently issued clarificatory questions on the submissions in March 2026, which will require Adura to provide further information and potentially undertake an additional period of public consultation for the projects.

Adura's work is leading the way on establishing the information benchmark for successful EIA submissions, the results of which will inform the most efficient way forward for Buchan. It is expected that clarity on the Jackdaw and Rosebank submissions and the overall OPRED and NSTA approval processes should be achieved later this year.

Evolving UK North Sea

Set against the recent evolution in the regulatory landscape, there has been dramatic changes in the UK North Sea corporate landscape. We have witnessed a significant period of consolidation, with many of the Majors exiting their direct holdings by combining operations with the independent producers in the basin. 

Most significantly for JOG, the Buchan operator recently became the largest producer in the UK North Sea, with a production portfolio of over 250,000 barrels of oil equivalent per day. In the last twelve months, NEO Energy Limited has not only combined its business with the UK subsidiary of Repsol S.A., but in March 2026 it completed a subsequent merger with the UK business of TotalEnergies S.A., to create NEO Next+ ("NEO"). 

Serica Energy ("Serica") also announced a series of strategic acquisitions during the year, establishing the business as the leading mid-tier UK North Sea producer.

The major transformations that have taken place with NEO and Serica places the growth prospects that the Buchan project provides within two high-quality, UK North Sea focused asset portfolios. Access to a project with estimated gross mid case proven and probable resources of approximately 70 million barrels of oil equivalent represents a material prize at this stage of the UK North Sea lifecycle. This level of resources, combined with the quality of the joint venture partners and our fully carried capital expenditure position, sets us apart as one of the leading listed small-cap UK North Sea players.

Financial Resilience

The Company remains well positioned financially, with total cash reserves and term deposits at the end of 2025 of £11 million and no debt. The cash running cost of the business has been carefully managed and reduced to an annualised rate of under £1.5 million to ensure resilience in the face of the delayed sanction of the Buchan development and receipt of the next milestone cash payment under the terms of the farm-out agreements. This has been achieved in no small part thanks to the support and commitment of our key service providers and our employees, who continue to work on reduced salaries to help bridge the Company's finances to the point of clarity on the Buchan development timeline.

Looking to the long term, the financial outlook of the business is clearly underpinned by the terms of the farm-out agreements executed with NEO and Serica. These provide for the Company's 20% share of the Buchan project expenditure included in the approved FDP budget to be fully carried by our two joint venture partners. A further $20 million cash tranche is payable under the terms of the agreements following approval of the Buchan FDP by the NSTA and receipt of all the associated regulatory and legal consents.

Summary and Outlook

The potential for the Buchan development to drive long term shareholder value is well understood and securing sanction for the project represents a huge opportunity that can unlock estimated gross resources of over 100 MMBOE and significant exploration upside in the Greater Buchan Area. The conclusion of the Government's industry consultations has clearly helped with providing additional clarity on the framework within which investment decisions can be evaluated, but it is apparent that the industry as a whole is still digesting the outcomes and assessing the optimal way to move capital expenditure programmes forward.

We recognise that the practicalities of how best to successfully navigate the environmental approval process for new developments like Buchan will be forthcoming following the on-going efforts of Adura on Jackdaw and Rosebank. Armed with such information and a re-assessment of the wider set of potential development options now open to the Buchan joint venture, we look forward to being able to provide additional details on the planned way forward and timelines for advancing the project later in the year.

It is naturally frustrating for us all to be in a period where patience is the name of the game. Positively, however, the political and societal desire for homegrown energy is greater than it has been for many years and this provides an encouraging backdrop for projects like Buchan. We continue to carefully manage the financial resilience of the Company to cope with the delayed development timeline, while maintaining the skills and capabilities of the business to deliver upon our strategic imperatives. We believe that there remains more to do to grow the business in the North Sea, especially as the number of companies operating in the basin reduces. To accelerate potential value creation from our existing UK tax allowances of over $100 million, we continue to thoroughly evaluate potential UK producing asset acquisitions. A limited number of potential international producing asset opportunities have also been assessed over the last year. While not immediately considered as the key strategic target, such assets are reviewed on a highly selective basis where it may be possible to materially add value through our internal expertise and resources.

We greatly appreciate the support and patience we have received from our shareholders over what has been a complicated time for the UK North Sea oil and gas industry and we will continue striving to successfully deliver upon the full potential of the business.

Les Thomas,

Non-Executive

Chairman

Andrew Benitz,

Chief Executive Officer

11 May 2026

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

for the year ended 31 December 2025

The notes are an integral part of these financial statements

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As at 31 December 2025

The financial statements were approved by the Board of Directors and authorised for issue on 11 May 2026. They were signed on its behalf by Graham Forbes - Chief Financial Officer.

