REG - IOG PLC - Final Results for the Year Ended 31 December 2022
16/03/2023 07:00
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RNS Number : 1559T IOG PLC 16 March 2023
16 March 2023
IOG plc
Final Audited Results for the Year Ended 31 December 2022
IOG plc ("IOG", or "the Company"), (AIM: IOG.L), is pleased to announce its
final audited results for the Year Ended 31 December 2022.
2022 Highlights
Corporate and Operational
· First Gas delivered from Blythe on 13 March and Elgood on 15
March 2022
· Gross average gas sales of 27.4 mmscfe/d and condensate sales of
1067 MT from First Gas to year end, at average Production Efficiency of 58.6%
· Southwark A1 well drilling suspended due to fluid losses above
reservoir section
· Southwark A2 well drilled, completed and stimulated, but suspended
post-year end after achieving 2.5 mmscf/d gas flow rate on well test after
remediation of water producing stimulated zones
· 2022 Scope 1 and 2 emissions intensity estimated at 0.8 kgCO₂e/boe
(North Sea average: 21.2 kgCO₂e/boe¹)
· Total Reportable Incident Rate (TRIR²) of 3.6 per 200,000
manhours for 2022
Financial
· Total revenue before sales deductions of £79.6 million (2021:
£nil), of which £76.0 million related to gas and £3.6 million condensate
· Weighted average realised 2022 gas price of 201.4 p/therm and
$805/MT for condensate
· Gross profit of £51.8 million, cost of sales of £23.6 million
and EBITDAX³ of £63.1 million for the period
· Net loss of £28.4 million (2021: £2.4 million), including a
£43.4 million impairment of Southwark and £7.6 million impairment of
Nailsworth and Elland
· Loss per share of 5.4p (2021: 0.4p loss); adjusted earnings per
share⁴ of 4.3p after exceptional one-off items
· Cash balance at period end of £32.4 million (2021: £34.7
million), including restricted cash of £5.7 million (2021: £3.4 million)
· Group net debt⁵ at year end £68.2 million (2021: £56.6
million)
· Accrued opex of £10.1 million, equating to gross unit opex of
24.0 p/therm (2021: N/A)
· £8.6 million (2021: £8.3 million) interest paid on €100
million September 2024 senior secured bond ("Bond")
· 2.7 mmscf/d fixed month-ahead in certain months in 2H 2022 at
prices from 263 p/therm to 444 p/therm
Board and Management
· Rupert Newall appointed as Chief Executive Officer (CEO), Dougie
Scott as Chief Operating Officer (COO) and Executive Director, and John Arthur
as Chief Financial Officer (CFO, non-board) in October 2022
Post Year End Developments
· Southwark A2 well suspended and further in-depth review of
deliverability initiated
· Blythe H2 well spudded in March 2023, intended to increase gas
production, limit water production and maximise reserve recovery from the
Blythe reservoir
· Nine Southern North Sea blocks applied for across five licences
areas in the 33(rd) UK Offshore Licensing Round, as operator of the 50:50
joint venture with CER
· Fiona MacAulay to stand down as Chair of the Company at the 2023
AGM, with Esa Ikaheimonen named as Interim Chair and a process underway to
recruit two further Non-Executive Directors
· Cash balance of £32.6 million as at 15 March, including
restricted cash of £6.2 million
· Over January and February 2023, gross average production from the
Blythe H1 well was 15.9 mmscf/d, with Production Efficiency of 89.7%
¹ Emissions intensity is measured in kilograms of carbon dioxide equivalent
per barrel of oil equivalent of production, kgCO₂e/boe, on a Scope 1 and 2
basis. North Sea average is taken from the NSTA Emissions Monitoring Report,
September 2022.
² Total Reportable Incident Rate (TRIR) includes all incidents reportable by
law to UK regulators, irrespective of size or consequence, whether involving
IOG personnel, duty holders or contractors, per 200,000 hours worked
³ EBITDAX is defined as profit or loss before net finance expense, income tax
expense, depreciation of property, plant and equipment and right-of-use
assets, amortisation of intangible assets, impairment of property, plant and
equipment, and foreign exchange gain or loss.
⁴ Adjusted earnings per share is defined as earnings per share before
exceptional one-off items, i.e. in respect of 2022, the Southwark, Nailsworth
and Elland impairments
⁵ Net debt is defined as total loans, primarily the EUR denominated Bond,
less restricted cash and cash equivalents.
Rupert Newall, CEO of IOG, commented:
"Having become the UK's newest gas producer in March 2022, IOG then
experienced a number of production issues followed by the very disappointing
Southwark A2 well result shortly after year end. Our FY 2022 results reflect
this operational performance amid a very volatile gas market. Pending the
outcome of the detailed evaluation of options for a commercial forward plan
for Southwark, we have taken a significant impairment. While this non-cash
impairment drove a full-year loss, adjusted earnings of 4.3p/share reflect
underlying profitability.
As a very well aligned new leadership team, we are already rolling out our
operational and financial improvement strategy, seeking to deliver production
resilience, reduce costs and maximise cash flow. Operating efficiency at
Blythe is much improved this quarter and we spudded the Blythe H2 well on 5th
March, targeting 30-40 mmscf/d initial gross production rates by mid-year. We
also continue with rigorous review of our portfolio to ensure we allocate
capital in a prudent and disciplined way."
This announcement contains inside information for the purposes of Article 7 of
the Market Abuse Regulation (EU) 596/2014 as it forms part of UK domestic law
by virtue of the European Union (Withdrawal) Act 2018 ("MAR"), and is
disclosed in accordance with the company's obligations under Article 17 of
MAR.
