Final Results for the year ended 31 December 2021

RNS Number : 0854I

i3 Energy PLC

12 April 2022

 

12 April 2022

i3 Energy plc

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

Final Results for the year ended 31 December 2021

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 2021.  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 30^th June 2022 at the offices of W H Ireland at 24 Martin Lane, London, EC4R0DR.

Highlights

CANADA			UK AND CORPORATE
Completed 20 August 2021	CENOVUS ACQUISITION			SERENITY	25% farmout on 1.85 for 1 basis (concluded post year-end)
Total 2021 Revenue	£86.8 MILLION			£25.1 MILLION	Profit after tax
FY 2021 and Q4 2021 Production	12,442 BOEPD AND 18,229 BOEPD			2.84 AND 2.60 PENCE	Basic and diluted EPS
Production acquisitions	8,000+ BOEPD			£40 MILLION	Equity raised
PDP and 2P reserves	45 MMBOE AND 153 MMBOE			£3.4 MILLION	Dividends declared and paid in 2021
Leasehold position	612k NET ACRES			£3.5 MILLION	Dividends declared to date in 2022
Net production wells	902			£11.8 MILLION	Full-year dividend guidance for 2022

Dividend Distributions

·During the course of 2021, i3 paid total dividends of 0.36 p/share, equating to a yield of approximately 6.5% for i3's shareholders based on i3's closing share price on 1 January 2021.

· Announced in December that the Company is committing to pay a minimum of £11.827 million in dividends during the course of 2022 (3.5x all dividends paid during 2021), equating to 1.05 pence per share or a 10.2% yield on the date of announcement, with forecasted year end "2022 Unencumbered Cash" of US$66 million which could support additional shareholder distributions or share buybacks, M&A, and supplemental development activity.

Financial Highlights

·2021 revenue of £86.8 million (net) and net operating income (revenue less royalties, opex, processing and transportation) of £48.8 million and cash flow from operations of £24.4 million.

·To fund the Cenovus acquisition on 7 July 2021, i3 raised approximately £40 million through the placing and subscription of 363,700,000 shares at an issue price of 11 pence per share, a 3% discount to the 15-day average closing price of 11.4 pence.

·Concluded a reduction of the Company's share premium account by way of a UK court approvals process in order to free up distributable reserves to effect the abovementioned dividend payments.

Operational Highlights

·2021 full-year production averaged 12,442 boepd, with Q4 2021 including the newly integrated Central Alberta assets acquired from Cenovus Energy (which closed in August 2021) averaging 18,229 boepd (compared to 13,239 boepd in Q3, 9,018 boepd in Q2 and 9,173 boepd in Q1 2021). Q4's production was comprised of 58 million standard cubic feet of gas per day ("mmscfd"), 5,210 barrels per day ("bbl/d") of NGLs, 3,015 bbl/d of oil and 331 boepd of gross overriding royalty interest production. Q4 2021 production was impacted by the closing of multiple non-core asset disposals and December's severe cold weather.

· Increased exposure to Alberta's premier Clearwater play:

•Confirmed presence of oil in three gas wells in i3's extensive Marten Creek acreage, providing a green light for a winter 2021/22 oil appraisal programme.

•Farmed-in to a 50% working interest in the Marten Hill's Clearwater area and participated in two successful development wells which added c.120 boepd net production, with an option to drill seven additional wells on the acreage.

•Participated in Crown Land Sales, bolstering acreage through a 15-year lease on seven sections (17.9 km²) of land in the emerging Cadotte area.

· Acquired a 49.5% interest in South Simonette at a cost of US$4.2 million, increasing i3's previously held 49.5% operated interest in this Montney oil play to 99% and allowing it to bring back on to production three wells to increase its corporate production by c.720 boepd and adding reserves of 4.9 MMboe at a before-tax NPV10 valuation of US$30.9 million. Total estimated 2P reserves as of 31 December 2021 were 10.3 MMboe.

·Elected to drill two oil-weighted wells with a partner at its Wapiti Elmworth acreage, expected to initially increase i3's production by c.175 boepd, with payback estimated in 1.3 years.

·Acquired c.230 boepd of Wapiti production, conducted six reactivations to increase production to 471 boepd, significantly exceeding the expected 310 boepd.

·Brought on stream a gas well located on the Company's Noel acreage in Northeast British Columbia at an average rate of 650 boepd, exceeding expectations by 30%.

·Acquired circa 8,400 boepd (51% oil and NGLs) of low decline production from Cenovus Energy Inc, located within i3's Central Alberta core area, for a total consideration of CAD65 million (US$53.7 million). The assets were acquired on excellent metrics of 1.73x next twelve months cashflow, US$6,381/boepd and US$0.68/boe of 2P reserves and contain 79.5 MMboe of 2P reserves with an NPV10 of US$193 million as at 1 April 2021, an inventory of greater than 140 net drilling locations, 80 net reactivation opportunities and 1,140 km network of operated pipelines, and key processing facilities. The transaction closed on 20 August 2021.

·To increase its focus on its high working interest assets in Central Alberta, Wapiti / Elmworth, Simonette and the Clearwater play, during Q4 2021 the Company executed multiple non-core disposals with the purpose of reducing its per boe operating costs, decreasing end-of-life obligations, and releasing US$945 thousand of decommissioning-related bonds to i3's balance sheet (previously held with provincial oil and gas authorities to offset potential end-of-life liabilities). On a combined basis, these disposals reduced i3's production by approximately 130 boepd from a combined 213 gross (184.5 net) wells (consisting of 36 gross (34.3 net) active and 177 gross (150.2 net) inactive wells) and reduced the Company's overall undiscounted asset retirement obligation by approximately US$9.8 million. The proceeds from these and future disposals will be utilised to accelerate growth from i3's extensive inventory of highly economic development locations as the Company remains focused on delivering total shareholder returns.

· During Q4 the Company brought on stream four gross (1.5 net) highly economic non-operated horizontal wells within its Central Alberta and Wapiti core areas, at an average 37% working interest.  The programme consisted of one well targeting the liquids-rich Ellerslie formation, one Belly River oil producer and two Dunvegan oil wells, which in aggregate contributed net average daily production over its initial 30-day production period ("IP30 rates") of approximately 600 boepd (65% oil and NGLs) and are collectively meeting or exceeding i3's forecasted type curves.  This non-operated programme is expected to pay out in approximately one year and serve to further bolster i3's year-end reserves and add newly identified offsetting development locations.

· The Company continued to systematically identify and develop its robust inventory of low-cost, high-return recompletion and reactivation opportunities, which produce top-tier returns and assist in further reducing i3's corporate operating costs on a boe basis through the utilisation of the Company's extensive network of owned and operated infrastructure while optimising field efficiencies with nominal capital. 16 gross (14 net) oil-focused recompletions and reactivations were brought on production in Q4, resulting in net IP30 rates of approximately 240 boepd (65% oil and NGLs).  Cumulatively, the operations were completed on budget and are anticipated to pay out in substantially less than one year.

· On 20 December 2021, the Company announced a fully funded 2022 capital budget of US$47 million to fund a 12.6 net well operated drilling programme, non-operated drilling, well reactivations, debottlenecking, consolidation, and third-party tariff generating projects. This programme is expected to deliver average corporate production in 2022 above 20,000 boepd, with peaks reaching 21,000 boepd.

· The Company commenced a hedging program which will result in approximately 50% of corporate volumes being hedged on a rolling 12 month forward looking basis.

· Agreed terms with a potential farm-in partner for the Serenity field appraisal drilling programme and, at year-end, the Company was awaiting confirmation of funding commitments from that potential farm-in partner before finalising and executing documentation.

Post Period and Outlook

A summary of key events which occurred after the reporting period are presented in note 24 to the financial statements.

The Company's focus for the remainder of 2022 will be on four 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  Drilling an appraisal well at the Company's Serenity oil discovery in the UK to prove reserves and to guide future development plans;

3  Dividend distributions to its shareholders of up to 30% of free cash flow; and

4  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:

"2021 was another truly transformational year for i3 which saw very significant growth for the Company across all factors which drive shareholder value - production, cashflow, reserves and portfolio scale and scope. We entered the year having completed two acquisitions in late January 2020 which saw our entry to the Canadian E&P market with circa 9,000 boepd of production. We have just exited Q1 2022 producing in excess of 20,000 boepd with year-end audited 2P reserves of 154 MMboe with a valuation of US$775mm and forecast NOI for the year of US$192mm. Our organic reserve replacement ratio for the year was over 200%, and this was achieved on the back of hundreds of well interventions which are a testament to the dedication of all our staff from field operations to those based in the office.  We were also active throughout the year optimising our portfolio with numerous acquisitions and divestments, including one substantial transaction, the acquisition of circa 8,400 boepd in our core Central Alberta area from Cenovus Energy, and other strategic acquisitions in our Simonette Montney acreage and the Clearwater play which has given us exposure to significant near-term share price catalysts. Analysis and prioritisation of our substantial drilling portfolio over the course of the second half of the year allowed us to announce in December our inaugural operated drilling program which commenced in January 2022, and which will see us drilling circa 12.6 net wells during the first three quarters of the year. In the UK we continued discussions with potential farminees for our Serenity appraisal well and in March 2022 announced a deal which will allow us to spud the well later this year.

We are also pleased to have commenced dividend payments in 2021 and to have announced an increased dividend for 2022. We are confident we will add substantial shareholder return through exploitation of the extensive portfolio of drilling options we have lined up for 2022. 

We are transformed into a strong, diversified production company with significant near-term growth catalysts over which we have operational control.

I would as always like to thank and pay tribute to all i3 staff, who have continued to work diligently, professionally and with good humour, whilst building our business under the difficult circumstances of the global COVID-19 pandemic and also for the continued support of our shareholders and investors who helped fund and support our growth in 2021."

"Majid Shafiq, Chief Executive Officer"

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:

i3 Energy plc Majid Shafiq (CEO) / Graham Heath (CFO)	c/o Camarco Tel: [phone]
WH Ireland Limited (Nomad and Joint Broker) James Joyce, Darshan Patel	Tel: [phone]
Tennyson Securities (Joint Broker) Peter Krens	Tel: [phone]
Stifel Nicolaus Europe Limited (Joint Broker) Ashton Clanfield, Callum Stewart	Tel: [phone]
Camarco Georgia Edmonds, James Crothers, Violet Wilson	Tel: [phone]

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.

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 to 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/ .

The information contained within this announcement is deemed by the Company to constitute inside information under the Market Abuse Regulation (EU) No. 596/2014.

INTERIM Chairperson's and Chief Executive's Statement

Overview of the year

i3 is extremely pleased with the results of 2021, which served to prove the Company's buy-and-build strategy of using acquisitions, operational focus, and the drill-bit to create a portfolio of producing assets with realisable upside from which shareholder value could be created and returned in the form of share price growth and a cash yield.

