31 August 2023

i3 Energy plc

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

Interim Report and Operational Update for the Six Months Ended 30 June 2023

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 unaudited results for its period ended 30 June 2023.  A copy of the Company's unaudited interim financial statements will be available shortly on the Company's website at https://i3.energy/investor-relations/regulatory-news.

Highlights And Outlook

H1 2023 HIGHLIGHTS
	Average Production	20,640 BOEPD (H1 2022: 18,950)
	2PDP and 2P Reserves	65.7 & 181.5 MMBOE (At 1 January 2023)
	Revenue (net of royalties)	£75.5 MILLION (H1 2022: £101.6 MILLION)
	Net Operating Income ("NOI")(1)	£38.9 MILLION (H1 2022: £68.8 MILLION)
	Acquisitions & Capex(1)	£27.2 MILLION (H1 2022: £23.7 MILLION)
	FCF(1)	(£2.9) MILLION (H1 2022: £24.7 MILLION)
	Profit Before & After Tax	£14.5 & £10.9 MILLION (H1 2022: £20.5 & £14.7 MILLION)
	Adjusted EBITDA(1)	£38.6 MILLION (H1 2022: £38.8 MILLION)
	Basic and Diluted EPS	0.91 and 0.90 PENCE (H1 2022: 1.30 & 1.20 PENCE)
	H1 2023 Dividends Declared	£10.2 MILLION (H1 2022: £6.9 MILLION)
	2023 Canadian Capital Programme	DRILLED 8 GROSS (5.5 NET) WELLS
	UK Assets	EVALUATING A ONE-WELL DEVELOPMENT OF SERENITY

 

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

Highlights

Financial Highlights

·       H1 2023 revenue (net of royalties) of £75.5 million (H1 2022: £101.6 million), net operating income ⁽¹⁾ of £38.9 million (H1 2022: £68.8 million), and cash flow from operations of £24.3 million (H1 2022: of £48.4 million).

·       Successfully completed the new CAD 100 million, 3-year, first lien Debt Facility with Trafigura Canada Ltd. (a subsidiary of Trafigura Pte Ltd.) and redeemed the H1 2019 Loan Notes in full.

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

Dividends

·       During the first half of 2023, i3 declared total dividends of 0.855 pence/share (totalling £10.215 million).

·       In June 2023 the Company revised its annual dividend guidance from a monthly equivalent of 0.1710 to 0.0855 pence per share, to be paid quarterly, which annualises to approximately £12.3 million based on the number of ordinary shares outstanding as at 30 June 2023.

Operational Highlights

·       Average H1 2023 production of 20,640 barrels of oil equivalent per day ("boepd") for the six-month period (9% higher than 18,950 boepd achieved in H1 2022) while exiting H1 above 22,000 boepd.

·       Average Q2 2023 production of approximately 18,529 boepd, representing a 5% decrease from Q2 2022, was more favourable than anticipated given that approximately 3,100 boepd was offline for the quarter due to restrictions associated with the Alberta wildfires, unanticipated apportionment issues associated with the Pembina Peace Pipeline liquids line and the scheduled turnarounds and debottlenecking projects.

·       Post May / June curtailments, Company production has recovered with a July average rate of 22,065 boepd.  

·       Drilled 8 gross wells (5.5 net) wells during H1 in the Company's core Central Alberta, Wapiti and Clearwater assets as part of the 2023 capital programme.

·       CO2e emission reduction initiatives continued with electrification of 12 well sites in Carmangay and Retlaw.

·       Responsive corporate action throughout Alberta and British Columbia during the May and June wildfire situation, focussing on the protection and safety of field staff, industry partners, emergency responders and the impacted communities, while minimizing production downtime and ensuring asset integrity.

•       As a result of the wildfires, certain facilities were periodically shut-in with resultant calendar day downtime estimated at 1,650 boepd and 385 boepd, respectively for May and June.

·       i3 performed 20 operated turnarounds on its facilities in Central Alberta, to ensure the regulatory compliance and integrity of its assets.

•       The turnaround operations were completed on time and within budgeted forecasts, and affected June's production by 7,230 boepd.

·       The Company's Q1 Wapiti Cardium programme is now producing unrestricted, with peak initial production ("IP") rates exceeding GLJ's Proved Plus Probable forecasts.

Outlook

A summary of key events which occurred after the reporting period are presented in note 19 to the financial statements. The Group'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 established 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 operations safely and in an environmentally secure manner.

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

 

Majid Shafiq, CEO of i3 Energy plc, commented:

"H1 2023 was another very active period for i3. We completed our planned Q1 capital program, drilling 8 gross (5.5 net) wells in our Central Alberta, Wapiti and Clearwater acreage, re-financed our outstanding loan notes which were due in May with a new CAD 100 million loan facility and successfully conducted 20 planned operated facility turnarounds, whilst safely managing our operations during the recent extended period of wildfires in Alberta. Our asset base continues to perform well, having averaged 20,640 boepd in H1, 9% higher than the same period last year and exiting H1 at greater than 22,000 boepd, and with 2P reserves of 182 mmboe provides a solid platform for growth.

Commodity price weakness in the first half of the year meant the Company revised its 2023 capital and dividend programme in June having declared £10.215 million in dividends to our shareholders in H1. Improvement in commodity prices in July and August and future pricing, has resulted in an increase of around 20% in our forecast for full year net operating income to USD 90 to 95 million. Price volatility has also resulted in potential opportunities for growth via M&A and we continue to monitor the market to ensure our capital allocation for the remainder of the year is optimised. We are confident that our business model, allied with our asset base and the skills and dedication of our staff, will continue to create and extract value through the commodity price cycle."

Qualified Person's Statement

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

Enquiries:

i3 Energy plc Majid Shafiq (CEO) / Jason Dranchuk (CFO)	c/o Camarco Tel: +44 (0) 203 781 8331
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 Andrew Turner, Sam Morris, Violet Wilson	Tel: +44 (0) 203 757 4980

 

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 asset base and the acquisition of long life, low decline conventional production assets.

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

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

The Company advises that it has obtained an exemption pursuant to Section 602.1 of the TSX Company Manual (the Manual), in respect of certain shareholder approval requirements that would otherwise be applicable to the Company's Employee Stock Option Plan and Non-Employee Stock Option Plan (together, the Plans), namely those set forth in Section 613 of the Manual (the Exemption).  As such, the Company is exempt from complying with the requirements of Section 613 in respect of the Plans.

Pursuant to the Manual, the Exemption will be valid for a period of three years from the date hereof, expiring on July 17, 2026.  The Company follows AIM Rules for Companies and has received shareholder approval for its Employee Stock Option Plan and Non-Employee Stock Option Plan.

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.

Chairman's and Chief Executive's Statement

Overview of the year to date

i3 has had an active first half of 2023 navigating a challenging period in the energy sector and the broader capital markets. The first half of 2023 was marked by commencement of the Company's capital programme in Wapiti, Central Alberta and in the Clearwater, the establishment of a new long-term debt facility and the operational challenges associated with the Alberta wildfires and multiple planned and unplanned production disruptions. With these hurdles behind it, the Company is well positioned to deliver continued value to shareholders through its total return model.

During the first half of 2023, the Company settled its outstanding £22 million Senior Secured Guaranteed Loan Notes (the "Loan Notes"), which were due for repayment at the end of May. The Loan Notes were settled from the proceeds of a new CAD 100 million loan facility (the "Facility") established with Trafigura Canada Ltd., a subsidiary of Trafigura Pte Ltd. The Facility consists of a CAD 75 million facility, used to repay the loan notes and for general corporate purposes, and a CAD 25 million accordion. We are very pleased to have established a relationship with Trafigura, a sophisticated oil and gas trader and a potential partner for future production focussed growth.

Operationally, i3 commenced 2023 following an active and very successful USD 71 million drilling campaign in 2022, which allowed the Company to average 20,317 boepd for the year with peak production exceeding 24,000 boepd. Although commodity prices had softened through 2022, the forecast at year end remained strong as the Company set a 2023 capital programme of USD 64 million based upon average annual price assumptions of USD 85/bbl for WTI and CAD 4.50/GJ for AECO gas (coinciding with the industry consensus). The initial portion of the 2023 capital programme, including 8 gross (5.5 net) wells, were successfully drilled and tied-in before the Spring break up period commenced. Initial production results from the 2023 programme were impacted by a weakening commodity price outlook and a series of other factors, including Alberta wildfires, unanticipated apportionment issues, as well as scheduled turnarounds and debottlenecking projects. These factors affected near-term production which, when combined with the continued softening commodity outlook, resulted in lower full year production and cashflow guidance and reduced capital and dividend programmes.

Since issuing the Company's revised 2023 capital and dividend programme at the end of June 2023, i3's predictable low decline production has recovered following the Company's planned maintenance activities which involved shutdown of certain major operated facilities, which were completed successfully during June. Seasonal wildfires this year have been worse and more prolonged than normal, and although none of our facilities (operated or non-operated) were damaged, periodical shut down of certain facilities was required as a precautionary measure, which negatively impacted our production volumes during May and June by 1,650 boepd and 385 boepd, respectively. Despite this, our wells and facilities which were impacted by maintenance and unplanned shutdowns have since been brought back on-stream and are performing at pre-shutdown levels. With the return in corporate production, combined with the recovery in underlying commodity prices, particularly WTI, we are forecasting an approximate 20% increase to the Company's revised 2023 estimated Net Operating Income guidance, as issued at the end of Q2.

As per i3's total return model, the Company continually evaluates the optimal way in which to deliver shareholder value. In addition to its distribution model, the Company weighs the expected return generated through organically drilling its extensive portfolio of development locations against potential acquisition opportunities and deploys capital accordingly to achieve the highest return on a risk adjusted basis. As is to be expected, the fall in commodity prices in H1 have resulted in lower asset transaction metrics in Canada. i3 continues to monitor the market and will participate in acquisitions should the Company find accretive opportunities that fit its strategy.