Enquiries:
IOG plc +44 (0) 20 7036 1400
Rupert Newall (CEO)
Dougie Scott (COO)
James Chance (Head of Capital Markets & ESG)
finnCap Ltd +44 (0) 20 7220 0500
Christopher Raggett / Simon Hicks
Peel Hunt LLP +44 (0) 20 7418 8900
Richard Crichton / David McKeown
Vigo Consulting +44 (0) 20 7390 0230
Patrick d'Ancona / Finlay Thomson
About IOG:
IOG is a UK developer and producer of indigenous offshore gas. The Company
began producing gas in March 2022 via its offshore and onshore Saturn Banks
production infrastructure. In addition to its production assets, IOG operates
several UK Southern North Sea licences containing gas discoveries and
prospects which, subject to future investment decisions, may be commercialised
through the Saturn Banks infrastructure. All its assets are co-owned 50:50
with its joint venture partner CalEnergy Resources (UK) Limited. Further
details of its portfolio can be found at www.iog.co.uk (http://www.iog.co.uk)
.
Competent Person's Statement
In accordance with the AIM Note for Mining and Oil and Gas Companies, IOG
discloses that Phil Cox, IOG's Head of Subsurface, is the qualified person
that has reviewed the technical information contained in this document. He has
an MSc in Geology from the Royal Holloway, University of London, is a fellow
of the Geological Society and has over 23 years' of experience in the upstream
oil and gas industry. Phil Cox consents to the inclusion of the information in
the form and context in which it appears.
Chief Executive's Review
2022 Review
2022 saw IOG become the UK's newest gas producer, as Saturn Banks was safely
brought onstream in mid-March. The IOG team's dedication, supported
constructively by our joint venture partner CalEnergy Resources (UK) Limited
(CER), turned the company from an unfunded concept into a low-carbon gas
producer in just a few years.
From First Gas in March until year end, we delivered average gross production
of 27.4 mmscfe/d, generating £79.6 million of revenue (£3.6 million of which
was from condensate). Whilst EBITDAX of £63.1 million demonstrates our
underlying profitability, the year was overshadowed by a number of operational
and subsurface challenges which led to production, revenue and profitability
being below our expectations. The full year loss of £18.7 million reflects
the impact of £52.6 million of asset impairments following the very
disappointing Southwark A2 well result.
FY 2022 Operating and Financial Summary
Operating Unit FY 2022 FY 2021
Annualised gross gas production mmscf/d 21.0 Nil
Net gas sales mmscf 3,444 Nil
Volume weighted average gas price p/therm 201.4 N/A
Net condensate sales MT 5,339 Nil
Average condensate price $/MT 805 N/A
TRIR per 200,000 hrs 3.6 3.5
Emissions intensity kgCO₂e/boe 0.8 N/A
Financial
Revenue £m 79.6 nil
Opex p/therm 24.0 N/A
Loss for the year £m (28.4) (2.4)
EBITDAX £m 63.1 (3.7)
Capex spend (net to IOG) £m 56.8 59.1
Cash (excluding restricted) £m 26.7 31.3
Net debt £m 65.1 56.6
Basic EPS £p (5.4) (0.4)
Adjusted EPS £p 4.3 (0.4)
At IOG, the first gas milestone was always intended to be the start of a new
era. The first fields were intended to deliver the operating cashflow to
enable the company to grow and diversify its production portfolio and deliver
shareholder returns. In that context, a combination of much lower reserves in
Elgood, formation water production from Blythe H1 and the failure of the
Southwark A2 well to produce at commercial rates has significantly impacted
our position compared to expectations. However, together with our joint
venture partner, we own a significant and strategic infrastructure position in
an area where there are multiple undeveloped gas resources and we remain a
production company with cashflow which we expect to be significantly enhanced
in mid-2023 by the Blythe H2 well.
This combination of challenges culminated in a change of senior management in
October 2022, with the highly experienced Dougie Scott arriving as COO, John
Arthur becoming CFO and my appointment as CEO. Our immediate focus was to turn
around near term operational performance and reduce operating costs. We are
now reviewing our future plans against a rebaselined technical assessment of
our reserves and resources, with a view to balancing cash generation and value
creation. Given the operational challenges we have experienced over the past
year, we are also ensuring that the lessons are learned and applied to future
operations.
The management change gave us the opportunity to reset and improve the way we
work. The skills and experience of the new leadership team are more suited to
this early production phase of the business and to delivering further phases
of development through the Saturn Banks system in a safe and efficient manner
to drive returns. More fundamentally, we redefined our core IOG values:
Safety, Integrity, Ownership, Performance, Ingenuity and Teamwork. This is
reflected in a new Code of Conduct that sets out our working principles and
the high standards we expect of each other.
As CEO, I believe it is vital that we lead by example in our key behaviours.
This includes taking personal responsibility for all decisions and actions
(not least on safety and environment); applying learnings for continued
improvement; communicating clearly, openly and effectively; tackling issues
proactively and looking for creative solutions; and listening to and
supporting our teammates. All with clear objectives in mind: more efficient
operations, higher production and lower costs.
In the UK context, our low carbon intensity domestic gas production strategy
retains compelling logic. In 2021, the UK imported 62% of its gas consumption.