Having acquired Toscana Energy Income Corporation ("Toscana") in 2020, with its modest amount of production, as a foundation atop which to build a growth-focused production business in the Western Canadian Sedimentary Basin ("WCSB"), followed by the purchase of the entire asset portfolio of Gain Energy Ltd. ("Gain"), the Company entered 2021 having secured over 9,000 boepd during one of the most depressed and volatile years in the sector's history. During a period when most companies hunkered down, i3 bought assets as quickly as access to capital and deal-flow permitted, as buying at or near market bottoms is a long-proven strategy for increasing both the margins of safety and error, providing tremendous torque to an eventual macro-economic recovery. Our acquisition-led entry into the WCSB during a period which saw unprecedented commodity price lows positioned the Company for success, and following a busy period of corporate, financial, and operational amalgamation of Toscana and Gain into i3 Energy Canada Limited, the Canadian operations team set to harvesting the low-hanging fruit that existed within these long-undercapitalised portfolios, while the executive continued to seek further material asset packages that could be purchased.

On 17 June, i3 announced that numerous acquisition and drilling initiatives it had concluded or committed to during the course of H1 would result in i3's production surpassing 10,000 boepd during the second half of the year and were expected to materially increase the Company's next twelve months ("NTM") net operating income ("NOI" = revenue minus royalties, opex, transportation and processing) well-beyond its previous market guidance. To mid-year 2021, i3 had been able to capture its entire Canadian portfolio at an average of 1.0x NTM NOI (from June 2021) and US$4,557/boepd.

On 6 July, i3 announced that it had signed an Asset Sale Agreement ("ASA") with Cenovus Energy Inc., a senior Canadian oil and gas producer, to acquire certain conventional central Alberta petroleum and infrastructure assets. The acquisition would include approximately 8,400 boepd (51% oil and NGLs) of predictable low-decline production, 79.5 MMboe of 2P reserves with an NPV₁₀ of US$193 million, as at 1 April 2021, an inventory of greater than 140 net drilling locations and 80 net reactivation opportunities across approximately 212,000 net acres, a 1,140 km network of operated pipelines, and key processing facilities. The Cenovus assets complement i3's existing area assets with approximately 3,090 boepd of overlapping joint working interest production and associated land positions. The CAD65 million acquisition was funded through an equity issuance of 363,700,000 shares at an issue price of 11 pence per share, representing a 3% discount to the 15-day average closing price to 7 July of 11.4p.

The Cenovus acquisition is a continuation of i3's stated strategy of capitalising on the abnormal market conditions of 2020 and 2021 to create a cash-generative, all-weather portfolio by efficiently consolidating high quality undercapitalised assets within our core operating areas. The production, infrastructure and lands associated with the acquisition directly overlap our current Central Alberta asset base and provide meaningful operational synergies. Through this strategic acquisition, i3 significantly enhances its production, cash flow and reserve base while strengthening its balance sheet. Furthermore, the Cenovus acquisition enhances i3's ability to grow future production, free cash flow, and its planned return of capital to shareholders through dividend payments.

All in, the abovementioned initiatives were concluded at exceptional effective acquisition metrics of 1.36x NTM NOI, or US$5,533/boepd. In the context of the market, the Directors believe this to be an outstanding result for such high-quality production assets. As importantly, i3's acquisitions have garnered untapped Proven Undeveloped (PUD) and/or Proven plus Probable (2P) development opportunities, resulting in several highly prospective projects now existing within our portfolio. The upside potential within i3's South Simonette, North Simonette and Clearwater positions in Canada and its Serenity discovery in the UK, as well as redevelopment options of some of our more mature assets via secondary recovery and infill drilling, present company-making opportunities that have the potential to deliver multiples of i3's current production, reserves and cash flow.

The opportunity high-grading process which followed our integration of the Cenovus assets culminated in the 20 December announcement of a planned US$47 million 2022 capital budget (the "Capital Budget"), such that production and cash flow can continue to be increased, targeted upside in the Company's key Clearwater and Simonette Montney plays can be advanced, and the substantial return of capital to i3's shareholders can be assured.

The Capital Budget, which is fully funded from existing Company resources and forecast internally generated cash flow, is predicted to provide incremental peak production of up to 5,250 boepd through the funding of 12.6 net wells (17 gross, 88% i3-operated, including one Montney oil producer at Simonette plus two (net) oil producers and two non-producing test wells in the Clearwater play), oil wells in the Cardium and liquids rich gas wells in the Falher and Glauconitic plays and maintenance capital to support producing wells and infrastructure. The budget also includes an amount of capital that has been allocated to fund highly economic, non-operated drilling opportunities as they arise, and projects which enhance cashflow and increase netbacks such as well reactivations, debottlenecking, consolidation, and tariff-generating third-party tie-ins to i3-operated facilities. This activity is expected to deliver a 26% production increase over the 2022 exit rates predicted under i3's blowdown case (which considers no capex and a conservatively estimated natural decline across the entire portfolio of 14%), resulting in average 2022 production above 20,000 boepd with peaks reaching 21,000 boepd. The Capital Budget focuses on a combination of swift payback and high impact targets in i3's core operating areas as follows:

Figure one

http://www.rns-pdf.londonstockexchange.com/rns/0854I_1-2022-4-12.pdf

Early results from the abovementioned activities position i3 to achieve or exceed the initial expectations noted above. Should similar success continue, the Company will look to accelerate additional capital deployment which will take advantage of operational momentum and the current favourable commodities environment. The Company remains highly confident that the continuance of its Canadian strategy, in accordance with the above, will deliver to its shareholders meaningful value through both share price appreciation and long-term cash distributions. The following graphically demonstrates i3's growth in the WCSB since its entry in 2020; we expect to continue along an equally exciting trajectory:

Figure two:

http://www.rns-pdf.londonstockexchange.com/rns/0854I_1-2022-4-12.pdf

154 MMBOE 2P reserves in the chart above reflects the Company Interest reserves as of 31 December 2021.

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 106 routine regulatory government inspections during 2021. 83 returned satisfactory results, 19 were categorised as low risk, and four that were deemed to be high risk were subsequently remedied.

The Company was very pleased to announce on 2 March 2022 that, regarding its UK assets, i3 would be welcoming Europa Oil & Gas Limited ("Europa") as a 25% working interest joint venture partner in the Company's Serenity oil discovery upon the execution of a farm-in, join operating agreement, and trust deed (each essentially agreed between the parties), in exchange for Europa funding 46.25% of the next Serenity appraisal well, being planned for H2 2022.  The team remains confident in its belief that the Serenity field holds a company-making resource, and we expect this next appraisal well to prove that premise. Discussions continue with other potential farminees, and i3 will consider bringing in additional parties up to the point of drilling commencement.

Financial Discipline

The Board and Management are focused on delivering consistent value to shareholders. i3 is committed to being a dividend payer that distributes up to 30% of its free cash flow, and it is protecting 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 additional free cash being redeployed to acquire production assets conditional on the associated acquisition metrics competing with the organic returns achievable through the development of our proven undeveloped (PUD) and 2P inventory. As i3 continues to grow its portfolio, a proportion of all incremental production will be hedged in order to secure future cash flow, 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 24 months, the Company's assets have continued to outperform the Directors' expectations. During H2 2021, i3 made dividend distributions totalling £3.417 million, and on 20 December 2021 the Company committed to pay a minimum dividend of £11.827 million during the course of 2022. Showing the Directors' confidence in the consistent performance of the portfolio, on 3 February 2022 i3 announced that this sum would be paid in ten equal increments on a monthly schedule with its first monthly dividend to be paid in March.

The strong performance of the Company's assets combined with the current strength in commodity prices will result in i3 having a substantial sum of unencumbered free cash which can be directed towards additional production growth initiatives, shareholder distributions or share buybacks, and deleveraging.

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 intend to 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 Chief Financial Officer) and four Non-Executive Directors (including the Interim 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 environmental operational, reporting and compliance obligations and abandonment and reclamation requirements. In Q4 2021 the Company commenced a detailed study of its recently acquired operated wells and facilities to record baseline emissions data for the purposes of developing an ESG strategy to meet its currently stated target of being net zero with respect to Scope 1 and Scope 2 emissions by 2050. The work included an evaluation of potential opportunities to reduce greenhouse gas emissions and the Company intends to publish in Q2 2022 its maiden annual sustainability report, which will report our emissions, water use and air quality data and outline our ESG vision and strategy. On acquisition of its Canadian portfolio in late 2020, the Company commenced initiatives to reduce GHG emissions from its operated assets. This has included the replacement of 389 pneumatic controllers which use natural gas as the operating fluid with low bleed controllers or replaced the operating fluid with air. The majority of these conversions were conducted in 2021. These initiatives qualify for carbon credits which can be sold or used to offset future carbon tax obligations. The Company has also commenced the replacement where practical and economically feasible of some propane power generation units with direct connections to utility electricity supply. The Company also takes very seriously its asset retirement obligations and is an active participant in the Government of Alberta's Site Rehabilitation Program ("SRP") from which it has received grants of US$1.8 million in total and Saskatchewan's Accelerated Site Closure Program ("ASCP") and has a regular and routine program to abandon non-operational assets and reclaim the associated land and environment. In 2021 the Company abandoned 17 wells (for a total of 30 including 2020), and 6 pipelines and decommissioned 1 facility and obtained 9 reclamation certificates.

Looking ahead

The Company is very proud of what it has and continues to accomplish since reinventing itself in 2020 and expects to deliver more of the same. We will carry on growing our Canadian production business by employing our stated strategy of being acquisitive when systemic or situational drivers offer good value, while drilling our ever-growing inventory of high-quality proven undeveloped and 2P reserves when doing so offers better returns than the M&A market. In the UK, we remain committed to the further appraisal and development of Serenity and are looking forward to our H2 2022 drilling programme.

Beyond our current business as an oil and gas company, we see climate change as the most urgent matter of our time and deem it critical to act in a manner that exhibits this concern. Though the world will undoubtedly require oil and gas for some time yet, we understand the crucial role that hydrocarbon-based corporates have to play in the transition to net zero and we remain committed to an evolution of our energy company into one that continues to benefit society for generations to come.

As always, we extend gratitude to our capital providers 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.