Graham Forbes

Chief Financial Officer 11 May 2026

Company Registration Number: 07503957

The notes are an integral part of these financial statements

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 31 December 2025

The following describes the nature and purpose of each reserve within owners' equity:

CONSOLIDATED STATEMENT OF CASH FLOWS

For the year ended 31 December

The notes are an integral part of these financial statements

Notes to the Consolidated Financial Statements

For the year ended 31 December 2025

1. General information

Jersey Oil and Gas plc (the "Company") and its subsidiaries (together, the "Group") are involved in the upstream oil and gas business in the UK.

The Company is a public limited company incorporated and domiciled in England & Wales and quoted on AIM, a market operated by London Stock Exchange plc. The address of its registered office is 71-75 Shelton Street, Covent Garden, London WC2H 9JQ.

2. Material accounting policies

The material accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all the periods presented, unless otherwise stated. 

Basis of Accounting

The consolidated financial statements of Jersey Oil and Gas Plc as of 31 December 2025 and for the year then ended (the "consolidated financial statements") were prepared in accordance with UK-adopted International Accounting Standards in conformity with the requirements of the Companies Act 2006 (the "Companies Act").

The financial statements have been prepared under the historic cost convention, except as disclosed in the accounting policies below. All amounts disclosed in the financial statements and notes have been rounded off to the nearest one thousand pounds unless otherwise stated.

Going Concern

The Group has sufficient resources to meet its liabilities as they fall due for a period of at least 12 months after the date of issue of these financial statements with forecast cashflow projections being performed out to December 2027. The Group had cash reserves and treasury deposits of £11.0 million as at 31 December 2025 and has a fully funded 20% interest in its on-going Buchan redevelopment project. Other work that the Group is undertaking in respect of the GBA licenses and surrounding areas is modest relative to its current cash reserves and treasury deposits. The Group's current cash reserves and treasury deposits are therefore expected to more than exceed its estimated cash outflows of under £1.4 million under all reasonable scenarios for at least 12 months following the date of issue of these financial statements. Even in a scenario where the Buchan redevelopment project did not progress for any reason and any future fam-out instalment payments were not realised, the Group already has in place a cost structure and expenditure profile that enables the business to continue beyond the next 12 months solely from utilisation of its existing cash reserves and treasury deposits. The directors have also considered the risk associated with contractual arrangements associated with the farm-outs and are satisfied that the Group is not exposed to any contractual commitments which could impact on the Group's going concern status over the next 12 months. Based on these circumstances, the directors have considered it appropriate to adopt the going concern basis of accounting in preparing the consolidated financial statements.

New and amended standards adopted by the Group. The Group has applied the following amendments for the first time for the annual reporting period commencing 1 January 2025:

• Lack of Exchangeability (Amendments to IAS 21)

The amendments listed above did not have any impact on the amounts recognised in prior periods and are not expected to significantly affect the current or future periods.

New standards and interpretations not yet adopted

Certain new accounting standards, amendments to accounting standards and interpretations have been published that are not mandatory for 31 December 2025 reporting periods and have not been early adopted by the Group. These standards, amendments or interpretations are not expected to have a material impact on the entity in the current or future reporting periods or on foreseeable future transactions.

• Amendments to the Classification and Measurement of Financial Instruments (Amendments

• to IFRS 9 and 7)

• IFRS 18 'Presentation and Disclosure in Financial Statements'

• IFRS 19 'Subsidiaries without Public Accountability: Disclosures'

• Annual Improvements to IFRS Accounting Standards - Volume 11

• Contracts Referencing Nature-dependent Electricity - Amendments to IFRS 9 and IFRS 7

Significant Accounting Judgements and Estimates

The preparation of the financial statements requires management to make estimates and assumptions that affect the reported amounts of expenses, assets and liabilities at the date of the financial statements. If in the future such estimates and assumptions, which are based on management's best judgement at the date of the financial statements, deviate from the actual circumstances, the original estimates and assumptions will be modified as appropriate in the period in which the circumstances change. The Group's accounting policies make use of accounting estimates and judgements in the following areas:

• The judgement of the existence of impairment triggers (note 10).

• The estimation of share-based payment costs (note 20).

• The judgement associated with the treatment of farm-out transactions.

