I3 Energy Regulatory News (I3E)

7 June 2023

i3 Energy plc

("i3", "i3 Energy", or the "Company")

Final Results for the year ended 31 December 2022

i3 Energy plc (AIM:I3E) (TSX:ITE), an independent oil and gas company with assets and operations in the UK and Canada, is pleased to announce the audited results for the year ended 31 December 2022. A copy of the Company's financial statements will be posted to shareholders and made available shortly on the Company's website at https://i3.energy. The Notice of Annual General Meeting ("AGM") will be posted in due course. The AGM will be held at 11:00 am BST on 30th June 2023 at the offices of WH Ireland Limited at 24 Martin Lane, London, EC4R 0DR.

2022 Financial, Reserves & PRODUCTION Highlights

(1) Non-IFRS measure. Refer to Appendix B

2022 Achievements

Organic Production Growth Delivering Record Production

· Four quarters of production growth with peak daily rates exceeding 24,000 barrels of oil equivalent per day ("boepd").

Shareholder Return

· Increased dividends declared from £3.4 million in 2021 to £17.4 million in 2022 and announced 2023 dividend guidance of £24.5 million (2.052 pence / share).

Capital Program

· £75.8 million capital expenditure in 2022 delivered 31 gross (20.1 net) wells.

· Increased the Group's leasehold position to 628,000 net acres.

· Aggregate well productivity met or exceeded management expectation and key wells drilled in strategic Simonette and Clearwater acreage.

· Through participation in land sale auctions, farm-ins and joint ventures, and partner consolidation, i3 has grown its acreage in the strategic Clearwater play to greater than 69,600 acres (109 sections) with an average working interest of 76%

· Farmed out 25% of the Serenity licence to Europa who paid 46.25% of the Serenity 13/23c-12 appraisal well costs. The well was drilled in October 2022. The company is evaluating one well development options.

Reserves Growth

· Our 2022 capital program helped to increase Proved plus Probable reserves ("2P") by 18% to 182 Million Barrels of Oil Equivalent ("mmboe"), resulting in reserves replacement of 479% on a 2P basis.

· The Group now has 376 gross booked drilling locations in its audited reserves and 940 including un-booked locations.

ESG Performance

· Published inaugural annual ESG Report.

· Eliminated all high-bleed pressure controllers and commenced installation of solar powered pumps. These initiatives when complete will eliminate 71,450 tonnes CO2e methane emissions equivalent to taking circa 16,000 cars off the road.

· Completed the electrification of 7 pumpjacks in Carmangay and Retlaw to reduce use of diesel and propane for power generation, with a further 29 electrifications underway.

· Implemented efficient disposal of oil based drilling fluid, avoiding 2,500 tonnes of CO2e emissions.

· Ongoing annual abandonment and reclamation program abandoned 69 wells and decommissioned 37 well sites, representing approximately 14% of operated non-producing wells.

Outlook

A summary of key events which occurred after the reporting period are presented in note 24 to the financial statements and includes the announcement on 31 May 2023 of the successful redemption of the Company's outstanding £22 million H1-2019 Loan Notes (the "Loan Notes"), due 31 May 2023, and the establishment of a CAD 100 million debt facility, which will provide i3 greater financial flexibility and enhanced credit capacity to further execute its ongoing business plan. The Company's focus for the remainder of 2023 will be on three key areas:

1 The growth of i3's Canadian business through the deployment of capital into its large proven undeveloped reserves base, operational excellence to improve uptime and field performance, and strategic upsizing in core areas;

2 Maintaining flexibility to adapt to economic challenges while maximizing total shareholder return; and

3 Conducting its operations safely and in an environmentally secure manner.

The Company continuously evaluates opportunities to strengthen its balance sheet whilst maintaining tight control of its costs and working capital position.

Majid Shafiq, CEO of i3 Energy plc, commented:

"Following an active period of acquisitions over the course of 2020 and 2021, 2022 was a period of consolidation and organic growth. Our most recent significant acquisition in Q3 2021 of circa 8,400 boepd in our core Central Alberta area from Cenovus Energy, was integrated into our Canadian business and operational and organisational efficiencies implemented across our entire portfolio. Commodity price strength in the second half of 2021 led us to pivot from growth via acquisitions to organic growth through the exploitation of our extensive inventory of drilling locations and in January 2022 we commenced our inaugural operated drilling program with an announced USD47 million budget. Based on the positive results from the wells drilled in Q1 2022, the Canadian capex program was expanded to circa USD90 million and during the course of the year we drilled a total of 20.1 net wells in Canada. The program was very successful with all wells meeting or exceeding management expectations in terms of production performance and costs versus budget. In conjunction with an extensive workover program the new wells contributed to the achievement of our stated goal of reaching 24,000 boepd before the end of the year and also to a very positive year end reserves audit which resulted in an 18% increase in our booked 2P reserves and a 479% increase in our reserves replacement ratio on a 2P basis. In the UK, a farmout of the Serenity appraisal well allowed the company to significantly reduce its capital exposure and the well was successfully drilled to complete the appraisal of the field. The potential for a single well development is being evaluated.

2022 also saw the publication of our maiden ESG report and we are very pleased that activities throughout the year saw significant reductions in CO2e emissions as we began to implement methane emission reduction initiatives. We continued to deliver on our total shareholder return model, as we balanced our production growth with increased cash returns to investors with an expanded dividend program which saw over £17.4 million in dividends being declared during the year.

The first half of 2023 has seen continued operational and commercial activity. Our 2023 capital program has commenced with the pre-spring break component completed and we are very pleased to have repaid our outstanding debt and established a new CAD100 million loan facility, which validates the quality and scale of our reserves base in Canada.

All of this was possible due to the expertise and commitment of our staff in Canada and the UK and I would like to thank them for their continued efforts and all our investors and shareholders for their continued support. We look forward to another successful year as we navigate the operational and business challenges that lay ahead with continued dedication and hard work".

AIM Application - Correction

i3 also announces that, further to the announcement on 17 May 2021, 5,277,045 ordinary shares ("Ordinary Shares") were issued to Baker Hughes, a GE company (GE Oil & Gas UK Limited and Baker Hughes collectively referred to hereafter as "BHGE") in relation to warrants exercised and these were not admitted to trading on AIM at that time. An application will be made for the Ordinary Shares to be admitted to trading on AIM and are expected to be admitted on 13 June 2023.

The Ordinary Shares rank pari passu with the existing Ordinary Shares, including the right to receive all dividends and other distributions declared after the date of issue.

Following Admission of the Ordinary Shares, the Company's issued share capital will though remain the same as previously reported at 1,201,874,464 Ordinary Shares with a nominal value of £0.0001 each. Shareholders may use this figure of ordinary shares as the denominator by which they are required to notify their interest in, or change their interest in, the Company under the Disclosure Guidance and Transparency Rules.

Qualified Person's Statement

In accordance with the AIM Note for Mining and Oil and Gas Companies, i3 discloses that Majid Shafiq is the qualified person who has reviewed the technical information contained in this document. He has a Master's Degree in Petroleum Engineering from Heriot-Watt University and is a member of the Society of Petroleum Engineers. Majid Shafiq consents to the inclusion of the information in the form and context in which it appears.

Enquiries:

Notes to Editors:

i3 Energy is an oil and gas Company with a low cost, diversified, growing production base in Canada's most prolific hydrocarbon region, the Western Canadian Sedimentary Basin and appraisal assets in the North Sea with significant upside.

