I3 Energy Regulatory News (I3E)

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

(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:

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.

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:

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.

2023 Updated Commodity Assumptions (4)

Next Twelve-Month Net Operating Income Sensitivity (5)

(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

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.

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.

(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).

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

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.

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.

(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.

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.

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

All operations are continuing.

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

Condensed Consolidated Statement of Financial Position

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

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

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

Condensed Consolidated Statement of Cash Flow

* 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:

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:

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:

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

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:

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:

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:

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:

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

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.

* 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.

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:

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.

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:

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