Impairments

The Group tests its capitalised exploration licence costs for impairment when indicators, further detailed below under 'Exploration and Evaluation Costs' as set out in IFRS 6, suggest that the carrying amount exceeds the recoverable amount which is inherently judgmental. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount. The recoverable amount of the Cash Generating Unit is the higher of an asset's fair value less costs of disposal and value in use. The Group assessed that there were no impairment triggers during the year.

Share-Based Payments

The Group currently has several share schemes that give rise to share-based payment charges. The charge to operating profit for these schemes amounted to £602,190 (2024: £764,774). Estimates and judgements for determining the fair value of the share options are required. For the purposes of the calculation, a Black-Scholes option pricing model has been used. Based on experience, it has been assumed that options will be exercised, on average, at the mid-point between vesting and expiring. The risk-free rate of return is based on the implied yield available on zero coupon gilts with a term remaining equal to the expected lifetime of the options at the date of grant. Estimates are also used when calculating the likelihood of share options vesting given the vesting conditions of time and performance on the options granted. Share options that expire unexercised are accounted for by reversing any previously recognised expense. Expired options do not result in a cash outflow and have no further impact on the Group's financial position beyond the reversal of previously recognised charges.

Farm-out transactions

Determining the value of the consideration received for a farm-out disposal of assets with proven resources can be challenging. This is even more the case for assets which are farmed out in the pre proven resources phase. A judgement has been made that for such farm-outs only cash payments received will be recognised and no recognition will be made of any consideration in respect of the future value of work to be performed and carried by the farmee. Rather, the Group will carry the remaining interest at the previous full interest cost reduced by the amount of any cash consideration received from entering into the agreement. The effect will be that there is no gain recognised on the farm-out unless the cash consideration received exceeds the carrying value of the entire asset held. Upon FID, the Group will start recognising both cash payments received and the value of future carried assets to be received and will recognise a future asset receivable with an accompanying gain in the income statement for the equity share of the asset disposed of.

Basis of Consolidation

(a) Subsidiaries

Subsidiaries are all entities over which the Group has the power to govern their financial and operating policies generally accompanying a shareholding of more than one half of the voting rights. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing whether the Group controls another entity. The Group also assesses the existence of control where it does not have more than 50% of the voting power but is able to govern the financial and operating policies by virtue of de facto control. De facto control may arise in circumstances where the size of the Group's voting rights relative to the size and dispersion of holdings of other Shareholders give the Group the power to govern the financial and operating policies.

Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are de-consolidated from the date the Group ceases to have control.

(b) Changes in ownership interests in subsidiaries without change of control

Transactions with non-controlling interests that do not result in loss of control are accounted for as equity transactions - that is, as transactions with the owners in their capacity as owners. The difference between fair value of any consideration paid and the relevant share acquired of the carrying value of net assets of the subsidiary is recorded in equity. Gains or losses on disposals to non-controlling interests are also recorded in equity.

(c) Disposal of subsidiaries

When the Group ceases to have control any retained interest in the entity is remeasured to its fair value at the date when control is lost, with the change in carrying amount recognised in profit or loss. The fair value is the initial carrying amount for the purposes of subsequently accounting for the retained interest as an associate, joint venture, or financial asset. In addition, any amounts previously recognised in other comprehensive income in respect of that entity are accounted for as if the Group had directly disposed of the related assets or liabilities. This may mean that amounts previously recognised in other comprehensive income are reclassified to profit or loss.

Inter-company transactions, balances, income and expenses on transactions between Group companies are eliminated on consolidation. Profits and losses resulting from inter-company transactions that are recognised in assets are also eliminated on consolidation. Accounting policies of subsidiaries have been changed where necessary to ensure consistency with the policies adopted by the Group.

The following subsidiaries which are included in these consolidated accounts are exempt from the requirements of the Companies Act relating to the audit of their accounts under section 479A of the Companies Act 2006:

*Dissolved 25 February 2025

**Dissolved 11 February 2025

Acquisitions, Asset Purchases and Disposals

Transactions involving the purchase of an individual field interest, farm-ins, farm-outs or acquisitions of exploration and evaluation licences for which a development decision has not yet been made that do not qualify as a business combination, are treated as asset purchases. Accordingly, no goodwill or deferred tax arises. The purchase consideration is allocated to the assets and liabilities purchased on an appropriate basis. Proceeds on disposal (including farm-ins/farm-outs) are applied to the carrying amount of the specific intangible asset or development and production assets disposed of, and any surplus is recorded as a gain on disposal in the Consolidated Statement of Comprehensive Income.