In the UK, in conjunction with our joint venture partner, the Company continues to progress discussions with all stakeholders regarding the potential development of the Serenity field.

The Company's YE 2022 reserves audit, which on a 2P basis, resulted in an increase in reserves of 18%, with a reserve life index of 22.5 years and a value of USD 1.161 billion. With more than 370 booked (gross) drilling locations, i3's reserves report exhibits a strong and diverse asset base which can support growth through the business and commodity cycles, and we look forward to advancing our growth initiatives throughout the remainder of 2023. We believe the mid-to-long-term supply/demand imbalance in oil and gas production is and will continue to support pricing; as we have seen both principal commodities strengthen in Q3 2023, positively impacting i3's forecast cashflows for the remainder of the year (as exhibited in the below 2023 Updated Guidance chart). 

i3 is committed to conducting its operations safely, responsibly and in accordance with industry best practices, and we continue to advance our health and safety policies and procedures as we integrate additional production assets. The Company's commitment to high ESG standards is central to maintaining its social licence to operate, creating value for all stakeholders, and ensuring long-term commercial success. Following the publication of our maiden annual sustainability report and establishing a baseline for our business we have continued efforts to reduce the carbon intensity of i3's operations through methane emission reductions and electrification projects, and these efforts will continue into the second half of the year.

 

"John Festival" John Festival Non-Executive Chairman 30 August 2023

"Majid Shafiq" Majid Shafiq Chief Executive Officer 30 August 2023

Operational Review

Production in the first half of 2023 averaged 20,640 boepd, comprised of 64.2 million standard cubic feet of natural gas per day ("mmcf/d"), 4,809 barrels per day ("bbl/d") of natural gas liquids ("NGLs"), 4,740 bbl/d of oil & condensate and 386 boepd of royalty interest production, which was 9% higher than production in the same period of 2022. A successful winter drilling and workover program helped bolster average production in Q1 2023. However, average production in Q2 2023 was negatively impacted by wildfires and scheduled turnarounds in the months of May and June, resulting in lower average sales production. Throughout this period, volumes from the Company's northern areas were temporarily shut-in due to encroaching forest fires. The areas affected included Lodgepole, Edson, Wapiti, Simonette, Tony Creek and Noel in Northern BC. On a calendar day basis approximately 1,650 boepd (comprised of 300 bbls of oil, 260 bbls on NGLs and 6,550 mcf/d of gas) was shut in for the month of May and approximately 385 boepd in June (comprised of 18 bbls of oil, 53 bbls on NGLs and 1,885 mcf/d of gas). Fortunately, no personnel were endangered during this period and no material damage was incurred to field facilities and production has since been restored. The Company would like to thank our field staff, industry partners, emergency responders and firefighters for their professionalism and rapid response in protecting the effected communities and our thoughts remain with impacted community members. In June, production was temporarily shut-in due to scheduled operated and third-party facility turnarounds primarily affecting the Company's central Alberta areas of Gilby and Rimbey, and to a lesser extent Wapiti in the North. In conjunction with a major third-party gas plant's scheduled four-year turnaround, i3 performed twenty operated turnarounds on associated facilities in Central Alberta to ensure the regulatory compliance and integrity of the Company's assets.  These turnarounds had a gross cost of USD 2.9 million (USD 2.4 million net) and were successfully executed with production now back online. i3's July 2023 Company production, averaging 22,065 boepd, comprised of 69.5 million standard cubic feet of natural gas per day ("mmcf/d"), 5,490 barrels per day ("bbl/d") of natural gas liquids ("NGLs"), 4,597 bbl/d of oil & condensate and 403 boepd of royalty interest production.

Royalty Interest production averaged 386 boepd in H1, which was in line with the same period of 2022. The Company remains focused on maximizing third-party activity on its extensive portfolio of 198,040 acres of royalty interest lands. During the first half of 2023, third-party operators drilled and brought on production 3 wells within the Company's royalty interest properties.

With the success of i3's 2022 drilling programme, the Company capitalized on the availability of services and accelerated a portion of its Q1 2023 programme in late Q4 2022. The drilling programme focussed on operated oil and liquids rich gas wells in Central Alberta (Cardium), Wapiti (Cardium, Dunvegan), and Clearwater (operated and non-operated) assets. As part of the 2023 programme, the Company participated in 8 gross (5.5 net) wells across its drilling portfolio, including 7 gross (5.0 net) operated wells and 1 gross (0.5 net) non-operated well.

Wapiti

In H1, i3 and its working interest partner completed the drilling of 4 gross (2.0 net) horizontal wells in the Wapiti area. The wells included 3 gross (1.8 net) operated 1.5-mile Cardium wells and 1 gross (0.2 net) operated 2-mile Dunvegan well. The Cardium wells were efficiently drilled off a common pad and tied-in to existing production facilities, in which i3 holds a working interest, while the Dunvegan well was drilled off an existing pad and tied-in to the same production facilities.

Production associated with the Q1 programme at Wapiti was impacted due to high gathering system pressures, which restricted the Company's ability to optimize the productive capacity of the new wells. The relevant third-party area operator, as scheduled, debottlenecked the gathering system in late Q2 through an upgrade of existing infrastructure, which alleviated line pressure constraints, thereby eliminating restrictions on well performance and have allowed the Company to optimize production from its new Wapiti wells.  Post debottlenecking, in the past 2 months the 3-well Cardium pad has performed above GLJ's Proved Plus Probable type curve expectations, with recent production readily outpacing IP peak rate forecasts.   

Additionally, throughout H1, the Wapiti area had experienced unanticipated apportionment issues (occurring when volumes exceed available pipeline capacity in any given month) associated with the Pembina Peace Pipeline liquids line, which resulted in reduced liquids yields realized by area operators. The apportionment issues have since been resolved with the commissioning of Keyera's Key Access Pipeline System.

Central Alberta

i3's Q1 capital programme in Central Alberta was focussed primarily in the greater Lodgepole area, where the Company expanded its extensive infrastructure network and drilled 1 gross (1.0 net) well. The Company's infrastructure improvements include a 2.3 km pipeline to reroute production away from third-party infrastructure, reducing the fee structure and improving run-time efficiencies.  The rerouting project was executed on-time and below budget.

i3 drilled 1 gross (1.0 net) horizontal Cardium oil well in the Lodgepole area of Central Alberta. The well was drilled off an existing pad-site and tied into its new pipeline system. The well was drilled on-budget and placed on stream in late Q1. The performance of the new well was impacted by disruptions associated with wildfires in the area but has since been brought back online. 

Gas processing in Central Alberta has been reduced as a result of consolidating and rationalizing gas volumes and agreements through a third-party gas plant for processing and sales.  The three-year processing agreement partially offset higher costs due to facility maintenance activities and will reduce operating expenses for the remainder of the term.

Clearwater

In Q1, i3 drilled 3 gross (2.5 net) multilateral horizontal Clearwater wells at Dawson and Marten Creek as part of its ongoing exploration and development portfolio of 144 gross sections (109 net sections, equivalent to 280 km2) of prospective Clearwater lands.

At Dawson, i3 and its 50% partner, drilled the 05-16-081-16W5 six-leg (7,500 m of total lateral length) multilateral horizontal Clearwater well. The well was drilled with oil-based mud ("OBM") and placed on production in late January. After recovering the OBM drilling fluid, the well had an initial 30 days' production averaging 81 barrels of oil per day ("bopd") before being shut-in late March due to road bans associated with spring breakup. Scaling the well performance for an industry standard eight-leg multilateral horizontal well configuration (10,000 m) translates, encouragingly, to an estimated 110 bopd rate. With the success of this initial earning well, i3 and its 50% partner have elected to drill the second and final earning well at Dawson, which the Company anticipates will be drilled and on production prior to year-end or early Q1 2024.  Throughout H1, i3 has been working to secure multiple pad sites at East Dawson to facilitate future expansion of the field, upon further operational success.

At Marten Creek, i3 followed up on its 2022 recompletion activity with 2 gross (2.0 net) exploratory three-leg multilateral horizontal wells (retrieving a vertical core from one well). The two exploratory wells were drilled in January, targeting two separate Clearwater sequences. The core indicated two thick, oil saturated sands with encouraging porosity and permeability levels and free oil was detected in the rig process system during drilling operations. The wells were equipped with temporary production facilities and placed on production in late January and early February, respectively.  Due to unseasonably warm weather in the area and early breakup of ice-roads, production equipment had to be removed from the well-sites before all the associated OBM was recovered. i3 intends to return this coming winter to complete testing of the wells to determine deliverability.

Hedging Programme

i3's risk management strategy currently protects USD ~51.02 million (CAD 67.86 million) of net operating income for 2023 with current hedges in place to cover 39%, 23%, 21% and 28% of the Company's projected Q1, Q2, Q3 and Q4 2023 production volumes, respectively. i3's 2023 hedges are shown in the below chart, with additional information provided below in notes 14 and note 19 to the H1 2023 Interim Consolidated Financial Statements:

 

		Swaps			Costless Collars			Basis Swaps
GAS		Volume (GJ)	Price (C$/GJ)		Volume (GJ)	Avg Floor Price (C$/GJ)	Avg Ceiling Price (C$/GJ)	Volume (mmbtu)	Price ($US/mmbtu)
Q1 2023		2,397,500	4.41		1,125,000	5.80	10.09
Q2 2023								960,101	(1.46)
Q3 2023		610,000	2.76					970,652	(1.46)
Q4 2023		1,835,000	2.99					327,067	(1.46)
								Participation Swaps
OIL		Volume (bbl)	Price (C$/bbl)		Volume (bbl)	Avg Floor Price (C$/bbl)	Avg Ceiling Price (C$/bbl)	Volume (bbl)	Avg Floor Price (C$/bbl)
Q1 2023		58,500	106.85		162,000	100.00	124.44
Q2 2023		36,400	112.83		113,650	100.00	127.35	91,000	90.00
Q3 2023		168,500	99.69
Q4 2023		184,000	99.16
PROPANE		Volume (bbl)	Price ($US/bbl)		Volume (bbl)	Avg Floor Price ($US/bbl)	Avg Ceiling Price ($US/bbl)
Q1 2023					45,000	42.00	51.61

 

Serenity

i3 continues to work with its partner Europa Oil and Gas to advance a field development plan for a one-well development for the Serenity field.

