Jersey Oil&gas Regulatory News (JOG)

6 May 2021

Jersey Oil and Gas plc

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

Final Results for the year ended 31 December 2020

Jersey Oil & Gas (AIM: JOG), an independent upstream oil and gas company ‎focused on the UK Continental Shelf ("UKCS") region of the North Sea, is pleased to announce its audited results for the year ended 31 December 2020.

Highlights

· Delivered 100% control across all of the Greater Buchan Area ("GBA")

o Acquired 70% working interest ("WI") and Operatorship in licence P2170 from Equinor

o Acquired CIECO V&C (UK) Limited ("CIECO V&C") (12% WI in P2170 and tax losses)

o The 32nd Licensing Round Award has been completed at part-block 20/5e (within the GBA acreage)

· Core GBA P50 Contingent Resources increased to 172 MMboe, from 124 MMboe in 2019, with four high graded, drill-ready exploration prospects at approximately 220 MMboe

· Grown the GBA project team, expanding the size and capabilities of the Company commensurate with the requirements of operatorship of the GBA Development project (the "GBA Project")

· Concept Select progressed during the period, focused on delivering detailed plans for a low-carbon development concept with highly attractive economics

· Year-end cash position of £5.1 million, with no debt

Post year end

· Key findings of the Concept Select published

o Uplift in P50 Contingent Resources estimates for the  core GBA to 172 MMboe

o Selected Concept for a  three phase, low-carbon, conventional platform  development

· A farm-out process has been launched to seek an aligned partner  to join the project and provide material funding

· Concluded a Placing and  Offer for Subscription

o Oversubscribed and raised £16.6 million

o Strengthened  the balance sheet and received strong institutional support

· Concluded the acquisition of CIECO V&C, providing a 12% WI in licence P2170 and associated tax losses of c.£15m

Outlook

· Farm out process for GBA underway

· JOG views the GBA as one of the most exciting  developments in the North Sea, with the potential to deliver significant value to shareholders from

o 4 operated licences

o 5 oil discoveries

o 4 drill-ready exploration prospects

· Project lifetime pre-tax free cash flow for the potential core GBA development is forecast to be circa US$6.4bn, with an estimated project value of approximately US$1.7bn pre-tax NPV (10%)

Andrew Benitz, CEO of Jersey Oil & Gas, commented:

"JOG is delivering on a strategy of focused growth, having successfully aggregated a significant portfolio of discovered resources in the GBA together with significant exploration upside. We have assembled an industry leading, multidisciplinary team of specialists who have delivered a significant upgrade in discovered and prospective resources and selected what we believe is the optimum development concept.

"I would like to express my thanks to all our team and everyone involved in our GBA project, who have worked tirelessly throughout the Covid-19 pandemic to ensure ongoing progress.

"The GBA project will be a major investment for the UK, create many jobs and ultimately produce a vital domestically sourced and low carbon supply of energy. Our shareholder support is continually appreciated, and it is only through their investment that we can achieve our plans."

Enquiries:

Notes to Editors:

Jersey Oil & Gas is a UK E&P company focused on building an upstream oil and gas business in the North Sea. The Company holds a significant acreage position within the Central North Sea referred to as the Greater Buchan Area ("GBA"), which includes operatorship and 100% working interests in blocks that contain the Buchan oil field and J2 and Glenn oil discoveries and an 100% working interest in the P2170 Licence Blocks 20/5b & 21/1d, that contain the Verbier oil discovery and other exploration prospects.

JOG's total GBA acreage is estimated by management to contain 190 million barrels of oil equivalent ("MMboe") of discovered P50 recoverable resources net to JOG, in addition to significant exploration upside potential of approximately 220 MMboe of prospective resources in close proximity to the Company's planned Buchan production platform. JOG has recently concluded the Concept Select phase of an FDP for the Greater Buchan Area and plans to progress into Front End Engineering and Design (FEED) later this year.

JOG is focused on delivering shareholder value and growth through creative deal-making, operational success and licensing rounds. Its management is convinced that opportunity exists within the UK North Sea to deliver on this strategy and the Company has a solid track-record of tangible success.

CHAIRMAN'S STATEMENT

Overview

During 2020 Jersey Oil and Gas ("JOG") worked tirelessly to de-risk the development of its North Sea licence interests, thereby setting the foundations for a very strong performance in the first quarter of 2021.

A large part of our 2020 efforts were spent advancing the Concept Select phase of our 100% owned and operated Greater Buchan Area (the "GBA Development Project"), details of which were announced in Q1 2021. This demonstrated an economically robust development plan through to first oil in late 2025 made up of pre-tax cash flows of US$6.4 billion, an NPV of US$1.7 billion and an internal rate of return in excess of 25%. These estimated economics included a low carbon approach to the development of the GBA, by way of an electrified platform supplied with electricity from shore. This has the potential to be a first for the United Kingdom sector of the North Sea and one we are proud to advance.

Another important part of our work undertaken in 2020, and announced in Q1 2021, was an extensive review of our Buchan contingent resources, based on extensive dynamic reservoir modelling of the Buchan field. This modelling was based on all available subsurface information which we successfully history matched to production data going back 36 years. This modelling, which was independently peer reviewed, demonstrated a significant uplift in our earlier contingent resource estimates. The resulting volumes for the Buchan Oil field and the J2 and Verbier oil discoveries (which we refer to as the GBA core volumes), are now forecast to be 162 million stock tank barrels ("MMstb") or 172 million of barrels of oil equivalent ("MMboe") including associated gas (which excludes 18 MMboe of discovered resources from the 100% owned Buchan Andrew and Glenn discoveries).