Acquisitions of oil and gas properties are accounted for under the purchase method where the acquisitions meet the definition of a business combination. The Group applies the acquisition method of accounting to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair value of the assets transferred, the liabilities incurred, and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair value at the acquisition date. The Group recognises any non-controlling interest in the acquiree on an acquisition-by-acquisition basis, either at fair value or at the non-controlling interest's proportionate share of the recognised amounts of the acquiree's identifiable net assets.

Acquisition related costs are expensed as incurred.

If the business combination is achieved in stages, the acquisition date fair value of the acquirer's previously held equity interest in the acquiree is remeasured to fair value at the acquisition date through profit or loss.

Any contingent consideration to be transferred on a business combination by the Group is recognised at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration that is deemed to be an asset or liability are recognised in accordance with IFRS 9 either in profit or loss or as a change to other comprehensive income. Contingent consideration that is classified as equity is not remeasured, and its subsequent settlement is accounted for within equity.

Goodwill is initially measured as the excess of the aggregate of the consideration transferred and the fair value of the non-controlling interest over the net identifiable assets acquired and liabilities assumed. If this consideration is lower than the fair value of the net assets of the subsidiary acquired, the difference is recognised in profit or loss.

Exploration and Evaluation Costs

The Group accounts for oil and gas exploration and evaluation costs using IFRS 6 "Exploration for and Evaluation of Mineral Resources". Such costs are initially capitalised as Intangible Assets and include payments to acquire the legal right to explore, together with the directly related costs of technical services and studies, seismic acquisition, exploratory drilling and testing. The Group only capitalises costs as intangible assets once the legal right to explore an area has been obtained. The Group assesses the intangible assets for indicators of impairment at each reporting date.

Potential indicators of impairment include but are not limited to:

a. the period for which the Group has the right to explore in the specific area has expired during the period or will expire soon and is not expected to be renewed.

b. substantive expenditure on further exploration for and evaluation of oil and gas reserves in the specific area is neither budgeted nor planned.

c. exploration for and evaluation of oil and gas reserves in the specific area have not led to the discovery of commercially viable quantities of oil and gas reserves and the entity has decided to discontinue such activities in the specific area.

d. sufficient data exist to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full-from successful development or by sale.

The Group analyses the oil and gas assets into cash generating units (CGUs) for impairment and reporting purposes. In the event an impairment trigger is identified the Group performs a full impairment test for the CGU under the requirements of IAS 36 Impairment of assets. An impairment loss is recognised for the amount by which the exploration and evaluation assets' carrying amount exceeds their recoverable amount. The recoverable amount is the higher of the exploration and evaluation assets' fair value less costs of disposal and value in use.

As at 31 December 2025, the carrying value of intangible assets was £11.9m, as per Note 10 'Intangible Assets'. The Group considered other factors which could give rise to an impairment trigger such as commodity prices, licence expiration dates, budgeted spend and movements in estimated recoverable reserves. Based on this assessment, no impairment triggers existed in relation to exploration assets as of 31 December 2025. For more detail on the current position, please refer to note 23, Post Balance Sheet Events.

Property, Plant and Equipment

Property, plant and equipment is stated at historic cost less accumulated depreciation. Asset lives and residual amounts are reassessed each year. Cost includes the original purchase price of the asset and the costs attributable to bringing the asset to its working condition for its intended use.

Depreciation on these assets is calculated on a straight-line basis as follows:

Computer & office equipment 3 years

Leases

Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the following lease payments:

• fixed payments (including in-substance fixed payments), less any lease incentives receivable;

• variable lease payments that are based on an index or a rate, initially measured using the index or rate as at the commencement date;

• amounts expected to be payable by the Group under residual value guarantees;

• the exercise price of a purchase option if the Group is reasonably certain to exercise that option; and

• payments of penalties for terminating the lease, if the lease term reflects the Group exercising that option.

Lease payments to be made under reasonably certain extension options are also included in the measurement of the liability.

The lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be readily determined, which is generally the case for leases in the Group, the lessee's incremental borrowing rate is used, being the rate that the individual lessee would have to pay to borrow the funds necessary to obtain an asset of similar value to the right-of-use asset in a similar economic environment with similar terms, security and conditions.

To determine the incremental borrowing rate, the Group where possible, uses recent third-party rates provided by banks or financial institutions as a starting point, adjusted to reflect changes in financing conditions since third party financing was received.

Lease payments are allocated between principal and finance cost. The finance cost is charged to profit or loss over the lease period to produce a constant periodic rate of interest on the remaining balance of the liability for each period.

Right-of-use assets are measured at cost comprising the following:

• the amount of the initial measurement of lease liability;

• any lease payments made at or before the commencement date less any lease incentives received;

• any initial direct costs; and

• restoration costs.

