REG - i3 Energy PLC - Interim Report and Operational Update for H1 2023
31/08/2023 07:15
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RNS Number : 9306K i3 Energy PLC 31 August 2023
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
(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 c/o Camarco
Majid Shafiq (CEO) / Jason Dranchuk (CFO) 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/ (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" "Majid Shafiq"
John Festival Majid Shafiq
Non-Executive Chairman
Chief Executive Officer
30 August 2023 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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'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 £'000 £'000
(unaudited) (unaudited) (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 £'000 £'000
(unaudited) (unaudited) (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 Year Ended 31 December 2022
* Restated * Restated
OPERATING ACTIVITIES £'000 £'000 £'000
(unaudited) (unaudited) (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 (#_Borrowings) . 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 Canada Total
£'000 £'000 £'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 Canada Total
£'000 £'000 £'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 Canada Total
£'000 £'000 £'000
Revenue - 208,436 208,436
Production costs - (76,418) (76,418)
Loss on risk management contracts - (18,990) (18,990)
Depreciation and depletion (4) (34,335) (34,339)
Gross (loss) / profit (4) 78,693 78,689
Administrative expenses (6,821) (8,217) (15,038)
Acquisition costs - - 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 Canada Total
£'000 £'000 £'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 Canada Total
£'000 £'000 £'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 Canada Total
£'000 £'000 £'000
Total assets 57,500 295,712 353,212
Total liabilities (30,166) (158,300) (188,466)
Capital expenditure - E&E 5,650 6,677 12,327
Capital expenditure - PP&E - 75,793 75,793
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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'000
* Restated
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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'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 30 June 2022 31 December 2022
£'000 £'000 £'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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'000
Earnings
Earnings for the purposes of basic and diluted earnings per share being net 10,944 14,725 41,951
loss attributable to owners of i3 Energy
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 Right of use assets Other fixed assets Total
£'000 £'000 £'000 £'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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'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 30 June 2022 31 December 2022
£'000 £'000 £'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 30 June 2022 31 December 2022
£'000 £'000 £'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 (#_Finance_costs) ).
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 30 June 2022 31 December 2022
£'000 £'000 £'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 30 June 2022 31 December 2022
£'000 £'000 £'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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'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 30 June 2022 31 December 2022
£'000 £'000 £'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 Ordinary shares Deferred shares Nominal value per Share Ordinary shares Deferred shares Share premium before share issuance costs Share issuance costs Share premium after Share issuance costs
date
Shares Shares £ £'000 £'000 £'000 £'000 £'000
At 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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'000
* Restated
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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
£'000 £'000 £'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 Six-months Ended 30 June 2022 Year Ended 31 December 2022
* Restated * Restated
£'000 £'000 £'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 30 June 2022 December 2022
£'000 £'000 £'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
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