The Company is well positioned to deliver future growth through the optimisation of its existing 100% owned asset base and the acquisition of long life, low decline conventional production assets.

i3 is dedicated to responsible corporate practices and the environment, and places high value on adhering to strong Environmental, Social and Governance ("ESG") practices. i3 is proud of its performance to date as a responsible steward of the environment, people, and capital management. The Company is committed to maintaining an ESG strategy, which has broader implications for long-term value creation, as these benefits extend beyond regulatory requirements.

i3 Energy is listed on the AIM market of the London Stock Exchange under the symbol I3E and on the Toronto Stock Exchange under the symbol ITE. For further information on i3 Energy please visit https://i3.energy/.

This announcement contains inside information for the purposes of Article 7 of the UK version of Regulation (EU) No 596/2014 which is part of UK law by virtue of the European Union (Withdrawal) Act 2018, as amended ("MAR"). Upon the publication of this announcement via a Regulatory Information Service, this inside information is now considered to be in the public domain

Chairperson's and Chief Executive's Statement

Following its very successful entry into Canada through M&A and the aggregation of a significant portfolio of development assets over the course of 2020 and 2021, the strengthening of oil and gas prices in 2021 resulted in a shift of strategy for the Company to focus on internally generated growth through the exploitation of its extensive portfolio of development drilling locations.

In January 2022, i3 embarked on its inaugural drilling campaign in Canada. The Company announced in December 2021 an internally funded USD 47 million programme of drilling which was designed to drill 17 gross wells (12.6 net) across its key assets. The programme was designed to maximize near-term production and cash flow through further development of the Company's large inventory of predictable and highly economic Glauconite locations in Central Alberta, while continuing to advance i3's high-impact Simonette Montney position and recently expanded Clearwater holdings. The program was expected to add incremental peak production of 5,250 boepd and result in average 2022 production of over 20,000 boepd while testing and advancing important growth catalysts in its portfolio. Based on the very positive results of the wells drilled in the first quarter, the Company's strong operational performance and the forecasted strength of commodity prices, the Company decided in May to expand its program with an additional US$50 million of capital. The revised capital budget was forecast to provide peak production above 24,000 boepd by year end. 

We are very pleased that the drilling programme was executed under budget and the aggregate well performance met management expectations. In total, i3's 2022 drilling programme delivered 31 gross (18.4 net) wells and was executed circa 5% under budget with excellent capital efficiencies, which was a major achievement considering the highly inflationary environment the Company and its industry peers were challenged with. Such success was achieved by a strong focus on operational efficiency and cost control and is a testament to the dedication and skills of all our staff. In addition to production wells in our Core Central Alberta and Wapiti areas, key development and delineations wells were drilled in our growth assets in Simonette (in the Montney formation) and Marten Hills (in the Clearwater formation), and production data from these wells will help us plan for future expansion in these areas.

The very successful drilling campaign allied with an extensive suite of regular workovers, reactivations and a focus on uptime and operational efficiencies resulted in a continuation of production growth since our entry into Canada. The company entered the year at circa 18,000 boepd and reached 24,000 boepd in December, with a Q4 average production level of 22,757 boepd.

Although our focus in 2022 was on production growth, the drilling campaign targeted locations that would advance the development of strategic assets in our Simonette Montney and Clearwater assets. We also significantly grew our exposure to the Clearwater play through a series of strategic transactions including successful bids at Alberta Crown Land Sales, joint ventures, farm-in agreements and partner consolidation. This activity has grown our Clearwater land position by circa 120% to 109 net sections (279 km2) from the 50 net sections (128 km2) acquired as part of the Company's first transaction in Canada, the Toscana acquisition in 2020.

The Company's year end 2022 audited reserves reflect the successful reservoir management of ongoing operations and the results of the 2022 drilling program. The Company offset production declines and increased its Proven Developed Producing (PDP), Total Proved (1P) and Proved plus Probable (2P) reserves to 49.1 mmboe, 93.5 mmboe and 181.5 mmboe respectively. Relative to year end 2021 the Company's PDP, P1 and 2P reserves increased by 6%, 10% and 19% respectively. This was a significant result and achieved with positive revisions to existing reserves and reserves adds from new development drilling locations. The scale and longevity of our asset portfolio is demonstrated by a reserves life index of 22.5 years for the Company's 2P reserves.

Our 2022 drilling program and subsurface technical work has contributed to an increase in the Company's total inventory to 940 gross (537 net) drilling locations of which only 376 gross (255 net) are booked in the year end 2022 reserves report. A significant proportion of these un-booked drilling locations are located in Simonette, Wapiti and our Clearwater acreage, which illustrate the organic growth potential in these assets. Together the booked and un-booked drilling locations provide for multiple years of future drilling activity and production growth.

In the UK, we farmed out 25% of our Serenity discovery to Europa Oil and Gas Limited in return for a 1.85 for 1 carry, resulting in the reduction of our drilling capex share from 100% to 53.75%. The well was drilled in October but unfortunately the targeted sand was not found at the appraisal well location and consequently in place hydrocarbon volumes are much lower than originally estimated. Updated mapping of the field around the 13/23-10 discovery well, shows there is the potential for a single well development, for which development and monetization options are being evaluated. The well was drilled significantly below budget resulting in a net cost to the Company of USD 5.7 million.

Based on the success of our 2022 drilling campaign and our budget commodity price forecasts, the Company announced its 2023 capital budget and drilling programme on 22 December 2022. The Company plans to spend USD 64.05 million focussed on a drilling campaign on its Canadian assets. Similar to the 2022 programme, the drilling targets production wells in our key assets in Central Alberta, Simonette, Wapiti and the Clearwater with an additional element of Clearwater appraisal wells in our legacy acreage (acquired via the Toscana acquisition) and an earn-in appraisal well in our non-operated asset base. In total the 2023 programme is scheduled to deliver 23 gross wells (15.2 net, 70% net i3 operated). Based on the expected performance of these wells, forecast 2023 annual production is expected to be in the range of 22,250 to 23,000 boepd, representing a year-over-year increase of approximately 10% to 13%, with an expected peak production rate in 2023 of approximately 26,000 boepd. Our budget allocation to the UK is limited to USD 0.6 million, which will be used to advance the Serenity one well development to field development plan stage. The Canadian drilling programme for Q1 2023 has been completed with wells being equipped and tied into production facilities for clean-up. Drilling operations will recommence in Q3 2023 when surface conditions allow operations, following the Spring seasonal wet period.

We continue to actively identify production optimisation and cost reduction opportunities within our portfolio, focussing on maintaining high uptime, minimising operating costs, optimising operated processing facilities and infrastructure, and implementing high return workovers to offset natural production declines. These efforts continue to increase aggregate average net production and substantially reduce the decline rates predicted within the Company's competent persons reports. This is a testament to the quality of the assets in the portfolio and the dedication of our workforce. In parallel with operational activity, we continue to review the reservoir performance of the producing assets and identify mature fields where redevelopment, particularly through the implementation of relatively low-cost secondary recovery projects, could materially increase production and ultimate hydrocarbon recovery. Operating our assets in a safe and secure manner is fundamental to our business and we continue to advance our health and safety policies and procedures as we acquire and integrate additional production assets. There were 101 routine regulatory government inspections during 2022. 75 returned satisfactory results, 20 were categorised as low risk, and six that were deemed to be high risk were subsequently remedied.