We were also pleased to announce the results of a comprehensive subsurface evaluation of our prospective resources, P2170 ("Verbier Deep"), P2498 ("Wengen" and "Cortina NE"), and P2497 ("Zermatt"). Each of these prospects can be regarded as drill ready and able to be tied back to the GBA hub development in the event of a discovery. This evaluation, which was also subject to a peer review process, resulted in combined prospective P50 resource volumes of approximately 220 MMboe. With these prospects in close proximity to the planned GBA hub, minimum economic volumes are at or below the P90 volumes calculated by JOG.

The year began with JOG acquiring an additional 70% interest in Licence P2170 ("Verbier") from Equinor UK Limited which was followed later in the year by the announcement of the acquisition of a further 12% interest from Cieco V&C (UK) Limited, which completed in Q2 2021, thereby resulting in JOG owning 100% of this licence which includes the Verbier oil discovery, some 6km from the Buchan oil field.

Business Environment

Following the Covid-19 outbreak in the first quarter of 2020, the Brent Crude oil price fell to levels of around US$20 per barrel. Since that time, the oil price has recovered to its pre-Covid-19 levels and at the time of this statement is trading at approximately US$65 per barrel. We continue to plan for first oil from the GBA development to be in late 2025, with many market commentators anticipating long term oil prices of US$60 and above. Such levels are substantially above our current estimates for the lifecycle costs for our GBA project, being approximately in US$30 per barrel.

Shortly after the Covid-19 outbreak we temporarily closed our London and Jersey offices and put in place systems under which the Board and employees of the Company could work remotely. We also took steps to ensure that our staff maintained social contact with each other through various remote activities.

I am pleased to report that this worked well and, indeed, we increased the number of employees working for the Company over the course of the year.

Environmental, Social and Corporate Governance

We fully support the UK Government's commitment to net zero emissions by 2050 together with the various policy initiatives being introduced by the Oil and Gas Authority ("OGA"), in particular the revised "OGA Strategy" announced in Q1 2021, which sets out a range of net zero obligations on the oil and gas industry.

We adopt an active approach to environmental, social and corporate governance issues in all that we do, ranging from the environment in which our employees work through to the effect of our North Sea development activities. As part of this process, JOG is planning to limit its Scope 1 CO2 emissions by powering the GBA platform with electrical power emissions through either a direct electricity supply from shore, or participation in an industry wide collaboration to electrify certain areas of the central North Sea. This will avoid the requirement to install platform based gas turbines, with a consequent, and substantial, reduction in related CO2 emissions. We are working closely with the OGA on this, who are fully supportive of this approach.

A full statement on JOG's approach to Environmental, Social and Corporate Governance matters appears later in this Annual Report, as does a Corporate Governance Report.

People

During 2020, we hired additional staff in order to progress the development of the GBA. These talented industry professionals bring many skills to JOG ranging from experience of developing other similar sized North Sea fields through to expertise in health, safety, environmental and social responsibility matters. We welcome all of these individuals to the Company.

As we progress beyond the Concept Select phase of the GBA development, in Q1 2021, and begin work on the Front End Engineering Design of the project, the number of additional staff required will increase.

During 2020 we were also pleased to announce the appointment of Dr Chris Haynes, OBE, as an adviser to the Board. Chris has extensive experience in the oil and gas industry and is providing very helpful strategic guidance and oversight to our many work programmes.

In April 2021 we were also pleased to announce the appointment of Les Thomas to the Board as a Non-Executive Director. Les has over 35 years' experience in the oil and gas industry and his wealth of experience, particularly in the North Sea, will be of significant value as we progress the development of Greater Buchan Area.

Also in 2021, Frank Moxon was appointed as the Senior Independent Director of JOG, which is an increasingly important role as we grow the Company.

Outlook

JOG has successfully progressed and further de-risked the development of the GBA during 2020. With increased ownership of acreage within the GBA via two acquisitions, a successful licence round award, the completion of the Concept Select phase and the significant uplift in our estimates of our GBA resources, we view the GBA development as one of the most exciting developments in the North Sea and one with the potential to deliver significant value to shareholders.

There are substantial costs to be incurred in taking the GBA development through to first oil, which will require additional funding. However we are confident that this project, by virtue of its size, location and low carbon, electrically powered credentials, will be of interest to many industry participants. We formally launched a farm out process in Q1 2021 in addition to raising approximately £16.6m (gross) of new equity capital, which will enable us to maintain our plans for first oil in 2025 and provide the Company with financial flexibility as we negotiate with prospective farm in partners. We look forward to updating shareholders as this process proceeds.

On behalf of the Board, I would like to thank all of our employees, both old and new, for the continuing hard work that is being put into the development of the GBA, particularly as we have all had to adapt to working remotely.

As always, I also would also thank our shareholders for their continuing support and welcome our new shareholders into this exciting and low carbon project.

Marcus Stanton

Non-Executive Chairman

5 May 2021

CHIEF EXECUTIVE OFFICER'S REPORT

Overview

2020 has been an important year of consolidation for the planned development of the Company's Greater Buchan Area (GBA). Having matured our understanding of the subsurface we have now selected our preferred development concept - a low carbon, fully electrified fixed platform located over the Buchan oil field. In parallel, the Company has positioned itself with operatorship and complete ownership of the GBA acreage putting JOG in an advantageous position ahead of the Company's much anticipated farm-out process which was launched in March 2021 in order to attract an industry partner to join us in unlocking the considerable value that exists within the GBA.

Subsurface

The subsurface evaluation undertaken with the benefit of the recently acquired PGS 3D broadband seismic data has resulted in the validation and furthering of our understanding of the existing discovered and prospective resource potential.

The Buchan static model was built by Rockflow Resources Ltd (Rockflow) and as part of their deliverables, P90, P50 and P10 static models were provided to Schlumberger UK Oilfield Plc (Schlumberger) in order to undertake history matching with the 36 years of historic Buchan production data. The history matched models were then used to generate production forecasts based on subsurface development plan reflecting different producer and water injection well counts. The subsurface development plans used for these production forecasts, combined with economic modelling, provide the basis for the final concept selection.