Environmental, Social and Governance ("ESG")

i3 is committed to conducting its operations responsibly and in accordance with industry best practices. The Company'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.

On an operated basis in H1 2023, i3 invested USD 1.4 million gross (USD 0.8 million net) to complete 20 well abandonments, decommission 6 facilities and abandon 5 pipelines as well as advance site reclamations across its portfolio achieving 10 site closures with reclamation certification. With a net spend of USD 0.8 million i3 was able to reduce the Company's deemed liability by USD 1.1 million.  In 2023, i3 is on track and committed to exceed its mandated, operated closure spend, with approximately USD 3.9 million gross being directed to pipeline and wellbore abandonments, pipeline and facility decommissioning, along with well site reclamation.  In H1 2023, i3 deployed USD 2.4 million towards closure spend incorporating non-operated activities.

Additionally, i3 continues to reduce its emissions footprint through its ongoing electrification projects. The Company has spent a net USD 0.3 million (including USD 0.1 million, which is reimbursable through Alberta's SPEED funding) to complete the electrification of 12 gross (10.5 net) well sites in Carmangay and Retlaw to eliminate the use of propane and natural gas for power generation.

2023 Updated Guidance

i3's full year 2023 revised guidance, as at 30 August 2023, which is now based on strip pricing for the remainder of the year, is shown below. With the improvement in underlying commodity prices and the continued performance of the Company's stable production base, 2023 expected NOI has increased approximately 19% to USD 92.5 million. Guidance provided previously, as part of our 29 June 2023 press release has been presented for comparative purposes.  Sensitivity to movement in commodity prices is also provided.

	Previous full year 2023 guidance and assumptions as provided - 29 June 2023	Revised full year 2023 guidance and assumptions - 30 Aug 2023
Annual Average Production (1)	20,000 - 21,000 boepd	20,000 - 21,000 boepd
Royalty Rate	15.3%	14.3%
Operating & Transport	USD 13.40 - 13.60 / boe	USD 12.90 - 13.10 / boe
Net Operating Income (2)	USD 75 million - 80 million	USD 90 million - 95 million
EBITDA (2)	USD 67 million - 72 million	USD 80 million - 85 million
Capital Expenditures	USD 25 million	USD 25 million
Dividends Paid (3) (Forecast for Jan - Oct. 2023)	USD 19 million	USD 19 million

 

2023 Updated Commodity Assumptions ⁽⁴⁾

WTI (USD/bbl)	USD 72.00/bbl	USD 76.60/bbl
MSW Oil Differential (USD/bbl)	USD 3.10/bbl	USD 2.75/bbl
AECO Natural Gas (CAD/GJ)	CAD 2.60/GJ	CAD 2.70/GJ
USD / CAD Foreign Exchange	1.33	1.35
GBP / CAD Foreign Exchange	1.68	1.68
GBP / USD Foreign Exchange	1.26	1.26

 

Next Twelve-Month Net Operating Income Sensitivity ⁽⁵⁾

Next twelve months' sensitivity	Estimated change to net operating income - 29 June 2023	Estimated change to net operating income - 30 Aug 2023
Change in WTI USD 1.00/bbl	USD 1.30 million	USD 1.33 million
Change in AECO CAD 0.10/GJ	USD 1.40 million	USD 1.41 million
Change in CAD/USD exchange rate CAD 0.01	USD 1.27 million	USD 0.98 million

 

(1) Total annual average production (boepd) is comprised of approximately 48% Oil, Condensate & NGLs, 51% Natural Gas and 1% Gross Overriding Royalty Production.

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

(3) Based on i3's forecast nine-month 2023 ordinary share dividend payments of £15.2 million (US$19.0 million assuming 1.26 GBP:USD) to be paid through October 2023. The declaration of dividends is subject to terms of loan facility and the approval of i3's board of directors, compliance with (or waiver from) the financial ratios contained within the Company's refinanced debt documentation and is subject to change. Forecast of Q4 2023 dividends are not included in current guidance numbers but will be revisited when the Company reviews its Q4 capital and dividend programmes this fall.

(4) Commodity prices and foreign exchange reflect full year average realized prices or rates.

(5) Illustrates the expected impact of changes in commodity prices and the CAD:USD exchange rate on i3's estimate of Net Operating Income for 2023 of USD 90 million to USD 95 million, holding all other variables constant. The sensitivity is based on the commodity price and exchange rate assumptions set forth in the table above. Calculations are performed independently and may not be indicative of actual results. Actual results may vary materially when multiple variables change at the same time and/or when the magnitude of the change increases.

Financial Review

Production

Average Sales Production	Six-months Ended 30 June 2023	Six-months Ended 30 June 2022	Year Ended 31 December 2022
Oil and condensate (bbl/d)	4,740	3,916	4,340
Natural gas liquids (bbl/d)	4,809	5,021	5,047
Natural gas (mcf/d)	64,231	57,754	63,076
Royalty interest (boepd)	386	387	418
Total Production (boepd)	20,640	18,950	20,317

 

Average Sales Production Mix	Six-months Ended 30 June 2023	Six-months Ended 30 June 2022	Year Ended 31 December 2022
Oil and condensate	23%	21%	21%
Natural gas liquids	23%	26%	25%
Natural gas	52%	51%	52%
Royalty interest	2%	2%	2%
	100%	100%	100%

 

Production in the first half of 2023 averaged 20,640 boepd, which was 9% higher than production in the same period of 2022. A successful H2 2022 drilling and workover program helped bolster average production in Q1 2023, however average production in Q2 2023 was negatively impacted by forest fires in the month of May and scheduled turnarounds in the month of June 2023, resulting in lower average sales production. In May, average sales production from the Company's northern areas (Simonette, Wapiti, Lodgepole, Edson, Tony Creek and Noel in BC) were temporarily shut-in as a precaution to encroaching forest fires. In June, production was temporary shut-in due to scheduled operated facility turnarounds, which primarily affected the Company's central Alberta areas of Gilby and Rimbey. The Wapiti area was also affected by temporary shut-in production due to a third-party facility turnaround. No major damage was incurred due to forest fires and wells have since come back on-line. In addition, scheduled turnarounds progressed as expected and wells impacted by the downtime have also come back on-line.

Average sales production mix, period over period, was consistent with just over 50% of sales derived from natural gas and 46% - 47% of sales represented by oil, condensate and natural gas liquids followed by 2% of sales from royalty interest wells.

Royalty Interest production averaged 386 boepd in H1, which was in line with the same period of 2022. The Company remains focused on maximizing third-party activity on its extensive portfolio of 198,040 acres of royalty interest lands. During the first half of 2023, third-party operators drilled and brought on production 3 wells on the Company's royalty interest properties.

A summary of average sales volumes for the 8 preceding quarters is presented below.

 

Average Sales Production	Q3 2021	Q4 2021	Q1 2022	Q2 2022	Q3 2022	Q4 2022	Q1 2023	Q2 2023
Oil and condensate (bbl/d)	2,425	3,624	3,945	3,886	4,396	5,119	5,238	4,247
Natural gas liquids (bbl/d)	2,999	4,601	4,942	5,099	5,038	5,106	5,569	4,057
Natural gas (mcf/d)	45,079	58,037	54,689	60,785	64,180	72,442	69,555	58,965
Royalty interest (boepd)	302	331	389	385	440	458	373	398
Total Sales Production (boepd)	13,239	18,229	18,391	19,502	20,571	22,757	22,773	18,529

 

Revenue

i3's proceeds from the sale of oil and gas produced from its Canadian oil and gas assets are based on average sales production volumes and averaged realised sales prices in Canadian dollars. The below table shows the average prices in Canadian dollars realised by the Group for the six months ended 30 June 2023 and 2022 and the year ended 31 December 2022.

Average Realised Pricing (1)	Six-months Ended 30 June 2023	Six-months Ended 30 June 2022	Year Ended 31 December 2022
Oil and condensate (CAD$/bbl)	94.60	123.72	114.66
Natural gas liquids (CAD$/bbl)	22.97	37.01	35.02
Natural gas (CAD$/mcf)	2.97	6.19	5.42
Royalty interest (CAD$/bbl)	36.14	46.94	51.37
Total (CAD$/boe)	37.01	55.18	51.08

 

(1)         Average realised prices derived by dividing oil and gas sales in GBP by averaged sales production and converting to CAD using period-average GBP/CAD exchange rate six months ended 30 June 2023 of 1.6613, six months ended 30 June 2022 of 1.6513 (year ended 31 December 2022 of 1.6073).