Financial Discipline

The Board and Management are focused on delivering consistent value to shareholders. i3 is committed to its total shareholder return model which allies production and asset value growth with a progressively growing dividend and protects this commitment through a conservative hedging program. The Company has and continues to keep a substantial portion of its production hedged through risk management contracts to manage commodity price risk, with free cash post dividend payments deployed to either acquire production assets or develop our proven undeveloped (PUD) and 2P inventory dependent on which option delivers higher returns in the prevailing commodity price environment. As i3 continues to grow its portfolio, a proportion of all incremental production will be hedged in order to secure future cash flows, and the Company will remain commercial in monetising assets when third-party interest warrants consideration.

With the well-timed acquisitions and capital deployment of the last 30 months, the Company's assets have continued to outperform the Directors' expectations. As per our commitment to those shareholders who funded our entry to and growth in Canada, and as part of our total shareholder return model, we commenced paying a dividend in 2021 and have grown that year-on-year from £3.4 million in 2021, to £15.4 million in 2022 and plan to pay dividends of £24.5 million in 2023.

Operational flexibility and the short-term nature of forward capital commitments in Canada mean that the Company has considerable optionality to rapidly expand or reduce its capital programme to prudently manage its balance sheet to ensure risks are appropriately mitigated in volatile commodity markets.

Governance

The Board recognises its responsibility for the proper management of the Company and is committed to maintaining a high standard of corporate governance. The Directors also recognise the importance of sound corporate governance commensurate with the size and nature of the Company and the interests of its shareholders. The Quoted Companies Alliance has published a set of corporate governance guidelines for AIM companies, which include a code of best practice comprising principles intended as a minimum standard, and recommendations for reporting corporate governance matters. The Directors comply with the QCA Corporate Governance Guidelines for Smaller Quoted Companies so far as it is practicable having regard to the size and current stage of development of the Company. The Board currently comprises two Executive Directors (being the Chief Executive Officer and the President Canada) and four Non-Executive Directors (including the Chairperson).

The Board's decision-making process is not dominated by any one individual or group of individuals. The composition of the Board will be reviewed regularly and modified as appropriate in response to the Company's changing requirements. The Board has established an Audit and Risk Committee, Corporate Governance Committee, Health, Safety, Environment and Security Committee, Reserves Committee, and Remuneration Committee to ensure proper adherence to sound governance and decision making.

Environmental Stewardship

i3 is fortunate to operate in the UK and Canada which have some of the world's most stringent and rigorous environmental laws and regulations and the Company strives to meet or exceed all local, provincial or national operational, environmental, reporting and compliance obligations and abandonment and reclamation requirements. The Company is committed to conducting its operations responsibly and in accordance with industry best practices. i3's commitment to high ESG standards is central to maintaining our social licence to operate, creating value for all stakeholders, and ensuring long-term commercial success. i3 recognises the safety and well-being of our employees, local communities, and other key stakeholders as a priority, and considers climate change as having a material impact on our business.

To demonstrate the Company's commitment to long-term sustainable resource development, environmental stewardship and the well-being of employees and the communities in which i3 operates, i3 published its inaugural annual ESG report in July 2022. The ESG report set out the Company's goals and ambitions with respect to greenhouse gas emission reductions, environmental stewardship, social policies and governance. i3 published an updated ESG report in December 2022, which included disclosure on the assets acquired from Cenovus Energy in 2021. This data was not available when the inaugural report was published in July 2022.

The Company made big strides in 2022 to reduce methane emissions. After completing the upgrading of high bleed pneumatic controllers to low bleed or non-bleed alternatives across its portfolio, the Company commenced replacement of pneumatic pumps with solar driven pumps (no venting). These initiatives have resulted in a decrease of 71,450 tonnes of CO2e/year, which is the equivalent of removing 15,530 cars from the road per year. i3 also completed the electrification of 30 pumpjacks in its Carmangay and Retlaw properties, reducing CO2e emissions by approximately 6,366 tonnes/year. The Company further partnered with Recover Energy Services ("Recovery") to manage the efficient disposal of oil-based drilling waste and as determined by Recovery, avoided 2,500 metric tonnes of CO2e emissions. Similar initiatives will continue in 2023 as we continue to reduce the carbon intensity of our production base. These CO2e emissions reductions qualify for carbon credits which can be sold or used to offset future carbon tax obligations.

i3 also takes its abandonment and reclamation obligations very seriously and in 2022 it abandoned a total of 69 wells and decommissioned 37 well sites, representing approximately 14% of its operated non-producing well stock. In 2023, and in accordance with the Alberta Energy Regulator's decommissioning guidance, i3 expects to deliver a similar number of abandonment operations as achieved in 2022.

Looking ahead

The Company looks forward to executing a successful drilling program in Canada in 2023, growing production and returning cash to shareholders and so delivering on its total shareholder return model.

Looking beyond 2023, we have a high quality and diverse asset portfolio in Canada with immense unrealized upside potential. We will continue to focus our efforts on advancing these key assets to efficient and rapid commercialisation and value crystallisation. We will selectively target key assets and wells to optimise these developments and conversion of resources to reserves bookings. We are fortunate that we operate the vast majority of our assets which allows us to control the timing and pace of development. We also own high working interests in our operated assets which also provides us with optionality on how to finance these developments.

Whilst our current focus is on organic growth, we recognise that commodity price volatility and resulting market dislocations will provide opportunities to grow through low-cost mergers and acquisitions and we remain vigilant to take advantage of these opportunities as and when they arise.

We are committed to operating in a safe and socially responsible manner and the safety of our employees and contractors is of primary importance. We are proud of our green house gas emission reduction initiatives and achievements in 2022 and we will endeavour to deliver year-on-year reductions in the carbon intensity of our production.

As always, we extend gratitude to our shareholders for their ongoing support and to our employees for their relentless commitment to making i3 a success. Though we operate within a macro environment that is beyond our control, we believe we are doing the right things to create a very valuable business that can weather good times and bad.

i3 will continue to manage our Canadian and UK businesses in a manner that maximizes value creation and distributed returns.

Consolidated Statement of Comprehensive Income

All operations are continuing.

The accompanying notes form an integral part of these financial statements.

Consolidated Statement of Financial Position

The accompanying notes form an integral part of these financial statements.

The consolidated financial statements of i3 Energy plc, company number 10699593, were approved by the Board of Directors and authorised for issue on 6 June 2023. Signed on behalf of the Board of Directors by:

Majid Shafiq

Director

Consolidated Statement of Changes in Equity

The accompanying notes form an integral part of these financial statements.

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

Note: The issued share capital comprises of both ordinary and deferred shares and the consolidated nominal value exceeds the required minimum issued capital of £50,000.

Consolidated Statement of Cash Flow

Included within cash and cash equivalents is £354 thousand of restricted cash, which relates to guarantees for product marketing. Non-current accounts payables reconciliation is show in note 15 and the debt reconciliation is shown in note 16.

The accompanying notes form an integral part of these financial statements.

Notes To the Group Financial Statements

1 General information

i3 Energy plc ("the Company") is a Public Company, limited by shares, registered in England and Wales under the Companies Act 2006 with registered number 10699593. The Company's ordinary shares are traded on the Toronto Stock Exchange and the AIM Market operated by the London Stock Exchange. The address of the Company's registered office is New Kings Court, Tollgate, Chandler's Ford, Eastleigh, Hampshire, SO53 3LG.

The Company and its subsidiaries (together, "the Group") principal activities consist of oil and gas production in Western Canadian Sedimentary Basin and of the appraisal of oil and gas assets on the UK Continental Shelf.

2 Basis of preparation

The financial statements of i3 Energy plc have been prepared in accordance with UK-adopted international accounting standards in accordance with the requirements of the Companies Act 2006 and in accordance with the requirements of the AIM rules.