The initial core development will comprise Buchan, J2 (now recognised as being structurally separated into J2 West and J2 East) and Verbier (now recognised as being structurally separated into Verbier West and Verbier East) with a combined 2C resource of 172 million barrels of oil equivalent ("MMboe"). This includes a significant increase in our 2C contingent resource estimate for the Buchan oil field to 132 MMboe.

Evaluation of the prospective resource potential has not only validated existing prospectivity but identified a volumetrically material new prospect in Wengen. Of the prospective resource inventory, four of the identified prospects have been matured to drill-ready status: Verbier Deep, Wengen, Cortina NE (J64) and Zermatt with a combined prospective resource in excess of 200 MMboe.

An assessment has been performed to determine the optimum drilling sequence of these various exploration prospects, resulting in the following sequence (subject to funding).

• Wengen - Q2 2023

• Cortina NE - Q2 2023

Analysis shows that in a P50 resource success case, each exploration prospect offers a highly economic tie-back opportunity to the GBA development. A successful outcome at either of the Wengen or Cortina prospects has been shown to offer the potential to extend the GBA Development Project's plateau production period into the mid- to late- 2030s with enhanced economics.

Summary of Concept Select Findings

Delivering Concept Select has been a comprehensive work effort led by our project team requiring over 14,000 JOG hours and 18,000 contractor hours. In early 2020, JOG completed an Appraise Phase assessment of the various development options for the GBA. This option screening phase concluded that development of the GBA's resources via a fixed production platform located at the Buchan field, offered the optimum solution when considering environmental factors, safety issues, technical feasibility, execution risk, schedule, capital and operating costs, project economics, availability and operability.

Subsequently, the Company has progressed this development option through the Concept Select Phase, with work commencing in April 2020. The objective of this Select Phase was to deliver a single, economically acceptable concept to develop the GBA in order to take the project forward into the Define Phase. The selected concept for the GBA Development is planned to be executed in three Phases. Phase 1 will deliver a single integrated wellhead, production, utilities and quarters (WPUQ) platform located at the Buchan oil field. The facility will be normally manned. The Buchan wells will be drilled utilising a heavy- duty jack-up (HDJU) rig located over an 12 slot well bay. The Phase 1 facilities will be designed to accommodate Phase 2 and Phase 3 of the development. Phase 2 will develop the J2 West, J2 East and Verbier East oil discoveries via a subsea tie-back to the GBA platform.

Phase 3 will develop the Verbier West oil discovery via connection to the Phase 2 subsea infrastructure. Production from the reservoir will be supported by injection of both produced water and seawater and enhanced by the use of electric submersible pumps (ESP). Field life is anticipated to be 31 years.

The Buchan location benefits from proximity to existing export infrastructure for both oil and gas. Selection of the final oil and gas export routes will be subject to a detailed commercial dialogue through formal requests for service issued in February 2021. It is scheduled that this work will be completed to inform FEED (Front End Engineering and Design), currently planned to take place later this year.

GBA's Compelling Economics[1]

Our Concept Select findings have yielded some encouraging economic estimates. Our management estimates show the GBA to be a significantly cash generative asset, with the first full year of production expected to generate US$840 million in EBITDA. Expected pre tax free cash flow for the core discovered volumes is estimated to be in excess of US$6 billion and this has the potential to double on the back of near field exploration success.

Cost estimates for each phase have been prepared in accordance with the detailed work break down structures for Phase 1, 2 and 3. CAPEX costs for Phase 1 are estimated to be approximately £1 billion. Operating costs during plateau production are estimated at US$8/boe to US$9/boe, with a payback period estimated at under 3 years. Plateau production is estimated for more than 3 years. Total project costs based on current day values are estimated to be approximately US$30/boe. Power from Shore is our preferred development concept, and our economics are based off this assumption.

Electrification

In line with the UK Government's net zero strategy and policies, JOG recognises the need for a low carbon power solution and has an aspiration to deliver production from the GBA Development Project at an industry-leading carbon intensity level. Accordingly, options have been assessed that offer the opportunity to eliminate carbon dioxide emissions associated with power generation on the planned production facility. Economics have been run based on the provision of power from the UK national grid via the installation of a subsea cable to shore.

The provision of power from shore offers the opportunity to reduce CAPEX and OPEX due to the removal of certain utility systems and a resulting lower maintenance burden although such reductions are offset by the cost of the grid connection and subsea cable and the in-service purchase price of electricity.

A "Net Zero" solution for the GBA Development Project is economically attractive, despite a 'Green Premium' compared to the conventional case utilising gas turbines.

Overall carbon emissions from the GBA with platform electrification are estimated to be less than 1kg/boe. This compares to estimated carbon emissions from the GBA development using gas turbines of 13kg/boe, which is less than the UKCS average of approximately 20kg/boe.

The forecast economic outturn for the power from shore case relative to the conventional gas turbine case is based on current UK Government carbon tax forecasts up to 2030 and the cost of sourcing power from the UK. Based on these assumptions, the "Green Premium" results in a project NPV reduction of approximately 8%.

The GBA is optimally located in the heart of the UK Central North Sea such that there is credible potential for JOG to be an enabler for regional electrification. Collaboration with other regional operators could reduce overall capital costs associated with the cable infrastructure. Additionally, early stage engagement with infrastructure funds has indicated that there is potential interest in financing the capital costs in return for future tariff payments. The Company continues to progress studies that may lead to electrification costs reducing in line with conventional power solutions.