Right-of-use assets are generally depreciated over the shorter of the asset's useful life and the lease term on a straight-line basis. If the Group is reasonably certain to exercise a purchase option, the right-of-use asset is depreciated over the underlying asset's useful life.

Payments associated with short-term leases of equipment and vehicles, and all leases of low-value assets are recognised on a straight-line basis as an expense in profit or loss. Short-term leases are leases with a lease term of 12 months or less. Low-value assets comprise any lease with a value of £5,000 or less.

Joint Ventures

The Group participates in joint venture/co-operation agreements with strategic partners; these are classified as joint operations. The Group accounts for its share of assets, liabilities, income and expenditure of these joint venture agreements and discloses the details in the appropriate Statement of Financial Position and Statement of Comprehensive Income headings in the proportion that relates to the Group per the joint venture agreement.

Investments

Fixed asset investments in subsidiaries are stated at cost less accumulated impairment in the Company's Statement of Financial Position and reviewed for impairment if there are any indications that the carrying value may not be recoverable.

Financial Instruments

Financial assets and financial liabilities are recognised in the Group and Company's Statement of Financial Position when the Group becomes party to the contractual provisions of the instrument. The Group does not have any derivative financial instruments.

Cash and cash equivalents include cash in hand and deposits held on call with banks with a maturity of three months or less.

Term deposits are those amounts held by third parties on behalf of the Group and are not available for the Group's use; these are recognised separately from cash and cash equivalents on the balance sheet.

Trade receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, less any expected credit loss. The Group recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through profit or loss. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that the Group expects to receive, discounted at an approximation of the original effective interest rate. The carrying amount of the asset is reduced with an allowance account, and the amount of the loss will be recognised in the Consolidated Statement of Comprehensive Income within administrative expenses. Subsequent recoveries of amounts previously provided for are credited against administrative expenses in the Consolidated Statement of Comprehensive Income.

Trade payables are stated initially at fair value and subsequently measured at amortised cost.

Offsetting of Financial Instruments

Financial assets and financial liabilities are offset, and the net amount is reported in the Consolidated Statement of financial position if there is a currently enforceable legal right to offset the recognised amounts and there is an intention to settle on a net basis, or to realise the assets and settle the liabilities simultaneously.

Deferred Tax

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit. Deferred taxation liabilities are provided, using the liability method, on all taxable temporary differences at the reporting date. Such assets and liabilities are not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit.

Deferred income tax assets are recognised to the extent that it is probable that future taxable profits will be available against which the temporary differences can be utilised. The carrying amount of deferred tax assets is reviewed at each reporting date.

Current Tax

The current income tax charge is calculated based on the tax laws enacted or substantively enacted at the end of the reporting period in the countries where Jersey Oil and Gas Plc and its subsidiaries operate and generate taxable income. We periodically evaluate positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. Provisions are established where appropriate based on amounts expected to be paid to the tax authorities.

Current tax is payable based upon taxable profit for the year. Taxable profit differs from net profit as reported in the Statement of Comprehensive Income because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. Any Group liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the reporting date.

Foreign Currencies

The functional currency of the Company and its subsidiaries is Sterling. Monetary assets and liabilities in foreign currencies are translated into Sterling at the rates of exchange ruling at the reporting date. Transactions in foreign currencies are translated into Sterling at the rate of exchange ruling at the date of the transaction. Gains and losses arising on retranslation are recognised in the Consolidated Statement of Comprehensive Income for the year.

Employee Benefit Costs

Payments to defined contribution retirement benefit schemes are recognised as an expense when employees have rendered service entitling them to contributions.

Share-Based Payments

Equity settled share-based payments to employees and others providing similar services are measured at the fair value of the equity instruments at the grant date. The total amount to be expensed is determined by reference to the fair value of the options granted using the Black-Scholes Model:

• including any market performance conditions (for example, an entity's share price);

• excluding the impact of any service and non-market performance vesting conditions (for example, profitability, sales growth targets and remaining an employee of the entity over a specified time-period); and

• including the impact of any non-vesting conditions (for example, the requirement for employees to save).

The fair value determined at the grant date of the equity settled share-based payments is expensed on a straight-line basis over the vesting period, based on the Group's estimate of equity instruments that will eventually vest, with a corresponding increase in equity. At the end of each reporting period, the Group revises its estimate of the number of equity instruments expected to vest. The impact of the revision of the original estimates, if any, is recognised in profit or loss such that the cumulative expense reflects the revised estimate, with a corresponding adjustment to the equity settled employee benefits reserve.