 

	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
Oil and condensate	48,850	53,104	113,003
Natural gas liquids	12,035	20,366	40,142
Natural Gas	20,816	39,157	77,656
Royalty interest	1,520	1,991	4,890
Oil and gas sales	83,221	114,618	235,691
Royalties	(10,540)	(16,174)	(33,536)
Revenue from the sale of oil and gas	72,681	98,444	202,155
Processing income	2,701	3,081	5,995
Other operating income	107	46	286
Total revenue	75,489	101,571	208,436

Total revenue for the first half of 2023 was £75.5 million.  Oil and gas sales of £83.2 million in the first half of 2023 was 27% lower than the same period in 2022, which was primarily due to lower commodity prices in the first half of 2023. Oil prices trended lower in the first half of 2023, as initial 2022 post Covid travel demand levelled off, the recovery of the Chinese economy was more sluggish than expected, and concerns over Russian oil curtailment at the start of the Ukrainian / Russian war in 2022 diminished. Natural gas liquid prices fell in Q2 2023, compared to the same period in 2022 due to lower underlying oil and gas prices in addition to a return to normal North America NGL inventory levels in 2023. AECO and NYMEX pricing was high in H1 2022 in response to the war. However, pricing experienced downward pressure due to a mild winter, increased production, and strong storage levels in H1 2023, resulting in lower realised pricing. 

Royalty rates in Alberta, which is where most of the Company's production comes from, are based on a sliding scale where the royalty rate is dependent on a monthly Alberta par price for oil and on a monthly Alberta reference price for natural gas and NGLs and individual well production rates. Higher commodity prices attract a higher royalty rate and vice-versa. Similarly, high individual production rates attract higher royalty rates and vice-versa. Royalties for the first half of 2023, consisting of Crown, gross overriding and freehold payments, was £10.5 million, compared to £16.2 million in the first half of 2022. Royalties as a percentage of oil and gas sales in the first half of 2023 and the same period in 2022 were 13% and 14%, respectively. In the first half of 2023, i3 received a positive one-time yearly gas cost allowance ("GCA") adjustment from the Alberta Government of £1.8 million.

Processing and other income of £2.8 million in the first half of 2023 was slightly lower than processing and other income of £3.1 million in the first half of 2022. Lower processing and other income in the first half of 2023, compared to the same period in 2022 was primarily due to the impact of scheduled facility turnarounds in June 2023, which temporarily restricted third party production through certain of the Company's operated facilities.

Expenses

Production costs	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
Total Production Costs	36,437	32,782	76,418
Total Production Costs (£/boe)	9.75	9.56	10.31

 

Total production costs are primarily comprised of field labour and general field maintenance, land retention and taxes, well repairs and expensed well workovers / facility turnarounds, processing fees, and product transportation.

Total production costs in the first half of 2023 associated with the extraction and processing of the Group's Canadian oil and gas assets totalled £36.4 million, or £9.75/boe, compared to total production costs in the first half of 2022 of £32.8 million, or £9.56/boe. An increase in production costs period over period is primarily due to production outages in conjunction with scheduled one-time facility turnaround costs in June of 2023, which were on budget and totaled approximately £1.9 million, or approximately £0.51/boe. Also attributing to the increase in production costs in the first half of 2023 are higher electricity costs due to increased price and usage and continued inflationary pressures on existing production costs. These increases were partially offset by reduced third-party processing fees negotiated in the period.  

Administrative expenses decreased by £5.4 million to £4.1 million from the first half of 2022 to the first half of 2023. The decrease is largely due to a decrease in personnel costs following changes to the Group's short term incentive plan in the first half of 2023, along with a general reduction in professional fees and other administrative costs.   

Finance costs

The Group incurred finance costs of £4.7 million, an increase of £1.4 million from the £3.3 million in the first half of 2022. £0.2 million of the increase is attributable to increases in interest expense and amortisation of deferred finance costs due to the larger principal balance on the May 2023 Debt Facility, discussed further below. There was also a £0.3 million increase in bank charges and interest on creditors relating to timing of income tax payments, a £0.2 million increase in the unwinding of discount on decommissioning provision, and a £0.7 million increase relating to a gain on financial instrument at FVTPL which was recorded in the first half of 2022 with no such gain in 2023. Further details are provided in financial statements note 5 and note 12.

Tax charge

The Group's current and deferred tax charges are presented in the following table.

Of which:	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
Current tax charge	5,262	5,675	10,002
Deferred tax (credit) / charge	(1,737)	123	3,824
Total income tax charge	3,525	5,798	13,826

 

The current tax charge in 2023 and 2022 resulted from taxable income at the Group's Canadian operations, which prior to 2022 had been sheltered by the Group's accumulated non-capital losses. These non-capital losses were fully utilised in 2022 and the residual taxable income was subject to taxation at the combined rate of 23%. The Group paid the current income tax expense for the year ended 31 December 2022 in the first half of 2023 and has made installment payments against the expected tax owing for the year ending 31 December 2023. The current tax charge in 2023 was partially offset by the receipt of R&D tax refunds of £0.2 million in the UK in respect of the 2020 and 2021 fiscal years.

The deferred tax credit resulted from changes in net deductible temporary differences in Canada. Further details are provided in note 6.

Profit, EPS, EBITDA, Adjusted EBITDA, and Net Operating Income

The Group's profit, EPS, EBITDA, Adjusted EBITDA, and Net operating income are presented in the following table.

	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
Profit for the period	10,944	14,725	41,951
Basic earnings per share (pence)	0.91	1.30	3.60
Diluted earnings per share (pence)	0.90	1.20	3.43
EBITDA (1)	38,561	38,821	97,981
Adjusted EBITDA (1)	38,561	38,821	97,990
Net operating income (1)	38,945	68,835	131,732

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

Cash and cash equivalents

The Group had £12.7 million of cash and cash equivalents at 30 June 2023, a decrease of £3.9 million from 31 December 2022. The decrease was driven by £24.3 million in net cash from operating activities, offset by £27.0 million of net cash used in investing activities, primarily capital expenditure at the Group's Canadian operations as discussed below, and £1.2 million of net cash used in financing activities, primarily dividends paid and various debt finance costs.

PP&E and E&E

The Group had PP&E assets of £219.9 million (30 June 2022:  £221.5 million, 31 December 2022 - £236.5 million) and intangible E&E assets of £63.0 million (30 June 2022: £54.7 million, 31 December 2022: £62.1 million) as at 30 June 2023.

The increase due to additions and acquisitions was offset by various disposals and the depletion charge for the period. Further details are in Note 8 of the financial statements.

Total property, plant and equipment additions in the first half of 2023 totaling £15.4 million was comprised of work associated with the Group's Canadian oil and gas assets.

	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
Land	118	57	975
Seismic	21	99	452
Drilling, completions	8,234	28,966	58,135
Facilities, equipment and pipelines	6,851	4,416	14,862
Other	136	611	1,369
Total Property, Plant & Equipment Additions	15,360	34,149	75,793

 

During the first half of 2023, i3 invested £15.4 million on property, plant and equipment additions. i3 participated in drilling 8 (5.5 net) wells, which includes 3 (1.8 net) wells in the Wapiti area which were spud in December 2022. 3 wells (2.5 net) were drilled in the Clearwater area and are currently shut-in due to seasonal, winter only access. The remaining 2 wells, which consisted of 1 well (1.0 net) in the Lodgepole area and 1 well (0.2 net) in the Wapiti area were drilled, completed and equipped and placed on production in the first half of 2023. i3 also completed, equipped and placed on production 3 (1.8 net) Wapiti wells that were drilled in December 2022. Additional investments focused on various well and facility electrification projects along with facility upgrades and well and pipeline modifications. An additional £0.3 million was spent on land retention costs, seismic and other costs.

During the first half of 2022, i3 invested £29 million to drill and complete 19 (10.7 net) wells, in addition to drilling 1 (1.0 net) well that commenced its completion program in July 2022. Also, i3 tested well locations in the Marten Hills and Gilby area. i3 also invested £4.4 million on equipping the above drilled wells, except for the Wapiti wells, which were equipped in July 2022. Also included in the £4.4 million, were various well and facility electrification projects along with facility upgrades and pipeline modifications. An additional £0.8 million was spent on land retention costs, seismic costs and other. 

During the first half of 2023, additions to intangible exploration and evaluation assets of £1.2 million was primarily comprised of appraisal drilling costs in the Clearwater play in Canada and costs associated with progressing a development of the Serenity in the UK.

	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
Canada	986	4,284	6,677
UK	214	379	5,650
Total E&E capital expenditure	1,200	4,663	12,327

 

Borrowings and leases

The Group had borrowings and leases of £41.2 million at 30 June 2023, an increase of £14.0 million from £27.2 million at 31 December 2022. The increase is largely due to drawing £44.5 million on the new Debt Facility and fully repaying £28.9 million on the H1-2019 Loan Notes, partially offset by deferred finance costs and an amortisation payment on the Debt Facility. The Debt Facility amortises monthly on a straight-line basis, and accordingly £13.8 million has been classified as a current liability, which represents the principal payments net of deferred finance costs over the 12 months following 30 June 2023. Further details regarding the establishment of the Debt Facility and the repayment of the H1-2019 Loan Notes are provided in note 12 to the financial statements.  

Dividends

In the first half of 2023, the Group declared and paid £10.2 million and £12.3 million of dividends, respectively (first half 2022: declared £6.9 million and paid £5.2 million, full year 2022: declared £17.4 million and paid £15.4 million). In June 2023 the Group revised its annual dividend guidance to a monthly equivalent of 0.0855 pence per share, to be paid quarterly, which annualises to approximately £12.3 million at £3.1 million per quarter based on the number of ordinary shares outstanding as at 30 June 2023. 

Principal risks and uncertainties

The Group operates in the oil and gas industry in an environment subject to a range of inherent risk and uncertainties. The principal risks and uncertainties, being those determined to be the most significant, are set out in the annual report for the year ended 31 December 2022, along with the way they are mitigated. The Directors have reconsidered the principal risks and uncertainties and have concluded that the risks published in the 2022 annual report remain appropriate, although highlight that the new Debt Facility established during the period contains various covenants, and non-compliance with these covenants could negatively impact the Group. The Group closely monitors these covenants and was in full compliance as at 30 June 2023.