Regional hub potential

Collaborative studies conducted in parallel with the GBA Concept Select Phase, have identified the potential for significant synergies with neighbouring, third-party discovered resources. The production of such resources through the GBA facility offers the potential for both parties to realise reductions in development costs and OPEX costs offering the potential to increase incremental recovery of oil from the GBA and neighbouring discoveries.

Schedule

JOG's detailed planning and schedule for delivering first is currently targeting late Q3 2025. Key milestones in achieving this first oil date include:

• Concept Select Report finalised - Q1 2021

• Commit to FEED - Q3 2021

• Field investment decision (FID) - Q3 2022

• First oil - Q3 2025

Licensing activity

During the year JOG acquired operatorship of, and increased its equity in, Licence P2170 to 100% having acquired 70% from Equinor UK Ltd in April 2021 and more recently, acquired the remaining 12% through the corporate acquisition of CIECO V&C (UK) Limited. Details relating to the acquisitions can be found in note 19 of the Consolidated Financial Statements.

In September 2020, JOG was awarded a 100% working interest in, and operatorship of, part-block 20/5e in the Oil & Gas Authority's ("OGA's") 32nd Offshore Licensing Round. Part-block 20/5e has been incorporated into our existing Licence P2498 and is located within the GBA development acreage and contains an extension of the J2 oil discovery.

These acquisitions serve to increase JOG's discovered resources, add material value and increase our exposure to additional exploration potential.

Effective 30 November, JOG made a discretionary partial relinquishment of P2170, retaining the prospective areas and realising a significant saving in licence fees.

Environmental, Social and Corporate Governance ("ESG") Considerations

It is the Company's ambition to be a market differentiator in emissions accountability and management. To ensure meaningful carbon commitments, JOG has been working with ITPEnergised, a leading environmental consultancy, to set specific targets based on a quantifiable baseline. The defined action plan is to be underpinned by our Carbon Policy. This Policy communicates the Company's emissions intensity targets and reporting boundaries looking forward.

Furthermore, JOG has undertaken analysis of the requirements of the Taskforce for Climate-Related Financial Disclosures (TCFD) and plans to report its disclosures in line with the recommendations of the TCFD from 2021.

As a proud signatory of the UN Global Compact, JOG continues to align itself with the philosophy of the Compact's Ten Principles in the areas of Human Rights, Labour, Environment and Anti- Corruption. Details of JOG's actions to integrate the Global Compact and its Principle's into the Company's strategy, culture and daily operations are outlined in our inaugural Sustainability report included within this annual report.

Acquisition Strategy

2020 saw oil prices hit recent unexpected lows and the shock of supply conflicts, demand slump as a result of the Covid-19 pandemic and diminished investor sentiment challenged our industry to its limit. Nevertheless, despite global economic havoc, demand for oil, on an annual basis fell by approximately only 6%. Oil prices have recovered following news of a Covid-19 vaccine during November 2020. This recovery has led to a re-emergence of deal activity across the North Sea, with the announcement of several transactions in the early weeks of 2021. As we have approached completion of our Concept Select phase for the GBA Development Project, JOG's priority has been focused on its core asset base and the launch of the farm-out process.

As mentioned above, JOG announced two acquisitions during 2020, successfully increasing its working interest in Licence P2170 from 18% to full control and a 100% working interest. The acquisition of Equinor UK Limited's 70% working interest was an asset acquisition, with certain future milestone contingent and royalty payments. The acquisition of CIECO V&C (UK) Ltd. which was completed in Q2 2021 was a corporate acquisition, which included CIECO's 12% working interest in Licence P2170 and approximately £15 million of tax loses. Consideration comprised a modest upfront payment and certain future milestone contingent payments. JOG remains active in its pursuit of accretive acquisition opportunities and we have seen a significant uplift in deal activity across the North Sea during 2021.

Financial Review

JOG's cash position was approximately £5.1 million as of 31 December 2020. As an oil and gas exploration and development company, JOG generated no production revenue during the year. We received a small amount of interest on our cash deposits.

The loss for the year, before and after tax, was £2.8 million (2019 Year End: £2.1 million). Our main expenditure during the year related to the Concept Select work on our GBA project.

Post year end, we were pleased to announce an oversubscribed equity placing and a directors' subscription in addition to an offer for subscription for existing shareholders, raising gross proceed of approximately £16.6 million. The net proceeds from the fundraising, together with the Company's existing cash reserves, will be used to strengthen the Company's balance sheet ahead of anticipated commercial negotiations for the GBA development project during the farm-out process and to maintain momentum and ensure that time and funding pressures do not interfere in the efficient delivery of the overall project. Costs for the next stages of the GBA development project will include surveys, license fees, pre-FEED and FEED work and project management.

Summary and outlook

JOG is delivering on a strategy of focused growth having successfully aggregated a significant portfolio of discovered resources in the GBA, together with significant exploration upside. We have assembled an industry leading, multidisciplinary team of specialists who have delivered a significant upgrade in discovered and prospective resources and selected the optimum development concept.

Having completed our Concept Select work, we will be submitting for approval to the OGA a report summarising the Company's findings by 31st July 2021, in compliance with JOG's commitment under the P2498 licence. Work continues apace with respect to the issuance of tenders for marine surveys to support the Environmental Statement required for the Field Development Plan. Tendering processes for the provision of FEED engineering services is also underway.

JOG is currently working towards being ready to enter the FEED phase of the GBA project in Q3 2021, with FID (Final Investment Decision) currently anticipated for late H2 2022.

With the Concept Select Report finalised, JOG has now launched its farm-out process to seek to secure an industry partner for the GBA Development Project.

JOG's Board anticipates that this will be well received by the industry as an exciting investment opportunity, in light of its scale, economics and low carbon production approach.

Oil prices have recovered strongly from the lows witnessed during 2020. JOG expects a significant supply crunch from global under investment in upstream projects, which can be expected to lead to further oil price increases favourably timed for our development.