The consolidated financial statements have been prepared under the historical cost convention, as modified by the financial assets and financial liabilities (including derivative instruments) at fair value through profit or loss.

The financial information is presented in Pounds Sterling (£, GBP), which is the Company's functional currency, and rounded to the nearest thousand unless otherwise stated. The functional currency of the Company's UK subsidiary, i3 Energy North Sea Limited, is GBP, and the functional currency of its Canadian subsidiary, i3 Energy Canada Limited, is CAD. A summary of period-average and period-end exchange rates is presented in the table below:

The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied unless otherwise stated.

Basis of Consolidation

The consolidated financial statements consolidate the audited financial statements of i3 Energy plc and the financial statements of its subsidiary undertakings made up to 31 December 2022.

Subsidiaries are entities over which the Group has control. The Group controls an entity when the Group is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are de-consolidated from the date that control ceases.

When necessary, adjustments are made to the financial statements of subsidiaries to bring their accounting policies into line with the Group's accounting policies. All intra-group assets and liabilities, equity, income, expenses, and cash flows relating to transactions between members of the Group are eliminated in full on consolidation.

Going concern

The Directors have, at the time of approving the financial statements, a reasonable expectation that the Company and the Group have adequate resources to continue in operational existence for the foreseeable future. Thus, they continue to adopt the going concern basis of accounting in preparing the financial statements. The use of this basis of accounting takes into consideration the Group's current and forecast financing position, additional details of which are provided in the going concern section of the Directors' Report.

3 Significant accounting policies

Financial instruments

Cash and cash equivalents

Cash and cash equivalents comprise cash on hand and cash held on current account or on short-term deposits at variable interest rates with original maturity periods of up to three months. Any interest earned is accrued monthly and classified as interest income within finance income.

Trade and other receivables

Trade and other receivables are initially recognised at fair value when related amounts are invoiced then carried at this amount less any impairment of these receivables using the expected credit loss model. A provision for impairment is made when there is objective evidence (such as the probability of insolvency or significant financial difficulties of the debtor) that the Company will not be able to collect all of the amounts due under the original terms of the invoice. The carrying amount of receivables is reduced through use of an allowance account. Impaired debts are derecognised when they are assessed as uncollectible.

Trade and other payables

These financial liabilities are all non-interest bearing and are initially recognised at the fair value of the consideration payable.

Loan Notes

These financial liabilities are all interest bearing and are initially recognised at amortised cost and include the transaction costs directly related to the issuance. The transaction costs are amortised using the effective interest rate method over the life of the Loan Notes.

Financial liabilities at Fair Value Through Profit or Loss ("FVTPL")

Financial liabilities at FVTPL comprise of the Group's risk management contracts and non-current accounts payable. Financial liabilities are classified as at FVTPL when the financial liability is (i) contingent consideration that may be paid by an acquirer as part of a business combination to which IFRS 3 applies, (ii) held for trading, or (iii) it is designated as at FVTPL.

A financial liability is classified as held for trading if:

· it has been incurred principally for the purpose of repurchasing it in the near term; or

· on initial recognition it is part of a portfolio of identified financial instruments that the Company manages together and has a recent actual pattern of short-term profit-taking; or

· it is a derivative that is not designated and effective as a hedging instrument.

A financial liability other than a financial liability held for trading or contingent consideration that may be paid by an acquirer as part of a business combination may be designated as at FVTPL upon initial recognition if:

· such designation eliminates or significantly reduces a measurement or recognition inconsistency that would otherwise arise; or

· the financial liability forms part of a group of financial assets or financial liabilities or both, which is managed, and its performance is evaluated on a fair value basis, in accordance with the Company's documented risk management or investment strategy, and information about the grouping is provided internally on that basis; or

· it forms part of a contract containing one or more embedded derivatives, and IFRS Financial Instruments: Recognition and Measurement permits the entire combined contract (asset or liability) to be designated as at FVTPL.

Financial liabilities at FVTPL are stated at fair value, with any gains or losses arising on re-measurement recognised in profit or loss. The net gain or loss recognised in profit or loss incorporates any interest paid on the financial liability and is included in the 'other gains and losses' line item in the consolidated statement of comprehensive income.

Risk management contracts

Financial risk management contracts are measured and recognised in accordance with the Group's accounting policy for financial liabilities at FVTPL as described above. Physical risk management contracts represent physical delivery sales contracts in the ordinary course of business and are therefore not recorded at fair value in the consolidated financial statements. Settlements on these physical risk management contracts are recognised within realised gains or losses on risk management contracts at the time of settlement.

Embedded derivatives

Derivatives embedded in other financial instruments or other host contracts are treated as separate derivatives when their risks and characteristics are not closely related to those of the host contracts and the host contracts are not measured at FVTPL.

Leases

Lease liabilities are initially measured at the present value of lease payments unpaid at the commencement date. Lease payments are discounted using the incremental borrowing rate (being the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions) unless the rate implicit in the lease is available. The Group currently uses the rate implicit in the lease as the discount rate for all leases. For the purposes of measuring the lease liability, lease payments comprise fixed payments.

Right-of-use assets are measured at cost, which comprises the initial measurement of the lease liability, plus any lease payments made prior to lease commencement, initial direct costs incurred and the estimated cost of restoration or decommissioning, less any lease incentives received. The right-of-use assets is depreciated on a straight-line basis over their expected useful lives. Right-of-use assets are subject to an impairment test if events and circumstances indicate that the carrying value may exceed the recoverable amount.

Lease repayments made are allocated to capital repayment and interest so as to produce a constant periodic rate of interest on the remaining lease liability balance.

Right-of-use assets are presented within property, plant, and equipment. Lease liabilities are presented within borrowings and leases. In the cash flow statement, lease repayments (both the principal and interest portion) are presented within cash used in financing activities, except for payments for leases of short-term and low-value assets and variable lease payments, which are presented within cash flows from operating activities.

Leases of low-value items (such as office equipment) and short-term leases (where the lease term is 12 months or less) are expensed on a straight-line basis to the consolidated statement of comprehensive income.

Inventory

Inventories comprise oil and gas in tanks and field parts and supplies, all of which are stated at the lower of production cost (including royalties, depletion and amortisation of plant, property, and equipment), and net realisable value. Net realisable value is the estimated selling price in the ordinary course of business less marketing costs. The cost of inventory is expensed in the period in which the related revenue is recognised.

Equity

Equity instruments issued by the Company are usually recorded at the proceeds received, net of direct issue costs, and allocated between called up share capital and share premium accounts as appropriate.

Foreign currency

Transactions denominated in currencies other than functional currency are translated at the exchange rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are re-translated at the rate of exchange ruling at the balance sheet date. All differences that arise are recorded in the consolidated statement of comprehensive income. The functional currency of the Company is GBP, and the Group results and financial position are presented in GBP.

For the purpose of presenting consolidated financial statements, the assets and liabilities of the Group's foreign operations are translated at exchange rates prevailing on the reporting date. Income and expense items are translated at the average exchange rates for the period, unless exchange rates fluctuate significantly during that period, in which case the exchange rates at the date of transactions are used. Exchange differences arising, if any, are recognised in other comprehensive income and accumulated in a separate component of equity (attributed to non‑controlling interests as appropriate).

Taxation

Tax is recognised in profit or loss, except to the extent that it relates to items recognised in other comprehensive income or directly in equity. In this case, the tax is also recognised in other comprehensive income or directly in equity respectively.

