REG - i3 Energy PLC - Final Results for the year ended 31 December 2022
07/06/2023 07:00
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RNS Number : 8751B i3 Energy PLC 07 June 2023
7 June 2023
i3 Energy plc
("i3", "i3 Energy", or the "Company")
Final Results for the year ended 31 December 2022
i3 Energy plc (AIM:I3E) (TSX:ITE), an independent oil and gas company with
assets and operations in the UK and Canada, is pleased to announce the audited
results for the year ended 31 December 2022. A copy of the Company's
financial statements will be posted to shareholders and made available shortly
on the Company's website at https://i3.energy (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 2023 at the offices of WH Ireland
Limited at 24 Martin Lane, London, EC4R 0DR.
2022 Financial, Reserves & PRODUCTION Highlights
CANADA UK AND CORPORATE
Average daily production (BOE/d) 2022: 20,317 Group Revenue (£m) 2022: 208.4
2021: 12,442 2021: 86.8
2020: 8,732 2020: 13.0
2019: 0 2019: 0
2P reserves (MMBOE) 2022: 181.5 Group Profit / (loss) after tax (£m) 2022: 42.0
2021: 154.1 2021: 25.1
2020: 54.0 2020: 11.7
2019: 0 2019: (10.9)
PDP reserves (MMBOE) 2022: 49.1 Group NOI (£m) ((1)) 2022: 131.7
2021: 46.2 2021: 48.6
2020: 18.1 2020: 4.9
2019: 0 2019: 0
2P reserves Before-tax NPV 10 (USDm) 2022: 1,162 Group Adjusted EBITDA (£m) ((1)) 2022: 98.0
2021: 775 2021: 30.2
2020: 183 2020: (0.8)
2019: 0 2019: (5)
Dividends declared (£m) 2022: 17.4
2021: 3.4
2020: 0
2019: 0
(1) Non-IFRS measure. Refer to Appendix B
2022 Achievements
Organic Production Growth Delivering Record Production
· Four quarters of production growth with peak daily rates exceeding
24,000 barrels of oil equivalent per day ("boepd").
Shareholder Return
· Increased dividends declared from £3.4 million in 2021 to £17.4
million in 2022 and announced 2023 dividend guidance of £24.5 million (2.052
pence / share).
Capital Program
· £75.8 million capital expenditure in 2022 delivered 31 gross (20.1
net) wells.
· Increased the Group's leasehold position to 628,000 net acres.
· Aggregate well productivity met or exceeded management expectation
and key wells drilled in strategic Simonette and Clearwater acreage.
· Through participation in land sale auctions, farm-ins and joint
ventures, and partner consolidation, i3 has grown its acreage in the strategic
Clearwater play to greater than 69,600 acres (109 sections) with an average
working interest of 76%
· Farmed out 25% of the Serenity licence to Europa who paid 46.25% of
the Serenity 13/23c-12 appraisal well costs. The well was drilled in October
2022. The company is evaluating one well development options.
Reserves Growth
· Our 2022 capital program helped to increase Proved plus Probable
reserves ("2P") by 18% to 182 Million Barrels of Oil Equivalent ("mmboe"),
resulting in reserves replacement of 479% on a 2P basis.
· The Group now has 376 gross booked drilling locations in its
audited reserves and 940 including un-booked locations.
ESG Performance
· Published inaugural annual ESG Report.
· Eliminated all high-bleed pressure controllers and commenced
installation of solar powered pumps. These initiatives when complete will
eliminate 71,450 tonnes CO2e methane emissions equivalent to taking circa
16,000 cars off the road.
· Completed the electrification of 7 pumpjacks in Carmangay and
Retlaw to reduce use of diesel and propane for power generation, with a
further 29 electrifications underway.
· Implemented efficient disposal of oil based drilling fluid,
avoiding 2,500 tonnes of CO2e emissions.
· Ongoing annual abandonment and reclamation program abandoned 69
wells and decommissioned 37 well sites, representing approximately 14% of
operated non-producing wells.
Outlook
A summary of key events which occurred after the reporting period are
presented in note 24 to the financial statements and includes the announcement
on 31 May 2023 of the successful redemption of the Company's outstanding £22
million H1-2019 Loan Notes (the "Loan Notes"), due 31 May 2023, and the
establishment of a CAD 100 million debt facility, which will provide i3
greater financial flexibility and enhanced credit capacity to further execute
its ongoing business plan. The Company's focus for the remainder of 2023 will
be on three key areas:
1 The growth of i3's Canadian business through the deployment of
capital into its large proven undeveloped reserves base, operational
excellence to improve uptime and field performance, and strategic upsizing in
core areas;
2 Maintaining flexibility to adapt to economic challenges while
maximizing total shareholder return; and
3 Conducting its operations safely and in an environmentally secure
manner.
The Company continuously evaluates opportunities to strengthen its balance
sheet whilst maintaining tight control of its costs and working capital
position.
Majid Shafiq, CEO of i3 Energy plc, commented:
"Following an active period of acquisitions over the course of 2020 and 2021,
2022 was a period of consolidation and organic growth. Our most recent
significant acquisition in Q3 2021 of circa 8,400 boepd in our core Central
Alberta area from Cenovus Energy, was integrated into our Canadian business
and operational and organisational efficiencies implemented across our entire
portfolio. Commodity price strength in the second half of 2021 led us to pivot
from growth via acquisitions to organic growth through the exploitation of our
extensive inventory of drilling locations and in January 2022 we commenced our
inaugural operated drilling program with an announced USD47 million budget.
Based on the positive results from the wells drilled in Q1 2022, the Canadian
capex program was expanded to circa USD90 million and during the course of the
year we drilled a total of 20.1 net wells in Canada. The program was very
successful with all wells meeting or exceeding management expectations in
terms of production performance and costs versus budget. In conjunction with
an extensive workover program the new wells contributed to the achievement of
our stated goal of reaching 24,000 boepd before the end of the year and also
to a very positive year end reserves audit which resulted in an 18% increase
in our booked 2P reserves and a 479% increase in our reserves replacement
ratio on a 2P basis. In the UK, a farmout of the Serenity appraisal well
allowed the company to significantly reduce its capital exposure and the well
was successfully drilled to complete the appraisal of the field. The potential
for a single well development is being evaluated.
2022 also saw the publication of our maiden ESG report and we are very pleased
that activities throughout the year saw significant reductions in CO2e
emissions as we began to implement methane emission reduction initiatives. We
continued to deliver on our total shareholder return model, as we balanced our
production growth with increased cash returns to investors with an expanded
dividend program which saw over £17.4 million in dividends being declared
during the year.
The first half of 2023 has seen continued operational and commercial activity.
Our 2023 capital program has commenced with the pre-spring break component
completed and we are very pleased to have repaid our outstanding debt and
established a new CAD100 million loan facility, which validates the quality
and scale of our reserves base in Canada.
All of this was possible due to the expertise and commitment of our staff in
Canada and the UK and I would like to thank them for their continued efforts
and all our investors and shareholders for their continued support. We look
forward to another successful year as we navigate the operational and business
challenges that lay ahead with continued dedication and hard work".
AIM Application - Correction
i3 also announces that, further to the announcement on 17 May 2021, 5,277,045
ordinary shares ("Ordinary Shares") were issued to Baker Hughes, a GE company
(GE Oil & Gas UK Limited and Baker Hughes collectively referred to
hereafter as "BHGE") in relation to warrants exercised and these were not
admitted to trading on AIM at that time. An application will be made for the
Ordinary Shares to be admitted to trading on AIM and are expected to be
admitted on 13 June 2023.
The Ordinary Shares rank pari passu with the existing Ordinary Shares,
including the right to receive all dividends and other distributions declared
after the date of issue.
Following Admission of the Ordinary Shares, the Company's issued share capital
will though remain the same as previously reported at 1,201,874,464 Ordinary
Shares with a nominal value of £0.0001 each. Shareholders may use this figure
of ordinary shares as the denominator by which they are required to notify
their interest in, or change their interest in, the Company under the
Disclosure Guidance and Transparency Rules.
Qualified Person's Statement
In accordance with the AIM Note for Mining and Oil and Gas Companies, i3
discloses that Majid Shafiq is the qualified person who has reviewed the
technical information contained in this document. He has a Master's Degree
in Petroleum Engineering from Heriot-Watt University and is a member of the
Society of Petroleum Engineers. Majid Shafiq consents to the inclusion of the
information in the form and context in which it appears.
Enquiries:
i3 Energy plc c/o Camarco
Majid Shafiq (CEO) Tel: +44 (0) 203 781 8338
WH Ireland Limited (Nomad and Joint Broker)
James Joyce, Darshan Patel Tel: +44 (0) 207 220 1666
Tennyson Securities (Joint Broker)
Peter Krens Tel: +44 (0) 207 186 9030
Stifel Nicolaus Europe Limited (Joint Broker)
Ashton Clanfield, Callum Stewart Tel: +44 (0) 20 7710 7600
Camarco
Georgia Edmonds, Violet Wilson, Sam Morris Tel: +44 (0) 203 781 8338
Notes to Editors:
i3 Energy is an oil and gas Company with a low cost, diversified, growing
production base in Canada's most prolific hydrocarbon region, the Western
Canadian Sedimentary Basin and appraisal assets in the North Sea with
significant upside.
The Company is well positioned to deliver future growth through the
optimisation of its existing 100% owned asset base and the acquisition of long
life, low decline conventional production assets.
i3 is dedicated to responsible corporate practices and the environment, and
places high value on adhering to strong Environmental, Social and Governance
("ESG") practices. i3 is proud of its performance to date as a responsible
steward of the environment, people, and capital management. The Company is
committed to maintaining an ESG strategy, which has broader implications for
long-term value creation, as these benefits extend beyond regulatory
requirements.
i3 Energy is listed on the AIM market of the London Stock Exchange under the
symbol I3E and on the Toronto Stock Exchange under the symbol ITE. For
further information on i3 Energy please visit https://i3.energy/
(https://i3.energy/) .
This announcement contains inside information for the purposes of Article 7 of
the UK version of Regulation (EU) No 596/2014 which is part of UK law by
virtue of the European Union (Withdrawal) Act 2018, as amended ("MAR"). Upon
the publication of this announcement via a Regulatory Information Service,
this inside information is now considered to be in the public domain
Chairperson's and Chief Executive's Statement
Following its very successful entry into Canada through M&A and the
aggregation of a significant portfolio of development assets over the course
of 2020 and 2021, the strengthening of oil and gas prices in 2021 resulted in
a shift of strategy for the Company to focus on internally generated growth
through the exploitation of its extensive portfolio of development drilling
locations.
In January 2022, i3 embarked on its inaugural drilling campaign in Canada. The
Company announced in December 2021 an internally funded USD 47 million
programme of drilling which was designed to drill 17 gross wells (12.6 net)
across its key assets. The programme was designed to maximize near-term
production and cash flow through further development of the Company's large
inventory of predictable and highly economic Glauconite locations in Central
Alberta, while continuing to advance i3's high-impact Simonette
Montney position and recently expanded Clearwater holdings. The program was
expected to add incremental peak production of 5,250 boepd and result in
average 2022 production of over 20,000 boepd while testing and advancing
important growth catalysts in its portfolio. Based on the very positive
results of the wells drilled in the first quarter, the Company's strong
operational performance and the forecasted strength of commodity prices, the
Company decided in May to expand its program with an additional US$50 million
of capital. The revised capital budget was forecast to provide peak production
above 24,000 boepd by year end.
We are very pleased that the drilling programme was executed under budget and
the aggregate well performance met management expectations. In total, i3's
2022 drilling programme delivered 31 gross (18.4 net) wells and was executed
circa 5% under budget with excellent capital efficiencies, which was a major
achievement considering the highly inflationary environment the Company and
its industry peers were challenged with. Such success was achieved by a strong
focus on operational efficiency and cost control and is a testament to the
dedication and skills of all our staff. In addition to production wells in our
Core Central Alberta and Wapiti areas, key development and delineations wells
were drilled in our growth assets in Simonette (in the Montney formation) and
Marten Hills (in the Clearwater formation), and production data from these
wells will help us plan for future expansion in these areas.
The very successful drilling campaign allied with an extensive suite of
regular workovers, reactivations and a focus on uptime and operational
efficiencies resulted in a continuation of production growth since our entry
into Canada. The company entered the year at circa 18,000 boepd and reached
24,000 boepd in December, with a Q4 average production level of 22,757 boepd.
Although our focus in 2022 was on production growth, the drilling campaign
targeted locations that would advance the development of strategic assets in
our Simonette Montney and Clearwater assets. We also significantly grew our
exposure to the Clearwater play through a series of strategic transactions
including successful bids at Alberta Crown Land Sales, joint ventures, farm-in
agreements and partner consolidation. This activity has grown our Clearwater
land position by circa 120% to 109 net sections (279 km(2)) from the 50 net
sections (128 km(2)) acquired as part of the Company's first transaction in
Canada, the Toscana acquisition in 2020.