I would like to express my thanks to all our team and everyone involved in our GBA project, who have worked tirelessly throughout the Covid-19 pandemic to ensure ongoing progress. The GBA Development Project will be a major investment for the UK, create many jobs and ultimately produce a vital domestically sourced and low CO2 supply of energy. Our shareholder support is continually appreciated, and it is only through their investment that we can achieve our plans.

Andrew Benitz

Chief Executive Officer

5 May 2021

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the year ended 31 December 2020

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As at 31 December 2020

Vicary Gibbs

Chief Financial Officer

5 May 2021

Company Registration Number: 07503957

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 31 December 2020

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

CONSOLIDATED STATEMENT OF CASH FLOWS

for the year ended 31 December 2020

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the year ended 31 December 2020

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 the United Kingdom and quoted on AIM, a market operated by London Stock Exchange plc. The address of its registered office is 10 The Triangle, ng2 Business Park, Nottingham, NG2 1AE.

2. SIGNIFICANT ACCOUNTING POLICIES

The principal 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

These financial statements have been prepared in accordance with international accounting standards in conformity with the requirements of the Companies Act 2006.

Going Concern

The Company is required to have sufficient resources to cover the expected running costs of the business for a period of at least 12 months after the issue of these financial statements. Further to the equity placing and offer for subscription concluded in April 2021 the Company has in a severe but plausible downside scenario surplus funds significantly in excess of the outstanding commitments to conclude the GBA Concept Select work programmes and the ongoing Operator overheads and licence fees beyond November 2022. The farm-out process launched in March 2021 to secure a new partner and material associated funding to progress the GBA Project through FEED and to FID and beyond is expected to conclude in Q3 2021. Subject to securing suitable funding from this process development work will continue at pace. Delays to the farm-out process may serve to slow the pace of development and may delay the date at which the project achieves FID. Given JOG currently owns and operates 100% of project, the rate at which JOG may choose to progress the project is entirely within its control and hence the Company's current cash reserves are therefore expected to more than exceed its estimated liabilities. Based on these circumstances, the Directors have considered it appropriate to adopt the going concern basis of accounting in preparing the Company's financial statements.

Changes in Accounting Policies and Disclosures

The group has applied the following standards and amendments for the first time for their annual reporting period commencing 1 January 2020:

· Definition of Material - Amendments to IAS 1 and IAS 8;

· Definition of a Business - Amendments to IFRS 3;

· Interest Rate Benchmark Reform - Amendments to IFRS 9, IAS 39 and IFRS 7; and

· Revised Conceptual Framework for Financial Reporting.

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.

Significant Accounting Judgements and Estimates

The preparation of the financial statements requires management to make estimates and assumptions that affect the reported amounts of revenues, expenses, assets and liabilities at the date of the financial statements. If in 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 assessment of the existence of impairment triggers (note 11).

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

Impairments

The Group tests its capitalised exploration licence costs for impairment when facts and circumstances suggest that the carrying amount exceeds the recoverable amount. The recoverable amounts of Cash Generating Units are determined based on fair value less costs of disposal calculations. There were no impairment triggers in 2020 and no impairment charge has been recorded.

Share-Based Payments

The Group currently has a number of share schemes that give rise to share-based charges. The charge to operating loss for these schemes amounted to £181,870 (2019: £437,080). For the purposes of calculating the fair value of the share options, a Black- Scholes option pricing model has been used. Based on past experience, it has been assumed that options will be exercised, on average, at the mid-point between vesting and expiring. The share price volatility used in the calculation is based on the actual volatility of the Company's shares, since 1 January 2017. 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.

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 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.

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 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 IAS 39 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 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.

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. Accounting policies of subsidiaries have been changed where necessary to ensure consistency with the policies adopted by the Group.

(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.

Acquisitions, Asset Purchases and Disposals

Acquisitions of oil and gas properties are accounted for under the purchase method where the acquisitions meet the definition of a business combination.

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 Statement of Comprehensive Income.

Intangible assets are recognised at acquisition at the cost paid using the cost accumulation model. Variable payments are not included in the carrying amount of the asset at acquisition, and no liability is recognised for the contingent consideration. The Group does not recognise a liability because, following the IFRIC agenda decision (March 2016), it is not clear that there is an obligation before the uncertainty is resolved.

Exploration and Evaluation Costs

The Group financial statements 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. For the purposes of impairment the group allocates all of its licences to one cash generating unit. The Group considers this to be appropriate due to the future interdependency of these fields.

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 in the near future, 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 exists 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.

In the event an impairment trigger is identified the Group performs a full impairment test for the asset 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 to sell.

Property, Plant and Equipment

Property, plant and equipment is stated at historic purchase 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

From 1 January 2019, leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the Group.

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 payment 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 financing received by the individual lessee 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/operation agreements with strategic partners. 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. Measurement is based on the higher of fair value less cost of disposal or value in use.

Financial Instruments

Financial assets and financial liabilities are recognised in the Group'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.

The simplified approach requires expected lifetime losses to be recognised from initial recognition of the receivables. This involves determining the expected loss rates using a provision matrix that is based on the company's historical default rates observed over the expected life of the receivable and adjusted forward-looking estimates. This is then applied to the gross carrying amount of the receivable to arrive at the loss allowance for the period.

The three-stage approach assesses impairment based on changes in credit risk since initial recognition using the past due criterion and other qualitative indicators such as increase in political concerns or other macroeconomic factors and the risk of legal action, sanction or other regulatory penalties that may impair future financial performance. Financial assets classified as stage 1 have the ECL measured as a proportion of their lifetime ECL that results from possible default events that can occur within one year, while assets in stage 2 or 3 have their ECL measured on a lifetime basis. If the borrower has sufficient accessible highly liquid assets in order to repay the loan if demanded at the reporting date, the expected credit loss is considered immaterial.