Deferred tax is accounted for using the balance sheet liability method in respect of temporary differences arising from differences between the carrying amount of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit. However, deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill; deferred tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss.

In principle, deferred tax liabilities are recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profit will be available against which deductible temporary differences can be utilised.

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and associates, and interests in joint ventures, except where the Company is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.

Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets against current tax liabilities and when the deferred tax assets and liabilities relate to taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the balances on a net basis.

Deferred tax is calculated at the tax rates that are expected to apply to the period when the asset is realised or the liability is settled. Deferred tax assets and liabilities are not discounted.

Intangible assets - Exploration and evaluation expenditures (E&E)

Development expenditure

Expenditure on the construction, installation, and completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including service, is capitalised initially within intangible fixed assets and when the well has formally commenced commercial production, then it is transferred to property, plant and equipment and is depreciated from the commencement of production as described in the accounting policy for property, plant and equipment.

Drilling costs and intangible licences

The Group applies the successful efforts method of accounting for oil and gas assets, having regard to the requirements of IFRS 6 'Exploration for and Evaluation of Mineral Resources'. Costs incurred prior to obtaining the legal rights to explore an area are expensed immediately to the consolidated statement of comprehensive income.

Expenditure incurred on the acquisition of a licence interest is initially capitalised within intangible assets on a field-by-field basis. Costs are held, unamortised, within Petroleum mineral leases until such time as the exploration phase of the field area is complete or commercial reserves have been discovered. The cost of the licence is subsequently transferred into property, plant and equipment and depreciated over its estimated useful economic life.

Exploration expenditure incurred in the process of determining exploration targets is capitalised initially within intangible assets as drilling costs. Drilling costs are initially capitalised on a well-by-well basis until the success or otherwise has been established. Drilling costs are written off on completion of a well unless the results indicate that hydrocarbon reserves exist and there is a reasonable prospect that these reserves are commercially viable. Drilling costs are subsequently transferred into 'Drilling expenditure' within property, plant and equipment and depreciated over their estimated useful economic life.

Impairment

The Group assesses at each reporting date whether there is an indication that an asset may be impaired. This includes consideration of the IFRS 6 impairment indicators for any intangible exploration and evaluation expenditure capitalised as intangible assets. Examples of indicators of impairment include whether:

(a) the period for which the entity 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 mineral resources in the specific area is neither budgeted nor planned.

(c) exploration for and evaluation of mineral resources in the specific area have not led to the discovery of commercially viable quantities of mineral resources 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.

If any such indication exists, or when annual impairment testing for an asset is required, the Group makes an estimate of the asset's recoverable amount, which is the higher of its fair value less costs to sell and its value in use. Any impairment identified is recorded in the consolidated statement of comprehensive income.

Property, plant and equipment

Oil and gas assets - cost

Oil and gas assets are accumulated generally on a cost generating unit (CGU) basis and represent the cost of developing the commercial reserves discovered and bringing them into production, together with the intangible exploration and evaluation asset expenditures incurred in finding commercial reserves transferred from intangible exploration and evaluation assets. The cost of oil and gas properties also includes the cost of directly attributable overheads, borrowing costs capitalised and the cost of recognising provision for future restoration and decommissioning.

Oil and gas assets - depreciation and depletion

Oil properties, including certain related pipelines, are depreciated using a unit-of-production method. The cost of producing wells is amortised over proved plus probable reserves. Licence acquisition, common facilities and future decommissioning costs are amortised over total proved plus probable reserves. The unit-of-production rate for the depreciation of common facilities takes into account expenditures incurred to date, together with estimated future capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be processed through these common facilities.

Oil and gas assets - impairment

An impairment test is performed whenever events and circumstances arising during the development or production phase indicate that the carrying value of an oil and gas property may exceed its recoverable amount.

The carrying value is compared against the expected recoverable amount of the asset, generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves. The cash-generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped as a single cash-generating unit where the cash inflows of each field are interdependent.

Any impairment identified is charged to the statement of comprehensive income. Where conditions giving rise to impairment subsequently being reversed, the effect of the impairment charge is also reversed as a credit to the statement of comprehensive income, net of any depletion that would have been charged since the impairment.

Non-oil and gas assets

Property, plant and equipment is stated at cost less accumulated depreciation and any accumulated impairment losses. Depreciation is provided on all property, plant, and equipment to write off the cost less estimated residual value of each asset over its expected useful economic life on a straight-line basis at the following annual rates:

· Office equipment - 20% or straight line over the life of the equipment, whichever is the lesser

· Field equipment - between 5% and 25%

All assets are subject to annual impairment reviews where indicators of impairment are present.

Property, plant, and equipment - disposals

An item of property, plant and equipment is derecognised upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. The gain or loss arising on the disposal or retirement of an asset is determined as the difference between the sales proceeds and the carrying amount of the asset and is recognised in profit or loss.

Decommissioning provision

Liabilities for decommissioning costs are recognised when the Group has an obligation to plug and abandon a well, dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reliable estimate of that liability can be made. Where an obligation exists for a new facility or item of plant, such as oil production or transportation facilities, this liability will be recognised on construction or installation. Similarly, where an obligation exists for a well, this liability is recognised when it is drilled. An obligation for decommissioning may also crystallise during the period of operation of a well, facility or item of plant through a change in legislation or through a decision to terminate operations; an obligation may also arise in cases where an asset has been sold but the subsequent owner is no longer able to fulfil its decommissioning obligations, for example due to bankruptcy. The amount recognised is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. The provision for the costs of decommissioning wells, production facilities and pipelines at the end of their economic lives is estimated using existing technology, at future prices, depending on the expected timing of the activity, and discounted using a risk-free rate.

An amount equivalent to the decommissioning provision is recognised as part of the corresponding intangible asset (in the case of an exploration or appraisal well) or property, plant, and equipment. The decommissioning portion of the property, plant and equipment is subsequently depreciated at the same rate as the rest of the asset. Other than the unwinding of discount on or utilisation of the provision, any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding asset where that asset is generating or is expected to generate future economic benefits. If government assistance is obtained to reduce the liability, the carrying value of the decommissioning provision and the corresponding E&E or PP&E asset are reduced by the estimated amount of the extinguished liability.

Joint operations

The majority of the Group's exploration and production activities are conducted jointly with others and, accordingly, these consolidated financial statements reflect only the Group's interest in such activities.

Revenue

Revenue from contracts with customers is recognised, net of royalties, when or as the Group satisfies a performance obligation by transferring control of a promised good or service to a customer. The transfer of control of oil, natural gas, natural gas liquids and petroleum, and other items usually coincides with title passing to the customer and the customer taking physical possession. The Group principally satisfies its performance obligations at a point in time; the amounts of revenue recognised relating to performance obligations satisfied over time are not significant.

When, or as, a performance obligation is satisfied, the Group recognises as revenue the amount of the transaction price that is allocated to that performance obligation. The transaction price is the amount of consideration to which the Group expects to be entitled. The transaction price is allocated to the performance obligations in the contract based on standalone selling prices of the goods or services promised.

Contracts for the sale of commodities are typically priced by reference to quoted prices. Revenue from term commodity contracts is recognised based on the contractual pricing provisions for each delivery. Certain of these contracts have pricing terms based on prices at a point in time after delivery has been made. Revenue from such contracts is initially recognised based on relevant prices at the time of delivery and subsequently adjusted as appropriate. All revenue from these contracts, both that recognised at the time of delivery and that from post-delivery price adjustments, is disclosed as revenue from contracts with customers.