Every molecule produced locally limits the UK's reliance on high carbon
intensity liquefied natural gas (LNG) imports. Gas remains the UK's largest
primary energy source, heating 85% of UK homes, generating around 40% of UK
electricity (providing vital balance to intermittent renewable generation) and
fuelling key industries. Under all forecast scenarios, gas will continue to
play an indispensable role in the energy transition, at least to 2050, and
Liquefied Natural Gas (LNG) has become increasingly critical to energy
security. In that context, IOG's industry-leading 2022 Scope 1 and 2 emissions
intensity of just 0.8 kgCO₂e/boe, compared to the 2021 UK North Sea average
of 21.2 kgCO₂e/boe, gives us clear environmental differentiation, especially
in comparison to imported LNG which can exceed 100 kgCO₂e/boe. We will
continue to look for ways to minimise operating costs and emissions alike.
In 2022 we also witnessed several important market, regulatory and
geopolitical developments. The year was overshadowed politically by the
conflict in Ukraine. Beyond the manifest human tragedy of this war, it has had
and will continue to have profound implications for European energy markets.
It was an extraordinary year for gas markets, with UK day-ahead prices ranging
from 10 p/therm (in May) to 450 p/therm (in August). We expect 2023 UK gas
prices will remain volatile and above historical norms, if lower than our 2022
realised average of 201.4 p/therm. Such volatility can be challenging to
manage, but we retain the same fundamental approach to our economic planning:
to look through short-term noise and stress-test our investment decisions
against a range of prudent through-cycle assumptions.
Although the Ukraine conflict brought renewed focus on energy security,
counterintuitively, the post-pandemic commodity price spikes also fuelled
fiscal changes that will likely weaken energy security. For the UK, maximising
the value of domestic UK resources, ensuring greater energy security as an
import-dependent market, and delivering the Net Zero journey requires a stable
and balanced fiscal regime. The introduction, swiftly followed by the
extension, of the Energy Profits Levy (EPL) presents clear risks to upstream
investment and industry competitiveness. The 75% marginal tax rate, without
price floors or allowances for smaller projects, is now effectively one of the
world's most punitive fiscal regimes. While the ultimate amounts to be paid
will depend on our production volumes, realised gas prices and the size and
nature of future investments, these accounts reflect a 2.2 p/share value
impact for IOG.
Post-Year End and 2023 Outlook
Lower than expected production following the Southwark A2 setback has created
uncertainty over future cash flows. The new leadership team has been carefully
assessing the Company's projected financial performance and continues to
analyse options to best manage the capital structure in both the short and
longer term. In that context, we have been working to deliver incremental
improvements such as fixed cost reductions and increased oversight and
assurance. We have also initiated a full technical review of the
pre-development portfolio to ensure we allocate capital in the most effective
way in future.
In February the IOG-CER joint venture sanctioned the Blythe H2 well. This is
designed to significantly enhance current production rates, reduce water
production into the Saturn Banks pipeline and minimise associated operating
costs. It has a compelling economic and operational logic and can pay back
rapidly, enabling us to boost cash flow from mid-2023.
Early in 2023, following a rigorous technical and commercial screening
process, we submitted joint bids with our partner CER, under our Area of
Mutual Interest Agreement, for nine SNS blocks across five licences in the
33(rd) UK Offshore Licensing Round. Licensing round acquisitions are an
important, low entry-cost strategic tool with which we have had significant
previous success. All the target licences are adjacent to existing Saturn
Banks licences and contain discovered resources, with some containing
redevelopment opportunities and others featuring near-field exploration
potential. If successful, these applications could add tangible value to all
of our gas hubs.
In February 2023, Fiona MacAulay, who has been Chair of IOG since December
2018 having first joined the Board in July 2018, confirmed that she will not
stand for re-election as a director at the 2023 Annual General Meeting. Esa
Ikaheimonen will replace Fiona as Chair initially on an interim basis,
bringing his deep understanding of the Company, a wealth of industry expertise
and extensive financial and commercial experience to the role. We have
initiated a process to bring in two further non-executive directors to further
strengthen the Board.
Finally, I would like to reiterate my thanks to everyone in the IOG team, who
have been working incredibly hard in difficult circumstances. Equally, I thank
our very constructive joint venture partner CER and all our Duty Holders and
contractors, as well as all our regulators at NSTA, the newly inaugurated
Department for Energy Security and Net Zero, OPRED and UK HSE, for working
with us on Saturn Banks. Finally, my sincere thanks goes to all our investors
for their support through this turbulent period as we look towards the next
stage of the IOG journey, building production resilience and new growth across
the portfolio.
Rupert Newall
Chief Executive Officer
15 March 2023
Operational Update
Saturn Banks Development and Production Assets
Blythe (P1736) and Elgood (P2260)
The Blythe platform is a monopile normally unmanned installation (NUI) with
one well, H1, drilled and in production. The Elgood field has one subsea well
installed, tied back subsea to the Blythe platform via a 6" connection and
umbilical. The Blythe platform has a 12" pipeline tied into the 24" Saturn
Banks Pipeline System (SBPS) 29km offshore via a subsea T-piece. From here the
gas is transported into the Saturn Banks Reception Facilities (SBRF) at
Bacton. Following completion of the SBRF refurbishment in the early part of
the year, the Blythe and Elgood fields were brought onstream on the 13(th) and
15(th) March 2022 respectively.
Average gas production from Blythe and Elgood from First Gas in March to the
end of the year, was 27.4 mmscf/d. Gross condensate sales from both fields
amounted to 1067.9 metric tonnes over the same period.
Production Efficiency, which includes planned and unplanned losses, for Blythe
and Elgood on a combined average basis was 58.6% from First Gas to the end of
2022. Unplanned platform outages downtime in 2022 resulted from various
factors, including a mono-ethylene glycol (MEG, hydrate inhibitor) injection
fault and generator trips. In response, the Company undertook production
resilience measures, including enhanced helicopter and vessel access to enable
faster offshore restarts. Onshore, modification to a recycle compressor in the
Bacton terminal's condensate stabilisation unit also caused a one-week
production outage in May 2022.