If the borrower does not have sufficient accessible highly liquid assets, the ECL is determined by projecting the probability of default (PD), loss given default (LGD) and exposure at default (EAD).

The PD is based on default rates determined by external rating agencies for the counterparties. The LGD is determined based on management's estimate of expected cash recoveries after considering the historical pattern of the receivable, and it assesses the portion of the outstanding receivable that is deemed to be irrecoverable at the reporting period. For intercompany balances, the discounted cashflows of the lender are also considered in calculating the LGD. The EAD is the total amount of outstanding receivable at the reporting period.

These three components are multiplied together, and adjusted for forward looking information, such as crude oil prices, to arrive at a summed ECL in relation to base, optimistic and downturn scenarios, that carry different probability weightings.

Loss allowances for financial assets measured at amortised cost are deducted from the gross carrying amount of the related financial assets and the amount of the loss is recognised in the statement of comprehensive income.

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

Exceptional Items

Exceptional items are disclosed separately in the financial statements where it is necessary to do so to provide further understanding of the financial performance of the Group. They are material items of income or expense that have been shown separately due to the significance of their nature or amount.

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.

Foreign Currencies

The functional currency of the Group and the Company 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 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:

· 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 the 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.

Other Income

Other income relates to proceeds received from settlements and is only recognised in the statement of comprehensive income when it is virtually certain the economic benefits will flow to the Group.

Cost of Sales

Within the statement of comprehensive income, costs directly associated with generating revenue are included in cost of sales. The Group only capitalises costs as intangible assets once the legal right to explore an area has been obtained, any costs incurred prior to the date of acquisition are recognised as cost of sales within the statement of comprehensive income.

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 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 and do not consider it appropriate to disaggregate data further from that disclosed.

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

During 2020 and 2019 the Group had no turnover. During the 2019 year the Group did receive £750,000 from TEPUK in relation to TEPUK's termination of its 2013 farm-in to licence P2032 (Blocks 21/8c, 21/9c, 21/10c, 21/14a and 21/15b), which has been recognised in the Income Statement as Other Income.

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.

The Group also has a number of joint venture arrangements where co-venturers have made commitments to fund certain expenditure. Management evaluate the credit risk associated with each contract at the time of signing and regularly monitor the creditworthiness of our partners.

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 needs on the basis of suitability of the type of capital available at a given stage to the quantum required for that 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 to production then typically more debt is available.

The Group seeks to maintain progress in developing its assets in a timely fashion. Given the Group's current cash position is insufficient to progress its assets to first oil it will be seeking to bring an industry partner into its assets in return for a capital (equity) contribution. This may be in the form of either cash or payment of some or all the Group's development expenditures. As the development progresses towards first oil, debt becomes available and will be sought in order to enhance equity returns. JOG's debt today is 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.

The ratio of net debt to equity as at 31 December 2020 is Nil (2019: Nil).

Maturity analysis of financial assets and liabilities

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

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

The Director's remuneration is shown net of share-based payments.

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

Information regarding the highest paid Director is as follows:

The Directors did not exercise any share options during the year.

Key management compensation

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

6. OTHER INCOME

Settlement agreement with Total E&P UK Limited: Funds received from TEPUK in relation to TEPUK's termination of its 2013 farm-in to licence P2032, (Blocks 21/8c, 21/9c, 21/10c, 21/14a and 21/15b) received in May 2019.

7. NET FINANCE INCOME

8. LOSS BEFORE TAX

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

In December 2020 the Company reached a settlement with TGS-Nopec Geophysical Company ASA ("TGS") pursuant to an agreement entered into with TGS on 9 February 2018. Under the agreement, TGS claimed uplift payments from JOG totalling US$1,050,838 in respect of: a) licence awards to Jersey Petroleum Limited ("JPL") in the Oil & Gas Authority's 31st Supplementary Offshore Licencing Round; and b) the acquisition by JPL of Equinor UK Limited's 70% interest in Licence P2170 (Verbier). The company disputed the validity of both claims, following which two hearings took place in the Norwegian courts. Subsequent to these hearings and, on the basis of legal advice received, the Company agreed a final settlement payment to TGS of US$850,000 (£637,028).

9. TAX

Reconciliation of tax charge

No liability to UK corporation tax arose on ordinary activities for the year ended 31 December 2020 or for the year ended 31 December 2019.

In April 2023 the rate of corporation tax will increase to 25% as announced in the March 2021 Budget.

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 £46 million (2019: £39 million).

10. 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 their being no dilutive shares in the period.

11. INTANGIBLE ASSETS

During 2020, the Group acquired an additional 70% working interest in licence P2170 (Verbier). The consideration for the Acquisition consists of two milestone payments, which are considered contingent liabilities, (note 19) US$3 million upon sanctioning by the UK's Oil & Gas Authority ("OGA") of a Field Development Plan ("FDP") in respect of the Verbier Field; and US$5 million upon first oil from the Verbier Field. In addition to the existing 18% equity interest and retained 100% working interests in the licences awarded pursuant to the OGA's 31 SLR (2019), Licence P2498 (Buchan and J2), Licence P2499 (Glenn) and Licence P2497 (Zermatt). The Group was also awarded a 100% working interest in, and operatorship of, part-block 20/5e in the OGA's 32 Offshore Licensing Round in 2020. Part- block 20/5e is incorporated within Licence P2498 (Buchan & J2) and is located within the Group's existing Greater Buchan Area.

In line with the requirements of IFRS 6, we have considered whether there are any indicators of impairment on the exploration assets. Based on our assessment, as at 31 December 2020 there are not deemed to be indicators that the licences are not commercial and the carrying value of £14,991,295 continues to be supported by ongoing exploration work on the licence area with no further impairments considered necessary.