The Company's year end 2022 audited reserves reflect the successful reservoir
management of ongoing operations and the results of the 2022 drilling program.
The Company offset production declines and increased its Proven Developed
Producing (PDP), Total Proved (1P) and Proved plus Probable (2P) reserves to
49.1 mmboe, 93.5 mmboe and 181.5 mmboe respectively. Relative to year end 2021
the Company's PDP, P1 and 2P reserves increased by 6%, 10% and 19%
respectively. This was a significant result and achieved with positive
revisions to existing reserves and reserves adds from new development drilling
locations. The scale and longevity of our asset portfolio is demonstrated by a
reserves life index of 22.5 years for the Company's 2P reserves.
Our 2022 drilling program and subsurface technical work has contributed to an
increase in the Company's total inventory to 940 gross (537 net) drilling
locations of which only 376 gross (255 net) are booked in the year end 2022
reserves report. A significant proportion of these un-booked drilling
locations are located in Simonette, Wapiti and our Clearwater acreage, which
illustrate the organic growth potential in these assets. Together the booked
and un-booked drilling locations provide for multiple years of future drilling
activity and production growth.
In the UK, we farmed out 25% of our Serenity discovery to Europa Oil and Gas
Limited in return for a 1.85 for 1 carry, resulting in the reduction of our
drilling capex share from 100% to 53.75%. The well was drilled in October but
unfortunately the targeted sand was not found at the appraisal well location
and consequently in place hydrocarbon volumes are much lower than originally
estimated. Updated mapping of the field around the 13/23-10 discovery well,
shows there is the potential for a single well development, for which
development and monetization options are being evaluated. The well was drilled
significantly below budget resulting in a net cost to the Company of USD 5.7
million.
Based on the success of our 2022 drilling campaign and our budget commodity
price forecasts, the Company announced its 2023 capital budget and drilling
programme on 22 December 2022. The Company plans to spend USD 64.05 million
focussed on a drilling campaign on its Canadian assets. Similar to the 2022
programme, the drilling targets production wells in our key assets in Central
Alberta, Simonette, Wapiti and the Clearwater with an additional element of
Clearwater appraisal wells in our legacy acreage (acquired via the Toscana
acquisition) and an earn-in appraisal well in our non-operated asset base. In
total the 2023 programme is scheduled to deliver 23 gross wells (15.2 net, 70%
net i3 operated). Based on the expected performance of these wells, forecast
2023 annual production is expected to be in the range of 22,250 to 23,000
boepd, representing a year-over-year increase of approximately 10% to 13%,
with an expected peak production rate in 2023 of approximately 26,000 boepd.
Our budget allocation to the UK is limited to USD 0.6 million, which will be
used to advance the Serenity one well development to field development plan
stage. The Canadian drilling programme for Q1 2023 has been completed with
wells being equipped and tied into production facilities for clean-up.
Drilling operations will recommence in Q3 2023 when surface conditions allow
operations, following the Spring seasonal wet period.
We continue to actively identify production optimisation and cost reduction
opportunities within our portfolio, focussing on maintaining high uptime,
minimising operating costs, optimising operated processing facilities and
infrastructure, and implementing high return workovers to offset natural
production declines. These efforts continue to increase aggregate average net
production and substantially reduce the decline rates predicted within the
Company's competent persons reports. This is a testament to the quality of the
assets in the portfolio and the dedication of our workforce. In parallel with
operational activity, we continue to review the reservoir performance of the
producing assets and identify mature fields where redevelopment, particularly
through the implementation of relatively low-cost secondary recovery projects,
could materially increase production and ultimate hydrocarbon recovery.
Operating our assets in a safe and secure manner is fundamental to our
business and we continue to advance our health and safety policies and
procedures as we acquire and integrate additional production assets. There
were 101 routine regulatory government inspections during 2022. 75 returned
satisfactory results, 20 were categorised as low risk, and six that were
deemed to be high risk were subsequently remedied.
Financial Discipline
The Board and Management are focused on delivering consistent value to
shareholders. i3 is committed to its total shareholder return model which
allies production and asset value growth with a progressively growing dividend
and protects this commitment through a conservative hedging program. The
Company has and continues to keep a substantial portion of its production
hedged through risk management contracts to manage commodity price risk, with
free cash post dividend payments deployed to either acquire production assets
or develop our proven undeveloped (PUD) and 2P inventory dependent on which
option delivers higher returns in the prevailing commodity price environment.
As i3 continues to grow its portfolio, a proportion of all incremental
production will be hedged in order to secure future cash flows, and the
Company will remain commercial in monetising assets when third-party interest
warrants consideration.
With the well-timed acquisitions and capital deployment of the last 30 months,
the Company's assets have continued to outperform the Directors' expectations.
As per our commitment to those shareholders who funded our entry to and growth
in Canada, and as part of our total shareholder return model, we commenced
paying a dividend in 2021 and have grown that year-on-year from £3.4 million
in 2021, to £15.4 million in 2022 and plan to pay dividends of £24.5 million
in 2023.
Operational flexibility and the short-term nature of forward capital
commitments in Canada mean that the Company has considerable optionality to
rapidly expand or reduce its capital programme to prudently manage its balance
sheet to ensure risks are appropriately mitigated in volatile commodity
markets.
Governance
The Board recognises its responsibility for the proper management of the
Company and is committed to maintaining a high standard of corporate
governance. The Directors also recognise the importance of sound corporate
governance commensurate with the size and nature of the Company and the
interests of its shareholders. The Quoted Companies Alliance has published a
set of corporate governance guidelines for AIM companies, which include a code
of best practice comprising principles intended as a minimum standard, and
recommendations for reporting corporate governance matters. The Directors
comply with the QCA Corporate Governance Guidelines for Smaller Quoted
Companies so far as it is practicable having regard to the size and current
stage of development of the Company. The Board currently comprises two
Executive Directors (being the Chief Executive Officer and the President
Canada) and four Non-Executive Directors (including the Chairperson).
The Board's decision-making process is not dominated by any one individual or
group of individuals. The composition of the Board will be reviewed regularly
and modified as appropriate in response to the Company's changing
requirements. The Board has established an Audit and Risk Committee, Corporate
Governance Committee, Health, Safety, Environment and Security Committee,
Reserves Committee, and Remuneration Committee to ensure proper adherence to
sound governance and decision making.
Environmental Stewardship
i3 is fortunate to operate in the UK and Canada which have some of the world's
most stringent and rigorous environmental laws and regulations and the Company
strives to meet or exceed all local, provincial or national operational,
environmental, reporting and compliance obligations and abandonment and
reclamation requirements. The Company is committed to conducting its
operations responsibly and in accordance with industry best practices. i3's
commitment to high ESG standards is central to maintaining our social licence
to operate, creating value for all stakeholders, and ensuring long-term
commercial success. i3 recognises the safety and well-being of our employees,
local communities, and other key stakeholders as a priority, and considers
climate change as having a material impact on our business.
To demonstrate the Company's commitment to long-term sustainable resource
development, environmental stewardship and the well-being of employees and the
communities in which i3 operates, i3 published its inaugural annual ESG report
in July 2022. The ESG report set out the Company's goals and ambitions with
respect to greenhouse gas emission reductions, environmental stewardship,
social policies and governance. i3 published an updated ESG report in December
2022, which included disclosure on the assets acquired from Cenovus Energy in
2021. This data was not available when the inaugural report was published in
July 2022.
The Company made big strides in 2022 to reduce methane emissions. After
completing the upgrading of high bleed pneumatic controllers to low bleed or
non-bleed alternatives across its portfolio, the Company commenced replacement
of pneumatic pumps with solar driven pumps (no venting). These initiatives
have resulted in a decrease of 71,450 tonnes of CO2e/year, which is the
equivalent of removing 15,530 cars from the road per year. i3 also completed
the electrification of 30 pumpjacks in its Carmangay and Retlaw properties,
reducing CO2e emissions by approximately 6,366 tonnes/year. The Company
further partnered with Recover Energy Services ("Recovery") to manage the
efficient disposal of oil-based drilling waste and as determined by Recovery,
avoided 2,500 metric tonnes of CO2e emissions. Similar initiatives will
continue in 2023 as we continue to reduce the carbon intensity of our
production base. These CO2e emissions reductions qualify for carbon credits
which can be sold or used to offset future carbon tax obligations.
i3 also takes its abandonment and reclamation obligations very seriously and
in 2022 it abandoned a total of 69 wells and decommissioned 37 well sites,
representing approximately 14% of its operated non-producing well stock. In
2023, and in accordance with the Alberta Energy Regulator's decommissioning
guidance, i3 expects to deliver a similar number of abandonment operations as
achieved in 2022.
Looking ahead
The Company looks forward to executing a successful drilling program in Canada
in 2023, growing production and returning cash to shareholders and so
delivering on its total shareholder return model.
Looking beyond 2023, we have a high quality and diverse asset portfolio in
Canada with immense unrealized upside potential. We will continue to focus our
efforts on advancing these key assets to efficient and rapid commercialisation
and value crystallisation. We will selectively target key assets and wells
to optimise these developments and conversion of resources to reserves
bookings. We are fortunate that we operate the vast majority of our assets
which allows us to control the timing and pace of development. We also own
high working interests in our operated assets which also provides us with
optionality on how to finance these developments.
Whilst our current focus is on organic growth, we recognise that commodity
price volatility and resulting market dislocations will provide opportunities
to grow through low-cost mergers and acquisitions and we remain vigilant to
take advantage of these opportunities as and when they arise.
We are committed to operating in a safe and socially responsible manner and
the safety of our employees and contractors is of primary importance. We are
proud of our green house gas emission reduction initiatives and achievements
in 2022 and we will endeavour to deliver year-on-year reductions in the carbon
intensity of our production.
As always, we extend gratitude to our shareholders for their ongoing support
and to our employees for their relentless commitment to making i3 a success.
Though we operate within a macro environment that is beyond our control, we
believe we are doing the right things to create a very valuable business that
can weather good times and bad.
i3 will continue to manage our Canadian and UK businesses in a manner that
maximizes value creation and distributed returns.
"John Festival" "Majid Shafiq"
John Festival Majid Shafiq
Non-Executive Chairperson
Chief Executive Officer
6 June 2023
6 June 2023
Consolidated Statement of Comprehensive Income
Notes Year Ended 31 December 2022 Year Ended 31 December 2021
£'000 £'000
Revenue 6 208,436 86,763
Production costs (76,418) (37,945)
Loss on risk management contracts 18 (18,990) (5,485)
Depreciation and depletion 12 (34,339) (21,643)
Gross profit 78,689 21,690
Administrative expenses 7 (15,038) (13,094)
Acquisition costs - (256)
(Loss) / gain on bargain purchase and asset dispositions 4 (9) 25,013
Operating profit 63,642 33,353
Finance costs 8 (7,865) (7,609)
Profit before tax 55,777 25,744
Tax charge 9 (13,826) (661)
Profit for the year 41,951 25,083
Other comprehensive income:
Items that may be reclassified subsequently to profit or loss:
Foreign exchange differences on translation of foreign operations 6,688 1,511
Other comprehensive income for the year, net of tax 6,688 1,511
Total comprehensive income for the year 48,639 26,594
Earnings per share Pence Pence
Earnings per share - basic 11 3.60 2.84
Earnings per share - diluted 11 3.43 2.60
All operations are continuing.
The accompanying notes form an integral part of these financial statements.
Consolidated Statement of Financial Position
Assets Notes 31 December 2022 31 December 2021
£'000 £'000
Non-current assets
Property, plant & equipment 12 236,465 224,080
Exploration and evaluation assets 13 62,060 49,819
Other non-current assets 74 74
Total non-current assets 298,599 273,973
Current assets
Cash and cash equivalents 16,560 15,335
Trade and other receivables 14 34,843 25,503
Risk management contracts 18 1,111 814
Inventory 2,099 665
Total current assets 54,613 42,317
Current liabilities
Trade and other payables 15 (55,846) (19,709)
Risk management contracts 18 (381) (925)
Borrowings and leases 16 (27,241) (69)
Decommissioning provision 17 (3,190) (2,368)
Total current liabilities (86,658) (23,071)
Net current (liabilities) / assets (32,045) 19,246
Non-current liabilities
Non-current accounts payable 15 - (557)
Borrowings and leases 16 - (23,855)
Decommissioning provision 17 (90,141) (123,155)
Deferred tax liability 9 (11,667) (7,486)
Total non-current liabilities (101,808) (155,053)
Net assets 164,746 138,166
Capital and reserves
Ordinary shares 19 119 113
Deferred shares 19 50 50
Share premium 19 48,646 44,203
Share-based payment reserve 20 6,311 9,102
Warrants - LNs 16 2,045 2,045
Foreign currency translation reserve 8,052 1,364
Retained earnings 99,523 81,289
Shareholders' funds 164,746 138,166
The accompanying notes form an integral part of these financial statements.