Early in Q3 2022, formation water started to arrive onshore via the SBPS.
Analysis indicated that a sub-seismic resolution natural reservoir fracture
encountered during Blythe H1 development drilling was the most likely source
of this. Salinity levels of the formation water exceeded the maximum allowable
for processing at Bacton and thus necessitated an alternating regime of batch
slugcatcher liquid letdowns alongside other streams entering the terminal.
This revised liquid management regime constrained production levels.
Over a four-week period in October and November 2022, Blythe and Elgood were
shut in to allow the Southwark leg of the Saturn Bank Pipeline system to be
connected to the 24" pipeline to SBRF via the subsea T-piece. On production
restart, Blythe flowed as expected, however it was not possible to sustain
production from Elgood. Analysis indicated that the Elgood well would flow in
the event the pipeline was dewatered.
Blythe (P1736)
Prior to production, gross 1P/2P/3P management estimated Blythe gas reserves
were 25.9/43.3/56.9 billion cubic feet equivalent (BCFE, where condensate is
converted into gas equivalent at 5.8 bbl/mcf). In Q4, technical analysis of
production and reservoir pressure data from the first six months of Blythe H1
production indicated that the well is located in a reservoir compartment which
is materially baffled from the central and northwest areas of the field. It
was assessed at the time that the H1 well would ultimately recover an
estimated 29 BCF of gas.
A second Blythe production well, H2, has been planned in order to enhance
production levels and maximise ultimate recovery of Blythe reserves, as well
as to reduce production of formation water into the pipeline. In February
2023, the Blythe H2 well was sanctioned with the intention to be drilled and
completed over Q1-2 2023.
Blythe FY2022 1P and 2P reserve estimates shown in the reserves summary table
above represent a modest increase on FY2021 estimates, factoring in 2022
production of 4.1 BCFE.
The 1P case assumes production only from the H1 well, as H2 was not sanctioned
at year end, and the 2P case assumes production from H1 and H2, which was
sanctioned in February 2023.
Elgood (P2260)
Prior to production, gross 1P/2P/3P management estimated Elgood gas reserves
were 9.6/14.1/18.3 BCFE. In Q4, technical analysis of the production and
reservoir pressure data from the first six months of production indicated that
the flow rate was declining faster than anticipated given the pre-production
reserve estimate. This analysis indicated that gas is not flowing across the
NW-SE oriented intra-field fault to the wellbore as expected. On that basis
the most likely ultimate recovery from the field was further revised as shown
in the reserves table above.
During 2022, 4.1 BCFE was produced from Elgood. As at the date of this report,
the Elgood field is shut-in, with further production expected when a reduction
in pipeline export pressure is realised, in the following scenarios:
1. The SBPS has been dewatered, after which it could be produced cyclically
2. Onshore compression has been introduced
The 1P case assumes 0.4 BCFE production post-dewatering and the 2P case
assumes 0.4 BCFE post dewatering and a further 1.8 BCFE post-compression.
Southwark (P1915)
Following the spudding of the A1 development well at the end of 2021, in
January 2022 drilling was temporarily suspended due to damaged leg cross
members caused by serious scour issues around the jack-up spud cans. The jack
up rig was demobilised and repaired while the spud can location at the
platform was remediated by installing rock pads. The rig was re-mobilised and
operations on A1 recommenced in April. After drilling the initial section of
A1, the rig was skidded to drill the A2 well as planned before resuming A1.
In Q2 2022, the 6km 24" extension of the SBPS to the Southwark platform was
safely and successfully installed by the Seven Borealis S-lay vessel. This was
subsequently hooked up to the in situ 24" line in Q4.
On A1 extensive drilling fluid losses were encountered in the Bunter Sandstone
Formation. The 9-5/8'" casing was run in an attempt to isolate the loss zone,
however this was unsuccessful as further losses were encountered on drilling
out of the 9-5/8" casing shoe into the Bunter Shale Formation. After due
consultation, the JV elected to suspend the A1 well in order to evaluate and
develop an appropriate remediation plan for A1.
After an equipment rig-up period, stimulation operations on A2 commenced in
November and continued through to the year end. In total, six hydraulic
fractures were deployed into the reservoir. The well was cleaned up via the
temporary well test separator. The clean-up phase saw lower than expected gas
rates and high rates of associated water, indicating a connection to the
active aquifer. A production logging tool was then run which provided input
data for remediation via isolation of water producing zones. This remediation
reduced water production from 1500 bbls/d to an average rate of 380 bbl/d,
however, stabilised gas rates were limited to 2.5 mmscf/d, at a flowing
wellhead pressure of 1186 psi. These rates did not justify hooking up the A2
well for production and so the well was suspended in order to conduct a full
analysis to ascertain future production options.
Following the A2 result, the JV made the decision to delay the re-entry into
A1 pending further analysis. A1 remained suspended and the rig was moved to
Blythe to drill the H2 well.
The A1 well is intended to penetrate the western panel of the Southwark
reservoir and produce through deploying five hydraulic fracture stimulations.
This area of the field has greater well control from the Southwark discovery
well (49/21-8A). The A1 well is to be landed close to the discovery well, thus
providing more accuracy in reservoir entry depth, reservoir thickness and free
water level at that location.