12. PROPERTY, PLANT AND EQUIPMENT

13. LEASES

Amounts Recognised in the Statement of financial position

On adoption of IFRS 16, the group recognised lease liabilities in relation to leases which had previously been classified as 'operating leases' under the principles of IAS 17, 'Leases'. These 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 2020 remained at 3% and the leases relate to office space.

At 1 January 2019 the group held no leases which required restating.

Amounts Recognised in the Statement of comprehensive income

14. TRADE AND OTHER RECEIVABLES

As at 31 December 2020 there were no trade receivables past due nor impaired. There are immaterial expected credit losses recognised on these balances.

15. CASH AND CASH EQUIVALENTS

The cash balances are placed with a creditworthy financial institution.

16. CALLED UP SHARE CAPITAL

17. TRADE AND OTHER PAYABLES

18. LEASE LIABILITIES

19. CONTINGENT LIABILITIES

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.

Equinor UK Limited: During the year (in January 2020), Jersey Oil Limited 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 consists of two milestone payments, which are considered contingent liabilities: US$3 million upon sanctioning by the UK's Oil & Gas Authority ("OGA") 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 2022.

ITOCHU Corporation and Japan Oil, Gas and Metals National Corporation: During the year (in November 2020) Jersey Oil Limited announced that it 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 consideration for the Acquisition includes 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 Oil & Gas Authority ("OGA") 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 Field Development Plan.

The earliest of the milestone payments in respect of the Acquisition is not currently anticipated being payable before the start of 2022.

20. SHARE BASED PAYMENTS

The Group operates a number of share option 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 shares that will eventually vest.

The Group's share option schemes are for Directors, Officers and employees. The charge for the year was £181,870 (2019: £437,080) and details of outstanding options are set out in the table below.

The weighted average fair value of options granted previously was determined using the 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 of 2%. The volatility measured at the standard deviation of continuously compounded share returns is based on a statistical analysis of daily share prices from the date of admission to AIM to the date of grant on an annualised basis. The weighted average exercise price for the options granted in 2019 was 182 pence, the weighted average remaining contractual life of the options was 5 years, the weighted average volatility rates was 62.86% and the dividend yield was nil. For schemes and scheme rules, please refer to the Remuneration Report.

There were adjustments made to the opening balance of share options due to 6,667 of the January 2018 issue of share options lapsing in 2019 and 40,000 of the November 2016 issue lapsed and then were re-issued in June 2019.

21. RELATED UNDERTAKINGS AND ULTIMATE CONTROLLING PARTY

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

Registered Offices

1. 10 The Triangle, ng2 Business Park, Nottingham, NG2 1AE

2. 6 Rubislaw Terrace, Aberdeen, AB10 1XE

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

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 2020

Year ended 2019

23. POST BALANCE SHEET EVENTS

Share options awards

On 28th January 2021, 250,000 share options were granted to employees (but not Directors) at an exercise price of 155p. These had been awarded in July 2020 but could not be granted until January 2021 due to multiple close periods.

On 18th March 2021, 330,000 share options were granted to Directors and 192,000 to employees at an exercise price of 210p (a premium of 15.7% to the previous day's middle market closing price). As a result, the total number of share options outstanding is 13% of issued share capital, well within the overall ten-year limit of 15% under the Share Option Scheme. Post the equity placing, directors subscription and offer for subscription completed in April 2021 the total number of share options outstanding as a percentage of issued share capital reduces to less than 9%.

Capital raise

In April 2021 JOG held a General Meeting where the following were approved by Shareholders:

The Offer for Subscription, announced as part of the Fundraising on 17 March 2021, closed for applications on 12 April 2021, the Company announced that valid applications were received from Qualifying Participants in respect of, in aggregate, 974,157 Offer Shares, representing approximately 80.36 per cent. of the Offer Maximum. Accordingly, pursuant to the Placing, Subscription and Offer announced on 17 March 2021 and further to the abovementioned, the Company issued 9,054,548 new Ordinary Shares (the "Placing Shares") pursuant to the Placing, 36,361 new Ordinary Shares (the "Subscription Shares") pursuant to the Subscription and 974,157 new Ordinary Shares pursuant to the Offer at a price of 165 pence per share. The Company raised total gross proceeds from the Fundraising of approximately £16.61 million (net proceeds £15.8m).

Completion of the CIECO V&C acquisition

On 7th April 2021 JOG completed its acquisition of the entire issued share capital of CIECO V&C (UK) Limited ("CIECO V&C"), owned by ITOCHU Corporation ("ITOCHU") and Japan Oil, Gas and Metals National Corporation ("JOGMEC"). The consideration for the acquisition consisted of a completion payment of £150,000 and two contingent payments based on the UK's Oil & Gas Authority's consent for a Field Development Plan and the potential future development and production of oil volumes from the Verbier discovery in the Upper Jurassic (J62-J64) Burns Sandstone reservoir located on Licence P2170 (Blocks 20/5b and 21/1d) ("Licence P2170"). The Acquisition provides JOG with an opportunity to create significant value through potentially developing the Verbier discovery as part of its planned Greater Buchan Area ("GBA") hub. Licence P2170 also benefits from multiple material exploration prospects that have high value potential through tie-backs to the proposed new GBA hub.

Appointment of non-executive director

On 13th April 2021, Les Thomas was appointed a non-executive director of the Company. The terms of his letter of appointment provide for a rolling contract with a notice period of three months, no compensation for loss of office and an annual fee of £40,000.

24. AVAILABILITY OF THE ANNUAL REPORT 2020

A copy of these results 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 10 The Triangle, ng2 Business Park, Nottingham NG2 1AE. 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.