Going concern

The Directors have considered the going concern of the Group and are satisfied that the Group has sufficient resources to operate and to meet their commitments as they come due over the going concern period. The Group continues to closely monitor its cash balances which stood at £12.7 million and a net current liability of £2.7 million as at 30 June 2023. Refer to Note 2 of the financial statements for further discussion.

 

Condensed Consolidated Statement of Comprehensive Income

 

	Notes	Six-months Ended 30 June 2023	Six-months Ended 30 June 2022	Year Ended 31 December 2022
		£'000 (unaudited)	£'000 (unaudited)	£'000 (audited)
Revenue	4	75,489	101,571	208,436
Production costs		(36,437)	(32,782)	(76,418)
Gain / (loss) on risk management contracts	14	3,343	(20,475)	(18,990)
Depreciation and depletion	8	(19,410)	(15,017)	(34,339)
Gross profit		22,985	33,297	78,689
Administrative expenses		(4,083)	(9,493)	(15,038)
Loss on asset dispositions		-	-	(9)
Operating profit		18,902	23,804	63,642
Finance income		249	-	-
Finance costs	5	(4,682)	(3,281)	(7,865)
Profit before tax		14,469	20,523	55,777
Tax charge	6	(3,525)	(5,798)	(13,826)
Profit for the period		10,944	14,725	41,951
Other comprehensive income:
Items that may be reclassified subsequently to profit or loss:
Foreign exchange differences on translation of foreign operations		(4,449)	11,605	6,688
Other comprehensive income for the period, net of tax		(4,449)	11,605	6,688
Total comprehensive income for the period		6,495	26,330	48,639
Earnings per share		Pence	Pence	Pence
Earnings per share - basic	7	0.91	1.30	3.60
Earnings per share - diluted	7	0.90	1.20	3.43

 

All operations are continuing.

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

 

 

 

 

 

Condensed Consolidated Statement of Financial Position

Assets	Notes	30 June 2023	30 June 2022	31 December 2022
		£'000 (unaudited)	£'000 (unaudited)	£'000 (audited)
Non-current assets
Property, plant & equipment	8	219,894	221,469	236,465
Exploration and evaluation assets	9	63,036	54,715	62,060
Other non-current assets		-	74	74
Total non-current assets		282,930	276,258	298,599
Current assets
Cash and cash equivalents		12,682	30,335	16,560
Trade and other receivables	10	25,118	36,973	34,843
Risk management contracts	14	1,030	533	1,111
Inventory		2,597	883	2,099
Total current assets		41,427	68,724	54,613
Current liabilities
Trade and other payables	11	(27,273)	(54,970)	(55,846)
Risk management contracts	14	-	(8,271)	(381)
Borrowings and leases	12	(13,799)	(25,534)	(27,241)
Decommissioning provision	13	(3,084)	(2,509)	(3,190)
Total current liabilities		(44,156)	(91,284)	(86,658)
Net current (liabilities) / assets		(2,729)	(22,560)	(32,045)
Non-current liabilities
Borrowings and leases	12	(27,391)	-	-
Decommissioning provision	13	(81,883)	(92,533)	(90,141)
Deferred tax liability	6	(9,577)	(8,335)	(11,667)
Total non-current liabilities		(118,851)	(100,868)	(101,808)
Net assets		161,350	152,830	164,746
Capital and reserves
Ordinary shares	15	120	119	119
Deferred shares	15	50	50	50
Share premium	15	50,704	48,646	48,646
Share-based payment reserve	16	6,621	6,164	6,311
Warrants - LNs	16	-	2,045	2,045
Foreign currency translation reserve		3,603	12,969	8,052
Retained earnings		100,252	82,837	99,523
Shareholders' funds		161,350	152,830	164,746

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

The consolidated financial statements of i3 Energy plc, company number 10699593, were approved by the Board of Directors and authorized for issue on 30 August 2023. Signed on behalf of the Board of Directors by:

"Majid Shafiq"

Majid Shafiq - Director

 

Condensed 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 (unaudited)
		£'000	£'000	£'000	£'000	£'000	£'000	£'000	£'000
Balance at 1 January 2022		113	44,203	50	9,102	2,045	1,364	81,289	138,166
Total comprehensive income for the period		-	-	-	-	-	11,605	14,725	26,330
Transactions with owners:
Exercise of options		6	4,443	-	(3,774)	-	-	(6,324)	(5,649)
Exercise of warrants		-	-	-	-	-	-	-	-
Share-based payment expense		-	-	-	836	-	-	-	836
Dividends declared in the period		-	-	-	-	-	-	(6,853)	(6,853)
Balance at 30 June 2022		119	48,646	50	6,164	2,045	12,969	82,837	152,830
Balance at 1 January 2023		119	48,646	50	6,311	2,045	8,052	99,523	164,746
Total comprehensive income for the period		-	-	-	-	-	(4,449)	10,944	6,495
Transactions with owners:
Exercise of options	15	-	13	-	-	-	-	-	13
Exercise of warrants		1	2,045	-	-	(2,045)	-	-	1
Share-based payment expense	16	-	-	-	310	-	-	-	310
Dividends declared in the period		-	-	-	-	-	-	(10,215)	(10,215)
Balance at 30 June 2023		120	50,704	50	6,621	-	3,603	100,252	161,350

 

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 earnings 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

 

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

 

 

Condensed Consolidated Statement of Cash Flow

	Notes	Six-months Ended 30 June 2023	Six-months Ended 30 June 2022 * Restated	Year Ended 31 December 2022 * Restated
OPERATING ACTIVITIES		£'000 (unaudited)	£'000 (unaudited)	£'000 (audited)
Profit before tax		14,469	20,523	55,777
Adjustments for:
Depreciation and depletion	8	19,410	15,017	34,339
Loss on bargain purchase and asset dispositions		-	-	9
Finance costs	5	4,682	3,281	7,865
Unrealised (gain) / loss on risk management contracts	14	(328)	7,223	(858)
Non-cash other income		-	-	(215)
Unrealised FX (gain) / loss		(15)	(2)	113
Share-based payments expense - employees (including NEDs)	16	310	836	1,092
Expenditure on decommissioning oil and gas assets		(3,333)	(201)	(437)
Current taxes paid		(13,675)	-	-
Operating cash flows before movements in working capital:
Decrease / (Increase) in trade and other receivables		12,153	(11,686)	(8,378)
(Decrease) / Increase in trade and other payables		(8,881)	13,656	12,782
(Increase) in inventory		(498)	(218)	(1,434)
Net cash from operating activities		24,294	48,429	100,655
INVESTING ACTIVITIES
Acquisitions		(12)	15	(531)
Expenditures on property, plant & equipment		(25,963)	(19,277)	(64,374)
Disposal of property, plant & equipment		-	170	621
Expenditures on exploration and evaluation assets		(1,192)	(4,452)	(13,842)
Tax credit for R&D expenditure	6	184	-	-
Net cash used in investing activities		(26,983)	(23,544)	(78,126)
FINANCING ACTIVITIES
Exercise of warrants and options		14	635	635
Employment tax on exercised share options	16	-	(6,324)	(6,432)
Repayment of H1-2019 LN facility	12	(28,856)	-	-
Issuance of debt facility	12	44,481	-	-
Payment of deferred finance costs	12	(2,039)	-	-
Principal payments on debt facility	12	(1,238)	-	-
Interest and other finance charges paid	5	(1,277)	(1,161)	(2,330)
Lease payments	12	-	(15)	(74)
Dividends paid	15	(12,254)	(5,153)	(15,353)
Net cash used in financing activities		(1,169)	(12,018)	(23,554)
Effect of exchange rate changes on cash		(20)	2,133	2,250
Net (Decrease) / Increase in cash and cash equivalents		(3,878)	15,000	1,225
Cash and cash equivalents, beginning of period		16,560	15,335	15,335
CASH AND CASH EQUIVALENTS, END OF PERIOD		12,682	30,335	16,560

* The classification of certain comparative lines have been restated - see Note 2.  Included within cash and cash equivalents is £343 thousand of restricted cash, which relates to guarantees for product marketing. The debt reconciliation is shown in Note 12. The accompanying notes form an integral part of these interim financial statements.

 

Notes to the Condensed Consolidated Interim Financial Statements

1        Summary of significant accounting policies

General Information and Authorisation of Financial Statements

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 the Western Canadian Sedimentary Basin and of the appraisal of oil and gas assets on the UK Continental Shelf.

2        Basis of preparation

The condensed consolidated interim financial statements have been prepared in accordance with International Accounting Standard 34 'Interim Financial Reporting' ("IAS 34") and the AIM rules. These condensed consolidated interim financial statements have been prepared using the accounting policies that were applied in the Group's statutory financial statements for the year ended 31 December 2022 and are expected to be applied in the preparation of the financial statements for the year ending 31 December 2023. The condensed interim financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2022, which have been prepared in accordance with UK adopted international accounting standards.

The reports for the six months ended 30 June 2023 and 30 June 2022 are unaudited and do not constitute statutory accounts as defined by the Companies Act 2006. The financial statements for 31 December 2022 have been prepared and delivered to the Registrar of Companies. The auditor's report for these financial statements was unqualified.

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 Ltd., is CAD. A summary of period-average and period-end exchange rates is presented in the table below:

	Six-months Ended 30 June 2023	Six-months Ended 30 June 2022	Year Ended 31 December 2022
Period-average GBP:CAD exchange rate	1.6613	1.6513	1.6073
Period-end GBP:CAD exchange rate	1.6823	1.5661	1.6283

 

In preparing these interim financial statements, management has made judgements and estimates that affect the application of accounting policies and the reported amounts of assets and liabilities, income, and expense. Actual results may differ from these estimates. The significant judgements made by management in applying the Group's accounting policies and the key sources of estimation uncertainty were the same as those disclosed in the Group's statutory financial statements for the year ended 31 December 2022, except for 'Estimated future cash flows for intangible exploration and evaluation assets for impairment testing' as there were no indicators of impairment for the period ended 30 June 2023.