A multi-disciplinary task force involving external experts has commenced a
full review to ascertain the causes of the results encountered on A2 and
identify how any lessons learned can be implemented on A1. This review may
inform a further revision of the estimated reserves range. Pending that
review, the current estimated reserves range shown in the reserves table above
reflects the uncertainty following A2 as to the recoverability of commercial
gas volumes from both the A1 and A2 wells. The 1P case assumes no production
is possible from the field and the 2P case assumes production from the A1 well
only, based on a limited stimulation scenario, with no production from the A2
well.
Pre-Development Assets (PDAs)
Central Hub: Nailsworth (P130 & P2342) and Elland (P039) discoveries
The fully-owned subsidiary IOG UK Limited (IOGUKL) has a 50% working interest
and is operator of the P130 and P2342 licences, which contain the Nailsworth
gas discovery, and the P039 licence, which contains the Elland discovery.
Nailsworth is a three-way dip and fault sealed structure directly north of the
Vulcan field (which produced 665 BCF between 1988 and 2018). Four exploration
and appraisal wells have been drilled on the Nailsworth structure, confirming
a gas-water contact (GWC) of -7,657ft TVDSS. The Company has reprocessed 3D
seismic data to Pre-Stack Depth Migration (PSDM) standard and completed new
static and dynamic reservoir modelling of the field.
In the FY2022 reserves and resources review, the Nailsworth and Elland gas
fields, which are envisaged to be part of a Central Hub development in the
area north of Southwark, have been reclassified from the Reserves category
Justified for Development to the Contingent Resources category Development
Pending. This classification change is considered currently more appropriate
given the evolution in development plans and pre-Final Investment Decision
(FID) status. Following an FID, the fields would be expected to be
reclassified back into reserves.
The estimated contingent resources range for Nailsworth has been revised to
1C/2C/3C 48.5/84.9/140.2 BCFE. This follows a full subsurface uncertainty
analysis which included updates to the static and dynamic models. The post-A2
detailed technical review of Southwark may also have implications for the
Nailsworth estimated resource range. The volumetric estimates on the Elland
gas field have not changed.
Evaluation of the Nailsworth and wider Central Hub export route and host
options identified the preferred option as the Southwark platform 19km to the
southeast, with onward export via Saturn Bank Pipeline System. This is
considered to have the strongest operational and commercial synergies and
lowest expected emissions impact. The optimal development of the Nailsworth
reservoir is likely to be via hydraulically stimulated production wells, which
could be phased based on well performance.
Development concept engineering work, working closely with the JV partner CER,
has then considered a wide range of potential development concept options for
Nailsworth and the other Central Hub fields. This evaluation took into account
the bathymetry of the area, designated export route and minimisation of
environmental impact. This may justify some pre-investment to enable future
connection of the incremental subsea infrastructure for the other Central Hub
fields. The concept engineering and subsurface evaluation basis was collated
into a Concept Select Report (CSR) and submitted to the NSTA.
The key scopes within the planned Nailsworth Front-End Engineering and Design
(FEED) cover:
- engineering design of the subsea infrastructure including the
export pipeline to the Southwark platform
- design and configuration of the controls (power, hydraulics and
chemical supply) for the subsea wells
- flow assurance on the production fluids to confirm the sizing of
the pipeline for Nailsworth and the consideration through the asset life
incorporating the other central hub fields and compression
The Nailsworth FEED bid submissions were under evaluation at the time of this
report. In parallel, a Field Development Plan (FDP) and Environmental
Statement are being worked on in preparation for an eventual JV FID on
Nailsworth, as part of the wider Central Hub.
As previously disclosed, the Elland field has a suspended well 49/21-10A on
it. On acquisition from the previous owners, the Company took on the liability
to permanently plug and abandon this well. This work is planned for the first
half of 2023, at an estimated gross cost of £0.8 million (£0.4 million net
to IOG).
Potential Southern Hub: Abbeydale and Orrell (part) discoveries, Kelham North,
Kelham Central, Thornbridge and Thornbridge Deep prospects (P2442)
IOG holds a 50% working interest in Licence P2442, as operator, via its
fully-owned subsidiary IOG North Sea Limited (IOGNSL). The licence contains
the Abbeydale gas discovery, part of the Orrell discovery, and the Kelham
North, Kelham Central, Thornbridge and Thornbridge Deep prospects. The firm
work programme commitment to reprocess 150 km² of seismic data within two
years was completed in early 2021. An appraisal well is to be drilled on the
licence by the end of the Initial Term, which is currently 30 September 2023.
In early 2023, in light of unexpected delays to the Phase 1 development
drilling programme, IOGNSL formally requested a six-month extension to the
Initial Term of Licence P2442 so that the appraisal well could be drilled
within the appropriate licence term. The extension request is under
consideration by the NSTA at the time of this report.
Interpretation of the reprocessed dataset enhanced the Company's view of the
resource potential across the licence. The deterministic management estimate
of gross 1C/2C/3C contingent resources at Abbeydale remained at 19/23/25 BCFE.
The tight resource range reflects a well-defined structure, constrained by
well data from the 51/13a-13 appraisal well.
Technical work also included a more sophisticated depth conversion and mapping
work programme to better capture the Gross Rock Volume uncertainty range of
the identified structures, further evaluation of the existing adjacent well
stock and an improved understanding of rock quality. This identified several
further prospects and leads on the licence. To the immediate north of
Abbeydale lies the formerly producing Camelot Complex, comprising several
fields developed and produced by Mobil (and later Perenco). The Kelham North
prospect is a previously unmapped, distinct structural closure within the
Cador field, which was part of the Camelot Complex. Similarly, mapping of
the Kelham Central prospect, and reconciliation with production volumes from
Camelot Central, suggest an unconnected volume from an undrained structure.