Royalty income is recognised as it accrues in accordance with the terms of the overriding royalty agreements.

Processing income is recognised at the time the services are rendered.

Finance income

Finance income consists of bank interest on cash and cash equivalents which is recognised as accruing on a straight-line basis, over the period of the deposit.

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 fair value excludes the effect of non-market-based vesting conditions.

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 Company's estimate of equity instruments that will eventually vest. At each balance sheet date, the Company revises its estimate of the number of equity instruments expected to vest as a result of the effect of non-market-based vesting conditions. 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 equity reserves. When non-employee share options or warrants are exercised, the initial fair value ascribed to the instruments and recorded as a reserve is reclassified to share premium.

Business combinations

Acquisitions of business are accounted for using the acquisition method. The consideration transferred in a business combination is measured at fair value, which is calculated as the sum of the acquisition‑date fair values of assets transferred by the Group, liabilities incurred by the Group to the former owners of the acquiree and the equity interest issued by the Group in exchange for control of the acquiree. Acquisition‑related costs are recognised in profit or loss as incurred.

At the acquisition date, the identifiable assets acquired, and the liabilities assumed are recognised at their fair value at the acquisition date.

Goodwill is measured as the excess of the sum of the consideration transferred, the amount of any non‑controlling interests in the acquiree, and the fair value of the acquirers previously held equity interest in the acquiree (if any) over the net of the acquisition‑date amounts of the identifiable assets acquired, and the liabilities assumed. If, after reassessment, the net of the acquisition‑date amounts of the identifiable assets acquired and liabilities assumed exceeds the sum of the consideration transferred, the amount of any non‑controlling interests in the acquiree and the fair value of the acquirers previously held interest in the acquiree (if any), the excess is recognised immediately in profit or loss as a bargain purchase gain.

Segmental reporting

In the opinion of the Board of Directors, being the Chief Operating Decision Maker, the Group has one class of business, being the exploration for, and the development and production of, oil and has reserves and other related activities. The Group's primary reporting format is determined to be the geographical segment according to the location of the oil and gas asset, currently Canada and UK / Corporate.

Changes in accounting standards

The standards which applied for the first time this year have been adopted and have not had a material impact.

Standards which are in issue but not yet effective:

At the date of authorisation of these financial statements, the following Standards and Interpretation, which have not yet been applied in these financial statements, were in issue but not yet effective. The Group does not anticipate they will have a material impact.

The Group has not early adopted any of the above standards and intends to adopt them when they become effective.

Critical accounting judgements and key sources of estimation uncertainty

The preparation of financial statements using accounting policies consistent with IFRS requires the Directors to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of income and expenses. The preparation of financial statements also requires the Directors to exercise judgement in the process of applying the accounting policies. Changes in estimates, assumptions and judgements can have a significant impact on the financial statements.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised prospectively from the period in which the estimates are revised.

Critical Accounting Judgements

The following are critical judgements, apart from those involving estimations (which are presented separately below), that the Directors have made in the process of applying the Group's accounting policies and that have the most significant effect on the amounts recognises in the financial statements.

Carrying value of intangible exploration and evaluation assets

At 31 December 2022, the Group held oil and gas E&E assets of £62.1 million (2020: £49.8 million), note 13. The carrying value of E&E assets are assessed for impairment when there is an indication that the asset may be impaired. In making this judgement the Management considers the indicators of impairment in the intangible exploration and evaluation asset accounting policies set out above. For its UK assets, management has considered the well result at the 13/23c-12 Serenity appraisal well to represent an indicator of impairment and has made an estimate of the asset's recoverable amount. Further discussion is provided in note 13. 

For its Canada assets, management has considered the recency of the land purchases, budgeted spend, the plans to further appraise the Clearwater play and the fact that there is no observable data which would suggest that the carrying value of Clearwater play exceeds that of its value from successful development or sale, and have concluded that no indicators of impairment are present.

Carrying value of property, plant and equipment - oil and gas assets

At 31 December 2022, the Group held oil and gas PP&E assets of £236.5 million (2021: £224.1 million), note 12. These assets are subject to an annual impairment assessment under IAS 36 'Impairment of assets' whereby management is first required to consider if there are any indicators of impairment, and if so, management is then required to estimate the asset's recoverable amounts. The judgement over indicators of impairment considers several internal and external factors, including changes in estimated commercial reserves, changes in oil prices, and changes in expected future operating and capital expenditure, decommissioning expenditure, the NPV10 of 2P reserves per the 31 December 2022 independent competent person's report, and increases in cost of capital which may indicate a higher discount rate is likely required in assessing the asset's recoverable amount. There is also judgement in defining the Group's cash-generating units, which is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or group of assets. After considering the above, Management has concluded that there were no indicators of impairment of oil and gas PP&E assets as at 31 December 2022.

Key sources of estimation uncertainty

The key assumptions concerning the future, and other key sources of estimation uncertainty at the reporting period that may have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below.

Estimated future cash flows for intangible exploration and evaluation assets for impairment testing

The Group assesses at each reporting date whether there is an indication that an asset may be impaired. If any such indication exists, or when annual impairment testing for an asset is required, the Group makes an estimate of the asset's recoverable amount, which is the higher of its fair value less costs to sell and its value in use. As discussed in note 13, management considered the results of the 13/23c-12 Serenity appraisal well to represent an indicator of impairment and has made an estimate of the asset's recoverable amount based on value in use using a discounted cash flow model of a one well development of the Serenity field. A one well development is dependent on access to infrastructure at neighbouring fields which may not become available to the Group.

The discounted cash flow model required management to make assumptions about future production profiles, Brent pricing, capital, operating and abandonment costs, and the discount rate applied. The most difficult, subjective, or complex assumptions include the Brent pricing and the discount rate applied. The Brent pricing assumption ranges from $80-$95 over the life of a one well development of the Serenity field and is based on an average of price decks obtained from the Group's brokers, advisors, and the Group's reserves engineers. The discount rate of 10% is based on the risk profile of similar assets in the UKCS. Management has considered several downside scenarios on these assumptions. Decreasing the Brent pricing assumption by 5% or increasing the discount rate to 13% would not have resulted in an impairment individually but would have resulted in an impairment if aggregated. It is reasonably possible that changes to these assumptions within the next financial year could require a material adjustment to the Group's intangible exploration and evaluation assets.

Commercial hydrocarbon reserves estimates

Commercial hydrocarbon reserves are those that can be economically extracted from the Group's oil and gas assets. These estimates are based on information compiled by independent qualified persons, GLJ Ltd., as at 31 December 2022 and 31 December 2021 and consider a number of factors, including assumptions about future commodity prices, production rates, operating costs, exchange rates, and various geological and geophysical technical factors to model reservoir size, quality, and extractability. Reserve estimates may change from period to period. Changes to reserves estimates may have a material impact on the depletion charge for oil and gas PP&E assets, the decommissioning provision, the carrying value of deferred tax assets, and the Group's conclusions around indicators of impairment for oil and gas PP&E assets. The reserve reports are available at https://i3.energy/.

The Group estimates it commenced the year with 154.1 MMboe of proved plus probable reserves. A 2.0 MMboe increase/decrease to this estimate would have decreased/increased the oil and gas depletion charge for the period by £458 thousand, respectively.

Decommissioning costs

At 31 December 2022 the Group had recorded a decommissioning provision of £93.3 million (2021: £125.5 million). In estimating the amount of the provision, Management makes various assumptions around costs, time to abandonment and inflation rates, which are discounted at long term government bond rates, see note 17.