Equity settled share-based payment transactions with parties other than employees are measured at the fair value of the goods or services received, except where that fair value cannot be estimated reliably, in which case they are measured at the fair value of the equity instruments granted, measured at the date the entity obtains the goods, or the counterparty renders the service.

Exercise proceeds net of directly attributable costs are credited to share capital and share premium.

Contingent Liabilities & Provisions

In accordance with IAS 37, provisions are recognised where a present obligation exists to third parties because of a past event, where a future outflow of resources with economic benefits is probable and where a reliable estimate of that outflow can be made. If the criteria for recognising a provision are not met, but the outflow of resources is not remote, such obligations are disclosed in the notes to the consolidated financial statements (see note 19). Contingent liabilities are only recognised if the obligations are more certain, i.e. the outflow of resources with economic benefits has become probable and their amount can be reliably estimated.

Share Capital

Ordinary shares are classified as equity.

Incremental costs directly attributable to the issue of new ordinary shares or options are shown in equity as a deduction, net of tax, from the proceeds.

3. Segmental reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the Board of Directors.

The Board considers that the Group operates in a single segment, that of oil and gas exploration, appraisal, development and production, in a single geographical location, the North Sea of the United Kingdom.

The Board is the Group's chief operating decision maker within the meaning of IFRS 8 "Operating Segments".

During 2025 and 2024 the Group had no revenue.

4. Financial risk management

The Group's activities expose it to financial risks, and its overall risk management programme focuses on minimising potential adverse effects on the financial performance of the Group. The Company's activities are also exposed to risks through its investments in subsidiaries and it is accordingly exposed to similar financial and capital risks as the Group.

Risk management is carried out by the Directors, and they identify, evaluate, and address financial risks in close co-operation with the Group's management. The Board provides written principles for overall risk management, as well as written policies covering specific areas, such as mitigating foreign exchange risks and investing excess liquidity.

Credit Risk

The Group's credit risk primarily relates to its trade receivables. Responsibility for managing credit risks lies with the Group's management.

A debtor evaluation is typically obtained from an appropriate credit rating agency. Where required, appropriate trade finance instruments such as letters of credit, bonds, guarantees and credit insurance will be used to manage credit risk.

Liquidity Risk

Liquidity risk is the risk that the Group will not be able to meet its financial obligations as they become due. The Group manages its liquidity through continuous monitoring of cash flows from operating activities, review of actual capital expenditure programmes, and managing maturity profiles of financial assets and financial liabilities.

Capital Risk Management

The Group seeks to maintain an optimal capital structure. The Group considers its capital to comprise both equity and net debt.

The Group monitors its capital mix needs and suitability dependent upon the development stage of its asset base. Earlier stage assets (pre-production) typically require equity rather than debt given the absence of cash flow to service debt. As the asset mix becomes biased towards production then typically more debt is available. The Group seeks to maintain progress in developing its assets in a timely fashion. With the completion of the NEO Energy farm-out in 2023 and the Serica Energy farm-out in 2024, the Group expects 's that its two industry partners will deliver sufficient cash to progress its assets to first oil in return for a capital (equity) contribution via the farm-outs. As the GBA redevelopment project progresses towards first oil, debt will become available and may be sought to enhance equity returns. As at 31 December 2025 there are no borrowings within the Group (2024: Nil).

The Group monitors its capital structure by reference to its net debt to equity ratio. Net debt to equity ratio is calculated as net debt divided by total equity. Net debt is calculated as borrowings less cash and cash equivalents. Total equity comprises all components of equity.

Maturity analysis of financial liabilities

Financial liabilities

Lease liabilities

5. Employees and Directors

Other pension costs include employee and Group contributions to money purchase pension schemes.

The average monthly number of employees during the year was as follows:

The average number of Directors to whom retirement benefits were accruing was as follows:

Information regarding the highest paid Director is as follows:

Key management compensation

Key management includes Directors (Executive and Non-Executive) and an adviser to the Board. The compensation paid or payable to key management for employee services is shown below:

6. Finance Income and Expense

7. Loss Before Tax

The loss before tax is stated after charging/(crediting):

8. Tax

Reconciliation of tax charge

No liability to UK corporation tax arose on ordinary activities for the year ended 31 December 2025, or for the year ended 31 December 2024.

In April 2023, the rate of corporation tax rose to 25% for profits over £250,000.

The Group has not recognised a deferred tax asset due to the uncertainty over when the tax losses can be utilised. At the year end, the usable tax losses within the Group were approximately £63 million (2024: £62 million).

9. Loss Per Share

Basic loss per share is calculated by dividing the losses attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year.