"Linda Beal" Linda Beal Non-Executive Interim Chairperson 11 April 2022

"Majid Shafiq" Majid Shafiq Chief Executive Officer 11 April 2022

Consolidated Statement of Comprehensive Income

	Notes	Year Ended 31 December 2021	Year Ended 31 December 2020
		£'000	£'000
Revenue	6	86,763	12,991
Production costs		(37,945)	(8,075)
Loss on risk management contracts	18	(5,485)	-
Depreciation and depletion	12	(21,643)	(4,854)
Gross profit		21,690	62
Administrative expenses	7	(13,094)	(5,755)
Acquisition costs	4	(256)	(1,542)
Gain on bargain purchase and asset dispositions	4	25,013	25,211
Operating profit		33,353	17,976
Finance costs	8	(7,609)	(7,368)
Profit before tax		25,744	10,608
Tax (charge) / credit for the year	9	(661)	1,110
Profit for the year		25,083	11,718
Other comprehensive income / (loss):
Items that may be reclassified subsequently to profit or loss:
Foreign exchange differences on translation of foreign operations		1,511	(147)
Other comprehensive income / (loss) for the year, net of tax		1,511	(147)
Total comprehensive income for the year		26,594	11,571
Earnings per share		Pence	Pence
Earnings per share - basic	11	2.84	3.78
Earnings per share - diluted	11	2.60	3.46

All operations are continuing.

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

Consolidated Statement of Financial Position

Assets	Notes	31 December 2021	31 December 2020
		£'000	£'000
Non-current assets
Property, plant & equipment	12	224,080	108,509
Exploration and evaluation assets	13	49,819	48,809
Deferred tax asset	9	-	1,052
Other non-current assets		74	678
Total non-current assets		273,973	159,048
Current assets
Cash and cash equivalents		15,335	6,178
Trade and other receivables	14	25,503	8,731
Risk management contracts	18	814	-
Inventory		665	164
Total current assets		42,317	15,073
Current liabilities
Trade and other payables	15	(19,709)	(13,156)
Risk management contracts	18	(925)	-
Borrowings and leases	16	(69)	(28)
Decommissioning provision	17	(2,368)	(1,234)
Total current liabilities		(23,071)	(14,418)
Net current assets		19,246	655
Non-current liabilities
Non-current accounts payable	15	(557)	(3,000)
Borrowings and leases	16	(23,855)	(17,958)
Decommissioning provision	17	(123,155)	(65,549)
Deferred tax liability	9	(7,486)	-
Total non-current liabilities		(155,053)	(86,507)
Net assets		138,166	73,196
Capital and reserves
Ordinary shares	19	113	70
Deferred shares	19	50	50
Share premium	19	44,203	61,605
Share-based payment reserve	20	9,102	6,337
Warrants - LNs	16	2,045	9,714
Foreign currency translation reserve		1,364	(147)
Retained earnings / (accumulated deficit)		81,289	(4,433)
Shareholders' funds		138,166	73,196

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 11 April 2022. Signed on behalf of the Board of Directors by:

"Majid Shafiq"

Majid Shafiq

Director

Consolidated Statement of Changes in Equity

		Ordinary shares	Share premium	Deferred shares	Share-based payment reserve	Warrants - LN	Foreign currency translation reserve	Retained earnings	Total
		£'000	£'000	£'000	£'000	£'000	£'000	£'000	£'000
Balance at 31 December 2019		11	32,572	50	3,803	11,375	-	( 16,151)	31,660
Total comprehensive income for the year		-	-	-	-	-	(147)	11,718	11,571
Transactions with owners:
Issue of share capital	1 9	58	27,372	-	-	-	-	-	27,430
Exercise of warrants - LNs	20	1	1,661	-	-	(1,661)	-	-	1
Share-based payment expense	20	-	-	-	2,534	-	-	-	2,534
Balance at 31 December 2020		70	61,605	50	6,337	9,714	(147)	( 4,433)	73,196
Total comprehensive income for the year		-	-	-	-	-	1,511	25,083	26,594
Capital reduction	19	-	(64,056)	-	-	-	-	64,056	-
Transactions with owners:
Issue of share capital	19	36	37,970	-	-	-	-	-	38,006
Exercise of options	20	2	112	-	-	-	-	-	114
Exercise of warrants	20	5	8,572	-	(452)	(7,669)	-	-	456
Share-based payment expense	20	-	-	-	3,217	-	-	-	3,217
Dividends declared in 2021	19	-	-	-	-	-	-	(3,417)	(3,417)
Balance at 31 December 2021		113	44,203	50	9,102	2,045	1,364	81,289	138,166

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

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

Reserve	Description and purpose
Ordinary shares	Represents the nominal value of shares issued
Share premium account	Amount subscribed for share capital in excess of nominal value
Deferred shares	Represents the nominal value of shares issued, the shares have full capital distribution (including on wind up) rights and do not confer any voting or dividend rights, or any of redemption
Share-based payment reserve	Represents the accumulated balance of share-based payment charges recognised in respect of share options granted by the Company less transfers to retained deficit in respect of options exercised or cancelled/lapsed
Warrants - LNs	Represents the accumulated balance of share-based payment charges recognised in respect of warrants granted by the Company in respect to warrants granted to the loan note holders
Foreign currency translation reserve	Exchange differences arising on consolidating the assets and liabilities of the Group's non-Pound Sterling functional currency operations (including comparatives) recognised through the Consolidated Statement of Other Comprehensive Income.
Retained earnings	Cumulative net gains and losses recognised in the Consolidated Statement of Comprehensive Income

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

	Notes	Year ended 31 December 2021	Year ended 31 December 2020
		£'000	£'000
OPERATING ACTIVITIES
Profit / (loss) before tax		25,744	10,608
Adjustments for:
Depreciation and depletion	12	21,643	4,854
Gain on bargain purchase and asset dispositions	4	(25,013)	(25,211)
Finance costs	8	7,609	7,368
Unrealised loss on risk management contracts	18	111	-
Unrealised FX (gain) / loss	7	(154)	68
Share-based payments expense - employees (including NEDs)	7	3,217	336
Operating cash flows before movements in working capital:
(Increase) in trade and other receivables		(15,297)	(7,217)
Increase in trade and other payables		6,862	4,974
(Increase) / decrease in inventory		(283)	69
Net cash from / (used in) operating activities		24,439	(4,151)
INVESTING ACTIVITIES
Business acquisitions	4	(37,079)	(18,474)
Cash assumed on business acquisitions	4	-	262
Expenditures on property, plant & equipment		(9,465)	(229)
Disposal of property, plant & equipment		529	-
Expenditures on exploration and evaluation assets		(3,317)	(17,403)
Expenditure on decommissioning oil and gas assets	17	(648)	(131)
Tax credit for R&D expenditure	9	487	383
Net cash used in investing activities		(49,493)	(35,592)
FINANCING ACTIVITIES
Proceeds on issue of ordinary shares, net of issue costs	19	38,125	27,253
Interest and other finance charges paid	8	(448)	(114)
Lease payments	16	(30)	(10)
Dividends paid	19	(3,417)	-
Net cash from financing activities		34,230	27,129
Effect of exchange rate changes on cash		(19)	(278)
Net Increase / (decrease) in cash and cash equivalents		9,157	(12,892)
Cash and cash equivalents, beginning of year		6,178	19,070
CASH AND CASH EQUIVALENTS, END OF YEAR		15,335	6,178

Included within cash and cash equivalents is £315 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 the appraisal of oil and gas assets on the UK Continental Shelf and of oil and gas production in Western Canadian Sedimentary Basin.

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.

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 2021.

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 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 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 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 the Consolidated Statement of Comprehensive Income, 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 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 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

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 income statement. Where conditions giving rise to impairment subsequently being reversed, the effect of the impairment charge is also reversed as a credit to the income statement, net of any depreciation 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.

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.

Standard Interpretation	Description	Effective date for annual accounting period beginning on or after
IAS 1	Amendments - Presentation and Classification of Liabilities as Current or Non-current	TBC
IAS 16	Amendments - Property, Plant and Equipment	1 January 2022*
IAS 37	Provisions, Contingent Liabilities and Contingent Assets	1 January 2022*
IAS 8	Amendments - Definition of Accounting Estimates	1 January 2023*
IAS 1	Amendments - Disclosure of Accounting Policies	1 January 2023*
IFRS 3	Amendments - Business Combinations - Conceptual Framework	1 January 2022*
IFRS	Annual Improvements to IFRS Standards 2018-2020	1 January 2022*

*Subject to UK endorsement

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 2021, the Group held oil and gas E&E assets of £49.8 million (2020: £48.8 million), note 13. The carrying value of E&E assets are assessed for impairment when circumstances suggest that the carrying amount may exceed its recoverable value. In making this judgement the Management considers the indicators of impairment in the intangible exploration and evaluation asset accounting policies set out above. Management has considered the expiration of the P.1987 licence on 31 December 2020, prevailing commodity prices, and budgeted spend and future activity on the P2358 licence, concluding that these do not represent an indicator of impairment. Further discussion is provided in note 13. Refer to note 24 for discussion around the early-2022 farm-out of Serenity.

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

At 31 December 2021, the Group held oil and gas PP&E assets of £224.0 million (2020: £108.4 million), note 12, with the majority of the 2021 increase being acquired through the Cenovus acquisition which completed in the period, note 4. 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 2021 independent competent person's report, and increases in cost of capital which may indicate a higher discount rate is likely required in assessing the assets recoverable amount. 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 2021.

Fair value judgements for businesses acquired

The Group completed 1 business combination during the year ended 31 December 2021. Management has applied judgement in concluding that the Group had acquired a business in the Cenovus acquisition. In accordance with IFRS 3 'Business combinations', management has then applied judgement in estimating the fair value of assets acquired and liabilities assumed, which included estimates relating to oil and gas reserves, future production rates, oil and gas prices, operating and capital expenditure, decommissioning expenditure, and discount rates. Further details are provided in note 4. 

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.

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 as at 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 depreciation 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 had commenced the year with 54.0 MMboe of proved plus probable reserves and acquired a further 80.7 MMboe through the Cenovus acquisition. A 1.0 MMboe increase/decrease to each of these estimates would have decreased/increased the oil and gas depreciation charge for the period by £553 thousand, respectively.

Decommissioning costs

At 31 December 2021 the Group had recorded a decommissioning provision of £125.5 million (2020: £66.8 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 £18.5 million and £15.4 million, respectively. A 0.5% increase/decrease in the discount rate would have decreased/increased the decommissioning provision by £15.4 million and £18.6 million, respectively.

Recognition and measurement of deferred tax assets

At 31 December 2021, the Group held deferred tax liabilities of £7.5 million (2020: asset of £1.1 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 2021 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 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 statement of comprehensive income.