The most difficult, subjective, or complex assumptions include the inflation rate and the discount rate, which have been selected based on market rates published by the Bank of Canada. A 0.5% increase/decrease in the inflation rate would have increased/decreased the decommissioning provision by £12.4 million and £10.5 million, respectively. A 0.5% increase/decrease in the discount rate would have decreased/increased the decommissioning provision by £10.3 million and £12.3 million, respectively.

Recognition and measurement of deferred tax assets

At 31 December 2022, the Group held deferred tax liabilities of £11.7 million (2021: £7.5 million) which result from temporary differences at the Group's Canadian operations. This liability has been reduced by certain deferred tax assets from deductible temporary differences at the Group's Canadian operations. In accordance with IAS 12 'Income Taxes', deferred tax assets shall be recognised for all deductible temporary differences to the extent that it is probable that taxable profit will be available against which the deductible temporary difference can be utilised. The Group has generated positive cash flows and profits from its Canadian operations in 2022 and expects to continue to do so in the future. Management has applied judgement in determining the extent to which it is probable that taxable profits will be available based on estimates of future profits, which include estimates of commercial reserves, oil, gas and NGL prices, operating and capital expenditure, and decommissioning expenditure. If future taxable profits differ from these estimates, the deferred tax asset associated with these deductible temporary differences could be derecognised and result in a deferred tax charge to the consolidated statement of comprehensive income.

4 (Loss) / gain on bargain purchase and asset dispositions

The gain on bargain purchase and asset dispositions as per the consolidated statement of comprehensive income is as follows:

The loss in 2022 relates to purchase price adjustments on asset dispositions completed in the prior year.

5 Segmental reporting

The Chief Operating Decision Maker (CODM) is the Board of Directors. They consider that the Group operates as two segments, as follows:

· UK / Corporate - That of Corporate activities in the UK and oil and gas exploration, appraisal and development on the UKCS.

· Canada - That of oil and gas production in the WCSB.

Such components are identified on the basis of internal reports that the Board reviews regularly.

The following is an analysis of the Group's revenue and results by reportable segment in 2022:

The following is an analysis of the Group's revenue and results by reportable segment in 2021:

The following is an analysis of the Group's assets and liabilities by reportable segment as at 31 December 2022 and the capital expenditure for the year then ended:

The following is an analysis of the Group's assets and liabilities by reportable segment as at 31 December 2021 and the capital expenditure for the year then ended:

6 Revenue

All revenue is derived from contracts with customers and is comprised of the sale of oil and gas and processing income, net of royalties, as follows:

All revenue is from the Group's Canadian operations. Revenue from the sale of oil and natural gas liquids is recognised at the point in time when title transfers to the purchaser. Processing income is recognised at the time the service is rendered.

During the year ended 31 December 2022, three (2021: four) customers individually totalled more than 10% of total revenues, totalling 81% (2021: 79%) in aggregate and 35%, 25%, and 21%, individually (2021: 25%, 20%, 19%, and 15%).

7 Administrative expenses

* Group staff costs comprised:

i3 Energy plc had an average of two staff during the year ended 31 December 2022 (2021: Nil) and paid £1,050 thousand of wages, salaries and benefits and £137 thousand of social security costs (2021: Nil). The Non-Executive Directors of the Group are not considered staff, and their remuneration is disclosed in note 10.

The average number of persons employed by the Group, including Executive Directors, was:

** Included within professional fees are fees payable to the Company's auditor and its associates for the following:

8 Finance costs

9 Taxation

Taxation credit

The below table reconciles the tax charge for the year to the profit before tax per the consolidated statement of comprehensive income.

* Canada is the only jurisdiction where the Group produces oil and gas, generates taxable income, and records a current and deferred tax charge. As such, the Group elected to change the tax rate in reconciliation of the tax charge to 23% in 2022, the combined corporate rate of taxation in Canada. The comparative period has been restated on the same basis. The total income tax charge was unimpacted in both periods, with the only changes being to the 'Expected tax charge' and the 'Foreign tax rate difference' lines in the reconciliation above. The difference on foreign tax rate results from the difference between 65% overall tax rate in the UK and the 23% tax rate used in the reconciliation.

The current tax charge of £10,002 thousand in 2022 resulted from taxable income in the Group's Canadian subsidiary, i3 Energy Canada Limited, which is payable in the first half of 2023. The current tax credit of £487 thousand in 2021 resulted from the receipt of R&D tax refunds in the UK in respect of the 2019 fiscal year.

In 2022 the Energy Profits Levy (EPL) was introduced at a rate of 25% with effect from 26 May 2022. This, along with the Ring Fence Corporation Tax (RFCT) at 30% and the Supplementary Charge (SCT) of 10% brings the overall tax rate in the UK to 65%. The EPL increased to a rate of 35% effective 1 January 2023 which will bring the overall tax rate in the UK to 75%. The EPL will remain in effect until 31 March 2028. The Group will not be impacted by the increase until such time as taxable profits are generated in the UK. The combined corporate rate of taxation in Canada remained unchanged at 23%.

Deferred tax

The components of the net deferred tax asset and the movement during the year is summarised as follows:

A deferred tax asset has not been recognised in respect of tax losses and allowances in the UK due to uncertainty over the availability of future taxable profits in the UK to offset these losses against.

The Group recognised a net deferred tax liability through a deferred tax charge of £3,824 thousand for changes in net deductible temporary differences in the year and £357 thousand for FX movements during the year. The deferred tax liability has been partially offset by a deferred tax asset which has been recognised in Canada to the extent that the Group anticipates probable future taxable profits to against which the assets can be utilised.

The Group's estimated tax pools are summarised in the following table. The non-capital tax loss pools in Canada expire over a period of 20 years. All other tax pools do not expire.

10 Directors' remuneration

Share based payments represent the difference between the exercise price and the market value of i3 shares on the date of exercise, multiplied by the number of options exercised.

Included in Graham Heath Salary / Fees is a one-time compensation for loss of office payment of £417 thousand.

During the year the Company contributed £2 thousand to i3's CEO's pension scheme (2021 - £2 thousand).

11 Earnings per share

From continuing operations

Basic earnings or loss per share is calculated as profit/(loss) for the year, adjusted to exclude any costs of servicing equity (other than dividends), divided by the weighted average number of ordinary shares, adjusted for any bonus element.

Diluted earnings or loss per share amounts are calculated by dividing losses or profits for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year, plus the weighted average number of shares that would be issued on the conversion of dilutive potential ordinary shares into ordinary shares.

The calculation of the basic and diluted earnings per share is based on the following data:

In 2021, prior to the BHGE warrant repricing on 17 May 2021, these instruments were anti-dilutive as their exercise price exceed the average market price of the Ordinary Shares over this period. Concurrent with their repricing the BHGE warrants were immediately exercised for ordinary shares. The BHGE shares were therefore included in the basic weighted average number of Ordinary Shares from 17 May 2021 but were not further included in the effect of dilutive potential ordinary shares.

12 Property, plant, and equipment

13 Exploration and evaluation assets (Intangible)

Included within E&E assets is the Group's UK P.2358 Licence, which commenced its four-year second term on 30 September 2020 and contains the Serenity discovery and the Liberator West and Minor High prospective areas.