Going concern

The Group's business activities, together with the factors likely to affect its future development, performance and position are set out in the Chairman's and Chief Executive's Statement. The financial position of the Group, its net cash position and liabilities are described in these consolidated interim financial statements and in the Financial Review.

The Group ended the period with cash and cash equivalents of £12.7 million, current assets of £41.4 million, and current liabilities of £44.2 million. The Group's debt primarily consists of the CAD 75.0 million drawn on the Debt Facility in May 2023, whose carrying value is £41.2 million as at 30 June 2023 (note 12). During the 6 months ended 30 June 2023, the Group generated £24.3 million of cash from operating activities.

The Directors have given careful consideration to the appropriateness of the going concern assumption, including cash forecasts through the end of 2024, committed capital expenditure, and the principal risks and uncertainties faced by the Group. The cash flow forecasts include maintenance capital expenditure in Canada and monthly amortisation payments on the Debt Facility. This assessment also considered various downside scenarios including a combined downside scenario with a 15% reduction in strip commodity prices, risks which are partially mitigated by the risk management contracts the Group currently has in place.

Following this review, the Directors are satisfied that the Group has sufficient resources to operate and to meet their commitments as they come due over the going concern period which considers at least 12 months from the date of approval of the financial statements. Accordingly, the Directors continue to adopt the going concern basis in preparing the financial statements for the period ended 30 June 2023.

Reclassification of comparative information

Following an increase in decommissioning expenditure in 2023 and a review of the financial statements, the Group has elected to change the classification of expenditure on decommissioning oil and gas assets from investing activities to operating activities within the consolidated statement of cash flow. There has been no change to the consolidated statements of comprehensive income or financial position.

3        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 for the six months ended 30 June 2023:

	UK / Corporate £'000	Canada £'000	Total £'000
Revenue	-	75,489	75,489
Production costs	-	(36,437)	(36,437)
Loss on risk management contracts	-	3,343	3,343
Depreciation and depletion	(2)	(19,408)	(19,410)
Gross (loss) / profit	(2)	22,987	22,985
Administrative expenses	(1,310)	(2,773)	(4,083)
Operating (loss) / profit	(1,312)	20,214	18,902
Finance income	-	249	249
Finance costs	(2,978)	(1,704)	(4,682)
(Loss) / profit before tax	(4,290)	18,759	14,469
Tax credit / (charge) for the period	184	(3,709)	(3,525)
(Loss) / profit for the period	(4,106)	15,050	10,944

 

The timing of revenue recognition has been disclosed within Note 4.

The following is an analysis of the Group's revenue and results by reportable segment for the six months ended 30 June 2022:

	UK / Corporate £'000	Canada £'000	Total £'000
Revenue	-	101,571	101,571
Production costs	-	(32,782)	(32,782)
Loss on risk management contracts	-	(20,475)	(20,475)
Depreciation and depletion	(2)	(15,015)	(15,017)
Gross (loss) / profit	(2)	33,299	33,297
Administrative expenses	(4,749)	(4,744)	(9,493)
Acquisition costs	-	-	-
Operating (loss) / profit	(4,751)	28,555	23,804
Finance costs	(2,070)	(1,211)	(3,281)
(Loss) / profit before tax	(6,821)	27,344	20,523
Tax (charge) for the period	-	(5,798)	(5,798)
(Loss) / profit for the period	(6,821)	21,546	14,725

The following is an analysis for the Group's revenue and results by reportable segment for the 12 months ended 31 December 2022:

	UK / Corporate £'000	Canada £'000	Total £'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	-	-	0
(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) 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 assets and liabilities by reportable segment as at 30 June 2023 and the capital expenditure for the period then ended:

	UK / Corporate £'000	Canada £'000	Total £'000
Total assets	56,294	268,063	324,357
Total liabilities	(42,067)	(120,940)	(163,007)
Capital expenditure - E&E	214	986	1,200
Capital expenditure - PP&E	-	15,360	15,360

The following is an analysis of the Group's assets and liabilities by reportable segment as at 30 June 2022 and the capital expenditure for the period then ended:

	UK / Corporate £'000	Canada £'000	Total £'000
Total assets	52,791	292,191	344,982
Total liabilities	(29,041)	(163,111)	(192,152)
Capital expenditure - E&E	379	4,284	4,663
Capital expenditure - PP&E	1	34,149	34,150

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 period then ended:

	UK / Corporate £'000	Canada £'000	Total £'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

4        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:

	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
Oil and condensate	48,850	53,104	113,003
Natural gas liquids	12,035	20,366	40,142
Natural gas	20,816	39,157	77,656
Royalty interest	1,520	1,991	4,890
Oil and gas sales	83,221	114,618	235,691
Royalties	(10,540)	(16,174)	(33,536)
Revenue from the sale of oil and gas	72,681	98,444	202,155
Processing income	2,701	3,081	5,995
Other operating income	107	46	286
Total revenue	75,489	101,571	208,436

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.

5        Finance costs

	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
Accretion of loan notes (Note 12)	1,615	1,616	3,386
Cash interest expense on loan notes	951	1,154	2,309
Unwinding of discount on decommissioning provision (Note 13)	1,408	1,206	2,667
Interest on Debt Facility (Note 12)	318	-	-
Amortisation of deferred finance costs (Note 12)	93	-	-
Bank charges and interest on creditors	297	7	21
Gain on financial instrument at FVTPL	-	(702)	(518)
Total finance costs	4,682	3,281	7,865

6        Taxation

Taxation charge / (credit)

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

	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000 * Restated	Year Ended 31 December 2022 £'000
Profit before income tax	14,469	20,523	55,777
Rate of Corporate Tax	23%	23%	23%
Expected tax charge	3,328	4,720	12,829
Effects of:
Interest and other expenses not deductible for SCT or EPL	1,155	277	1,993
Permanent differences	609	464	1,213
Foreign tax rate difference	(2,231)	(1,159)	(5,041)
Change in estimated pool balances	-	53	22
Derecognition of deferred tax asset	848	1,443	2,810
R&D tax credit received	(184)	-	-
Total income tax charge / (credit)	3,525	5,798	13,826

 

* 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 2H 2022, the combined corporate rate of taxation in Canada. The comparative six-months ended period ended 30 June 2022 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. There has been no change to the year ended 31 December 2022 reconciliation as presented in the 31 December 2022 audited financial statements.

Of which:	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
Current tax charge	5,262	5,675	10,002
Deferred tax (credit) / charge	(1,737)	123	3,824
Total income tax charge	3,525	5,798	13,826

In 2023 the Group received £184 thousand in R&D tax refunds in the UK in respect of the 2020 and 2021 fiscal years.

Deferred tax

The components of the net deferred tax asset and the movements during the period is summarised as follows:

	At 31 December 2022	Acquired during the period	Recognised in income	FX movement	At 30 June 2023
	£'000	£'000	£'000	£'000	£'000
UK:
Deferred tax assets:
Losses	37,520	-	2,692	-	40,212
Valuation allowance	(15,123)	-	(2,531)	-	(17,654)
Deferred tax liabilities:
PP&E / E&E	(22,397)	-	(161)	-	(22,558)
Net deferred tax asset / (liability)	-	-	-	-	-
Canada:
Deferred tax assets:
Decommissioning provision	21,466	-	(1,250)	(673)	19,543
Losses	-	-	-	-	-
Risk management contracts	(168)	-	(75)	6	(237)
Other	234	-	(8)	(8)	218
Valuation allowance	(4,180)	-	673	126	(3,381)
Deferred tax liabilities:		-
PP&E / E&E	(29,019)	-	2,397	902	(25,720)
Net deferred tax asset / (liability)	(11,667)	-	1,737	353	(9,577)
Net deferred tax asset / (liability)	(11,667)	-	1,737	353	(9,577)

 

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 deferred tax credit of £1,737 thousand for changes in net deductible temporary differences in the period. The deferred tax asset has been recognised in Canada to the extent that the Group anticipates probable future taxable profits 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.

	30 June 2023 £'000	30 June 2022 £'000	31 December 2022 £'000
UK:
Taxable losses	43,001	34,986	38,927
Mineral extraction allowances	52,680	50,198	52,466
Total - UK	95,681	85,184	91,393
Canada:
Canadian exploration expense (CEE, deductible at 100% p.a.)	1,610	1,746	1,623
Canadian development expense (CDE, deductible at 30% p.a.)	38,428	30,568	37,870
Canadian oil and gas property expense (COGPE, deductible at 10% p.a.)	53,790	62,800	58,478
Undepreciated capital cost (UCC, deductible at 25% p.a.)	21,584	15,241	18,867
Non-capital losses (NCL, deductible at 100% p.a.)	-	-	-
Other (deductible at various rates p.a.)	954	921	1,019
Total - Canada	116,366	111,276	117,857

7           Earnings per share

From continuing operations

Basic earnings or loss per share is calculated as profit for the period, 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 profits or losses for the period attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the period, 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:

	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
Earnings
Earnings for the purposes of basic and diluted earnings per share being net loss attributable to owners of i3 Energy	10,944	14,725	41,951
Weighted average number of shares
Weighted average number of Ordinary Shares - basic	1,196,168,433	1,135,217,866	1,164,210,976
Effect of dilutive potential ordinary shares:
Share options	14,618,629	85,054,264	51,089,073
Warrants	5,748,341	9,047,953	9,048,113
Weighted average number of Ordinary Shares - diluted	1,216,535,403	1,229,320,083	1,224,348,162
Basic earnings per share (pence)	0.91	1.30	3.60
Diluted earnings per share (pence)	0.90	1.20	3.43

 

As at 30 June 2023, the number of potentially dilutive Share options and Warrants outstanding was 34,288,288 and nil, respectively, plus 250,000 EMI options (Note 16). 