The consolidated financial statements of i3 Energy plc, company number
10699593, were approved by the Board of Directors and authorised for issue on
6 June 2023. Signed on behalf of the Board of Directors by:
Majid Shafiq
Director
Consolidated Statement of Changes in Equity
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 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
Total comprehensive income for the year - - - - - 6,688 41,951 48,639
Transactions with owners:
Exercise of options 20 6 4,443 - (3,883) - - (6,324) (5,758)
Share-based payment expense 20 - - - 1,092 - - - 1,092
Dividends declared in 2022 19 - - - - - - (17,393) (17,393)
Balance at 31 December 2022 119 48,646 50 6,311 2,045 8,052 99,523 164,746
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 2022 Year ended 31 December 2021
£'000 £'000
OPERATING ACTIVITIES
Profit before tax 55,777 25,744
Adjustments for:
Depreciation and depletion 12 34,339 21,643
Loss / (gain) on bargain purchase and asset dispositions 4 9 (25,013)
Finance costs 8 7,865 7,609
Unrealised (gain) / loss on risk management contracts 18 (858) 111
Non-cash other income (215) -
Unrealised FX loss 7 113 (154)
Share-based payments expense - employees (including NEDs) 7 1,092 3,217
Operating cash flows before movements in working capital:
(Increase) in trade and other receivables (8,378) (15,297)
Increase in trade and other payables 12,782 6,862
(Increase) in inventory (1,434) (283)
Net cash from operating activities 101,092 24,439
INVESTING ACTIVITIES
Acquisitions (531) (37,079)
Expenditures on property, plant & equipment (64,374) (9,465)
Disposal of property, plant & equipment 621 529
Expenditures on exploration and evaluation assets (13,842) (3,317)
Expenditure on decommissioning oil and gas assets 17 (437) (648)
Tax credit for R&D expenditure 9 - 487
Net cash used in investing activities (78,563) (49,493)
FINANCING ACTIVITIES
Proceeds on issue of ordinary shares, net of issue costs 19 - 38,125
Interest and other finance charges paid 8 (2,330) (448)
Exercise of warrants and options 635 -
Employee tax on exercised share options (6,432) -
Lease payments 16 (74) (30)
Dividends paid 19 (15,353) (3,417)
Net cash (used in) / from financing activities (23,554) 34,230
Effect of exchange rate changes on cash 2,250 (19)
Net Increase in cash and cash equivalents 1,225 9,157
Cash and cash equivalents, beginning of year 15,335 6,178
CASH AND CASH EQUIVALENTS, END OF YEAR 16,560 15,335
Included within cash and cash equivalents is £354 thousand of restricted
cash, which relates to guarantees for product marketing. Non-current accounts
payables reconciliation is show in note 15 and the debt reconciliation is
shown in note 16.
The accompanying notes form an integral part of these financial statements.
Notes To the Group Financial Statements
1 General information
i3 Energy plc ("the Company") is a Public Company, limited by shares,
registered in England and Wales under the Companies Act 2006 with registered
number 10699593. The Company's ordinary shares are traded on the Toronto Stock
Exchange and the AIM Market operated by the London Stock Exchange. The address
of the Company's registered office is New Kings Court, Tollgate, Chandler's
Ford, Eastleigh, Hampshire, SO53 3LG.
The Company and its subsidiaries (together, "the Group") principal activities
consist of oil and gas production in Western Canadian Sedimentary Basin and of
the appraisal of oil and gas assets on the UK Continental Shelf.
2 Basis of preparation
The financial statements of i3 Energy plc have been prepared in accordance
with UK-adopted international accounting standards in accordance with the
requirements of the Companies Act 2006 and in accordance with the requirements
of the AIM rules.
The consolidated financial statements have been prepared under the historical
cost convention, as modified by the financial assets and financial liabilities
(including derivative instruments) at fair value through profit or loss.
The financial information is presented in Pounds Sterling (£, GBP), which is
the Company's functional currency, and rounded to the nearest thousand unless
otherwise stated. The functional currency of the Company's UK subsidiary, i3
Energy North Sea Limited, is GBP, and the functional currency of its Canadian
subsidiary, i3 Energy Canada Limited, is CAD. A summary of period-average and
period-end exchange rates is presented in the table below:
Year ended 31 December 2022 Year ended 31 December 2021
Period-average GBP:CAD exchange rate 1.6073 1.7246
Period-end GBP:CAD exchange rate 1.6283 1.7166
The principal accounting policies applied in the preparation of these
consolidated financial statements are set out below. These policies have been
consistently applied unless otherwise stated.
Basis of Consolidation
The consolidated financial statements consolidate the audited financial
statements of i3 Energy plc and the financial statements of its subsidiary
undertakings made up to 31 December 2022.
Subsidiaries are entities over which the Group has control. The Group controls
an entity when the Group is exposed to, or has rights to, variable returns
from its involvement with the entity and has the ability to affect those
returns through its power over the entity. Subsidiaries are fully consolidated
from the date on which control is transferred to the Group. They are
de-consolidated from the date that control ceases.
When necessary, adjustments are made to the financial statements of
subsidiaries to bring their accounting policies into line with the Group's
accounting policies. All intra-group assets and liabilities, equity, income,
expenses, and cash flows relating to transactions between members of the Group
are eliminated in full on consolidation.
Going concern
The Directors have, at the time of approving the financial statements, a
reasonable expectation that the Company and the Group have adequate resources
to continue in operational existence for the foreseeable future. Thus, they
continue to adopt the going concern basis of accounting in preparing the
financial statements. The use of this basis of accounting takes into
consideration the Group's current and forecast financing position, additional
details of which are provided in the going concern section of the Directors'
Report.
3 Significant accounting policies
Financial instruments
Cash and cash equivalents
Cash and cash equivalents comprise cash on hand and cash held on current
account or on short-term deposits at variable interest rates with original
maturity periods of up to three months. Any interest earned is accrued monthly
and classified as interest income within finance income.
Trade and other receivables
Trade and other receivables are initially recognised at fair value when
related amounts are invoiced then carried at this amount less any impairment
of these receivables using the expected credit loss model. A provision for
impairment is made when there is objective evidence (such as the probability
of insolvency or significant financial difficulties of the debtor) that the
Company will not be able to collect all of the amounts due under the original
terms of the invoice. The carrying amount of receivables is reduced through
use of an allowance account. Impaired debts are derecognised when they are
assessed as uncollectible.
Trade and other payables
These financial liabilities are all non-interest bearing and are initially
recognised at the fair value of the consideration payable.
Loan Notes
These financial liabilities are all interest bearing and are initially
recognised at amortised cost and include the transaction costs directly
related to the issuance. The transaction costs are amortised using the
effective interest rate method over the life of the Loan Notes.
Financial liabilities at Fair Value Through Profit or Loss ("FVTPL")
Financial liabilities at FVTPL comprise of the Group's risk management
contracts and non-current accounts payable. Financial liabilities are
classified as at FVTPL when the financial liability is (i) contingent
consideration that may be paid by an acquirer as part of a business
combination to which IFRS 3 applies, (ii) held for trading, or (iii) it is
designated as at FVTPL.
A financial liability is classified as held for trading if:
· it has been incurred principally for the purpose of repurchasing
it in the near term; or
· on initial recognition it is part of a portfolio of identified
financial instruments that the Company manages together and has a recent
actual pattern of short-term profit-taking; or
· it is a derivative that is not designated and effective as a
hedging instrument.
A financial liability other than a financial liability held for trading or
contingent consideration that may be paid by an acquirer as part of a business
combination may be designated as at FVTPL upon initial recognition if:
· such designation eliminates or significantly reduces a
measurement or recognition inconsistency that would otherwise arise; or
· the financial liability forms part of a group of financial assets
or financial liabilities or both, which is managed, and its performance is
evaluated on a fair value basis, in accordance with the Company's documented
risk management or investment strategy, and information about the grouping is
provided internally on that basis; or
· it forms part of a contract containing one or more embedded
derivatives, and IFRS Financial Instruments: Recognition and Measurement
permits the entire combined contract (asset or liability) to be designated as
at FVTPL.
Financial liabilities at FVTPL are stated at fair value, with any gains or
losses arising on re-measurement recognised in profit or loss. The net gain or
loss recognised in profit or loss incorporates any interest paid on the
financial liability and is included in the 'other gains and losses' line item
in the consolidated statement of comprehensive income.
Risk management contracts
Financial risk management contracts are measured and recognised in accordance
with the Group's accounting policy for financial liabilities at FVTPL as
described above. Physical risk management contracts represent physical
delivery sales contracts in the ordinary course of business and are therefore
not recorded at fair value in the consolidated financial statements.
Settlements on these physical risk management contracts are recognised within
realised gains or losses on risk management contracts at the time of
settlement.
Embedded derivatives
Derivatives embedded in other financial instruments or other host contracts
are treated as separate derivatives when their risks and characteristics are
not closely related to those of the host contracts and the host contracts are
not measured at FVTPL.
Leases
Lease liabilities are initially measured at the present value of lease
payments unpaid at the commencement date. Lease payments are discounted using
the incremental borrowing rate (being the rate that the lessee would have to
pay to borrow the funds necessary to obtain an asset of similar value in a
similar economic environment with similar terms and conditions) unless the
rate implicit in the lease is available. The Group currently uses the rate
implicit in the lease as the discount rate for all leases. For the purposes of
measuring the lease liability, lease payments comprise fixed payments.
Right-of-use assets are measured at cost, which comprises the initial
measurement of the lease liability, plus any lease payments made prior to
lease commencement, initial direct costs incurred and the estimated cost of
restoration or decommissioning, less any lease incentives received. The
right-of-use assets is depreciated on a straight-line basis over their
expected useful lives. Right-of-use assets are subject to an impairment test
if events and circumstances indicate that the carrying value may exceed the
recoverable amount.
Lease repayments made are allocated to capital repayment and interest so as to
produce a constant periodic rate of interest on the remaining lease liability
balance.
Right-of-use assets are presented within property, plant, and equipment. Lease
liabilities are presented within borrowings and leases. In the cash flow
statement, lease repayments (both the principal and interest portion) are
presented within cash used in financing activities, except for payments for
leases of short-term and low-value assets and variable lease payments, which
are presented within cash flows from operating activities.
Leases of low-value items (such as office equipment) and short-term leases
(where the lease term is 12 months or less) are expensed on a straight-line
basis to the consolidated statement of comprehensive income.
Inventory
Inventories comprise oil and gas in tanks and field parts and supplies, all of
which are stated at the lower of production cost (including royalties,
depletion and amortisation of plant, property, and equipment), and net
realisable value. Net realisable value is the estimated selling price in the
ordinary course of business less marketing costs. The cost of inventory is
expensed in the period in which the related revenue is recognised.
Equity
Equity instruments issued by the Company are usually recorded at the proceeds
received, net of direct issue costs, and allocated between called up share
capital and share premium accounts as appropriate.
Foreign currency
Transactions denominated in currencies other than functional currency are
translated at the exchange rate ruling at the date of the transaction.
Monetary assets and liabilities denominated in foreign currencies are
re-translated at the rate of exchange ruling at the balance sheet date. All
differences that arise are recorded in the consolidated statement of
comprehensive income. The functional currency of the Company is GBP, and the
Group results and financial position are presented in GBP.
For the purpose of presenting consolidated financial statements, the assets
and liabilities of the Group's foreign operations are translated at exchange
rates prevailing on the reporting date. Income and expense items are
translated at the average exchange rates for the period, unless exchange rates
fluctuate significantly during that period, in which case the exchange rates
at the date of transactions are used. Exchange differences arising, if any,
are recognised in other comprehensive income and accumulated in a separate
component of equity (attributed to non‑controlling interests as
appropriate).
Taxation
Tax is recognised in profit or loss, except to the extent that it relates to
items recognised in other comprehensive income or directly in equity. In this
case, the tax is also recognised in other comprehensive income or directly in
equity respectively.
Deferred tax is accounted for using the balance sheet liability method in
respect of temporary differences arising from differences between the carrying
amount of assets and liabilities in the financial statements and the
corresponding tax bases used in the computation of taxable profit. However,
deferred tax liabilities are not recognised if they arise from the initial
recognition of goodwill; deferred tax is not accounted for if it arises from
initial recognition of an asset or liability in a transaction other than a
business combination that at the time of the transaction affects neither
accounting nor taxable profit or loss.
In principle, deferred tax liabilities are recognised for all taxable
temporary differences and deferred tax assets are recognised to the extent
that it is probable that taxable profit will be available against which
deductible temporary differences can be utilised.