In March 2022 the Group announced it had agreed farm-in terms with Europa Oil & Gas Limited ("Europa") for a 25% working interest ("WI") in Block 13/23c North (Licence P.2358) which contains the Serenity discovery. Under the terms of the farmout, Europa will fund 46.25% of the cost of the upcoming Serenity appraisal well up to a gross capped well cost of £15 million. Any well costs exceeding £15 million will be funded by the companies in proportion to their respective working interests. The Farm-In Agreement ("FIA") was signed in April 2022 and following the fulfilment of all conditions precedent in the FIA, the transaction closed in August 2022. Following this farm-out, i3 retains a 75% WI in Block 13/23c North (Licence P.2358) and a 100% WI in Block 13/23c South (Licence P.2358), which contains the Minos High Prospect and Liberator discovery.

In September 2022, the 13/23c-12 Serenity appraisal well was spud and drilled to a total vertical depth of 5,630 ft below sea level. The targeted Lower Cretaceous Captain sand, which contained hydrocarbons in the 13/23c-10 well discovered in October 2019, was not present at this location. Over 100 ft of other Captain sands in various sequences were found but were water wet. The well was plugged and abandoned. Management considers the well result to represent an indicator of impairment and has made an estimate of the asset's recoverable amount based of management's best estimate of value in use using a discounted cash flow model of a one well development of the Serenity field. The estimated recoverable amount exceeded the carrying amount of the Group's UK E&E assets as at 31 December 2022, and accordingly no impairment was recognised. Further discussion is provided in note 2.

Also included within E&E assets are costs associated with land purchases and a preliminary appraisal well in the Clearwater play in Canada. 

14 Trade and other receivables

Trade and accrued receivables are all due within one year.

Joint venture receivables represent amounts due from operating partners for operating and capital activity in Canada and the UK.

The fair value of trade and other receivables is the same as their carrying values as stated above and they do not contain any impaired assets.

The maximum exposure to credit risk at the reporting date is the carrying value of each class of receivable mentioned above. The Group does not hold any collateral as security.

15 Trade and other payables

The average credit period taken for trade purchases is 60 days. No interest is charged on the trade payables. The carrying values of trade and other payables are considered to be a reasonable approximation of the fair value and are considered by the Directors as payable within one year.

Joint venture payables represent amounts due to operating partners for operating and capital activity in Canada.

Non-current accounts payable

On 2 July 2019 the Group agreed with Baker Hughes, a GE Company, and GE Oil & Gas Limited (collectively referred to as "BHGE" hereafter) that £3,000 thousand of oilfield service and oilfield equipment contract payments will not become payable until such time as i3 has received its first sales revenues from Liberator Phase I. This payable was previously recorded as a non-current accounts payable.

On 17 May 2021, i3 announced that it had successfully restructured legacy contracts and agreements for equipment, oil field services, and warrants with BHGE. In summary, the remainder of a £5.8 million contract for subsea trees and wellheads was cancelled, 5,277,045 warrants had an exercise price reduction to £0.0001 per share (the "Warrant Shares"), and an outstanding contingent payment for £3.0 million ("Deferred Payment Invoice Balance", or "DPIB") in oil field services and equipment that becomes payable at such time as the Group receives consideration from any sale or farm-down of its Serenity or Liberator assets will be reduced by the exercise value of the Warrant Shares, the market value of the Warrant Shares from time to time, all dividends received by BHGE associated with the Warrant Shares, and certain payments to be made to BHGE. The purpose of this restructuring was to enable i3 to become a dividend payer, as certain conditions of the abovementioned contracts prevented it from reducing its share premium account - a required step in order for i3 to effect dividend distributions to its shareholders. The incremental fair value of the modified warrants was expensed in 2021 (note 8).

In Q4 2022, the Group received consideration from the Serenity farm-in in excess of the DPIB amount and the repayment was triggered. The repayment amount of £1,270 thousand was calculated as the £3.0 million payable amount, less the exercise value of the Warrant Shares of £1 thousand, less cash payments of £487 thousand made in 2021 against the DPIB balance, less the Market Value of the Warrant Shares of £1,161 thousand, which totals the 5,277,045 Warrant Shares as at the repayment date share price of 22.00p/share, less £81 thousand of dividends paid on the Warrant Shares. The repayment amount was settled in cash in 2022 and the liability was extinguished. The increase in i3's share price from 13.35p/share from 31 December 2021 to 22.00p/share at the repayment date resulted in a non-cash gain in the value of the Warrant Share which has been recorded in the consolidated statement of comprehensive income within Finance Costs.

A reconciliation of the balance is as follows:

16 Borrowings

H1-2019 loan note facility

In May 2019, the Company completed a £22 million H1-2019 loan note facility ("H1-2019 LN"). The H1-2019 LNs have a term of 4 years, maturing on 31 May 2023 and bearing interest, payable on a quarterly basis at the Group's option (i) in cash at a rate of 8% per annum, or (ii) in kind at a rate of 11% per annum by the issuance of additional H1-2019 LNs. The Group elected to pay all interest in kind prior to 2022, and in cash for all four quarters in 2022. 

The noteholders were granted warrants ("H1-2019 LN Warrants") in the notional amount of £1 for each £1 of loan notes issued, with H1-2019 Warrants being issued proportionately across three series. The H1-2019 LN Warrants vested on the issue date and expire 4 years thereafter and can be exercised through either/or a combination of a cash payment and/or surrender of H1-2019 LNs plus accrued interest equal to the aggregate notional amount of the H1-2019 LN Warrants being exercised. Each H1-2019 LN Warrant gives the holder the right to convert the notional amount into such number of shares as is derived by dividing the notional amount by the exercise price. The following table outlines the terms of the warrants as at their issuance date.

Total fair value of the Tranche 1, Tranche 2 and Tranche 3 warrants on issuance was £11,375 thousand and was bifurcated from the debt contract and classified as equity. The H1-2019 LNs are comprised of the following components: the debt contract, the conversion feature, the interest rate payment option and the early conversion feature (at the Group's option). At inception the debt component was recorded at an estimated fair value of £10,625 thousand. The debt balance is unwound using the effective interest rate method to the principal value at maturity with a corresponding non-cash accretion charge to earnings.

Interest expense and accretion expense to 31 December 2022 was £2,309 thousand and £3,386 thousand respectively.

Borrowings reconciliation

The classification as at 31 December 2022 is as follows:

The classification as at 31 December 2021 is as follows:

17 Decommissioning provision

A summary of the key estimates and assumptions are as follows:

Liabilities settled reflect work undertaken in the period. This includes wells decommissioned under Alberta's Site Rehabilitation Program ("SRP") and Saskatchewan's Accelerated Site Closure Program ("ASCP") whereby certain costs of settling the Group's liabilities were borne by the Government of Canada. Where liabilities were settled through the SRP and ASCP a corresponding decrease to the decommissioning asset was recorded. The change in estimate for the year ended 31 December 2022 was primarily driven by changes in market interest and inflation rates as published by the Bank of Canada. The inflation and discount rates have been pinpointed as a key source of estimation uncertainty and are further discussed in note 2.

18 Risk management contracts

The Group enters risk management contracts to hedge a portion of the Group's exposure to fluctuations in prevailing commodity prices for oil, gas, and natural gas liquids. The Group's physical commodity contracts represent physical delivery sales contracts in the ordinary course of business and are therefore not recorded at fair value in the consolidated financial statements. The Group's financial risk management contracts have not been designated as hedging instruments in a hedge relationship under IFRS 9 and are carried at fair value through profit and loss. The financial risk management contracts are classified as Level 2 in the fair value hierarchy as defined by IFRS 13 'Fair value measurements' (note 22).

The principal terms of the risk management contracts held as at 31 December 2022 are presented in the table below.