The seismic reinterpretation combined with available production data has been
used to generate the current management estimated gross Low/Mid/High
contingent gas resources of 34/46/58 BCFE in Kelham North and 11/16/22 BCFE in
Kelham Central, both with a 72% Geological Chance of success (GCoS). The
planned appraisal well and side-track is intended to confirm these resource
ranges in the structures.
If successfully appraised, these assets would form the basis of a new Southern
Hub development that would include a subsea tie-back of the Abbeydale
discovery to gas gathering infrastructure tied directly into the Saturn Banks
Pipeline System. In the Company's view, successful appraisal would
significantly de-risk the other discoveries and prospects in the P2442
licence, enhancing the commercial potential of the area and providing add-on
development opportunities for the potential Southern Hub.
Thornbridge and Thornbridge Deep are two further prospects on the P2442
licence, lying to the northwest of Abbeydale. Subject to successful
exploration, these structures may provide further resource additions to the
potential Southern Hub, as detailed in the prospective resources table above.
A further discovery, which the Company has named Orrell, lies partly on the
P2442 licence, extending over its northern limit into an unlicensed area.
Management estimated prospective resources on licence were revised marginally
down in the FY2022 technical review to Low/Mid/High 11/16/22 BCFE. Subject to
further technical assessment and successful appraisal of the Kelham North and
Kelham Central structures, Orrell could potentially become part of a Southern
Hub development via a single well subsea tie-back to an unmanned host
platform.
Potential Northern Hub: Goddard discovery, Goddard Flank structures, Southsea
prospect (P2438)
IOGNSL also has a 50% working interest and is operator of Licence P2438, which
contains the Goddard field, an undeveloped gas discovery. In light of the
relative maturity of Goddard's contingent resources, and to improve structural
imaging of the field as much as possible, further reprocessing to PSDM and
reinterpretation of 3D seismic data over the Goddard area was undertaken in
2020-21. Additional seismic mapping was then carried out that incorporated
further structural analysis of the PSDM seismic data, resulting in clearer
definition of the greater Goddard area, a better understanding of lateral
velocity variation across the field allowing an enhanced depth conversion
methodology. There is now also better definition of main field bounding faults
and possible intra-field faults which is key to optimal development of the
field. This work resulted in management estimated contingent resources for the
main Goddard structure of 52/115/169 BCFE. Further mapping work also resulted
in management estimated prospective resources in the Goddard flank structures
to Low/Mid/High 16/27/42 BCFE and 30/50/73 BCFE, with 71% GCoS in each case.
The management estimated contingent and prospective resources range for
Goddard, the Goddard Flanks and Southsea remained the same in the FY2022
technical review.
An appraisal well is to be drilled on the licence by the end of the Initial
Term, which is currently 30 September 2023. The PSDM has also been used to
optimally locate the planned appraisal well to be drilled approximately 4
kilometres away from the Goddard discovery. The well is intended to test the
full range of possible gas-water contacts resulting in greater certainty of
the Gas-Initially-in-Place (GIIP) within the Goddard structure and to de-risk
the Goddard Flank structures. The results of the appraisal well will enable
the Company to determine the optimum field development scenario, including
well count, to maximise the return on investment from commercialisation.
On 3 May 2022, the Initial Term of Licence P2438 (Goddard) was extended by 12
months to 30 September 2023, to allow the drilling and completion of the
Goddard appraisal well within the appropriate licence term. In early 2023, in
light of unexpected delays to the Phase 1 development drilling programme,
IOGNSL formally requested a six-month extension to the Initial Term of Licence
P2438 so that the drilling and completion of the appraisal well could be
undertaken within the appropriate licence term. The extension request is under
consideration by the NSTA at the time of this report.
Seismic reinterpretation has also identified the Southsea prospect within
Licence P2438 close to the south-east of Goddard, with gross management
estimated prospective resources of Low/Mid/High 13/31/76 BCF and a 48% GCOS.
The results of the Goddard appraisal well may inform an update to these
estimates.
Grafton and Panther (P2589)
The P2589 licence was awarded in the 32(nd) Licensing Round and formally
commenced on 1 December 2020. The licence commitment to reprocess 79km2 of
seismic data within three years has been completed. Under the licence, a
decision must be taken in 2023 either to drill an appraisal well on the
licence by 30 November 2025 or relinquish the licence.
The licence contains the Grafton discovery, for which management's initially
estimated gross 1C/2C/3C contingent gas resources of 24/35/46 BCFE has not
changed to date. IOG has completed a programme of 3D seismic reprocessing to
PSDM standard, from which data is currently being interpreted. This includes a
more sophisticated depth conversion and mapping work programme than previously
undertaken and should enable a clearer view of the commercial potential across
the licence.
The licence also contains the Panther discovery which lies approximately 5km
northwest of Elland. Subject to interpretation of reprocessed seismic, could
potentially form part of the Central Hub development. Pending reinterpretation
of reprocessed seismic, management's estimate of gross 1C/2C/3C contingent gas
resources remains at 38/46/55 BCFE.
Business Development
The Company takes a systematic focused approach to screening opportunities to
enhance its asset portfolio and further develop the business. All
opportunities are evaluated in terms of fundamental value, potential return,
materiality and synergy with the existing portfolio, ranked alongside the
Company's existing assets. The fundamental purpose is to generate enhanced
stakeholder value over time, rather than simply to build a bigger business.