Deferred tax liabilities are recognised for taxable temporary differences
arising on investments in subsidiaries and associates, and interests in joint
ventures, except where the Company is able to control the reversal of the
temporary difference and it is probable that the temporary difference will not
reverse in the foreseeable future.
Deferred tax assets and liabilities are offset when there is a legally
enforceable right to offset current tax assets against current tax liabilities
and when the deferred tax assets and liabilities relate to taxes levied by the
same taxation authority on either the same taxable entity or different taxable
entities where there is an intention to settle the balances on a net basis.
Deferred tax is calculated at the tax rates that are expected to apply to the
period when the asset is realised or the liability is settled. Deferred tax
assets and liabilities are not discounted.
Intangible assets - Exploration and evaluation expenditures (E&E)
Development expenditure
Expenditure on the construction, installation, and completion of
infrastructure facilities such as platforms, pipelines and the drilling of
development wells, including service, is capitalised initially within
intangible fixed assets and when the well has formally commenced commercial
production, then it is transferred to property, plant and equipment and is
depreciated from the commencement of production as described in the accounting
policy for property, plant and equipment.
Drilling costs and intangible licences
The Group applies the successful efforts method of accounting for oil and gas
assets, having regard to the requirements of IFRS 6 'Exploration for and
Evaluation of Mineral Resources'. Costs incurred prior to obtaining the legal
rights to explore an area are expensed immediately to the consolidated
statement of comprehensive income.
Expenditure incurred on the acquisition of a licence interest is initially
capitalised within intangible assets on a field-by-field basis. Costs are
held, unamortised, within Petroleum mineral leases until such time as the
exploration phase of the field area is complete or commercial reserves have
been discovered. The cost of the licence is subsequently transferred into
property, plant and equipment and depreciated over its estimated useful
economic life.
Exploration expenditure incurred in the process of determining exploration
targets is capitalised initially within intangible assets as drilling costs.
Drilling costs are initially capitalised on a well-by-well basis until the
success or otherwise has been established. Drilling costs are written off on
completion of a well unless the results indicate that hydrocarbon reserves
exist and there is a reasonable prospect that these reserves are commercially
viable. Drilling costs are subsequently transferred into 'Drilling
expenditure' within property, plant and equipment and depreciated over their
estimated useful economic life.
Impairment
The Group assesses at each reporting date whether there is an indication that
an asset may be impaired. This includes consideration of the IFRS 6 impairment
indicators for any intangible exploration and evaluation expenditure
capitalised as intangible assets. Examples of indicators of impairment include
whether:
(a) the period for which the entity has the right to explore in the specific
area has expired during the period or will expire in the near future and is
not expected to be renewed.
(b) substantive expenditure on further exploration for and evaluation of
mineral resources in the specific area is neither budgeted nor planned.
(c) exploration for and evaluation of mineral resources in the specific area
have not led to the discovery of commercially viable quantities of mineral
resources and the entity has decided to discontinue such activities in the
specific area.
(d) sufficient data exist to indicate that, although a development in the
specific area is likely to proceed, the carrying amount of the exploration and
evaluation asset is unlikely to be recovered in full from successful
development or by sale.
If any such indication exists, or when annual impairment testing for an asset
is required, the Group makes an estimate of the asset's recoverable amount,
which is the higher of its fair value less costs to sell and its value in use.
Any impairment identified is recorded in the consolidated statement of
comprehensive income.
Property, plant and equipment
Oil and gas assets - cost
Oil and gas assets are accumulated generally on a cost generating unit (CGU)
basis and represent the cost of developing the commercial reserves discovered
and bringing them into production, together with the intangible exploration
and evaluation asset expenditures incurred in finding commercial reserves
transferred from intangible exploration and evaluation assets. The cost of oil
and gas properties also includes the cost of directly attributable overheads,
borrowing costs capitalised and the cost of recognising provision for future
restoration and decommissioning.
Oil and gas assets - depreciation and depletion
Oil properties, including certain related pipelines, are depreciated using a
unit-of-production method. The cost of producing wells is amortised over
proved plus probable reserves. Licence acquisition, common facilities and
future decommissioning costs are amortised over total proved plus probable
reserves. The unit-of-production rate for the depreciation of common
facilities takes into account expenditures incurred to date, together with
estimated future capital expenditure expected to be incurred relating to as
yet undeveloped reserves expected to be processed through these common
facilities.
Oil and gas assets - impairment
An impairment test is performed whenever events and circumstances arising
during the development or production phase indicate that the carrying value of
an oil and gas property may exceed its recoverable amount.
The carrying value is compared against the expected recoverable amount of the
asset, generally by reference to the present value of the future net cash
flows expected to be derived from production of commercial reserves. The
cash-generating unit applied for impairment test purposes is generally the
field, except that a number of field interests may be grouped as a single
cash-generating unit where the cash inflows of each field are interdependent.
Any impairment identified is charged to the statement of comprehensive income.
Where conditions giving rise to impairment subsequently being reversed, the
effect of the impairment charge is also reversed as a credit to the statement
of comprehensive income, net of any depletion that would have been charged
since the impairment.
Non-oil and gas assets
Property, plant and equipment is stated at cost less accumulated depreciation
and any accumulated impairment losses. Depreciation is provided on all
property, plant, and equipment to write off the cost less estimated residual
value of each asset over its expected useful economic life on a straight-line
basis at the following annual rates:
· Office equipment - 20% or straight line over the life of the
equipment, whichever is the lesser
· Field equipment - between 5% and 25%
All assets are subject to annual impairment reviews where indicators of
impairment are present.
Property, plant, and equipment - disposals
An item of property, plant and equipment is derecognised upon disposal or when
no future economic benefits are expected to arise from the continued use of
the asset. The gain or loss arising on the disposal or retirement of an asset
is determined as the difference between the sales proceeds and the carrying
amount of the asset and is recognised in profit or loss.
Decommissioning provision
Liabilities for decommissioning costs are recognised when the Group has an
obligation to plug and abandon a well, dismantle and remove a facility or an
item of plant and to restore the site on which it is located, and when a
reliable estimate of that liability can be made. Where an obligation exists
for a new facility or item of plant, such as oil production or transportation
facilities, this liability will be recognised on construction or installation.
Similarly, where an obligation exists for a well, this liability is recognised
when it is drilled. An obligation for decommissioning may also crystallise
during the period of operation of a well, facility or item of plant through a
change in legislation or through a decision to terminate operations; an
obligation may also arise in cases where an asset has been sold but the
subsequent owner is no longer able to fulfil its decommissioning obligations,
for example due to bankruptcy. The amount recognised is the present value of
the estimated future expenditure determined in accordance with local
conditions and requirements. The provision for the costs of decommissioning
wells, production facilities and pipelines at the end of their economic lives
is estimated using existing technology, at future prices, depending on the
expected timing of the activity, and discounted using a risk-free rate.
An amount equivalent to the decommissioning provision is recognised as part of
the corresponding intangible asset (in the case of an exploration or appraisal
well) or property, plant, and equipment. The decommissioning portion of the
property, plant and equipment is subsequently depreciated at the same rate as
the rest of the asset. Other than the unwinding of discount on or utilisation
of the provision, any change in the present value of the estimated expenditure
is reflected as an adjustment to the provision and the corresponding asset
where that asset is generating or is expected to generate future economic
benefits. If government assistance is obtained to reduce the liability, the
carrying value of the decommissioning provision and the corresponding E&E
or PP&E asset are reduced by the estimated amount of the extinguished
liability.
Joint operations
The majority of the Group's exploration and production activities are
conducted jointly with others and, accordingly, these consolidated financial
statements reflect only the Group's interest in such activities.
Revenue
Revenue from contracts with customers is recognised, net of royalties, when or
as the Group satisfies a performance obligation by transferring control of a
promised good or service to a customer. The transfer of control of oil,
natural gas, natural gas liquids and petroleum, and other items usually
coincides with title passing to the customer and the customer taking physical
possession. The Group principally satisfies its performance obligations at a
point in time; the amounts of revenue recognised relating to performance
obligations satisfied over time are not significant.
When, or as, a performance obligation is satisfied, the Group recognises as
revenue the amount of the transaction price that is allocated to that
performance obligation. The transaction price is the amount of consideration
to which the Group expects to be entitled. The transaction price is allocated
to the performance obligations in the contract based on standalone selling
prices of the goods or services promised.
Contracts for the sale of commodities are typically priced by reference to
quoted prices. Revenue from term commodity contracts is recognised based on
the contractual pricing provisions for each delivery. Certain of these
contracts have pricing terms based on prices at a point in time after delivery
has been made. Revenue from such contracts is initially recognised based on
relevant prices at the time of delivery and subsequently adjusted as
appropriate. All revenue from these contracts, both that recognised at the
time of delivery and that from post-delivery price adjustments, is disclosed
as revenue from contracts with customers.
Royalty income is recognised as it accrues in accordance with the terms of the
overriding royalty agreements.
Processing income is recognised at the time the services are rendered.
Finance income
Finance income consists of bank interest on cash and cash equivalents which is
recognised as accruing on a straight-line basis, over the period of the
deposit.
Share-based payments
Equity-settled share-based payments to employees and others providing similar
services are measured at the fair value of the equity instruments at the grant
date. The fair value excludes the effect of non-market-based vesting
conditions.
The fair value determined at the grant date of the equity-settled share-based
payments is expensed on a straight-line basis over the vesting period, based
on the Company's estimate of equity instruments that will eventually vest. At
each balance sheet date, the Company revises its estimate of the number of
equity instruments expected to vest as a result of the effect of
non-market-based vesting conditions. The impact of the revision of the
original estimates, if any, is recognised in profit or loss such that the
cumulative expense reflects the revised estimate, with a corresponding
adjustment to equity reserves. When non-employee share options or warrants are
exercised, the initial fair value ascribed to the instruments and recorded as
a reserve is reclassified to share premium.
Business combinations
Acquisitions of business are accounted for using the acquisition method. The
consideration transferred in a business combination is measured at fair value,
which is calculated as the sum of the acquisition‑date fair values of assets
transferred by the Group, liabilities incurred by the Group to the former
owners of the acquiree and the equity interest issued by the Group in exchange
for control of the acquiree. Acquisition‑related costs are recognised in
profit or loss as incurred.
At the acquisition date, the identifiable assets acquired, and the liabilities
assumed are recognised at their fair value at the acquisition date.
Goodwill is measured as the excess of the sum of the consideration
transferred, the amount of any non‑controlling interests in the acquiree,
and the fair value of the acquirers previously held equity interest in the
acquiree (if any) over the net of the acquisition‑date amounts of the
identifiable assets acquired, and the liabilities assumed. If, after
reassessment, the net of the acquisition‑date amounts of the identifiable
assets acquired and liabilities assumed exceeds the sum of the consideration
transferred, the amount of any non‑controlling interests in the acquiree and
the fair value of the acquirers previously held interest in the acquiree (if
any), the excess is recognised immediately in profit or loss as a bargain
purchase gain.
Segmental reporting
In the opinion of the Board of Directors, being the Chief Operating Decision
Maker, the Group has one class of business, being the exploration for, and the
development and production of, oil and has reserves and other related
activities. The Group's primary reporting format is determined to be the
geographical segment according to the location of the oil and gas asset,
currently Canada and UK / Corporate.
Changes in accounting standards
The standards which applied for the first time this year have been adopted and
have not had a material impact.
Standards which are in issue but not yet effective:
At the date of authorisation of these financial statements, the following
Standards and Interpretation, which have not yet been applied in these
financial statements, were in issue but not yet effective. The Group does not
anticipate they will have a material impact.
Standard Interpretation Description Effective date for annual accounting period beginning on or after
IAS 1 Amendments - Presentation of Financial Statements and IFRS Practice Statement 1 January 2023
2: Disclosure of Accounting Policies
IAS 8 Amendments - Accounting Policies, Changes in Accounting Estimates and Errors - 1 January 2023
Definition of Accounting Estimates
IAS 12 Amendments - Income Tax - Deferred Tax related to Assets and Liabilities 1 January 2023
arising from a Single Transaction
IFRS 16 Amendments - Lease Liability in a Sale and Leaseback TBC
The Group has not early adopted any of the above standards and intends to
adopt them when they become effective.
Critical accounting judgements and key sources of estimation uncertainty
The preparation of financial statements using accounting policies consistent
with IFRS requires the Directors to make estimates and assumptions that affect
the reported amounts of assets and liabilities, disclosure of contingent
assets and liabilities and the reported amounts of income and expenses. The
preparation of financial statements also requires the Directors to exercise
judgement in the process of applying the accounting policies. Changes in
estimates, assumptions and judgements can have a significant impact on the
financial statements.
Estimates and underlying assumptions are reviewed on an ongoing basis.