Diluted loss per share is calculated using the weighted average number of shares adjusted to assume the conversion of all dilutive potential ordinary shares.

There is no difference between dilutive and ordinary earnings per share due to there being a loss recorded in the year.

The share options (note 20) issued in the Group that would potentially dilute earnings per share in the future have not been included in the calculation of diluted loss per share as their effect would be anti-dilutive.

10. Intangible assets

Additions represent the work capitalised on the Buchan redevelopment assets. 

At the start of 2023 the Company owned 100% interests in two licenses: P2498 containing the Buchan field and J2 Discovery, and P2170 containing the Verbier discovery. At the end of 2023 the costs incurred in acquiring and advancing the licenses to their then current state was £25,700,982 (2022: £24,548,122). During 2023 a farm-out of a 50% interest in both licenses to NEO was completed and in 2024 a farm out of a 30% interest in both licenses to Serica was completed. Both deals had similar terms whereby in exchange for the farm in, the respective parties agreed to a series of cash payments and both a pre-development and development carry on the Buchan Redevelopment project. In accordance with our farm-out policy for assets at that stage of development, the cash proceeds of £5,519,216 in 2024 and £9,103,944 in 2023 were both deducted from the carrying value of the assets.

In line with the requirements of IFRS 6, we have considered whether there are any indicators of impairment on the exploration and development assets. Based on our assessment, as at 31 December 2025 there were deemed to be no indicators that the licences are not commercial and that the carrying value of £11,873,232 continues to be supported by ongoing, be it reduced, development work on the licence areas with no impairments considered necessary. It is noted that increases in North Sea taxes which came into effect in 2024 contributed to the lapsing of the contractual agreement to purchase the Western Isles FPSO in the first quarter of 2025. As a result, project sanction will require the joint venture to re-contract this FPSO or secure another suitable development option.

11. Property, Plant and Equipment

12. Leases

Amounts Recognised in the Statement of financial position

The liabilities were measured at the present value of the remaining lease payments, discounted using the lessee's incremental borrowing rate as of 1 January 2019. The weighted average lessee's incremental borrowing rate applied to the lease liabilities on 1 January 2019 was 3%. The borrowing rate applied for 2025 remained at 3% and the leases relate to office space.

A new lease agreement was entered into in June 2023 for a total of 9 years with break clauses after 3 and 6 years. The interest rate implicit in the agreement was 3% over the Bank of England's base rate. Given the 3-year break clause and the future plans for the business it was deemed appropriate to recognise the liability relating to a 3-year period. This lease was in relation to an office in Jersey.

Amounts Recognised in the Statement of comprehensive income

13. Trade and other receivables

14. Cash and cash equivalents

The cash balances are placed with creditworthy financial institutions with a minimum rating of 'A'.

15. Term deposits

Term deposits are placed with creditworthy financial institutions with a minimum rating of 'A'. The maturity periods of the term deposits range from three to ten months from the original date of deposit. 

16. Called up share capital

Ordinary shares have a par value of 1p. They entitle the holder to participate in dividends, distributions or other participation in the profits of the Company in proportion to the number of and amounts paid on the shares held.

On a show of hands every holder of ordinary shares present at a meeting, in person or by proxy, is entitled to one vote, and on a poll each share is entitled to one vote.

17. Trade and other payables

18. Lease liabilities

19. Contingent Liabilities

(i) 2015 settlement agreement with Athena Consortium: In accordance with a 2015 settlement agreement reached with the Athena Consortium, although Jersey Petroleum Ltd remains a Licensee in the joint venture, any past or future liabilities in respect of its interest can only be satisfied from the Group's share of the revenue that the Athena Oil Field generates and up to 60 per cent. of net disposal proceeds or net petroleum profits from the Group's interest in the P2170 licence which is the only remaining asset still held that was in the Group at the time of the agreement with the Athena Consortium who hold security over this asset. Any future repayments, capped at the unpaid liability associated with the Athena Oil Field, cannot be calculated with any certainty, and any remaining liability still in existence once the Athena Oil Field has been decommissioned will be written off. A payment was made in 2016 to the Athena Consortium in line with this agreement following the farm-out of P2170 (Verbier) to Equinor and the subsequent receipt of monies relating to that farm-out.