4  Business combinations

On 6 July 2021 ("Cenovus ASA Date") the Group through its wholly owned subsidiary i3 Energy Canada Limited ("i3 Canada") entered into a binding purchase and sale agreement to acquire certain petroleum and infrastructure assets (the "Cenovus Assets") from Cenovus Energy Inc. ("Cenovus") for gross consideration of CAD65.0 million (£37.1 million). The transaction completed on 20 August 2021 (the "Acquisition Date") at which point i3 obtained control of the Cenovus Assets, which include approximately 8,400 boepd (51% oil and NGLs) of predictable low-decline production, 79.5 MMboe of 2P reserves, an inventory of greater than 140 net drilling locations and 80 net reactivation opportunities across approximately 212,000 net acres, an 1,140 km network of operated pipelines, and key processing facilities. The acquisition enabled the Group to expand its Canadian operations through cash flow generating assets.

The Cenovus Assets are an integrated set of activities and assets that are capable of being managed and conducted for the purpose of providing a return, and therefore constitute a business. Accordingly, the transaction has been accounted for in accordance with IFRS 3 'Business Combinations' which requires the assets acquired and liabilities assumed to be recognised on the acquisition date at their fair value. 

The acquisition had an effective date of 1 April 2021 and therefore the acquisition price of CAD65 million was (i) reduced by CAD7.6 million for the income generated from the Cenovus assets between the "Economic Effective Date" of 1 May 2020 and the Acquisition Date; and (ii) increased by CAD0.9 million for interest accruing from the Economic Effective Date to the Acquisition Date at Canadian Prime + 1.0% on the Gross consideration. 

The fair value of oil and gas assets is estimated based on the pre-tax net present value of PDP reserves as derived from a reserves report by a firm of independent reservoir engineers dated 30 April 2021, re-run with an effective date of 20 August 2021 with an updated price deck, discounted at a rate of 10% which management determined to be representative of the risk profile of the assets, along with the market value of the seismic data acquired as estimated from the sale price of similar data. The fair value of the decommissioning provision is estimated based on rates published by the AER. These represent a level 3 valuation in the IFRS 13 fair value hierarchy as they are based on valuation techniques that use inputs which are not based on observable market data. The fair value of the assets acquired, and liabilities assumed exceed the consideration by £24.3 million, reflecting the gain on bargain purchase which has been recorded in the statement of comprehensive income. It is likely that the gain on bargain purchase arose due to the oil price recovery between the date the purchase price was agreed and the acquisition date. Further details of the transaction are provided in the Strategic Report.

The amounts recognised in respect of the identifiable assets acquired and liabilities assumed are as set out in the table below.

	20 August 2021 £'000
Net consideration to allocate	33,264
Property, plant, and equipment - oil and gas assets	117,416
Inventory	218
Prepaid expenses	979
Decommissioning provisions	(53,840)
Deferred tax liability	(7,247)
Gain on bargain purchase	(24,262)
Total	33,264

The Cenovus assets contributed £23.2 million revenue (net of royalties) and £16.8 million to the Group's net operating income for the period between the acquisition date and the reporting date. If the acquisition of the Cenovus assets had been completed on the first day of the financial year, Group revenues for the year would have been £118.4 million and Group net operating income would have been £66.3 million. Net operating income is a non-IFRS measure, refer to Appendix B. It is considered impractical to present the impact on profit as if the acquisition had competed on the first day of the financial year as it would require estimation of commercial reserves, future development costs, various judgements over the decommissioning provision, and certain administrative costs, all of which are not readily available to Management, and therefore the impact on net operating income has been presented instead.

Acquisition costs of £0.3 million (2020 - £1.5 million) relating to the acquisition have been recognised in the statement of comprehensive income.

A gain on asset dispositions arose upon the sale of certain oil and gas assets. Further details are provided in note 12.

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

	2021 £'000	2020 £'000
Gain on bargain purchase	24,262	25,211
Gain on asset dispositions	751	-
Gain on bargain purchase and asset dispositions	25,013	25,211

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 2021:

	UK / Corporate £'000	Canada £'000	Total £'000
Revenue	-	86,763	86,763
Production costs	-	(37,945)	(37,945)
Loss on risk management contracts	-	(5,485)	(5,485)
Depreciation and depletion	(4)	(21,639)	(21,643)
Gross (loss) / profit	(4)	21,694	21,690
Administrative expenses	(7,059)	(6,035)	(13,094)
Acquisition costs	-	(256)	(256)
Gain on bargain purchase and asset dispositions	-	25,013	25,013
Operating profit	(7,063)	40,416	33,353
Finance costs	(5,930)	(1,679)	(7,609)
(Loss) / profit before tax	(12,993)	38,737	25,744
Tax (charge) / credit for the year	487	(1,148)	(661)
(Loss) / profit for the year	(12,506)	37,589	25,083

The following is an analysis of the Group's revenue and results by reportable segment in 2020:

	UK / Corporate £'000	Canada £'000	Total £'000
Revenue	-	12,991	12,991
Production costs	-	(8,075)	(8,075)
Depreciation and depletion	(5)	(4,849)	(4,854)
Gross (loss) / profit	(5)	67	62
Administrative expenses	(3,335)	(2,420)	(5,755)
Acquisition costs	(989)	(553)	(1,542)
Bargain purchase gain	5,962	19,249	25,211
Operating profit	1,633	16,343	17,976
Finance costs	(7,108)	(260)	(7,368)
(Loss) / profit before tax	(5,475)	16,083	10,608
Tax credit for the year	383	727	1,110
(Loss) / profit for the year	(5,092)	16,810	11,718

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:

	UK / Corporate £'000	Canada £'000	Total £'000
Total assets	50,129	266,161	316,290
Total liabilities	(25,733)	(152,391)	(178,124)
Capital expenditure - E&E	1,010	-	1,010
Capital expenditure - PP&E	-	11,184	11,184

The following is an analysis of the Group's assets and liabilities by reportable segment as at 31 December 2020 and the capital expenditure for the year then ended:

	UK / Corporate £'000	Canada £'000	Total £'000
Total assets	48,932	125,189	174,121
Total liabilities	(24,160)	(76,765)	(100,925)
Capital expenditure - E&E	2,281	-	2,281
Capital expenditure - PP&E	-	697	697

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:

	2021 £'000	2020 £'000
Oil and natural gas liquids	61,027	7,274
Natural Gas	34,994	5,978
Royalties	(12,094)	(830)
Revenue from the sale of oil and gas	83,927	12,422
Processing income	2,605	569
Other operating income	231	-
Total revenue	86,763	12,991

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 2021, four (2020: three) customers individually totalled more than 10% of total revenues, totalling 79% (2020: 70%) in aggregate.

7  Administrative expenses

	2021 £'000	2020 £'000
Directors' fees	300	229
Employee costs*	8,503	2,879
Professional fees**	1,728	1,207
Other	2,448	1,388
Realised FX loss / (gain)	269	(16)
Unrealised FX (gain) / loss	(154)	68
Total administrative expenses	13,094	5,755

* Group staff costs comprised:

	2021 £'000	2020 £'000
Wages, salaries, and benefits	6,027	3,185
Social security costs	336	44
Other pension costs	254	64
Share-based payments expense - employees (including NEDs)	3,217	336
Total staff costs	9,834	3,629
Capitalised salaries and overhead recoveries	(1,331)	(750)
Charge to the profit or loss	8,503	2,879

i3 Energy plc had no staff during the year ended 31 December 2021 (2020 - Nil) and therefore no payments were made.  The 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:

Average number of persons employed	2021 Number	2020 Number
Operations	29	13
Corporate and administration	18	7
Total	47	20

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

	2021 £'000	2020 £'000
Audit services
The audit of the Company's annual accounts	120	80
The audit of the Company's subsidiaries	-	-
Total audit fees	120	80
Reporting accountant work in relation to 2020 admission documents	-	170
Total	120	250

8  Finance costs

	2021 £'000	2020 £'000
Accretion of loan notes ( note 16 )	2,824	2,355
Interest expense on loan notes ( note 16 )	3,144	2,487
Stock-based compensation - warrants ( note 20 )	451	2,198
Unwinding of discount on decommissioning provision ( note 17 )	1,539	214
Bank charges and interest on creditors	374	114
(Gain) / loss on BHGE DPIB ( note 15 )	(723)	-
Total finance costs	7,609	7,368

9  Taxation

Taxation credit

The below table reconciles the tax charge for the year to the expected tax charge based on the result for the year and the corporation tax rate.

	2021 £'000	2020 £'000
Profit before income tax	25,744	10,608
Rate of Corporate Tax	40%	40%
Expected tax charge	10,298	4,243
Effects of:
Interest and other not deductible for SCT	620	491
Permanent differences	(3,804)	(4,415)
Foreign tax rate difference	(6,585)	(3,747)
Change in estimated pool balances	179	-
Derecognition of deferred tax asset	440	2,701
R&D tax credit received	(487)	(383)
Total income tax charge / (credit)	661	(1,110)

Of which:	2021 £'000	2020 £'000
Current tax (credit) - prior years	(487)	(383)
Deferred tax charge / (credit) - current year	1,148	(727)
Total income tax charge / (credit)	661	(1,110)

During the year the Group received £487 thousand in R&D tax refunds in the UK in respect of the 2019 fiscal year. The difference on foreign tax rate results from the 23% rate of corporate taxation at its Canadian subsidiary.

Deferred tax

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

	At 31 December 2020	Acquired during the year	Recognised in income	FX movement	At 31 December 2021
	£'000	£'000	£'000	£'000	£'000
UK:
Deferred tax assets:
Losses	25,764	-	2,947	-	28,711
Valuation allowance	(6,238)	-	(2,544)	-	(8,782)
Deferred tax liabilities:
PP&E	(19,526)	-	(403)	-	(19,929)
Net deferred tax asset	-	-	-	-	-
Canada:
Deferred tax assets:
Decommissioning provision	15,360	12,383	679	448	28,870
Losses	5,625	-	(3,263)	54	2,416
Risk management contracts	-	-	25	-	25
Other	157	-	48	2	207
Valuation allowance	(7,912)	-	2,360	(87)	(5,639)
Deferred tax liabilities:
PP&E	(12,178)	(19,630)	(997)	(560)	(33,365)
Net deferred tax asset	1,052	(7,247)	(1,148)	(143)	(7,486)
Net deferred tax asset / (liability)	1,052	(7,247)	(1,148)	(143)	(7,486)

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 the Cenovus acquisition of £7,247 thousand, and a deferred tax charge of £1,148 thousand for changes in net deductible temporary differences in 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.