Revisions to accounting estimates are recognised prospectively from the period
in which the estimates are revised.
Critical Accounting Judgements
The following are critical judgements, apart from those involving estimations
(which are presented separately below), that the Directors have made in the
process of applying the Group's accounting policies and that have the most
significant effect on the amounts recognises in the financial statements.
Carrying value of intangible exploration and evaluation assets
At 31 December 2022, the Group held oil and gas E&E assets of £62.1
million (2020: £49.8 million), note 13 (#_Exploration_and_evaluation) . The
carrying value of E&E assets are assessed for impairment when there is an
indication that the asset may be impaired. In making this judgement the
Management considers the indicators of impairment in the intangible
exploration and evaluation asset accounting policies set out above. For its UK
assets, management has considered the well result at the 13/23c-12 Serenity
appraisal well to represent an indicator of impairment and has made an
estimate of the asset's recoverable amount. Further discussion is provided in
note 13 (#_Exploration_and_evaluation) .
For its Canada assets, management has considered the recency of the land
purchases, budgeted spend, the plans to further appraise the Clearwater play
and the fact that there is no observable data which would suggest that the
carrying value of Clearwater play exceeds that of its value from successful
development or sale, and have concluded that no indicators of impairment are
present.
Carrying value of property, plant and equipment - oil and gas assets
At 31 December 2022, the Group held oil and gas PP&E assets of £236.5
million (2021: £224.1 million), note 12 (#_Property,_plant,_and) . These
assets are subject to an annual impairment assessment under IAS 36 'Impairment
of assets' whereby management is first required to consider if there are any
indicators of impairment, and if so, management is then required to estimate
the asset's recoverable amounts. The judgement over indicators of impairment
considers several internal and external factors, including changes in
estimated commercial reserves, changes in oil prices, and changes in expected
future operating and capital expenditure, decommissioning expenditure, the
NPV10 of 2P reserves per the 31 December 2022 independent competent person's
report, and increases in cost of capital which may indicate a higher discount
rate is likely required in assessing the asset's recoverable amount. There is
also judgement in defining the Group's cash-generating units, which is the
smallest identifiable group of assets that generates cash inflows that are
largely independent of the cash inflows from other assets or group of assets.
After considering the above, Management has concluded that there were no
indicators of impairment of oil and gas PP&E assets as at 31 December
2022.
Key sources of estimation uncertainty
The key assumptions concerning the future, and other key sources of estimation
uncertainty at the reporting period that may have a significant risk of
causing a material adjustment to the carrying amounts of assets and
liabilities within the next financial year, are discussed below.
Estimated future cash flows for intangible exploration and evaluation assets
for impairment testing
The Group assesses at each reporting date whether there is an indication that
an asset may be impaired. If any such indication exists, or when annual
impairment testing for an asset is required, the Group makes an estimate of
the asset's recoverable amount, which is the higher of its fair value less
costs to sell and its value in use. As discussed in note 13
(#_Exploration_and_evaluation) , management considered the results of the
13/23c-12 Serenity appraisal well to represent an indicator of impairment and
has made an estimate of the asset's recoverable amount based on value in use
using a discounted cash flow model of a one well development of the Serenity
field. A one well development is dependent on access to infrastructure at
neighbouring fields which may not become available to the Group.
The discounted cash flow model required management to make assumptions about
future production profiles, Brent pricing, capital, operating and abandonment
costs, and the discount rate applied. The most difficult, subjective, or
complex assumptions include the Brent pricing and the discount rate applied.
The Brent pricing assumption ranges from $80-$95 over the life of a one well
development of the Serenity field and is based on an average of price decks
obtained from the Group's brokers, advisors, and the Group's reserves
engineers. The discount rate of 10% is based on the risk profile of similar
assets in the UKCS. Management has considered several downside scenarios on
these assumptions. Decreasing the Brent pricing assumption by 5% or increasing
the discount rate to 13% would not have resulted in an impairment individually
but would have resulted in an impairment if aggregated. It is reasonably
possible that changes to these assumptions within the next financial year
could require a material adjustment to the Group's intangible exploration and
evaluation assets.
Commercial hydrocarbon reserves estimates
Commercial hydrocarbon reserves are those that can be economically extracted
from the Group's oil and gas assets. These estimates are based on information
compiled by independent qualified persons, GLJ Ltd., as at 31 December 2022
and 31 December 2021 and consider a number of factors, including assumptions
about future commodity prices, production rates, operating costs, exchange
rates, and various geological and geophysical technical factors to model
reservoir size, quality, and extractability. Reserve estimates may change from
period to period. Changes to reserves estimates may have a material impact on
the depletion charge for oil and gas PP&E assets, the decommissioning
provision, the carrying value of deferred tax assets, and the Group's
conclusions around indicators of impairment for oil and gas PP&E assets.
The reserve reports are available at https://i3.energy/ (https://i3.energy/)
.
The Group estimates it commenced the year with 154.1 MMboe of proved plus
probable reserves. A 2.0 MMboe increase/decrease to this estimate would have
decreased/increased the oil and gas depletion charge for the period by £458
thousand, respectively.
Decommissioning costs
At 31 December 2022 the Group had recorded a decommissioning provision of
£93.3 million (2021: £125.5 million). In estimating the amount of the
provision, Management makes various assumptions around costs, time to
abandonment and inflation rates, which are discounted at long term government
bond rates, see note 17 (#_Decommissioning_provision) .
The most difficult, subjective, or complex assumptions include the inflation
rate and the discount rate, which have been selected based on market rates
published by the Bank of Canada. A 0.5% increase/decrease in the inflation
rate would have increased/decreased the decommissioning provision by £12.4
million and £10.5 million, respectively. A 0.5% increase/decrease in the
discount rate would have decreased/increased the decommissioning provision by
£10.3 million and £12.3 million, respectively.
Recognition and measurement of deferred tax assets
At 31 December 2022, the Group held deferred tax liabilities of £11.7 million
(2021: £7.5 million) which result from temporary differences at the Group's
Canadian operations. This liability has been reduced by certain deferred tax
assets from deductible temporary differences at the Group's Canadian
operations. In accordance with IAS 12 'Income Taxes', deferred tax assets
shall be recognised for all deductible temporary differences to the extent
that it is probable that taxable profit will be available against which the
deductible temporary difference can be utilised. The Group has generated
positive cash flows and profits from its Canadian operations in 2022 and
expects to continue to do so in the future. Management has applied judgement
in determining the extent to which it is probable that taxable profits will be
available based on estimates of future profits, which include estimates of
commercial reserves, oil, gas and NGL prices, operating and capital
expenditure, and decommissioning expenditure. If future taxable profits differ
from these estimates, the deferred tax asset associated with these deductible
temporary differences could be derecognised and result in a deferred tax
charge to the consolidated statement of comprehensive income.
4 (Loss) / gain on bargain purchase and asset dispositions
The gain on bargain purchase and asset dispositions as per the consolidated
statement of comprehensive income is as follows:
2022 2021
£'000 £'000
Gain on bargain purchase - 24,262
(Loss) / gain on asset dispositions (9) 751
(Loss) / gain on bargain purchase and asset dispositions (9) 25,013
The loss in 2022 relates to purchase price adjustments on asset dispositions
completed in the prior year.
5 Segmental reporting
The Chief Operating Decision Maker (CODM) is the Board of Directors. They
consider that the Group operates as two segments, as follows:
· UK / Corporate - That of Corporate activities in the UK and oil
and gas exploration, appraisal and development on the UKCS.
· Canada - That of oil and gas production in the WCSB.
Such components are identified on the basis of internal reports that the Board
reviews regularly.
The following is an analysis of the Group's revenue and results by reportable
segment in 2022:
UK / Corporate Canada Total
£'000 £'000 £'000
Revenue - 208,436 208,436
Production costs - (76,418) (76,418)
Loss on risk management contracts - (18,990) (18,990)
Depreciation and depletion (4) (34,335) (34,339)
Gross (loss) / profit (4) 78,693 78,689
Administrative expenses (6,821) (8,217) (15,038)
Acquisition costs - - -
(Loss) on bargain purchase and asset dispositions - (9) (9)
Operating (loss) / profit (6,825) 70,467 63,642
Finance costs (5,179) (2,686) (7,865)
(Loss) / profit before tax (12,004) 67,781 55,777
Tax (charge) / credit for the year - (13,826) (13,826)
(Loss) / profit for the year (12,004) 53,955 41,951
The following is an analysis of the Group's revenue and results by reportable
segment in 2021:
UK / Corporate Canada Total
£'000 £'000 £'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 (loss) / 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 assets and liabilities by
reportable segment as at 31 December 2022 and the capital expenditure for the
year then ended:
UK / Corporate Canada Total
£'000 £'000 £'000
Total assets 57,500 295,712 353,212
Total liabilities (30,166) (158,300) (188,466)
Capital expenditure - E&E 5,650 6,677 12,327
Capital expenditure - PP&E - 75,793 75,793
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 Canada Total
£'000 £'000 £'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
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:
2022 2021
£'000 £'000
Oil and condensate 113,003 40,829
Natural gas liquids 40,142 19,107
Natural gas 77,656 34,134
Royalty interest 4,890 1,951
Oil and gas sales 235,691 96,021
Royalties (33,536) (12,094)
Revenue from the sale of oil and gas 202,155 83,927
Processing income 5,995 2,605
Other operating income 286 231
Total revenue 208,436 86,763
All revenue is from the Group's Canadian operations. Revenue from the sale
of oil and natural gas liquids is recognised at the point in time when title
transfers to the purchaser. Processing income is recognised at the time the
service is rendered.
During the year ended 31 December 2022, three (2021: four) customers
individually totalled more than 10% of total revenues, totalling 81% (2021:
79%) in aggregate and 35%, 25%, and 21%, individually (2021: 25%, 20%, 19%,
and 15%).
7 Administrative expenses
2022 2021
£'000 £'000
Directors' fees 323 300
Employee costs* 9,982 8,503
Professional fees** 1,830 1,728
Other 2,285 2,448
Realised FX loss 505 269
Unrealised FX loss / (gain) 113 (154)
Total administrative expenses 15,038 13,094
* Group staff costs comprised:
2022 2021
£'000 £'000
Wages, salaries, and benefits 11,602 6,027
Social security costs 1,189 336
Other pension costs 304 254
Share-based payments expense - employees (including NEDs) 1,092 3,217
Total staff costs 14,187 9,834
Capitalised salaries and overhead recoveries (4,205) (1,331)
Charge to the profit or loss 9,982 8,503
i3 Energy plc had an average of two staff during the year ended 31 December
2022 (2021: Nil) and paid £1,050 thousand of wages, salaries and benefits and
£137 thousand of social security costs (2021: Nil). The Non-Executive
Directors of the Group are not considered staff, and their remuneration is
disclosed in note 10 (#_Directors%E2%80%99_remuneration) .
The average number of persons employed by the Group, including Executive
Directors, was:
Average number of persons employed 2022 Number 2021 Number
Operations 31 29
Corporate and administration 25 18
Total 56 47
** Included within professional fees are fees payable to the Company's auditor
and its associates for the following:
2022 2021
£'000 £'000
Audit services
The audit of the Company's annual accounts 130 120
The audit of the Company's subsidiaries - -
Total audit fees 130 120
Advisory on certain employment matters 1 -
Procedures related to the Group's interim financial statements 3 -
Total 134 120
8 Finance costs
2022 2021
£'000 £'000
Accretion of loan notes (note 16) 3,386 2,824
PIK interest expense on loan notes (note 16) - 3,144
Cash interest expense on loan notes (note 16) 2,309 -
Stock-based compensation - warrants (note 20) - 451
Unwinding of discount on decommissioning provision (note 17) 2,667 1,539
Bank charges and interest on creditors 21 374
(Gain) / loss on financial instrument at FVTPL (note 15) (518) (723)
Total finance costs 7,865 7,609
9 Taxation
Taxation credit
The below table reconciles the tax charge for the year to the profit before
tax per the consolidated statement of comprehensive income.
2022 2021
£'000
£'000
* Restated
Profit before income tax 55,777 25,744
Rate of Corporate Tax in Canada 23% 23%
Expected tax charge 12,829 5,921
Effects of:
Interest and other not deductible for SCT or EPL 1,993 620
Permanent differences 1,213 (3,804)
Foreign tax rate difference (5,041) (2,208)
Change in estimated pool balances 22 179
Derecognition of deferred tax asset 2,810 440
R&D tax credit received - (487)
Total income tax charge 13,826 661
* Canada is the only jurisdiction where the Group produces oil and gas,
generates taxable income, and records a current and deferred tax charge. As
such, the Group elected to change the tax rate in reconciliation of the tax
charge to 23% in 2022, the combined corporate rate of taxation in Canada. The
comparative period has been restated on the same basis. The total income tax
charge was unimpacted in both periods, with the only changes being to the
'Expected tax charge' and the 'Foreign tax rate difference' lines in the
reconciliation above. The difference on foreign tax rate results from the
difference between 65% overall tax rate in the UK and the 23% tax rate used in
the reconciliation.