There are several different types of possible acquisition opportunities
continually evaluated by management, each with potential to generate operating
and economic synergies with the existing portfolio. The first of these is
licensing activity, whether in formal licence rounds or by separation
engagement with the OGA, which offers a well-established and low-cost path to
adding suitable incremental assets. The Company has an extensive track record
of successful licence round applications, including the 27(th), 30(th) and
32(nd) UK Offshore Licensing Rounds. However, licensing rounds are relatively
infrequent and not guaranteed to include the most attractive licences,
therefore out-of-round applications and expressions of interest are also
considered valid approaches to acquiring suitable unlicensed acreage.
In addition, there may be at any given time potential acquisitions from other
licensees and operators who may be interested in either selling or farming-out
assets at various stages of maturity, including appraisal, development or also
previously developed shut-in or decommissioned assets. The Company undertakes
a systematic ongoing review of all such opportunities to ensure it can
prioritise those it may wish to pursue. Furthermore, the Company also
discusses potential gas transportation tariffing opportunities and engages
with parties who may be seeking access to export infrastructure as part of
their own development planning.
In January 2023, after a rigorous technical and commercial screening process,
IOG and its joint venture (JV) partner CalEnergy Resources (UK) Limited (CER)
applied for nine Southern North Sea blocks across five licences in the 33rd UK
Offshore Licensing Round. All applications are adjacent to existing Saturn
Banks JV licences. All on a 50:50 IOG-CER basis with IOG as operator, as per
the JV's Area of Mutual Interest agreement. These applications exhibit strong
synergies with the Saturn Banks portfolio and infrastructure: all licences
would fit clearly within IOG's area plan. Each licence contains discovered
resources that could be added to development hubs. Some have field
redevelopment opportunities and some have near-field exploration potential.
The UK North Sea Transition Authority is expected to start making the first
33rd Round licence awards in Q2 2023.
Key Performance Indicators
The Group's main business is the acquisition, development and production of
gas reserves and resources in a safe, efficient and environmentally
responsible manner. This is undertaken by assembling and managing a carefully
selected portfolio of licence interests containing a range of prospective,
contingent and proven reserves, working these up from a technical perspective,
planning, designing and executing appropriate appraisal, pre-development and
development activities and ensuring effective ongoing production operations.
The Company monitors its performance against its primary HSE and ESG KPIs,
which are the Total Recordable Incident Rate (Lost Time Incidents per 200,000
manhours worked) and Scope 1 and 2 emissions and emissions intensity. Other
HSE performance indicators include securing all relevant environmental
permits, consent and approvals, and maintaining a verified Environmental
Management System.
The main operational KPIs include production rates as well as the total
reserves and resources in the portfolio. Other operational performance
indicators include successfully meeting all licence commitments relating to
the Company's asset portfolio during the year, maintaining effective
relationships at all levels with JV partners in compliance with Joint
Operating Agreements (JOAs), operating within appropriate governance and HR
policies, ensuring the Company has adequate in-house capability to manage its
operations and third-party providers, and ensuring all corporate legal
obligations are met.
Financial performance is tracked against established metrics and budgets which
are set according to carefully assessed cost estimates and the availability of
funds, whether raised from capital providers or delivered from operations,
with the overriding objective of creating value per share. The main financial
KPIs include unit operating cost i.e. opex (measured either in the standard
industry metric of US dollars per barrel of oil equivalent to ensure
comparability or more relevantly to IOG in pence per therm), operating cash
flow and net debt. Financial performance indicators also include maintaining
full compliance with terms of debt facilities, maintaining constructive
relationships with debt providers and equity investors, being adequately
resourced for all corporate and JV-related financial matters, maintaining
appropriate fit-for-purpose finance systems, delivering approved annual
budgets and adhering to updated financial and corporate operating policies.
Insurance
The Group insures the risks it considers appropriate and proportionate for its
needs and circumstances, including any risks that it has an obligation to
insure against. However, it may elect not to put insurance in place at certain
times for certain risks, for example due to high premium costs or extremely
low probability risks. During 2021 the Group put in place insurance coverage
for both construction and operational energy packages, covering Operators
Extra Expense (OEE) during drilling activities, physical loss/damage, third
party liability and OPOL in accordance with market standards. This insurance
coverage and associated limits were in line with its energy sector peer group.
Principal Risks and Uncertainties
The Company seeks to generate shareholder returns by developing and producing
its portfolio of offshore gas assets. This primarily entails construction and
installation of production, transportation and processing infrastructure and
drilling of production wells. These activities carry a number of associated
financial, operational, regulatory, legal, commercial, human resource, HSE and
sustainability related risks and uncertainties. The most pertinent corporate
risks and associated mitigations are set out below.