	31 December 2021 £'000	31 December 2020 £'000
UK:
Taxable losses	29,325	20,585
Mineral extraction allowances	49,819	48,809
	79,144	69,394
Canada:
Canadian exploration expense	3,107	3,068
Canadian development expense	7,519	4,698
Canadian oil and gas property expense	56,391	39,311
Undepreciated capital cost	11,991	8,383
Non-capital losses	10,503	24,456
Other	833	684
Total	90,344	80,600

10  Directors' remuneration

	Salary / Fees	Bonus	Share based payments	Total
	£'000	£'000	£'000	£'000
2021 Executive Directors
Majid Shafiq	384	438	252	1,074
Graham Heath	319	358	156	833
Non-Executive Directors
Neill Carson	60	-	51	111
Richard Ames	60	-	51	111
Linda Beal	120	-	45	165
John Festival	60	-	13	73
Total	1,003	796	568	2,367
2020 Executive Directors	Salary / Fees	Bonus	Share based payments	Total
Majid Shafiq	313	389	-	702
Graham Heath	244	329	-	573
Non-Executive Directors
David Knox	22	-	-	22
Neill Carson	57	-	-	57
Richard Ames	54	-	-	54
Linda Beal	70	-	-	70
John Festival	6	-	-	6
Total	766	718	-	1,484

Share based payments represents 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. The comparative figures for 2020 have also been presented on this basis.

During the year the Company contributed £2 thousand to i3's CEO's pension scheme (2020 - £3 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:

	Year Ended 31 December 2021	Year Ended 31 December 2020
Earnings
Earnings for the purposes of basic and diluted earnings per share being net profit attributable to owners of i3 Energy (£'000)	25,083	11,718
Weighted average number of shares
Weighted average number of Ordinary Shares - basic	883,664,352	309,889,077
Effect of dilutive potential ordinary shares:
Share options	49,369,708	2,399,909
Warrants	32,758,752	26,700,708
Weighted average number of Ordinary Shares - diluted	965,792,812	338,989,694
Basic earnings / (loss) per share (pence)	2.84	3.78
Diluted earnings / (loss) per share (pence)	2.60	3.46

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.

In 2020, prior to the option and warrant repricing on 28 October 2020 and 23 June 2020 (note 20), respectively, these instruments were anti-dilutive as their exercise prices exceeded the average market price of the Ordinary Shares over this period. The Share options and Warrants were dilutive following their re-pricing and their impact is presented in the table above.

12  Property, plant, and equipment

	Oil and gas assets	Right of use assets	Other fixed assets	Total
Cost
As at 1 January 2020	-	-	22	22
Acquisitions	114,826	-	-	114,826
Additions	697	110	-	807
Changes to decommissioning estimates	(2,310)	-	-	(2,310)
Decommissioning settlements under SRP and ASCP ( note 17 )	(104)	-	-	(104)
Exchange movement	84	(2)	-	82
As at 31 December 2020	113,193	108	22	113,323
Acquisitions	122,762	-	-	122,762
Additions	11,184	-	50	11,234
Disposals	(8,242)	-	-	(8,242)
Changes to decommissioning estimates	7,603	-	-	7,603
Decommissioning settlements under SRP and ASCP ( note 17 )	(324)	-	-	(324)
Exchange movement	3,857	1	-	3,858
As at 31 December 2021	250,033	109	72	250,214
Accumulated depreciation
As at 1 January 2020	-	-	(14)	(14)
Charge for the year	(4,843)	(6)	(5)	(4,854)
Exchange movement	54	-	-	54
As at 31 December 2020	(4,789)	(6)	(19)	(4,814)
Charge for the year	(21,611)	(27)	(5)	(21,643)
Disposals	481	-	-	481
Exchange movement	(158)	-	-	(158)
As at 31 December 2021	(26,077)	(33)	(24)	(26,134)
Carrying amount at 31 December 2020	108,404	102	3	108,509
Carrying amount at 31 December 2021	223,956	76	48	224,080

During the year, i3 disposed of certain assets in its Weyburn, Marten Creek, and Drayton Valley areas for net proceeds of £529 thousand. After removing the associated decommissioning obligations, a resulting gain on disposition of £751 thousand has been recognised in the consolidated statement of comprehensive income.

Right of use assets consist of certain field vehicles whose leases commenced in September 2020.

13  Exploration and evaluation assets (Intangible)

	Year Ended 31 December 2021 £'000	Year Ended 31 December 2020 £'000
At start of year	48,809	46,528
Additions	1,010	2,281
At end of year	49,819	48,809

The Directors have considered the carrying value of the exploration and evaluation assets as at 31 December 2021 and concluded that no indicators of impairment arose during the period. In reaching this conclusion, the Directors have given particular attention to the relinquishment of UKCS Licence P.1987 which reached the end of its two-year second term on 31 December 2020. Licence P.1987 encompasses UK Block 13/23d which contains contingent resources for the Group's Liberator asset, which have been evaluated as sub-commercial by i3 and in an 'independent competent person' report and as such do not represent a viable commercial development. i3 may choose to re-apply for Licence P.1987 licence in the future if justified by its appraisal of the Liberator West / Minos High prospective areas and/or the Serenity discovery. The relinquishment will result in a significant saving in licence fees whilst i3 progresses its appraisal of resources on its adjoining P.2358 Licence.

This relinquishment has no impact on Licence P.2358, which commenced its four-year second term on 30th September 2020 and contains the vast majority of the resources and potential reserves in the Company's UK acreage. Licence P.2358 includes the Serenity discovery and the Liberator West and Minos High prospective areas, which will be the focus of plans for appraisal and exploration drilling.

Management also considered the active farm-out discussion which were ongoing at 31 December 2021, which ultimately led to an agreement with a new joint venture partner in early-2022. Further details are provided in note 24 .

14  Trade and other receivables

	31 December 2021 £'000	31 December 2020 £'000
Trade receivables	21,982	6,295
Sales tax receivables	-	46
JV receivables	1,483	864
Prepayments & other receivables	2,038	1,526
Total trade and other receivables	25,503	8,731

All receivables are all due within one year.

JV receivables represent amounts due from operating partners for operating and capital activity in Canada.

The fair value of 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

	31 December 2021 £'000	31 December 2020 £'000
Trade creditors	5,169	7,780
Sales tax payable	65	-
Accruals	13,565	5,146
JV payables	910	230
Total trade and other payables	19,709	13,156

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.

JV 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 £3.0 million 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 Company 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 ).

The future Market Value reduction of the payable amount will vary with the trading value of i3 shares and therefore represents an embedded derivative. The entire combined contract is designated as at FVTPL. The fair value of £1,789 thousand has been 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 against the DPIB balance, less the Market Value of the Warrant Shares of £723 thousand, which totals the 5,277,045 Warrant Shares as at the 31 December 2021 share price of 13.35p/share and £19 thousand of dividends paid to the Warrant Shares.  The fair value of the combined contract is classified as Level 2 in the fair value hierarchy as defined by IFRS 13 'Fair value measurements'. £1,232 thousand is expected to be paid in 2022 has been classified as a current liability (31 December 2020: nil), and the remaining £557 thousand has been classified as a non-current liability (31 December 2020: £3.0 million). A reconciliation of the balance is as follows:

	Year Ended 31 December 2021 £'000	Year Ended 31 December 2020 £'000
At start of year	3,000	3,000
Exercise value of the Warrant Shares	(1)	-
Cash payments made during the year	(487)	-
Non-cash change in market value of the Warrant Shares ( note 8 )	(723)	-
At end of year	1,789	3,000

	31 December 2021 £'000	31 December 2020 £'000
Of which:
Current, within trade accounts payable	1,232	-
Non-current	557	3,000
Total	1,789	3,000

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 Company's option (i) in cash at a rate of 8% per annum, or (ii) in kind (at i3's option) at a rate of 11% per annum by the issuance of additional H1-2019 LNs.

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.

	Notional amount of warrants ( £)		Exercise price upon issuance ( £/share)		Shares to be issued upon exercise of warrants		Share price at issuance ( £)		Time to maturity (years)		Value ( £/share)
Tranche 1	7,333,333		0.4070		18,018,018		0.39		4		0.2557
Tranche 2	7,333,333		0.4810		15,246,015		0.39		4		0.2435
Tranche 3	7,333,333		0.5550		13,213,213		0.39		4		0.2313

Total fair value of the Tranche 1, Tranche 2 and Tranche 3 warrants on issuance was £11,375,184 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 i3's option). At inception the debt component was recorded at an estimated fair value of £10,624,816. 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.

On the 23 June 2020 the Company amended the 30 April 2020 Development Funding Long-stop Date (previously amended on 8 November 2019 when the Majority Noteholders of the Company's secured loan notes agreed to extend the date by which the Company must either inter into a reserves-based lending facility or find an alternative means of funding to achieve first oil from the Liberator field, to 30 April 2020). As the Company was not in a position to enter into such a facility by 30 April 2020, the Company and the Majority Noteholders have come to an agreement to waive this condition in return for certain amendments to the May 2019 Loan Note Instrument and the associated Warrant Instruments.

The Loan Note Instrument Amendments are as follows:

The obligation to enter into a development facility for Liberator by a certain date has been removed. A new Corporate Development Long-stop Date had been set for 30 September 2020 prior to which i3 has to achieve one of the following Corporate Development Longstop Conditions:

· Secure firm irrevocable commitments for a minimum £15 million of unsecured or fully subordinated financing, subject only to closing mechanics; or

· Agree a farm-out and/or funding term sheet, subject only to legal documentation to fund the drilling of a least one appraisal well on Serenity during 2020 or 2021; or

· Execute an acquisition agreement for at least 2500 boepd of production net to i3.

In addition, the Company has an obligation to achieve net corporate production at or above 5000 boepd by 30 April 2021. These requirements were met with the completion of the Gain acquisition on 3 September 2020.

The Loan Note Instrument amendments include the requirement that the currently outstanding i3 management options will be cancelled, and replacement options will be issued to i3 staff and Directors which replicate the terms of the adjusted Loan Note warrants (the "New Options") in relation to the exercise price, to seek alignment between the Noteholders and management (note 20).

The Warrant Instrument Amendments are as follows:

All warrants associated with the Loan Notes will have their strike prices reset to the nominal value of i3 shares (£0.0001/share). The Company calculated the difference in the fair value of the unmodified and modified warrants at the modification date of June 23, 2020, resulting in an additional expense of £2,199 thousand recognised in share-based payment expense in 2020 (note 20). 40,140,172 H1-2019 LN Warrants were exercised in 2021 (note 20).

The H1-2019 LNs are redeemable before the maturity date and the holders are secured against the Group's assets. The Company may repay all or part of the H1-2019 LNs within the first 12 months at 116% of par and at par plus accrued interest thereafter. The fair value of the repayment option is nil at 31 December 2021.

Interest expense and accretion expense to 31 December 2021 was £3,144 thousand and £2,824 thousand respectively.