Of which: 2022 2021
£'000
£'000
Current tax charge / (credit) 10,002 (487)
Deferred tax charge 3,824 1,148
Total income tax charge 13,826 661
The current tax charge of £10,002 thousand in 2022 resulted from taxable
income in the Group's Canadian subsidiary, i3 Energy Canada Limited, which is
payable in the first half of 2023. The current tax credit of £487 thousand in
2021 resulted from the receipt of R&D tax refunds in the UK in respect of
the 2019 fiscal year.
In 2022 the Energy Profits Levy (EPL) was introduced at a rate of 25% with
effect from 26 May 2022. This, along with the Ring Fence Corporation Tax
(RFCT) at 30% and the Supplementary Charge (SCT) of 10% brings the overall tax
rate in the UK to 65%. The EPL increased to a rate of 35% effective 1 January
2023 which will bring the overall tax rate in the UK to 75%. The EPL will
remain in effect until 31 March 2028. The Group will not be impacted by the
increase until such time as taxable profits are generated in the UK. The
combined corporate rate of taxation in Canada remained unchanged at 23%.
Deferred tax
The components of the net deferred tax asset and the movement during the year
is summarised as follows:
At 31 December 2021 Acquired during the year Recognised in income FX movement At 31 December 2022
£'000 £'000 £'000 £'000 £'000
UK:
Deferred tax assets:
Losses 28,711 - 8,809 - 37,520
Valuation allowance (8,782) - (6,341) - (15,123)
Deferred tax liabilities:
PP&E (19,929) - (2,468) - (22,397)
Net deferred tax asset - - - - -
Canada:
Deferred tax assets:
Decommissioning provision 28,870 - (9,088) 1,684 21,466
Losses 2,416 - (2,579) 163 -
Risk management contracts 25 - (197) 4 (168)
Other 207 - 16 11 234
Valuation allowance (5,639) - 1,788 (329) (4,180)
Deferred tax liabilities:
PP&E (33,365) - 6,236 (1,890) (29,019)
Net deferred tax liability (7,486) - (3,824) (357) (11,667)
Net deferred tax asset / (liability) (7,486) - (3,824) (357) (11,667)
A deferred tax asset has not been recognised in respect of tax losses and
allowances in the UK due to uncertainty over the availability of future
taxable profits in the UK to offset these losses against.
The Group recognised a net deferred tax liability through a deferred tax
charge of £3,824 thousand for changes in net deductible temporary differences
in the year and £357 thousand for FX movements during the year. The deferred
tax liability has been partially offset by a deferred tax asset which has been
recognised in Canada to the extent that the Group anticipates probable future
taxable profits to against which the assets can be utilised.
The Group's estimated tax pools are summarised in the following table. The
non-capital tax loss pools in Canada expire over a period of 20 years. All
other tax pools do not expire.
31 December 2022 31 December 2021
£'000 £'000
UK:
Taxable losses 38,927 29,325
Mineral extraction allowances 52,466 49,819
Total 91,393 79,144
Canada:
Canadian exploration expense (CEE, deductible at 100% p.a.) 1,623 3,107
Canadian development expense (CDE, deductible at 30% p.a.) 37,870 7,519
Canadian oil and gas property expense (COGPE, deductible at 10% p.a.) 58,478 56,391
Undepreciated capital cost (UCC, deductible at 25% p.a.) 18,867 11,991
Non-capital losses (NCL, deductible at 100% p.a.) - 10,503
Other (deductible at various rates p.a.) 1,019 833
Total 117,857 90,344
10 Directors' remuneration
Salary / Fees Bonus Share based payments Total
£'000 £'000 £'000 £'000
2022
Executive Directors
Majid Shafiq 487 833 3,507 4,827
Graham Heath 702 668 2,596 3,966
Ryan Heath 295 535 2,511 3,341
Non-Executive Directors
Neill Carson 68 - 227 295
Richard Ames 68 - 227 295
Linda Beal 106 - 117 223
John Festival 81 - 223 304
Total 1,807 2,036 9,408 13,251
Salary / Fees Bonus Share based payments Total
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
Share based payments represent the difference between the exercise price and
the market value of i3 shares on the date of exercise, multiplied by the
number of options exercised.
Included in Graham Heath Salary / Fees is a one-time compensation for loss of
office payment of £417 thousand.
During the year the Company contributed £2 thousand to i3's CEO's pension
scheme (2021 - £2 thousand).
11 Earnings per share
From continuing operations
Basic earnings or loss per share is calculated as profit/(loss) for the year,
adjusted to exclude any costs of servicing equity (other than dividends),
divided by the weighted average number of ordinary shares, adjusted for any
bonus element.
Diluted earnings or loss per share amounts are calculated by dividing losses
or profits for the year attributable to ordinary equity holders of the parent
by the weighted average number of ordinary shares outstanding during the year,
plus the weighted average number of shares that would be issued on the
conversion of dilutive potential ordinary shares into ordinary shares.
The calculation of the basic and diluted earnings per share is based on the
following data:
Year Ended 31 December 2022 Year Ended 31 December 2021
Earnings
Earnings for the purposes of basic and diluted earnings per share being net 41,951 25,083
profit attributable to owners of i3 Energy (£'000)
Weighted average number of shares
Weighted average number of Ordinary Shares - basic 1,164,210,976 883,664,352
Effect of dilutive potential ordinary shares:
Share options 51,089,073 49,369,708
Warrants 9,048,113 32,758,752
Weighted average number of Ordinary Shares - diluted 1,224,348,162 965,792,812
Basic earnings per share (pence) 3.60 2.84
Diluted earnings per share (pence) 3.43 2.60
In 2021, prior to the BHGE warrant repricing on 17 May 2021, these instruments
were anti-dilutive as their exercise price exceed the average market price of
the Ordinary Shares over this period. Concurrent with their repricing the BHGE
warrants were immediately exercised for ordinary shares. The BHGE shares were
therefore included in the basic weighted average number of Ordinary Shares
from 17 May 2021 but were not further included in the effect of dilutive
potential ordinary shares.
12 Property, plant, and equipment
Oil and gas assets Right of use assets Other fixed assets Total
Cost
As at 1 January 2021 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 (note 17) 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
Acquisitions 1,653 - - 1,653
Additions 75,793 - 21 75,814
Disposals (1,386) (28) - (1,414)
Changes to decommissioning estimates (note 17) (40,233) - - (40,233)
Decommissioning settlements under SRP and ASCP (note 17) (731) - - (731)
Transfer between asset classes - (88) 88 -
Exchange movement 12,585 7 3 12,595
As at 31 December 2022 297,714 - 184 297,898
Accumulated depreciation and depletion
As at 1 January 2021 (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)
Charge for the year (34,301) (17) (21) (34,339)
Disposals - 12 - 12
Transfer between asset classes - 42 (42) -
Exchange movement (968) (4) - (972)
As at 31 December 2022 (61,346) - (87) (61,433)
Carrying amount at 31 December 2021 223,956 76 48 224,080
Carrying amount at 31 December 2022 236,368 - 97 236,465
13 Exploration and evaluation assets (Intangible)
Year Ended 31 December 2022 Year Ended 31 December 2021
£'000 £'000
At start of year 49,819 48,809
Additions 12,327 1,010
Exchange movement (86) -
At end of year 62,060 49,819
Included within E&E assets is the Group's UK P.2358 Licence, which
commenced its four-year second term on 30 September 2020 and contains the
Serenity discovery and the Liberator West and Minor High prospective areas.
In March 2022 the Group announced it had agreed farm-in terms with Europa Oil
& Gas Limited ("Europa") for a 25% working interest ("WI") in Block 13/23c
North (Licence P.2358) which contains the Serenity discovery. Under the terms
of the farmout, Europa will fund 46.25% of the cost of the upcoming Serenity
appraisal well up to a gross capped well cost of £15 million. Any well costs
exceeding £15 million will be funded by the companies in proportion to their
respective working interests. The Farm-In Agreement ("FIA") was signed in
April 2022 and following the fulfilment of all conditions precedent in the
FIA, the transaction closed in August 2022. Following this farm-out, i3
retains a 75% WI in Block 13/23c North (Licence P.2358) and a 100% WI in Block
13/23c South (Licence P.2358), which contains the Minos High Prospect and
Liberator discovery.
In September 2022, the 13/23c-12 Serenity appraisal well was spud and drilled
to a total vertical depth of 5,630 ft below sea level. The targeted Lower
Cretaceous Captain sand, which contained hydrocarbons in the 13/23c-10 well
discovered in October 2019, was not present at this location. Over 100 ft of
other Captain sands in various sequences were found but were water wet. The
well was plugged and abandoned. Management considers the well result to
represent an indicator of impairment and has made an estimate of the asset's
recoverable amount based of management's best estimate of value in use using a
discounted cash flow model of a one well development of the Serenity field.
The estimated recoverable amount exceeded the carrying amount of the Group's
UK E&E assets as at 31 December 2022, and accordingly no impairment was
recognised. Further discussion is provided in note 2
(#_Critical_accounting_judgements) .
Also included within E&E assets are costs associated with land purchases
and a preliminary appraisal well in the Clearwater play in Canada.
14 Trade and other receivables
31 December 2022 31 December 2021
£'000 £'000
Trade and accrued receivables 26,770 21,982
Joint venture receivables 5,563 1,483
Prepayments & other receivables 2,510 2,038
Total trade and other receivables 34,843 25,503
Trade and accrued receivables are all due within one year.
Joint venture receivables represent amounts due from operating partners for
operating and capital activity in Canada and the UK.
The fair value of trade and other receivables is the same as their carrying
values as stated above and they do not contain any impaired assets.
The maximum exposure to credit risk at the reporting date is the carrying
value of each class of receivable mentioned above. The Group does not hold any
collateral as security.
15 Trade and other payables
31 December 2022 31 December 2021
£'000 £'000
Trade creditors 15,383 5,169
Sales tax payable 378 65
Accruals 26,909 13,565
Dividends payable 2,040 -
Joint venture payables 1,263 910
Income taxes payable 9,873 -
Total trade and other payables 55,846 19,709
The average credit period taken for trade purchases is 60 days. No interest is
charged on the trade payables. The carrying values of trade and other payables
are considered to be a reasonable approximation of the fair value and are
considered by the Directors as payable within one year.
Joint venture payables represent amounts due to operating partners for
operating and capital activity in Canada.
Non-current accounts payable
On 2 July 2019 the Group agreed with Baker Hughes, a GE Company, and GE Oil
& Gas Limited (collectively referred to as "BHGE" hereafter) that £3,000
thousand of oilfield service and oilfield equipment contract payments will not
become payable until such time as i3 has received its first sales revenues
from Liberator Phase I. This payable was previously recorded as a non-current
accounts payable.
On 17 May 2021, i3 announced that it had successfully restructured legacy
contracts and agreements for equipment, oil field services, and warrants with
BHGE. In summary, the remainder of a £5.8 million contract for subsea trees
and wellheads was cancelled, 5,277,045 warrants had an exercise price
reduction to £0.0001 per share (the "Warrant Shares"), and an outstanding
contingent payment for £3.0 million ("Deferred Payment Invoice Balance", or
"DPIB") in oil field services and equipment that becomes payable at such time
as the Group receives consideration from any sale or farm-down of its Serenity
or Liberator assets will be reduced by the exercise value of the Warrant
Shares, the market value of the Warrant Shares from time to time, all
dividends received by BHGE associated with the Warrant Shares, and certain
payments to be made to BHGE. The purpose of this restructuring was to enable
i3 to become a dividend payer, as certain conditions of the abovementioned
contracts prevented it from reducing its share premium account - a required
step in order for i3 to effect dividend distributions to its shareholders. The
incremental fair value of the modified warrants was expensed in 2021 (note 8).
In Q4 2022, the Group received consideration from the Serenity farm-in in
excess of the DPIB amount and the repayment was triggered. The repayment
amount of £1,270 thousand was calculated as the £3.0 million payable amount,
less the exercise value of the Warrant Shares of £1 thousand, less cash
payments of £487 thousand made in 2021 against the DPIB balance, less the
Market Value of the Warrant Shares of £1,161 thousand, which totals the
5,277,045 Warrant Shares as at the repayment date share price of 22.00p/share,
less £81 thousand of dividends paid on the Warrant Shares. The repayment
amount was settled in cash in 2022 and the liability was extinguished. The
increase in i3's share price from 13.35p/share from 31 December 2021 to
22.00p/share at the repayment date resulted in a non-cash gain in the value of
the Warrant Share which has been recorded in the consolidated statement of
comprehensive income within Finance Costs.