8           Property, plant, and equipment

	Oil and gas assets £'000	Right of use assets £'000	Other fixed assets £'000	Total £'000
Cost
As at 1 January 2022	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	(40,233)	-	-	(40,233)
Decommissioning settlements under SRP and ASCP (Note 13)	(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
Acquisitions	26	-	-	26
Additions	15,360	-	-	15,360
Disposals	(17)	-	-	(17)
Changes to decommissioning estimates	(4,992)	-	-	(4,992)
Exchange movement	(9,746)	-	(5)	(9,751)
As at 30 June 2023	298,345	-	179	298,524
Accumulated depreciation
As at 1 January 2022	(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)
Charge for the period	(19,397)	-	(13)	(19,410)
Exchange movement	2,211	-	2	2,213
As at 30 June 2022	(78,532)	-	(98)	(78,630)
Carrying amount at 31 December 2022	236,368	-	97	236,465
Carrying amount at 30 June 2023	219,813	-	81	219,894

 

9           Exploration and evaluation assets (Intangible)

	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
At start of period	62,060	49,819	49,819
Additions	1,200	4,663	12,327
Exchange movement	(224)	233	(86)
At end of period	63,036	54,715	62,060

 

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 Minos High prospective areas.

 

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

 

Management conducted an assessment of indicators of impairment for its E&E assets as at 30 June 2023, concluding that no indicators of impairment were identified.

10      Trade and other receivables

	30 June 2023 £'000	30 June 2022 £'000	31 December 2022 £'000
Trade receivables	12,650	28,459	26,770
Joint venture receivables	7,423	4,654	5,563
Prepayments & other receivables	5,045	3,860	2,510
Total trade and other receivables	25,118	36,973	34,843

Trade and other receivables are all due within one year.

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

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.

11      Trade and other payables

	30 June 2023 £'000	30 June 2022 £'000	31 December 2022 £'000
Trade creditors	8,162	13,698	15,383
Sales tax payable	149	632	378
Accruals	16,928	31,923	26,909
Dividends payable	-	1,700	2,040
Joint venture payables	605	1,033	1,263
Income taxes payable	1,429	5,984	9,873
Total trade and other payables	27,273	54,970	55,846

The average credit period taken for trade purchases is 30 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.

12      Borrowings and leases

Debt Facility

On 31 May 2023 i3 Energy Plc established a CAD 100 million debt facility in the form of a Prepayment Agreement (the "Debt Facility") with Trafigura Canada Ltd., a subsidiary of Trafigura Pte Ltd (collectively, "Trafigura"). Concurrently, i3 Energy Canada Ltd. ("i3 Canada") entered an associated commercial contract related to i3 Canada's oil production. The Debt 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. 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 CAD 75 million advance which has been fully drawn by the Company and a CAD 25 million accordion facility amount, which can be made available during the Debt Facility's three-year term. The Debt Facility is secured by a first lien against substantially all the assets and shares of i3 Canada. The Company utilised a portion of proceeds from the initial advance to redeem the outstanding H1-2019 Loan Notes as discussed below.

The Debt Facility contains the following covenants:

i.      Global Coverage Ratio greater than 125% for the first 12 months and 140% thereafter. Global Coverage Ratio is the percentage of (a) the aggregate of: (i) the Cash balance of i3 Energy Canada  as at such date, (ii) the PV10 of the Proved Developed Producing Reserves (or, if agreed by the Buyer, acting reasonably, the Proved Plus Probable Developed Producing Reserves) owned by i3 Canada) using 85% of the Strip Price and curves, and (iii) the mark to market value (gain or loss) of the Secured Swap Agreements; to, (b) the Principal amount outstanding at each date of determination.

 

ii.     Liquidity Ratio greater than 1.10:1.00. Liquidity Ratio is the ratio of (a) the sum of the following for the next quarter: (i) the revenues of the i3 Canada from the sale of Petroleum Substances, (ii) any royalty or processing income of i3 Canada; (iii) the aggregate amount of all uncalled debt, equity and other capital that is the subject of a binding commitment in favour of i3 Canada from a person who is not an Affiliate; (iv) expected revenue from Permitted Swap Agreements; and (v) all Cash of i3 Canada; to, (b) the sum of the following, all cash costs of i3 Canada in respect of the production, transportation and storage of Petroleum Substances including, without limitation, operating expenses, marketing expenditures, capital expenditures, taxes and interest expense and all distributions and payments of financial indebtedness made by i3 Canada for the next quarter.

 

iii.    Net Debt to EBITDAX less than 3.00:1.00. (a) Net Debt: means, on a consolidated basis and at any time, the aggregate amount of Financial Indebtedness of i3 Canada (excluding any intercompany Financial Indebtedness) net of free and available Cash and Cash Equivalents of i3 Canada. (b) EBITDAX: means, for any fiscal period and as determined in accordance with IFRS (on a consolidated basis) in respect of i3 Canada: (a) all Net Income for such period; plus (b) Interest Expense to the extent deducted in determining such Net Income; plus (c) all amounts deducted in the calculation of such Net Income in respect of the provision for income taxes; plus (d) all amounts deducted in the calculation of such Net Income in respect of non-cash items, including depreciation, depletion, amortization (including amortization of goodwill and other intangibles), accretion, deferred income taxes, foreign currency obligations, noncash losses resulting from marking-to-market any outstanding hedging and financial instrument obligations, non-cash compensation expenses, provisions for impairment of oil and gas assets and any other non-cash expenses for such period; plus (e) exploration expenses; and (f) losses attributable to extraordinary and non-recurring losses, in each case to the extent deducted in the calculation of such Net Income; less (on a consolidated basis), without duplication: (a) earnings attributable to extraordinary and non-recurring earnings and gains, in each case to the extent included in the calculation of such Net Income (including interest income); (b) to the extent included in the calculation of such Net Income, gains from asset sales; (c) all cash payments during such period relating to non-cash charges which were added back in determining EBITDAX in any prior period; and (d) to the extent included in such Net Income, any other non-cash items increasing such Net Income for such period, including non-cash gains resulting from marking-to-market any outstanding hedging and financial instrument obligations for such period.

 

iv.    Liquidity Threshold greater than CAD 10 million. i3 Canada shall ensure that at all times it has a Cash balance in a bank account in an amount equal to or greater than CAD 10 million.

 

The Global Coverage Ratio, Liquidity Ratio, and Net Debt to EBITDAX are tested on the last day of each fiscal quarter. The Liquidity Threshold must be always maintained. The Group was in compliance with all covenants as at 30 June 2023.

H1-2019 loan note facility

In May 2019, the Group 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 quarters since. The H1-2019 LNs matured on 31 May 2023 and were repaid in full using proceeds from the Debt Facility issuance.

Interest expense and accretion expense to 30 June 2023 was £951 thousand and £1,615 thousand respectively (note 5).

Borrowings reconciliation

	Leases	H1-2019 LN	Debt Facility	Total
	£'000	£'000	£'000	£'000
At 1 January 2022	69	23,855	-	23,924
Increase through interest (non-cash)	1	2,309	-	2,310
Accretion expense (non-cash)	-	3,386	-	3,386
Lease and interest payments (cash)	(74)	(2,309)	-	(2,383)
Exchange movement (non-cash)	4	-	-	4
At 31 December 2022	-	27,241	-	27,241
Issuance (cash)	-	-	44,481	44,481
Increase through interest (non-cash)	-	951	318	1,269
Accretion expense (non-cash)	-	1,615	-	1,615
Lease and interest payments (cash)	-	(951)	(318)	(1,269)
Principal payments (cash)	-	(28,856)	(1,238)	(30,094)
Additions in deferred finance costs (cash)	-	-	(2,039)	(2,039)
Amortisation of deferred finance costs (non-cash)	-	-	93	93
Exchange movement (non-cash)	-	-	(107)	(107)
At 30 June 2023	-	-	41,190	41,190

 

The classification as at 30 June 2023 is as follows:

	Leases	H1-2019 LN	Debt Facility	Total
	£'000	£'000	£'000	£'000
Current	-	-	13,799	13,799
Non-current	-	-	27,391	27,391
At 30 June 2023	-	-	41,190	41,190

 

The classification as at 31 December 2022 is as follows:

	Leases	H1-2019 LN	Debt Facility	Total
	£'000	£'000	£'000	£'000
Current	-	27,241	-	27,241
Non-current	-	-	-	-
At 31 December 2022	-	27,241	-	27,241

 

The classification as at 30 June 2022 is as follows:

	Leases	H1-2019 LN	Debt Facility	Total
	£'000	£'000	£'000	£'000
Current	63	25,471	-	25,534
Non-current	-	-	-	-
At 30 June 2022	63	25,471	-	25,534

 

13      Decommissioning provision

	30 June 2023 £'000	30 June 2022 £'000	31 December 2022 £'000
At start of period	93,331	125,523	125,523
Liabilities assumed through acquisitions	14	66	348
Liabilities incurred	135	612	1,369
Liabilities disposed	(17)	(190)	(213)
Liabilities settled	(1,921)	(320)	(2,190)
Liabilities settled under SRP and ASCP	-	-	(731)
Change in estimates	(4,992)	(43,992)	(40,233)
Unwinding of discount (Note 5)	1,408	1,206	2,667
Exchange movement	(2,991)	12,137	6,791
At end of period	84,967	95,042	93,331

 

	30 June 2023 £'000	30 June 2022 £'000	31 December 2022 £'000
Of which:
Current	3,084	2,509	3,190
Non-current	81,883	92,533	90,141
Total	84,967	95,042	93,331

 

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

	30 June 2023	30 June 2022	31 December 2022
Undiscounted / uninflated expenditure (CAD, thousands)	205,282	208,582	206,613
Inflation rate	1.70%	1.78%	2.09%
Discount rate	3.09%	3.14%	3.28%
Timing of cash flows	1-50 years	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") whereby certain costs of settling the Group's liabilities were borne by the Government of Canada in 2022. Where liabilities were settled through the SRP a corresponding decrease to the decommissioning asset was recorded. The change in estimate for the period ended 30 June 2023 was primarily driven by changes in market interest rates (which decreased 0.19%) and inflation rates (which decreased 0.39%) as published by the Bank of Canada. The inflation and discount rates have been pinpointed as a key source of estimation uncertainty, and a sensitivity to a +/- 0.50% movement to these inputs have been disclosed in the key sources of estimation uncertainty note in the Group's statutory financial statements for the year ended 31 December 2022.