(ii) Equinor UK Limited: During 2020, JOG announced that it had entered into a conditional Sale and Purchase Agreement ("SPA") to acquire operatorship of, and an additional 70% working interest in Licence P2170 (Blocks 20/5b and 21/1d) from Equinor UK Limited ("Equinor"), this transaction completed in May 2020. The consideration for the acquisition consisted of two milestone payments, which will be accounted for in line with the cost accumulation model, as opposed to contingent liabilities:

§ US$3 million upon sanctioning by the UK's North Sea Transition Authority ("NSTA") of a Field Development Plan ("FDP") in respect of the Verbier Field; and

§ US$5 million upon first oil from the Verbier Field.

The earliest of the milestone payments in respect of the acquisition is not currently anticipated being payable before the start of 2030.

(iii) ITOCHU Corporation and Japan Oil, Gas and Metals National Corporation: During 2020, JOG announced that it had entered into a conditional Sale and Purchase Agreement ("SPA") to acquire the entire issued share capital of CIECO V&C (UK) Limited, which was owned by ITOCHU Corporation and Japan Oil, Gas and Metals National Corporation, this transaction completed in April 2021. The acquisition was treated as an asset acquisition rather than a business combination due to the nature of the asset acquired. There were no assets or liabilities acquired other than the 12% interest in licence P2170 (Verbier). The consideration for the acquisition included a completion payment of £150k and two future milestone payments, which are considered contingent liabilities:

§ £1.5 million in cash upon consent from the UK's North Sea Transition Authority ("NSTA") for a Field Development Plan ("FDP") in respect of the Verbier discovery in the Upper Jurassic (J62-J64) Burns Sandstone reservoir located on Licence P2170; and

§ £1 million in cash payable not later than one year after first oil from all or any part of the area which is the subject of the FDP.

The earliest of the milestone payments in respect of the acquisition is not currently anticipated being payable before the start of 2030.

20. Share based payments

The Group operates several share options schemes. Options are exercisable at the prices set out in the table below. Options are forfeited if the employee leaves the Group through resignation or dismissal before the options vest.

Equity settled share-based payments are measured at fair value at the date of grant and expensed on a straight-line basis over the vesting period, based upon the Group's estimate of the number of shares that will eventually vest.

The Group's share option schemes are for Directors, Officers and employees. The charge for the year was £602,190 (2024: £764,774) and details of outstanding options are set out in the table below.

The weighted average value of the options granted during the year was determined using a Black-Scholes valuation. The significant inputs into the model were the mid-market share price on the day of grant as shown above and an annual risk-free interest rate ranging between 4.6% and 4.8%. The volatility measured at the standard deviation of continuously compounded share returns is based on a statistical analysis of daily share prices from over a four-year period. The weighted average exercise price for the options granted in 2025 was 82.50 pence, the weighted average remaining contractual life of the options was 6 years (for all schemes 3 years), the weighted average volatility rate was 104% and the dividend yield was nil. During the year 360,000 share options from the January 2018 issuance and 150,000 from the November 2018 issuance expired, these had an exercise price of 200 pence and 172 pence, respectively. A further 23,332 share options were forfeited due to the departure of employees, these had a weighted exercise price of 240 pence. The weighted average exercise price for all outstanding options at 31 December 2025 was 177 pence and the remaining contractual life was 3 years. For details of the schemes and scheme rules, please refer to the Remuneration Report.

21. Related undertakings and ultimate controlling party

The Group and Company do not have an ultimate controlling party.

*Dissolved 25 February 2025

**Dissolved 11 February 2025

Registered Offices

1. 71-75 Shelton Street, Covent Garden, London WC2H 9JQ

2. 7 Queen's Gardens, Aberdeen, Scotland AB15 4YD

3. First Floor, Tower House, La Route es Nouaux, St Helier, Jersey JE2 4ZJ

4. 10, The Triangle, NG2 Business Park Nottingham, Nottinghamshire NG2 1AE

5. 67 Gowrie Road, London SW11 5NN

22. Notes to the consolidated statement of cash flows

Reconciliation of Loss Before Tax to Cash Used in Operations

Cash and cash equivalents

The amounts disclosed on the consolidated Statement of Cash Flows in respect of Cash and cash equivalents are in respect of these statements of financial position amounts:

Year ended 2025

Year ended 2024

23. Post balance sheet events

After the reporting date, geopolitical events have increased volatility in global oil markets; the Group continues to monitor developments but does not currently expect any significant impact on its operations or strategy.

24. Availability of the annual report 2025

A copy of this report will be made available for inspection at the Company's registered office during normal business hours on any weekday. The Company's registered office is at 71-75 Shelton Street, Covent Garden, London WC2H 9JQ. A copy can also be downloaded from the Company's website at www.jerseyoilandgas.com. Jersey Oil and Gas Plc is registered in England and Wales, with registration number 7503957.