A reconciliation of the balance is as follows:
Year Ended 31 December 2022 Year Ended 31 December 2021
£'000 £'000
At start of year 1,789 3,000
Exercise value of the Warrant Shares (1) (1)
Cash payments made during the year (1,270) (487)
Non-cash change in market value of the Warrant Shares (note 8 (518) (723)
(#_Finance_costs) )
At end of year - 1,789
31 December 2022 31 December 2021
£'000 £'000
Of which:
Current, within trade accounts payable - 1,232
Non-current - 557
Total - 1,789
16 Borrowings
H1-2019 loan note facility
In May 2019, the Company completed a £22 million H1-2019 loan note facility
("H1-2019 LN"). The H1-2019 LNs have a term of 4 years, maturing on 31 May
2023 and bearing interest, payable on a quarterly basis at the Group's option
(i) in cash at a rate of 8% per annum, or (ii) in kind at a rate of 11% per
annum by the issuance of additional H1-2019 LNs. The Group elected to pay all
interest in kind prior to 2022, and in cash for all four quarters in 2022.
The noteholders were granted warrants ("H1-2019 LN Warrants") in the notional
amount of £1 for each £1 of loan notes issued, with H1-2019 Warrants being
issued proportionately across three series. The H1-2019 LN Warrants vested on
the issue date and expire 4 years thereafter and can be exercised through
either/or a combination of a cash payment and/or surrender of H1-2019 LNs plus
accrued interest equal to the aggregate notional amount of the H1-2019 LN
Warrants being exercised. Each H1-2019 LN Warrant gives the holder the right
to convert the notional amount into such number of shares as is derived by
dividing the notional amount by the exercise price. The following table
outlines the terms of the warrants as at their issuance date.
Notional amount of warrants (£) Exercise price upon issuance Shares to be issued upon exercise of warrants Share price at issuance (£) Time to maturity (years) Value (£/share)
(£/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 thousand and was bifurcated from the debt contract and
classified as equity. The H1-2019 LNs are comprised of the following
components: the debt contract, the conversion feature, the interest rate
payment option and the early conversion feature (at the Group's option). At
inception the debt component was recorded at an estimated fair value of
£10,625 thousand. The debt balance is unwound using the effective interest
rate method to the principal value at maturity with a corresponding non-cash
accretion charge to earnings.
Interest expense and accretion expense to 31 December 2022 was £2,309
thousand and £3,386 thousand respectively.
Borrowings reconciliation
H1-2019 LN Leases Total
£'000 £'000 £'000
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
Increase through interest (non-cash) 2,309 1 2,310
Accretion expense (non-cash) 3,386 - 3,386
Lease and interest payments (cash) (2,309) (74) (2,383)
Exchange movement (non-cash) - 4 4
At 31 December 2022 27,241 - 27,241
The classification as at 31 December 2022 is as follows:
H1-2019 LN Leases Total
£'000 £'000 £'000
Of which:
Current 27,241 - 27,241
Non-current - - -
At 31 December 2022 27,241 - 27,241
The classification as at 31 December 2021 is as follows:
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 - 23,924
17 Decommissioning provision
Year Ended 31 December 2022 Year Ended 31 December 2021
£'000 £'000
At start of year 125,523 66,783
Liabilities assumed through acquisitions 348 56,350
Liabilities incurred 1,369 312
Liabilities disposed (213) (7,984)
Liabilities settled (2,190) (670)
Liabilities settled under SRP and ASCP (731) (324)
Change in estimates (40,233) 7,603
Unwinding of discount (Note 8) 2,667 1,539
Exchange movement 6,791 1,914
At end of year 93,331 125,523
31 December 2022 31 December 2021
£'000 £'000
Of which:
Current 3,190 2,368
Non-current 90,141 123,155
Total 93,331 125,523
A summary of the key estimates and assumptions are as follows:
31 December 2022 31 December 2021
Undiscounted / uninflated cash flows (CAD, thousands) 206,613 207,371
Inflation rate 2.09% 1.82%
Discount rate 3.28% 1.68%
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 and ASCP a corresponding
decrease to the decommissioning asset was recorded. The change in estimate for
the year ended 31 December 2022 was primarily driven by changes in market
interest and inflation rates as published by the Bank of Canada. The inflation
and discount rates have been pinpointed as a key source of estimation
uncertainty and are further discussed in note 2
(#_Critical_accounting_judgements) .
18 Risk management contracts
The Group enters risk management contracts to hedge a portion of the Group's
exposure to fluctuations in prevailing commodity prices for oil, gas, and
natural gas liquids. The Group's physical commodity contracts represent
physical delivery sales contracts in the ordinary course of business and are
therefore not recorded at fair value in the consolidated financial statements.
The Group's financial risk management contracts have not been designated as
hedging instruments in a hedge relationship under IFRS 9 and are carried at
fair value through profit and loss. The financial risk management contracts
are classified as Level 2 in the fair value hierarchy as defined by IFRS 13
'Fair value measurements' (note 22 (#_Financial_instruments_and) ).
The principal terms of the risk management contracts held as at 31 December
2022 are presented in the table below.
Type Effective date Termination date Total Volume Avg. Price
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 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
AECO 7A Physical Collar 1 Jan 2023 31 Mar 2023 2,500 GJ/Day CAD 6.0000-9.4000 / GJ
AECO 7A Financial Collar 1 Jan 2023 31 Mar 2023 5,000 GJ/Day CAD 6.5000-9.3300 / GJ
AECO 7A Financial Collar 1 Jan 2023 31 Mar 2023 5,000 GJ/Day CAD 5.0000-11.2000 / GJ
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
WTI Physical Swaps 1 Jan 2023 30 Jun 2023 150 bbl/Day CAD 114.20 / bbl
WTI Physical Collar 1 Jan 2023 30 Jun 2023 150 bbl/Day CAD 100.00-129.50 / bbl
WTI Physical Collar 1 Jan 2023 30 Jun 2023 250 bbl/Day CAD 100.00-129.00 / bbl
WTI Physical Collar 1 Apr 2023 30 Jun 2023 250 bbl/Day CAD 100.00-131.25 / bbl
WTI Financial Collar 1 Apr 2023 30 Jun 2023 250 bbl/Day CAD 100.00-132.25 / bbl
WTI Financial Collar 1 Jan 2023 31 Mar 2023 300 bbl/Day CAD 100.00-120.00 / bbl
WTI Financial Collar 1 Jan 2023 31 Mar 2023 200 bbl/Day CAD 100.00-121.50 / bbl
WTI Financial Collar 1 Jan 2023 31 Mar 2023 300 bbl/Day CAD 100.00-125.25 / bbl
WTI Financial Collar 1 Jan 2023 31 Mar 2023 300 bbl/Day CAD 100.00-121.40 / bbl
WTI Physical Collar 1 Jan 2023 31 Mar 2023 300 bbl/Day CAD 100.00-126.75 / bbl
WTI Financial Collar 1 Apr 2023 30 Apr 2023 300 bbl/Day CAD 100.00-120.75 / bbl
WTI Financial Collar 1 Apr 2023 30 Jun 2023 250 bbl/Day CAD 100.00-118.20 / bbl
WTI Purchased Put Option 1 Apr 2023 30 Jun 2023 1,000 bbl/Day CAD 100.00 / bbl
WTI Financial Swaps 1 Apr 2023 30 Jun 2023 250 bbl/Day CAD 112.00 / bbl
Conway Financial Collar 1 Jan 2023 31 Mar 2023 250 bbl/Day USD 1.0000-1.2500 / gal
Conway Financial Collar 1 Jan 2023 31 Mar 2023 250 bbl/Day USD 1.0000-1.2100 / gal
The Group's losses on risk management contracts arose due to commodity price
increases in 2021 and 2022 which resulted in the Group settling its hedge
positions at lower prices than could have otherwise been achieved at
prevailing market prices. These losses are presented in the following table.
2022 2021
£'000 £'000
Unrealised (gain) / loss on risk management contracts (858) 111
Realised loss on risk management contracts 19,848 5,374
Total 18,990 5,485
The carrying value of the Group's risk management contracts are present in the
following table.
31 December 2022 31 December 2021
£'000 £'000
Current asset 1,111 814
Current liability (381) (925)
Net current asset / (liability) 730 (111)
19 Authorised, issued and called-up share capital
Issuance 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
date
Shares Shares £ £'000 £'000 £'000 £'000 £'000
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
Issued on exercise of 5 pence options 6 Jun 22 40,860,277 - 0.0001 4 - 2,038 - 2,038
Issued on exercise of 6.1 pence options 6 Jun 22 7,994,653 - 0.0001 1 - 487 - 487
Issued on exercise of 11 pence options 6 Jun 22 17,450,451 - 0.0001 1 - 1,918 - 1,918
At 31 December 2022 1,192,731,373 5,000 - 119 50 50,646 (2,000) 48,646
* 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 enabled 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.
On 6 June 2022, 66,305,381 ordinary shares were admitted to trading following
the exercise of employee share options. Further details are provided in note
20 (#_Stock-based_payments) .
£17.4. million of dividends were declared in 2022 as follows:
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 0.1050 1,183
9 March 2022 17 March 2022 18 March 2022 8 April 2022 0.1050 1,183
6 April 2022 14 April 2022 19 April 2022 6 May 2022 0.1050 1,183
11 May 2022 19 May 2022 20 May 2022 10 June 2022 0.1425 1,604
8 June 2022 16 June 2022 17 June 2022 8 July 2022 0.1425 1,700
6 July 2022 14 July 2022 15 July 2022 5 August 2022 0.1425 1,700
3 August 2022 11 August 2022 12 August 2022 2 September 2022 0.1425 1,700
7 September 2022 14 September 2022 15 September 2022 7 October 2022 0.1425 1,700
5 October 2022 13 October 2022 14 October 2022 4 November 2022 0.1425 1,700
2 November 2022 10 November 2022 11 November 2022 2 December 2022 0.1425 1,700
22 December 2022 5 January 2023 6 January 2023 27 January 2023 0.1710 2,040
Total 17,393
£3.4 million of dividends were declared in 2021 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 £1,092 thousand
(2021: £3,668 thousand).
Employee and NED share options
During the year the Group had share based payment expense relating to the
issuance of share options of £1,092 thousand (2021: £3,217 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 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
5p options exercised during the period (67,006,794) 5.00 8.54
6.1p options exercised during the period (12,454,359) 6.10 8.54
11p options exercised during the period (35,085,877) 11.00 9.09
Granted during the period 2,700,000 24.10 10.00
Forfeited during the period (708,390) 11.00 8.84
At 31 December 2022 31,404,955 10.72 7.93
In May 2022, i3 employees and directors elected to exercise options over an
aggregate 114,547,030 ordinary shares of i3 Energy plc. The Company primarily
settled in ordinary shares only the post-tax in-the-money value of the options
(based on c28 pence per share), which resulted in the issuance of 66,305,381
ordinary shares which were admitted to trading on 6 June 2022. £635 thousand
in proceeds was collected from employees who elected not to settle their
strike price through a reduction in ordinary shares received. £6,324 thousand
in employment tax was settled by the Company with the relevant taxation
authorities on behalf of the employees which has been recorded within equity
as a deduction from retained earnings. £6 thousand was recorded as an
increase to the ordinary shares account, which represents the number of
ordinary shares issued multiplied by their nominal value of £0.001 per share.
£4,443 thousand was recorded as an increase to the share premium account,
which represents the number of ordinary shares issued multiplied by the excess
in the respective strike prices over the nominal value of the shares. £3,883
thousand has been recorded as a decrease to the share-based payment reserve,
which represents the strike price settled through surrendered shares.
Throughout 2022, the Company issued options over a total of 2,700,000 ordinary
to new employees of i3 Canada. The options were issued in accordance with the
rules of the Company's Employee Share Option Plan at exercise prices equal to
the market price of i3 shares at the date of the grants, which ranged from
21.55 pence to 29.40 pence per share. One-third of the options will vest on
each of the 12-month, 24-month, and 36-month anniversaries of the employment
start dates. The fair values were calculated using the Black Scholes model
with inputs for stock price and exercise price ranging from 21.55 pence to
29.40 pence per share, time to maturity of 10 years, volatility ranging from
100% to 104%, the Risk-Free Interest rate ranging from 1.90% to 3.15%, and a
dividend yield ranging from 6% to 8%. The resulting fair value of £278
thousand will be expensed over the expected vesting period.
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 5.00 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
5.00 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 6.10 pence per share, the closing
price on 8 January 2021. The fair value was calculated using the Black Scholes
model with inputs for share price of 6.10 pence, exercise price of 6.10 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 5.00 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 11.00 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 11.00 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%. 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.
3,579,348 outstanding employee share options as at 31 December 2022 were fully
vested and exercisable.