Borrowings reconciliation

	H1-2019 LN	Leases	Total
	£'000	£'000	£'000
At 31 December 2019	13,046	-	13,046
New leases	-	110	110
Increase through interest (non-cash)	2,486	1	2,487
Accretion expense (non-cash)	2,355	-	2,355
Lease payments (cash)	-	(10)	(10)
Exchange movement (non-cash)	-	(2)	(2)
At 31 December 2020	17,887	99	17,986
Increase through interest (non-cash)	3,144	2	3,146
Accretion expense (non-cash)	2,824	-	2,824
Lease payments (cash)	-	(30)	(30)
Exchange movement (non-cash)	-	(2)	(2)
At 31 December 2021	23,855	69	23,924

	H1-2019 LN	Leases	Total
	£'000	£'000	£'000
Of which:
Current	-	69	69
Non-current	23,855	-	23,855
At 31 December 2021	23,855	69	23,924

17  Decommissioning provision

	Year Ended 31 December 2021 £'000	Year Ended 31 December 2020 £'000
At start of year	66,783	-
Liabilities assumed through acquisitions	56,350	69,092
Liabilities incurred	312	-
Liabilities disposed	(7,984)	-
Liabilities settled	(670)	(109)
Liabilities settled under SRP and ASCP	(324)	(104)
Change in estimates	7,603	(2,310)
Unwinding of discount ( Note 8 )	1,539	214
Exchange movement	1,914	-
At end of year	125,523	66,783

	31 December 2021 £'000	31 December 2020 £'000
Of which:
Current	2,368	1,234
Non-current	123,155	65,549
Total	125,523	66,783

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

	31 December 2021	31 December 2020
Undiscounted / uninflated cash flows (CAD, thousands)	207,371	122,926
Inflation rate	1.82%	1.00%
Discount rate	1.68%	1.21%
Timing of cash flows	1-50 years	1-50 years

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 a corresponding decrease to the decommissioning asset was recorded. The change in estimate for the year ended 31 December 2021 was primarily driven by changes in market interest and inflation rates as published by the Bank of Canada.

18  Risk management contracts

In 2021, the Group entered a variety of 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 2021 are presented in the table below. 

Type	Effective date	Termination date	Total Volume	Avg. Price
AECO 5A Financial Swaps	1 Nov 2021	31 Mar 2022	10,000 GJ/Day	CAD 4.0975 / GJ
AECO 5A Physical Swaps	1 Nov 2021	31 Mar 2022	15,000 GJ/Day	CAD 4.3313 / GJ
AECO 5A Physical Swaps	1 Apr 2022	31 Dec 2022	9,000 GJ/Day	CAD 3.6244 / GJ
Chicago Physical Basis Differential	1 Dec 2021	31 Mar 2022	5,000 MMBtu/Day	(USD 1.0450) / MMBtu
WTI Financial Swaps	1 Jan 2022	31 Mar 2022	350 bbl/Day	CAD 83.04 / bbl
WTI Financial Swaps	1 Apr 2022	31 Dec 2022	500 bbl/Day	CAD 87.86 / bbl
Purchased WTI Put Option *	1 Jan 2022	31 Dec 2022	1,000 bbl/Day	CAD 92.20 / bbl
Conway Financial Swaps	1 Jan 2022	31 Dec 2022	500 bbl/Day	USD 1.1175 / gal

* The purchased WTI put option has a strike price of CAD 92.20 / bbl and a premium of CAD 11.00 / bbl. The option premium has been deferred over the effective period of 1 January 2022 to 31 December 2022 and the resulting liability is included in the net carrying value of the financial instrument as of 31 December 2021.

The Group's losses on risk management contracts are presented in the following table. 

	2021 £'000	2020 £'000
Unrealised loss on risk management contracts	111	-
Realised loss on risk management contracts	5,374	-
Total	5,485	-

19  Authorised, issued and called-up share capital

	Issuance date	Ordinary shares	Deferred shares	Nominal value per Share	Ordinary shares	Deferred shares	Share premium before share issuance costs	Share issuance costs	Share premium after Share issuance costs
		Shares	Shares	£	£'000	£'000	£'000	£'000	£'000
At 31 December 2019		107,719,400	5,000	-	11	50	33,965	(1,393)	32,572
Warrants exercised at 0.01 pence/share	24 Aug 20	6,788,945	-	0.0001	1	-	1,661	-	1,661
Issued at 5 pence/share	28 Aug 20	581,147,255	-	0.0001	58	-	29,000	(1,806)	27,194
Issued for Toscana acquisition	30 Oct 20	4,399,215	-	0.0001	-	-	178	-	178
At 31 December 2020		700,054,815	5,000	-	70	50	64,804	(3,199)	61,605
Issued on exercise of 0.01 pence H1-2019 warrants	Various	40,140,172	-	0.0001	4	-	7,669	-	7,669
Issued on exercise of 0.01 pence options	Various	15,303,960	-	0.0001	2		-	-	-
Issued on exercise of 5 pence options	Various	1,700,000	-	0.0001	-	-	85	-	85
Issued on exercise of 0.01 pence BHGE warrants	4 Jun 21	5,277,045	-	0.0001	1	-	903	-	903
Capital reduction *	6 Jul 21	-	-	-	-	-	(67,255)	3,199	(64,056)
Issued at 11 pence/share	27 Jul 21	363,700,000	-	0.0001	36	-	39,970	(2,000)	37,970
Issued on exercise of 11 pence EMI options	1 Oct 21	250,000	-	0.0001	-	-	27	-	27
At 31 December 2021		1,126,425,992	5,000	-	113	50	46,203	(2,000)	44,203

* On 6 July 2021 the Registrar of Companies registered the cancellation of i3's share premium account. The £64.1 million balance of the Group's share premium net of share issuance costs was accordingly transferred to retained earnings. This created distributable reserves and enables the Company to become dividend paying.

The ordinary shares confer the right to vote at general meetings of the Company, to a repayment of capital in the event of liquidation or winding up and certain other rights as set out in the Company's articles of association.

The deferred shares do not confer any voting rights at general meetings of the Company and do confer a right to a repayment of capital in the event of liquidation or winding up, they do not confer any dividend rights or any of redemption.

£3.4 million of dividends were proposed and paid in 2021 (2020 - Nil) as follows:

Declaration date	Ex-Dividend date	Record date	Payment date	Dividend per share	Total Dividend
				(pence)	£'000
8 July 2021	15 July 2021	16 July 2021	6 August 2021	0.16	1,163
27 September 2021	7 October 2021	8 October 2021	29 October 2021	0.20	2,254
Total					3,417

20  Share-based payments

During the year the Group had share based payment expense of £3,668 thousand (2020: £2,534 thousand). 

Employee and NED Share Options

During the year the Group had share based payment expense relating to the issuance of share options of £3,217 thousand (2020: £335 thousand). Details on the employee and NED share options outstanding during the period are as follows:

	Number of options	Weighted average exercise price	Weighted average contractual life
		(pence)
At 31 December 2019	12,252,013	46.03	8.91
Cancelled - 28 October 2020	(12,252,013)	46.03	8.09
Issued - 28 October 2020	12,128,955	0.01	4.00
Issued - 3 December 2020	4,028,659	0.01	4.00
At 31 December 2020	16,157,614	0.01	3.85
Issued - 10 January 2021	13,166,358	6.10	10.00
Issued - 10 January 2021	75,184,252	5.00	10.00
Issued - 30 July 2021	57,121,402	11.00	10.00
Issued - 16 December 2021	1,625,000	11.00	10.00
Exercised during the year	(17,003,960)	0.51	3.98
Forfeited during the year	(2,290,291)	7.62	9.75
At 31 December 2021	143,960,375	7.48	9.22

On 10 January 2021, the Company issued options over a total of 75,184,252 ordinary shares as described in the Gain-related Readmission document released on 11 August 2020. The options were issued in accordance with the rules of the Company's Employee Share Option Plan at an exercise price of 5 pence per share. Of the options issued to employees of i3 Canada.  One-third of the options vested immediately, with a further one-third vesting in July 2021 if production exits at or above 9,000 boepd, and 100 per cent will vest if there is an addition of 5,000 boepd or, alternatively, 25 MMboe 2P reserves. Of the options issued to employees of i3 North Sea Limited, one-third of the options vested immediately, with a further one-third vesting at the spud of the next Serenity / Liberator appraisal well, and 100 per cent will vest upon a third-party reserve auditor attributing 25 MMbbls 2P post drilling of a Serenity / Liberator appraisal well.  The options will otherwise fully vest on the third anniversary. Of the options issued to the Executive and Non-Executive Directors and one corporate employee, one-third of the options vested immediately, with a further one-third vesting upon the earlier of spud of the next Serenity or Liberator appraisal well; and July 2021 production exits being at or above 9,000 boepd, and 100% will vest upon the earlier of a third-party reserve auditor attributing 25 MMbbls 2P post drilling of a Serenity or Liberator appraisal well and the addition of 5,000 boepd or 25 MMboe 2P reserves. The fair value was calculated using the Black Scholes model with inputs for stock price of 6.10 pence, exercise price of 5.0 pence, time to maturity of 10 years, volatility of 114%, the Risk-Free Interest rate of 0.360%, and a dividend yield of 11%. The resulting fair value of £1,384 thousand will be expensed over the expected vesting period.

On 10 January 2021, the Company also issued options over a total of 13,166,358 ordinary shares to key staff that joined its Canadian subsidiary, i3 Energy Canada Ltd., following the acquisition of Gain's oil & gas assets. The options were issued in accordance with the rules of the Company's Employee Share Option Plan at an exercise price of 6.1 pence per share, the closing price on 8 January 2021The fair value was calculated using the Black Scholes model with inputs for share price of 6.1 pence, exercise price of 6.1 pence, time to maturity of 10 years, volatility of 114%, the Risk-Free Interest rate of 0.360%, and a dividend yield of 11%. The options contain the same vesting conditions as the 5 pence options for employees of i3 Canada as described in the paragraph above. The resulting fair value of £240 thousand will be expensed over the expected vesting period.

On 30 July 2021, the Company issued options over a total of 53,705,491 ordinary shares to i3 staff and board and has additionally issued 1,750,000 options to incoming staff and conditionally allocated 3,750,000 for additional hires as part of the Acquisition. A total of 57,121,402 options were ultimately issued. The options were issued in accordance with the rules of the Company's Employee Share Option Plan at an exercise price of 11 pence per share. Of the options issued to employees of i3 Canada, one-third of the options vested immediately, with a further one-third vesting if production of 20,000 boepd is achieved prior to July 2022 (substantially funded from internally generated cash flow); and 100 per cent will vest upon the addition of 9,250 boepd or 50 MMboe 2P reserves. Of the options issued to employees of i3 North Sea Limited, one-third of the options vested immediately, with a further one-third vesting at spud of the earlier of a second appraisal well or first development well at either Serenity or Liberator, and 100 per cent will vest upon the addition of 2,500 boepd of European production. Of the options issued to the Executive and Non-Executive Directors and one corporate employee, one-third of the options vested immediately, with a further one-third vesting (i) at spud of the earlier of a second appraisal well or first development well at either Serenity or Liberator; or (ii) if production of 20,000 boepd is achieved prior to July 2022 (substantially funded from internally generated cash flow), whichever is first to occur, and 100 per cent will vest upon (i) the addition of 2,500 boepd of European production; or (ii) the addition of 9,250 boepd or 50 MMboe 2P reserves, whichever is first to occur. The fair value was calculated using the Black Scholes model with inputs for stock price of 10.95 pence, exercise price of 11.0 pence, time to maturity of 10 years, volatility of 110%, the Risk-Free Interest rate of 0.647%, and a dividend yield of 6%. The resulting fair value of £3,202 thousand will be expensed over the expected vesting period.