COMPANY STATMENT OF FINANCIAL POSITION

As at 31 December 2020

As permitted by Section 408 of the Companies Act 2006, the Statement of Comprehensive Income of the parent Company is not presented as part of these financial statements. The parent Company's loss for the year was £1,083,379 (2019: Loss £1,471,705).

Vicary Gibbs Chief

Financial Officer

5 May 2021

Company Registration Number: 07503957

COMPANY STATEMENT OF CHANGES IN EQUITY

For the year ended 31 December 2020

COMPANY STATEMENT OF CASH FLOWS

For the year ended 31 December 2020

NOTES TO THE COMPANY FINANCIAL STATEMENTS

For the year ended 31 December 2020

1. SIGNIFICANT ACCOUNTING POLICIES

The separate financial statements of the Company are presented as required by the Companies Act 2006. As permitted by that Act, the separate financial statements have been prepared in accordance with International Financial Reporting Standards.

These financial statements have been prepared in accordance with international accounting standards in conformity with the requirements of the Companies Act 2006. The financial statements have been prepared on a going concern basis. The principal accounting policies adopted are consistent with those set out in note 2 to the consolidated financial statements. The financial risk management strategy for the Company is consistent with that set out in note 4 to the consolidated financial statements. These policies have been consistently applied to all the periods presented, unless otherwise stated.

Investments in subsidiaries are stated at cost less, where appropriate, provisions for impairment.

Going Concern

The Company is required to have sufficient resources to cover the expected running costs of the business for a period of at least 12 months after the issue of these financial statements. Further to the equity placing and offer for subscription concluded in April 2021 the Company has in a severe but plausible downside scenario surplus funds significantly in excess of the outstanding commitments to conclude the GBA Concept Select work programmes and the ongoing Operator overheads and licence fees beyond November 2022. The farm-out process launched in March 2021 to secure a new partner and material associated funding

to progress the GBA Project through FEED and to FID and beyond is expected to conclude in Q3 2021. Subject to securing suitable funding from this process development work will continue at pace. Delays to the farm-out process may serve to slow the pace of development and may delay the date at which the project achieves FID. Given JOG currently owns and operates 100% of project, the rate at which JOG may choose to progress the project is entirely within its control and hence the Company's current cash reserves are therefore expected to more than exceed its estimated liabilities. Based on these circumstances, the Directors have considered it appropriate to adopt the going concern basis of accounting in preparing the Company's financial statements.

Risk management

The Company'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 Company. 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 Company'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. Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company 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.

2. EMPLOYEES AND DIRECTORS

Other pension costs include employee and Company contributions to money purchase pension schemes. The average monthly number of employees during the year was as follows:

The Director's remuneration is shown net of share-based payments.

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

Information regarding the highest paid Director is as follows:

The Directors did not exercise any share options during the year.

Key management compensation

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

3. LOSS OF PARENT COMPANY

As permitted by Section 408 of the Companies Act 2006, the Statement of Comprehensive Income of the parent Company is not presented as part of these financial statements.

The parent Company's loss for the year was £1,083,379 (2019: Loss £1,471,705). Auditors' remuneration is disclosed in note 8 in the consolidated financial statements.

4. INVESTMENT IN SUBSIDIARIES

The carrying value of investments in subsidiary entities has been written off in prior periods.

The subsidiary undertakings at 31 December 2020 were as follows:

* Registered address: 10 The Triangle, ng2 Business Park, Nottingham, NG2 1AE

** Registered address: 6 Rubislaw Terrace, Aberdeen, AB10 1XE

*** Registered address: First Floor, Tower House, La Route es Nouaux, St Helier, Jersey, JE2 4ZJ

NOTES TO THE COMPANY FINANCIAL STATEMENTS

For the year ended 31 December 2020

5. PROPERTY, PLANT AND EQUIPMENT

6. LEASES

Amounts Recognised in the Statement of financial position

On adoption of IFRS 16, the Group recognised lease liabilities in relation to leases which had previously been classified as 'operating leases' under the principles of IAS 17, 'Leases'. These 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 2020 was 3%. The leases relate to office space.

Amounts Recognised in the Statement of comprehensive income

7. TRADE AND OTHER RECEIVABLES

The balances above were assessed for recoverability under the expected credit loss model. There is no expected credit loss on these balances. The amounts due from Group undertakings are not interest bearing, and are repayable on demand.

8. CASH AND CASH EQUIVALENTS

9. CALLED UP SHARE CAPITAL

Issued and fully paid:

10. TRADE AND OTHER PAYABLES

11. RELATED PARTY DISCLOSURES AND ULTIMATE CONTROLLING PARTY

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

The Company lends cash to Jersey Oil & Gas E&P Ltd to fund salaries and other administrative costs. The balance outstanding at the end of the year from Jersey Oil & Gas E&P Ltd £3,295,427 (2019: £2,371,207) has been fully provided for as a doubtful debt given the nature of the company which does not generate revenue and the balance is not expected to be recovered.

The Company provides funding to Jersey Petroleum Limited to fund commitments due on its operations and licences. Historically these have been provided for in full as those licences where not deemed commercial. Following the historical drilling on Verbier the Company believes that the funding provided for this licence to be fully recoverable as the licence is commercially viable. The total amount of funding provided to Jersey Petroleum Limited amounts to £83,452,410 (2019: £78,109,749) of which £69,800,211 (2019: 66,371,145) is provided for as a doubtful debt with the remaining balance being the funding provided in respect of the Verbier licence.

The receivable balance is non-interest bearing and repayable on demand with recovery expected over a number of years. During the year the Company also charged a management fee to Jersey Petroleum Limited amounting to £2,355,741 (2019:£1,414,327).

12. NOTES TO THE COMPANY STATEMENT OF CASH FLOWS

Reconciliation of loss before income tax to cash used in operations

Cash and cash equivalents

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

Year ended 2020

Year ended 2019