Warrants
During the year the Group did not incur a share based payment expense relating
to the modification and issuance of warrants (2021: £451 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 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 0.30
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
Expired in the period (4,225,204) 47.34 NA
At 31 December 2022 9,051,927 0.01 0.42
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 (#_Trade_and_other) .
EMI options
The Company operates an Employee Management Incentive (EMI) share option
scheme. Grants were made on 14 April 2016 and 6 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 2022 and 2021 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 2022
have a weighted average exercise price of £0.11 and a weighted average
remaining contractual life of 3.93 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 prior to its redemption in Q4
2022, 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 was
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 2022 Carried at FVTPL Carried at amortised cost
Financial assets
Cash and cash equivalents - 16,560
Trade and other receivables - 34,843
Risk management contracts (Level 2) 1,111 -
Total 1,111 51,403
Financial liabilities
Trade and other payables - 55,846
Risk management contracts (Level 2) 381 -
Borrowings and leases - 27,241
Total 381 83,087
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
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 in currencies other than UK pound
sterling as at 31 December 2022.
The Group is also exposed to exchange differences on translation of its
foreign operations in Canada, which resulted in a gain of £6,529 thousand for
the year ended 31 December 2022 (2021: £1,511 thousand). A 10% strengthening
of GBP against CAD as at 31 December 2022 would have resulted in a loss on
translation of £7,073 thousand (2021: £8,876 thousand), and a 10% weakening
of GBP to CAD would have resulted in a gain of £23,152 thousand (2021:
£14,222 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 55,846 - - - 55,846
H1 2019 LNs 22,000 - - - 22,000
H1 2019 cash and PIK interest ** 7,204 - - - 7,204
At 31 December 2022 85,050 - - - 85,050
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
* The non-current payable was repayable at such time as i3 has received
consideration from any sale or farm-down of its Serenity or Liberator assets
(see note 15). This was achieved in 2022 and the full balance was repaid
within the year.
** 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 the remaining interest is paid in cash, with the accrued
PIK interest repaid at 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 at 31
December 2022 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 Increase in commodity price / (decrease) in profit before loss and equity
£'000 £'000
Change in WTI - CAD 5.00 / bbl 141 (141)
Change in AECO - CAD 0.50 / GJ 700 (700)
Change in Conway - USD 5.00 / bbl 140 (140)
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 £27,241 thousand at 31 December 2022 (2021: £23,924
thousand) (note 16 (#_Borrowings) ), has capital, defined as the total equity
and reserves of the Group of £164,746 thousand (2021: £138,166 thousand) and
cash and equivalents of £16,560 thousand (2021: £15,335 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
At 31 December 2022 1 year 2-3 years 4-5 years 5+ years Total
£'000 £'000 £'000 £'000 £'000
Operating 388 - - - 388
Transportation 1,720 1,423 225 18 3,386
Total 2,108 1,423 225 18 3,774
Transportation commitments relate to take-or-pay pipeline capacity in
Alberta.
The Group did not have any capital commitments as at 31 December 2022 or 2021.
24 Events after the reporting period
After 31 December 2022 i3 entered into various risk management contracts, as
summarised below.
Type Effective date Termination date Total Volume Avg. Price
NYMEX Physical Basis Differential 1 Apr 2023 31 Oct 2023 10,000 MMBtu/Day (USD 1.4625 / MMBtu)
WTI Financial Swaps 1 Jul 2023 31 Dec 2023 500 bbl/Day CAD 100.20 / bbl
WTI Physical Swaps 1 Jul 2023 31 Dec 2023 500 bbl/Day CAD 100.30 / bbl
In early-2023 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
12 January 2023 19 January 2023 20 January 2023 10 February 2023 0.1710 2,040
8 February 2023 16 February 2023 17 February 2023 10 March 2023 0.1710 2,040
15 March 2023 23 March 2023 24 March 2023 14 April 2023 0.1710 2,040
12 April 2023 20 April 2023 21 April 2023 12 May 2023 0.1710 2,040
17 May 2023 25 May 2023 26 May 2023 16 June 2023 0.1710 2,055
Total 10,215
On 4 January 2023 the Group issued a total of 116,667 Ordinary Shares of 0.01
pence each following the exercise of options by an employee, at an exercise
price of £0.11 per Ordinary Share. The Ordinary Shares were subsequently
admitted for trading on AIM.
On 3 April 2023 the Group announced the reserves of i3 Energy Canada Limited
as of 31 December 2022. Highlights include Company Interest PDP reserves of
49MMboe, 1P reserves of 93MMboe, and 2P reserves of 181MMboe. Further details
can be found on the Company's website at www.i3.energy (http://www.i3.energy)
.
On 19 April 2023, the Company issued options over a total of 3,000,000
Ordinary Shares to Jason Dranchuk, the CFO and a Person Discharging Managerial
Responsibilities of the Company. The options were issued in accordance with
the rules of the Company's Employee Share Option Plan at an exercise price of
20.00 pence per share. One-third of the options vest upon achieving production
of 26,000 boepd, one-third upon the addition of 5,000 boepd vs acquisitions,
and one-third upon the addition of 25 MMbbl of 2P reserves. The options will
otherwise vest as to one-third on the first, second, and third anniversary of
the grant date, to the extent the award has not otherwise vested in accordance
with the above provisions.
On 25 April 2023 the Group issued a total of 9,051,927 Ordinary Shares of 0.01
pence each following the exercise of Warrants by certain of its loan
noteholders. The Ordinary Shares were subsequently admitted for trading on
AIM. Following the exercise there were no more warrants outstanding.
On 31 May 2023 the Group announced the successful redemption of the Company's
outstanding £22 million H1-2019 Loan Notes (the "Loan Notes"), due 31 May 31
2023, and the establishment of a CAD 100 million debt facility, which will
provide i3 greater financial flexibility and enhanced credit capacity to
further execute its ongoing business plan. The Company and i3 Energy Canada
Ltd. have signed agreements with Trafigura Canada Ltd., a subsidiary of
Trafigura Pte Ltd., a market leader in the global commodities industry, for a
CAD100 million loan facility (the "Facility") and an associated commercial
contract related to i3 Energy Canada Ltd.'s oil production. The Facility has a
three-year term, with interest payable monthly at 9.521% per annum, calculated
on the outstanding portion of the loan. The Facility carries no penalty if
repaid early and amortises monthly on a straight-line basis, which aligns with
the Company's conservative approach to debt management. Advances under the
Facility can be repaid either with cash or by way of set-off against
deliveries of crude oil under the commercial contract which has a minimum term
of three years. The documentation establishing the Facility includes the
option for a CAD75 million advance which has been fully drawn by the Company
and a CAD25 million accordion facility amount, which can be made available
during the Facility's three-year term. The Facility is secured by a first lien
against substantially all the assets and shares of i3 Energy Canada Ltd.,
permitting maximum financing flexibility for the rest of the Company's
international portfolio. The Company will utilize a portion of proceeds from
the initial advance to redeem the outstanding Loan Notes. The balance of the
proceeds will be available for general corporate purposes of the Company and
of i3 Energy Canada Ltd., including working capital requirements, acceleration
of organic growth (from i3's proven portfolio of development drilling
locations) and to fund accretive acquisition opportunities.
Appendix A: Glossary
1P Proved reserves
2P Proved plus probable reserves
AER Alberta Energy Regulator
AIM The AIM Market of the London Stock Exchange
APM Alternate Performance Measure
ARO Asset Retirement Obligation
ASCP Saskatchewan's Accelerated Site Closure Program
bbl Barrel
bbl/d Barrels per day
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, CVE 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
the Code QCA Corporate Governance Code
Company i3 Energy plc
CPR Competent person's report
E&E Exploration and evaluation
EPL Energy Profits Levy
ERP Emergency Response Plan
Europa Europa Oil & Gas Limited
FCF Free cash flow
FIA Farm-In Agreement
FVTPL Fair Value through Profit or Loss
Gain Gain Energy Ltd.
gal Gallon
GBP British Pounds Sterling
GJ Gigaloule
Gross wells Wells participated in by i3
Group, 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
mcf Thousand cubic feet
mcf/d Thousand cubic feet per day
MMboe Million Barrels of Oil Equivalent
MMBtu Metric Million British Thermal Unit
NGL Natural gas liquids
NED Non-Executive Director
Net wells Gross wells multiplied by i3's working interest
NOI Net Operating Income
NPV 10 Net Present Value, discounted at 10%
NSTA UK North Sea Transition Authority
NTM Next Twelve Months
PDP Proved, developed, producing reserves
PIK Payment in kind
PP&E Property, plant and equipment
QCA Quoted Companies Alliance
RFCT Ring Fence Corporation Tax
SCT Supplementary Charge
SRP Alberta's Site Rehabilitation Program
Toscana Toscana Energy Income Corporation
TSX Toronto Stock Exchange
UKCS UK Continental Shelf
USD (US$) United States Dollar
WI Working Interest
Appendix B: Alternate performance measures
The Group uses Alternate Performance Measures ("APMs"), commonly referred to
as non-IFRS measures, when assessing and discussing the Group's financial
performance and financial position. APMs are not defined under IFRS and are
not considered to be a substitute for or superior to IFRS measures. Other
companies may not calculate similarly defined or described measures, and
therefore their comparability may be limited. The Group continually monitors
the selection and definitions of its APMs, which may change in future
reporting periods.
EBITDA and Adjusted EBITDA
EBITDA is defined as earnings before depreciation and depletion, financial
costs, and tax. Adjusted EBITDA is defined as EBITDA before gain on bargain
purchase and acquisition costs. Management believes that EBITDA provides
useful information into the operating performance of the Group, is commonly
used within the oil and gas sector, and assists our management and investors
by increasing comparability from period to period. Adjusted EBITDA removes the
gain or loss on bargain purchase and asset dispositions and the related
acquisition costs which management does not consider to be representative of
the underlying operations of the Group.
A reconciliation of profit as reported under IFRS to EBITDA and Adjusted
EBITDA is provided below.
2022 2021
£'000 £'000
Profit for the year 41,951 25,083
Depreciation and depletion 34,339 21,643
Finance costs 7,865 7,609
Tax 13,826 661
EBITDA 97,981 54,996
Acquisition costs - 256
Loss / (gain) on bargain purchase and asset dispositions 9 (25,013)
Adjusted EBITDA 97,990 30,239
Net operating income
Net operating income is defined as gross profit before depreciation and
depletion, gains or losses on risk management contracts, and other operating
income, which equals revenue from the sale of oil and gas and processing
income, less production costs. Management believes that net operating income
is a useful supplementary measure as it provides investors with information on
operating margins before non-cash depreciation and depletion charges and gains
or losses on risk management contracts.
A reconciliation of gross profit as reported under IFRS to net operating
income is provided below.
2022 2021
£'000 £'000
* Restated
Gross profit 78,689 21,690
Depreciation and depletion 34,339 21,643
Loss on risk management contracts 18,990 5,485
Other operating income (286) (231)
Net operating income 131,732 48,587
* In 2022 management changed the definition of net operating income to exclude
other operating income. Other operating income arises on an ad-hoc basis and
isn't considered representative of the underlying field operations and field
income of the Group. The comparative period has been restated on a consistent
basis.
Acquisitions & Capex
Acquisitions & Capex is defined as cash expenditures on acquisitions,
PP&E, and E&E. Management believes that Acquisition & Capex is a
useful supplementary measure as it provides investors with information on cash
capital investment during the period.
A reconciliation of the various line items per the statement of cash flows to
Acquisitions & Capex is provided below.
2022 2021
£'000 £'000
Acquisitions 531 37,079
Expenditures on property, plant & equipment 64,374 9,465
Expenditures on exploration and evaluation assets 13,842 3,317
Acquisitions & Capex 78,747 49,861
Free cash flow (FCF)
FCF is defined as cash from / (used in) operating activities less cash capital
expenditures on PP&E and E&E. Management believes that FCF provides
useful information to management and investors about the Group's ability to
pay dividends.
A reconciliation of cash from / (used in) operating activities to FCF is
provided below.
2022 2021
£'000 £'000
Net cash from operating activities 101,092 24,439
Expenditures on property, plant & equipment (64,374) (9,465)
Expenditures on exploration and evaluation assets (13,842) (3,317)
FCF 22,876 11,657
Net debt
Net debt is defined as borrowings and leases and trade and other payables,
less cash and cash equivalents and trade and other receivables. Management
believes that net debt is a meaningful measure to monitor the liquidity
position of the Group.
A reconciliation of the various line items per the statement of financial
position to net debt is provided below.
2022 2021
£'000 £'000
Borrowings and leases 27,241 23,924
Trade and other payables 55,846 19,709
Cash and cash equivalents (16,560) (15,335)
Trade and other receivables (34,843) (25,503)
Net debt 31,684 2,795
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