On 16 December 2021, the Company issued options over a total of 1,625,000 to new employees of i3 Canada. The vesting conditions mirror those of the 30 July 2021 grant described above, except for the first one-third of options vesting on the 6-month employment anniversary rather than immediately.

In addition, to incentivise the UK and Canadian offices of the Enlarged Group to work as one team and assist each other as required going forward, if one of the offices satisfies one of the early vesting criteria for the options described above then the equivalent vesting criteria for the other office shall be deemed 20 per cent satisfied (and a further 6.67 per cent. of the options held by employees in the other office would vest immediately).

All options issued on 10 January 2021, 30 July 2021, and 16 December 2021 will otherwise fully vest on the third anniversary of their grant dates.

99,721,892 outstanding employee share options as at 31 December 2021 were fully vested and exercisable.

Warrants

During the year the Group had share based payment expense relating to the modification and issuance of warrants of £451 thousand (2020: £2,198 thousand). Details on the warrants outstanding during the period are as follows:

	Number of warrants	Weighted average exercise price	Weighted average contractual life
		(pence)
At 31 December 2019	65,483,293	46.98	3.04
Modified - 23 June 2020	(55,981,044)	46.09	2.67
Modified - 23 June 2020	55,981,044	0.01	2.67
Exercised - 24 August 2020	(6,788,945)	0.01	2.77
At 31 December 2020	58,694,348	5.27	1.98
BHGE warrants modified - 17 May 2021	(5,277,045)	56.85	0.34
BHGE warrants modified - 17 May 2021	5,277,045	0.01	0.34
BHGE warrants exercised - 17 May 2021	(5,277,045)	0.01	0.3
H1-2019 LN warrants exercised throughout the year	(40,140,172)	0.01	1.34
At 31 December 2021	13,277,131	15.07	1.85

On 17 May 2021, i3 announced that it had successfully restructured legacy contracts and agreements for equipment, oil field services, and warrants with BHGE. This resulted in the exchange of 5,277,045 warrants with a strike price of 56.85 pence for Ordinary Shares with a nominal value of 0.01 pence. Further details are provided in Note 15.

EMI Options

The Company operates an Employee Management Incentive (EMI) share option scheme. Grants were made on 14th April 2016 and 6th December 2016. The scheme is based on eligible employees being granted EMI options. The right to exercise the option is at the employee's discretion for a ten-year period from the date of issuance.

250,000 options were exercised on 1 October 2021 at a price of £0.11 per share. 250,000 options remain outstanding and were exercisable at both 31 December 2021 and 2020 at a price of £0.11 per share. If the options remain unexercised after a period of ten years from the date of grant the options expire. Employees who leave i3 Energy have 60 days to exercise the Options prior to them being forfeited. The options outstanding at 31 December 2021 have a weighted average exercise price of £0.11 and a weighted average remaining contractual life of 4.93 years.

21  Related party transactions

Transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not disclosed in this note.

Remuneration of Key Management Personnel

Directors of the Group are considered to be Key Management Personnel. The remuneration of the Directors is set out in note 10.

Ultimate parent

There is no ultimate controlling party of the Group.

22  Financial instruments, financial and capital risk management

Financial instruments

Fair value measurements

The Group carries risk management contracts, and following its modification in May 2021, non-current accounts payable at FVTPL. The fair value of the risk management contracts is determined by discounting at a risk-free rate the difference between the contracted prices and the published forward curves at the reporting date. The fair value of non-current accounts payable is determined by subtracting the value of the Warrant Shares, being the 5,277,045 Warrant Shares multiplied by the higher of (i) the quoted price of one i3 share at the reporting date, and (ii) the 5-day volume weighted average value of one i3 share during the 5-day dealing period to 17 September 2021, from the remaining Deferred Payment Invoice Balance. The risk management contracts and non-current accounts payable are classified as Level 2 valuations within the fair value hierarchy as defined by IFRS 13 Fair Value Measurement which is as follows:

· Level 1 fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities;

· Level 2 fair value measurements are those derived from inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e., as prices) or indirectly (i.e., derived from prices); and

· Level 3 fair value measurements are those derived from valuation techniques that include inputs for the asset or liability that are not based on observable market data (unobservable inputs).

There were no financial assets or liabilities measured at Level 1 or 3 or reclassified between Levels 1, 2 or 3 during the year. 

The fair value of the Group's financial assets and liabilities approximate to their carrying amounts at the reporting date.  The following tables combine information about the Group's classes of financial instruments and their fair value and carrying amounts at the reporting date.

As at 31 December 2021	Carried at FVTPL	Carried at amortised cost
Financial assets
Cash and cash equivalents	-	15,335
Trade and other receivables	-	25,792
Risk management contracts (Level 2)	814	-
Total	814	41,127
Financial liabilities
Trade and other payables	1,232	17,746
Risk management contracts (Level 2)	925	-
Borrowings and leases	-	23,924
Non-current accounts payable (Level 2)	557	-
Total	2,714	41,670

As at 31 December 2020	Carried at FVTPL	Carried at amortised cost
Financial assets
Cash and cash equivalents	-	6,178
Trade and other receivables	-	8,731
Deposit	-	678
Total	-	15,587
Financial liabilities
Trade and other payables	-	13,156
Borrowings and leases	-	7,986
Non-current accounts payable	-	3,000
Total	-	24,142

Financial Risk Management

Financial Risk Factors

The Group's activities expose it to a variety of financial risks; market risk (including foreign currency risk and price risk), credit risk and liquidity risk. The Group's overall risk management programme focuses on the unpredictability of financial markets and seeks to minimise potential adverse effects on the Group's financial performance.

Risk management is carried out by the Board of Directors under policies approved at Board meetings. The Board frequently discusses principles for overall risk management including policies for specific areas such as foreign exchange.

a  Market Risk

i  Foreign Exchange Risk

The Group is exposed to foreign exchange risk arising from various currency exposures, primarily with respect to the UK pound sterling and the Canadian dollar and US Dollar. Foreign exchange risk arises from recognised monetary assets and liabilities (USD and CAD bank accounts) where they may be denominated in a currency that is not the local functional currency. The Group mitigates is foreign exchange exposure by holding monetary assets and liabilities primarily in the local functional currency. All of the monetary assets and liabilities held by the Group's Canadian operations were held in CAD, the functional currency, and therefore there is no foreign exchange exposure in the Canadian operations. The UK operations did not hold significant monetary assets or liabilities as at 31 December 2021.

The Group is also exposed to exchange differences on translation of its foreign operations in Canada, which resulted in a gain of £1,511 thousand for the year ended 31 December 2021 (2020: £185 thousand). A 10% strengthening of GBP against CAD as at 31 December 2020 would have resulted in a loss on translation of £8,876 thousand (2020: £4,522 thousand), and a 10% weakening of GBP to CAD would have resulted in a gain of £14,222 thousand (2020: £5,201 thousand). Profit after tax would not be impacted.

b  Credit Risk

Credit risk arises from cash and cash equivalents and trade receivables from the sale of hydrocarbons. It is Group policy to assess the credit risk of new customers.

The Group considers the credit ratings of banks in which it holds funds in order to reduce exposure to credit risk. The Group will only keep its holdings of cash with institutions which have a minimum credit rating of 'A'. The Group sells hydrocarbons to reputable purchasers and are settled the month following their sale. Long-term deposits for decommissioning provisions are lodged with government bodies. The carrying value of cash and cash equivalents and trade and other receivables represents the Group's maximum exposure to credit risk at year end.

The Group considers that it is not exposed to major concentrations of credit risk.

The Group holds cash as a liquid resource to fund its obligations. The Group's cash balances are held in Sterling Canadian Dollar, and US Dollar. The Group's strategy for managing cash is to maximise interest income whilst ensuring its availability to match the profile of the Group's expenditure. This is achieved by regular monitoring of interest rates and monthly review of expenditure forecasts.

c  Liquidity Risk

The Group relies upon debt and equity funding, and cash flow from its Canadian operations to finance operations. The Directors are confident that adequate liquidity will be forthcoming with which to finance operations. Controls over expenditure are carefully managed.

The Group ensures that its liquidity is maintained by a management process which includes projecting cash flows and considering the level of liquid assets in relation thereto, monitoring Balance Sheet liquidity and maintaining funding sources and back-up facilities.

The Group's expected cash flows for its financial liabilities are presented in the following table and includes undiscounted principal and expected interest payments.

	6 Months	6-12 months	1-2 years	2+ years	Total
	£'000	£'000	£'000	£'000	£'000
Trade and other payables	18,970	740	-	-	19,710
Non-current payable *	-	-	557	-	557
H1 2019 LNs	-	-	22,000	-	22,000
H1 2019 PIK interest **	-	-	9,680	-	9,680
Leases	11	6	-	-	17
At 31 December 2021	18,981	746	32,237	-	51,964

	6 Months	6-12 months	1-2 years	2+ years	Total
	£'000	£'000	£'000	£'000	£'000
Trade and other payables	13,155	-	-	-	13,155
Non-current payable *	-	-	-	3,000	3,000
H1 2019 LNs	-	-	-	22,000	22,000
H1 2019 PIK interest **	-	-	-	9,680	9,680
Leases	15	15	17	-	47
At 31 December 2020	13,170	15	17	34,680	47,882

* The non-current payable will not become payable until such time as i3 has received consideration from any sale or farm-down of its Serenity or Liberator assets (see note 15). However, as the DPIB will be reduced by certain payments to BHGE, management expects the balance will be repaid by 2023.

** The H1 2019 LNs have an early redemption option and the interest can be paid in either cash or in kind (see note 16).  The table assumes no early redemption and that all interest is paid in kind at the maturity.

d  Commodity Price Risk

Commodity price risk in the Group primarily arises from price fluctuations in markets for the Group's oil, gas and NGL products. Commodity prices can be volatile and may be impacted by various supply and demand factors which are outside the Group's control. Fluctuations in commodity prices could have a significant impact on future results of operations, cash flow generation, and development opportunities.

The Group manages commodity price risks by entering a variety of risk management contracts. Further details of risk management contracts entered in 2021 are provided in note 18, and of risk management contracts entered after the reporting period are provided in note 24.