14      Risk management contracts

The Group enters a variety of risk management contracts to hedge a portion of the Group's exposure to fluctuations in prevailing commodity prices for oil, gas, and natural gas liquids. The Group's physical commodity contracts represent physical delivery sales contracts in the ordinary course of business and are therefore not recorded at fair value in the consolidated interim 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'.

 The principal terms of the risk management contracts held as at 30 June 2023 are presented in the table 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)
AECO 5A Physical Swaps	1 Aug 2023	31 Mar 2024	10,000 GJ/Day	CAD 2.7600 / GJ
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
WTI Financial Swaps	1 Jul 2023	31 Dec 2023	500 bbl/Day	CAD 102.80 / bbl

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

	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
Unrealised (gain) / loss on risk management contracts	(328)	7,223	(858)
Realised (gain) / loss on risk management contracts	(3,015)	13,252	19,848
Total	(3,343)	20,475	18,990

The carrying value of the Group's risk management contracts are presented in the following table.

	30 June 2023 £'000	30 June 2022 £'000	31 December 2022 £'000
Current asset	1,030	533	1,111
Current liability	-	(8,271)	(381)
Net current asset / (liability)	1,030	(7,738)	730

15      Authorised, issued and called-up share capital

	Issuance date	Ordinary shares	Deferred shares	Nominal value per Share	Ordinary shares	Deferred shares	Share premium before share issuance costs	Share issuance costs	Share premium after Share issuance costs
		Shares	Shares	£	£'000	£'000	£'000	£'000	£'000
At 1 January 2022		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
Issued on exercise of 11 pence options	9 Jan 23	116,667	-	0.0001	-	-	13	-	13
Issued on exercise of 0.01 pence warrants	25 Apr 23	9,051,927	-	0.0001	1	-	2,045	-	2,045
Cancellation of shares	29 May 23	(25,503)	-	0.0001	-	-	-	-	-
As at 30 June 2023		1,201,874,464	5,000	-	120	50	52,704	(2,000)	50,704

 

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.

The cancellation of shares related to unclaimed shares from the Toscana acquisition which completed in 2020. The time limit to claim the shares had expired and 25,503 ordinary shares reverted to the Company to be held in treasury and were subsequently cancelled.

During the six-month period ended 30 June 2023 the Company 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				0.8550	10,215

 

During the year ended 31 December 2022 the Company declared dividends as summarised in the following table:

Declaration date	Ex-Dividend date	Record date	Payment date	Dividend per share	Total Dividend
				(pence)	£'000
9 February 2022	17 February 2022	18 February 2022	11 March 2022	0.1050	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				1.4835	17,393

 

16      Share-based payments

During the period the Group had share based payment expense of £310 thousand (Six-months ended 30 June 2022: £836 thousand; Year ended 31 December 2022: £1,092 thousand).   

Employee and NED share options

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)	(years)
At 1 January 2022	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
11p options exercised during the period	(116,667)	11.00	8.72
Granted during the period	3,000,000	20.00	10.00
At 30 June 2023	34,288,288	11.62	8.34

 

On 18 April 2023, the Company issued options over a total of 3,000,000 ordinary shares to the CFO, 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, the closing price on 18 April 2023. The fair value was calculated using the Black Scholes model with inputs for share price of 20.00 pence, exercise price of 20.00 pence, time to maturity of 10 years, volatility of 97%, the Risk-Free Interest rate of 3.742%, and a dividend yield of 10%. One-third of the options will vest upon achieving production of 26,000 boepd, one-third upon the addition of 5,000 boepd via acquisitions, and one-third upon the addition of 25 MMbbl of 2P reserves. The award shall vest as to one-third upon 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. The resulting fair value of £179 thousand will be expensed over the expected vesting period.

3,862,681 outstanding employee share options as at 30 June 2023 were fully vested and exercisable.

Warrants

Details on the warrants outstanding during the period are as follows:

	Number of warrants	Weighted average exercise price	Weighted average contractual life
		(pence)
At 1 January 2022	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
Exercised in the period	(9,051,927)	0.01	0.42
At 30 June 2023	-	-	-

 

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 throughout 2023 and 2022 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 30 June 2023 have a weighted average exercise price of £0.11 and a weighted average remaining contractual life of 3.43 years.

17      Related party transactions

Remuneration of Key Management Personnel

Directors of the Group are considered to be Key Management Personnel. The remuneration of the Directors will be set out in the annual report for the year-ending 31 December 2023.

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

Ultimate parent

There is no ultimate controlling party of the Group.

18      Commitments

	1 year	1-2 years	3-4 years	5+ years	Total
	£'000	£'000	£'000	£'000	£'000
Operating	188	-	-	-	188
Transportation	1,620	1,410	214	10	3,254
Total	1,808	1,410	214	10	3,442

 

Operating commitments relate to offices leases in Canada that expire in December 2023. Transportation commitments relate to take-or-pay pipeline capacity in Alberta.  

19      Events after the reporting period

Throughout July and August, i3 entered various risk management contracts, as summarised below.

Type	Effective date	Termination date	Total Volume	Avg. Price
AECO 5A Physical Swaps	1 Nov 2023	31 Mar 2024	15,000 GJ/Day	CAD 3.2267 / GJ
WTI Financial Swaps	1 Aug 2023	31 Mar 2024	500 bbl/Day	CAD 93.33 / bbl
WTI Financial Swaps	1 Jan 2024	31 Mar 2024	1,500 bbl/Day	CAD 96.47 / bbl
WTI Financial Swaps	1 Apr 2024	30 Jun 2024	1,750 bbl/Day	CAD 98.20 / bbl
WTI Financial Swaps	1 Jul 2024	31 Aug 2024	500 bbl/Day	CAD 101.50 / bbl

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, boe/d	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
CO2e	Carbon dioxide
the Code	QCA Corporate Governance Code
Company	i3 Energy plc
CPR	Competent person's report
Debt Facility	Prepayment Agreement with Trafigura, dated 31 May 2023
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
GCA	Gas Cost Allowance
GJ	Gigajoule
Gross wells	Wells participated in by i3
Group, i3	i3 Energy plc, together with its subsidiaries
i3 Canada	i3 Energy Canada Ltd.
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
Mmcf	Million 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
p.a.	per annum
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
Trafigura	Trafigura Pte Ltd. and its subsidiary Trafigura Canada Ltd.
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 calculate similarly defined or described measures differently, 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 on bargain purchase and asset disposition 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.

	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
Profit for the period	10,944	14,725	41,951
Depreciation and depletion	19,410	15,017	34,339
Finance costs	4,682	3,281	7,865
Tax	3,525	5,798	13,826
EBITDA	38,561	38,821	97,981
Loss on asset dispositions	-	-	9
Adjusted EBITDA	38,561	38,821	97,990

 

Net Operating Income

Net operating income is defined as gross profit before depreciation and gains or losses on risk management contracts, which equals revenue net of royalty expenses, less production costs. Management believes that net operating income is a useful supplement 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.

	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000 * Restated	Year Ended 31 December 2022 £'000
Gross profit for the period	22,985	33,297	78,689
Depreciation and depletion	19,410	15,017	34,339
(Gain) / loss on risk management contracts	(3,343)	20,475	18,990
Other operating income	(107)	46	(286)
Net operating income	38,945	68,835	131,732

 

* In 2H 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 H1 2022 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 supplement 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.

	Six-months Ended 30 June 2023 £'000	Six-months Ended 30 June 2022 £'000	Year Ended 31 December 2022 £'000
Acquisitions	12	(15)	531
Expenditures on property, plant & equipment	25,963	19,277	64,374
Expenditures on exploration and evaluation assets	1,192	4,452	13,842
Acquisitions & Capex	27,167	23,714	78,747

 

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.

	Six-months Ended 30 June 2023   £'000	Six-months Ended 30 June 2022 * Restated £'000	Year Ended 31 December 2022 * Restated £'000
Net cash from operating activities	24,294	48,429	100,655
Expenditures on property, plant & equipment	(25,963)	(19,277)	(64,374)
Expenditures on exploration and evaluation assets	(1,192)	(4,452)	(13,842)
FCF	(2,861)	24,700	22,439

 

* The classification of certain comparative lines have been restated - see Note 2.

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.

	30 June 2023 £'000	30 June 2022 £'000	December 2022 £'000
Borrowings and leases	41,190	25,534	27,241
Trade and other payables	27,273	54,970	55,846
Cash and cash equivalents	(12,682)	(30,335)	(16,560)
Trade and other receivables	(25,118)	(36,973)	(34,843)
Net debt	30,663	13,196	31,684