The following table illustrates the impact on the Group's profit before tax and equity due to reasonably possible changes in commodity prices and their impact on the fair value of financial instruments, with all other variables held constant.

	Decrease in commodity price / increase in profit before loss and equity £'000	Increase in commodity price / (decrease) in profit before loss and equity £'000
Change in WTI - CAD 5.00 / bbl	1,555	(651)
Change in AECO - CAD 0.50 / GJ	262	(262)
Change in Conway - USD 5.00 / bbl	677	(677)

Capital Risk Management

The Group's objectives when managing capital are to safeguard the Group's ability to position as a going concern and to continue its development and production activities. The capital structure of the Group consists of borrowings and leases of £23,924 thousand at 31 December 2021 (2020 - £17,986 thousand) (note 16), has capital, defined as the total equity and reserves of the Group of £138,731 thousand (2020 - £79,888 thousand) and cash and equivalents of £15,335 thousand (2020 - £6,178 thousand).

The Group monitors its level of cash resources available against future planned exploration and evaluation activities and may issue new shares in order to raise further funds from time to time.

23  Commitments

	1 year	2-3 years	4-5 years	5+ years	Total
	£'000	£'000	£'000	£'000	£'000
Operating	-	-	-	-	-
Transportation	1,663	1,322	298	55	3,338
Total	1,663	1,322	298	55	3,338

The Group previously held an operating commitment to lease offices in the UK that expired in April 2022, which was terminated early by the Group in 2021.Transportation commitments relate to take-or-pay pipeline capacity in Alberta. 

The Group did not have any capital commitments as at 31 December 2021 (2020 - £3,960 thousand).

24  Events after the reporting period

After 31 December 2021 i3 entered into various risk management contracts, as summarised below.

Type	Effective date	Termination date	Total Volume	Avg. Price
AECO 5A Physical Swaps	1 Apr 2022	30 Jun 2022	7,500 GJ/Day	CAD 3.2500 / GJ
AECO 5A Physical Swaps	1 Apr 2022	31 Oct 2022	20,275 GJ/Day	CAD 3.9371 / GJ
AECO 5A Physical Swaps	1 Jul 2022	31 Jul 2022	7,500 GJ/Day	CAD 3.2700 / GJ
AECO 5A Physical Swaps	1 Aug 2022	31 Aug 2022	7,500 GJ/Day	CAD 3.3300 / GJ
AECO 5A Physical Swaps	1 Sep 2022	30 Sep 2022	7,500 GJ/Day	CAD 3.2600 / GJ
AECO 5A Physical Swaps	1 Oct 2022	31 Dec 2022	7,500 GJ/Day	CAD 3.5000 / GJ
AECO 5A Physical Swaps	1 Nov 2022	30 Nov 2022	2,500 GJ/Day	CAD 5.0050 / GJ
AECO 5A Financial Swaps	1 Nov 2022	31 Mar 2023	10,000 GJ/Day	CAD 4.1500 / GJ
AECO 5A Physical Swaps	1 Nov 2022	31 Mar 2023	5,000 GJ/Day	CAD 4.3800 / GJ
AECO 5A Physical Swaps	1 Dec 2022	31 Dec 2022	2,500 GJ/Day	CAD 5.0800 / GJ
AECO 5A Physical Swaps	1 Jan 2023	31 Jan 2023	2,500 GJ/Day	CAD 5.1500 / GJ
AECO 5A Financial Swaps	1 Jan 2023	31 Mar 2023	5,000 GJ/Day	CAD 4.3800 / GJ
AECO 5A Physical Swaps	1 Jan 2023	31 Mar 2023	5,000 GJ/Day	CAD 4.7500 / GJ
AECO 5A Physical Swaps	1 Feb 2023	28 Feb 2023	2,500 GJ/Day	CAD 5.1300 / GJ
WTI Financial Swaps	1 Apr 2022	30 Jun 2022	250 bbl/Day	CAD 100.00 / bbl
WTI Financial Swaps	1 Apr 2022	31 Dec 2022	500 bbl/Day	CAD 97.41 / bbl
WTI Financial Swaps	1 Jul 2022	30 Sep 2022	250 bbl/Day	CAD 100.09 / bbl
WTI Physical Swaps	1 Oct 2022	31 Oct 2022	250 bbl/Day	CAD 100.00 / bbl
WTI Physical Swaps	1 Nov 2022	30 Nov 2022	250 bbl/Day	CAD 100.00 / bbl
WTI Physical Swaps	1 Dec 2022	31 Dec 2022	250 bbl/Day	CAD 101.05 / bbl
WTI Physical Swaps	1 Jan 2023	31 Jan 2023	250 bbl/Day	CAD 100.00 / bbl
WTI Financial Swaps	1 Jan 2023	31 Mar 2023	250 bbl/Day	CAD 106.00 / bbl
WTI Physical Swaps	1 Feb 2023	28 Feb 2023	250 bbl/Day	CAD 100.00 / bbl
WTI Physical Swaps	1 Mar 2023	31 Mar 2023	250 bbl/Day	CAD 109.53 / bbl
Sold WTI Call Option *	1 Mar 2022	31 Dec 2022	500 bbl/Day	CAD 92.20 / bbl

* The sold WTI call option has a strike price of CAD 92.20 / bbl and a premium of CAD 17.60 / bbl. The option premium has been deferred over the effective period of 1 March 2022 to 31 December 2022.

On 3 February 2022 the Group announced it had revised its dividend guidance from bi-annually to monthly. In early-2022 the Company has declared dividends as summarised in the following table:

Declaration date	Ex-Dividend date	Record date	Payment date	Dividend per share	Total Dividend
				(pence)	£'000
9 February 2022	17 February 2022	18 February 2022	11 March 2022	0.105	1,183
9 March 2022	17 March 2022	18 March 2022	8 April 2022	0.105	1,183
6 April 2022	14 April 2022	19 April 2022	6 May 2022	0.105	1,183
Total					3,549

On 2 March 2022 the Group noted the announcement by Europa Oil & Gas Limited ("Europa") (company number 03093716) regarding its agreement in principle to farm-in to the Company's Serenity oil discovery in the UK North Sea and the equity funding it is conducting to fund its farm-in obligations.

We can confirm that the farm-in, joint operating agreement and trust deed have been essentially agreed between the parties to enable Europa to acquire a 25% non-operated working interest ("WI") in a sub-area of UKCS Licence P.2358 Block 13/23c (containing the Serenity discovery) by funding a 46.25% paying interest for one appraisal well on the field, whereafter i3 will retain a 75% operated WI in the Block.

The well cost is estimated to be circa £14 million and Europa's 46.25% paying interest will be applied up to a capped gross well cost of £15 million. Any well costs exceeding £15 million will be paid by the companies in proportion to their respective working interests. Completion of the deal and transfer of the licence interest to Europa will be subject to the following principal conditions:

1.  Europa funding an escrow account with their paying interest obligation. We note that closing of Europa's equity funding is subject to the approval of its shareholders at an EGM. This shareholder approval was obtained by Europa on 25 March 2022.

2.  Approval of the UK Oil and Gas Authority ("OGA") to the creation of the Serenity area of Block 13/23c as a new block of Licence P.2358 (the "New Serenity Block").

3.  Consent of the OGA to assignment of an interest in the Licence and New Serenity Block to Europa.

4.  UK National Security and Investment Act approval.

5.  Approval of i3's Loan Note holders of the assignment of the Licence interest.

Following this farm-out i3 will retain a 100% WI in the remainder of Block 13/23c which contains the Minos High prospect and Liberator discovery. 

On 4 April 2022 the Group announced the reserves of i3 Energy Canada Limited as of 31 December 2022. Highlights include Company Interest PDP reserves of 46MMboe, 1P reserves of 85MMboe, and 2P reserves of 154MMboe. Further details can be found on the Company's website at www.i3.energy . 

Glossary

1P	Proved reserves
2P	Proved plus probable reserves
AER	Alberta Energy Regulator
AIM	The Alternate Investment Market of the London Stock Exchange
APM	Alternate Performance Measure
ARO	Asset Retirement Obligation
ASCP	Saskatchewan's Accelerated Site Closure Program
bbl	Barrel
BHGE	Baker Hughes, a GE Company, and GE Oil & Gas Limited
BOE	Barrels of Oil Equivalent
BOEPD	Barrels of Oil Equivalent Per Day
CAD	Canadian Dollars
Cenovus	Cenovus Energy Inc.
Cenovus Acquisition Date	20 August 2021
Cenovus Assets	Certain petroleum and infrastructure assets acquired from Cenovus
CEO	Chief Executive Officer
CFO	Chief Financial Officer
CLNs	Convertible Loan Notes
Company	i3 Energy plc
CPR	Competent person's report
E&E	Exploration and evaluation
Europa	Europa Oil & Gas Limited
FCF	Free cash flow
FVTPL	Fair Value through Profit or Loss
Gain	Gain Energy Ltd.
Gain Acquisition Date	3 September 2020
Gain Assets	Assets retained by i3 following the purchase from Gain and sale to Harvard
gal	Gallon
GBP	British Pounds Sterling
GJ	Gigaloule
Group	i3 Energy plc, together with its subsidiaries
Harvard	Harvard Resources Inc.
i3	i3 Energy plc, together with its subsidiaries
i3 Canada	i3 Energy Canada Limited
IAS	International Accounting Standard
IFRIC	International Financial Reporting Interpretations Committee
IFRS	International Financial Reporting Standard
IP30	Average daily production of a well over its initial 30-day production period
LLR	The licensee's deemed asset to deemed liability ratio as determined under Directive 006 (Licensee Liability Rating (LLR) Program and Licence Transfer Process) of the Alberta Energy Regulator (AER). The deemed asset value is calculated by multiplying the licensee's reported production of oil and gas for the prior 12 months by the rolling 3-year provincial industry average netback (determined by the AER). The deemed liability is the total cost for the future abandonment and site reclamation of all a licensee's wells and upstream facilities based on provincial industry average costs (determined by the AER).
MMboe	Million Barrels of Oil Equivalent
MMBtu	Metric Million British Thermal Unit
NGL	Natural gas liquids
NED	Non-Executive Director
NOI	Net Operating Income
NTM	Next Twelve Months
OGA	UK Oil and Gas Authority
PDP	Proved, developed, producing reserves
PP&E	Property, plant and equipment
RTO	Reverse Take-over
SRP	Alberta's Site Rehabilitation Program
TEIC	Toscana Energy Income Corporation
Toscana	Toscana Energy Income Corporation
Toscana Acquisition Date	30 October 2020
TSX	Toronto Stock Exchange
UKCS	UK Continental Shelf
USD (US$)	United States Dollar

 

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FR SFASIEEESELL