Risk Mitigation
Poor strategic decisions · Annual review of business plan & objectives
· Regular review of progress against objectives
· Regular lessons learned reviews
· Match Corporate Scorecard to business plan
· Regular review of organic investments and assumptions
· Regular review of M&A criteria & targets within strategic
boundaries
Corporate governance deficiency · Regular review of legislation and gap analysis with internal
compliance policies
· Annual training on corporate policies & procedures, covering
Financial Operations, Anti-Bribery & Corruption, Travel & Expenses,
Sustainability, and Insider Trading
· Tender Committee meetings to ensure policy compliance on
contracting
Undervalued market capitalisation · Ensure company strategy and progress presented as effectively as
possible in public materials
· Continually engage with and present to existing and prospective
investors where possible
· Maintain defence planning with appropriate advisors
Negative cash flow · Develop multiple business scenarios to determine cash flow
restrictions
· Develop cost reduction action plans
· Develop additional funding options
Inability to repay or refinance bond and/or comply with covenants · Close monitoring of liquidity position and cash flow projections
to manage exposures
· Tight cost control and working capital management
· Regular review of potential financing options to ensure state of
preparedness
· Regular engagement with the Company's debt providers and
advisors
· Maintain access to equity markets via AIM listing
Reduction or loss of reserves · Implement rigorous reserve and resource range assessment process
· Use third-party technical verification & peer reviews
· Use full reserves & profile range for project economics
· Accurate history matching to understand reservoir performance
& improve forecasts
· Ensure highly competent technical team
· Develop active lessons learned data base
Reduction or loss of production · Monthly reviews of all key topics (HSE, maintenance, integrity,
costs)
· Production loss and improvement process
· Robust oversight of duty holder via assurance plans for
production operations & pipeline management
· Deliver incremental production plans (e.g. Blythe H2)
· Add support for Production Asset Manager
· Detailed reviews of fixed opex and G&A
Underperformance of projects · Ensure project has clear business objectives
· Ensure project gate process is followed
· Regularly review economics, subsurface, engineering and designs
· Ensure project risks & mitigations, cost estimates &
schedule are fully understood
· Regular peer reviews and economic stress tests
· Maintain strong development team competencies and ensure clear
project ownership
Saturn Banks Pipeline System failure · Duty holder monthly reviews and surveillance on key topics (HSE,
reliability, maintenance and integrity)
· Robust oversight of duty holder through assurance plans for
production operations and pipeline management
Inability to attract and retain personnel with the right skills and experience · Maintain a clear, credible strategy to build a sustainable,
profitable and attractive business
· Identify key individuals required to deliver the strategy
effectively
· Ensure competitive remuneration packages and professional
development plans are in place
Loss of licences and/or regulatory licence to operate · Robust oversight of all areas of project delivery
· Maintain resources, processes, competencies to deliver licence
obligations
· Regular interaction with NSTA, BEIS/OPRED & HSE at all
levels
· Set realistic expectations with regulators
· Follow all NSTA guidance
· Compelling case & timely application for any license
extensions or variations
· Timely licence fee/levy payments
· Maintain robust licence commitments register
Government energy, licensing or fiscal policy changes · Maintain a low-cost business model
· Maintain a low-carbon intensity business and continue to offset
as necessary for Scope 1 & 2 Net Zero status
· Engage with government and industry bodies to demonstrate
company's contribution to UK energy
Gas price volatility · Short term price fixing with offtaker
· Maintain a low-cost business model
· Continue to track gas market trends and analysis
· Continue to take advice from gas market analysts
Finance Review
Following First Gas in March 2022, the Company moved into a revenue generation
phase of its development. Total revenue generated in the year, before sales
deductions, was £79.6 million, of which £76.0 million related to gas sales
and £3.6 million related to condensate sales. Total revenue after sales
deductions was £75.4 million. Cost of sales totalled £23.6 million
consisting of £10.1 million of operating running costs, depletion of £13.2
million and other operating expenditure of £0.4 million, offset by an
increase in inventories of £40,000. Gross unit operating costs (excluding
one-off and exceptional items) for the period were therefore 24.0 p/therm.
This resulted in a gross profit of £51.8 million.
Despite the commencement of production and initial revenues during the year,
the disappointing result from the Southwark A2 well and consequent downward
revision in reserves at Southwark, Nailsworth and Elland resulted in a £51.0
million impairment. This, coupled with the £11.4 million deferred tax
liability due to the Energy Profits Levy which was introduced during 2022,
contributed to a full-year net loss after tax of £28.4 million.
The Company ended the year with an unrestricted cash balance of £26.7 million
(2021: £31.3 million) plus £5.7 million of restricted cash (2021: £3.4
million), £2.6 million of which is the minimum holding of Bond interest in
the DSRA and £3.1 million of which is decommissioning security. Group net
debt at the end of the year was £65.1 million (2021: £56.6 million) (see
note 18).
The €100 million bond (see below) and £11.6 million long-term, unsecured,
non-interest-bearing Loan Note Instrument, convertible at 19p into 60,872,631
Ordinary Shares, both remained in place, with maturity dates in September
2024.
Income Statement
The Group made a loss for the year of £28.4 million (2021: £2.4 million
loss) after asset impairments of £51.0 million.
Gas revenues for 2022 were £76.0 million (2021: £nil) and condensate
revenues were £3.6 million (2021: £nil). Net gas revenues are £71.8 million
(2021: £nil) inclusive of £4.2 million of sales deductions (2021: £nil).
Total cost of sales was £23.6 million, consisting of operating expenditure
(opex) of £10.1 million (2021: £nil), depletion of £13.2 million (2021:
£nil), £0.4 million of other operating costs offset by an increase in
inventory of £40,000. Accrued opex in the period included £8.2 million of
production opex and £1.9 million of onshore tariffs and SBRF operating costs,
which equated to gross unit operating costs (excluding one-off and exceptional
items) of 24.0 p/therm. Cash opex was 13.9 p/therm, as the Group looked to
manage the produced water onshore and identify lower cost disposal routes.
This resulted in a gross profit of £51.8 million.
Operating loss for the period of £6.0 million includes £1.9 million of
administration expenses, £51.0 million of impairment, £0.2 million of
project, pre-licence and exploration expenses, and £4.7 million FX loss.
Reduction in 2P reserves over the Southwark development resulted in a £43.4
million impairment (2021: £0.9 million). The Nailsworth and Elland gas
fields, which are envisaged to be part of a Central Hub development north of
Southwark, have been reclassified as 2C contingent resources resulting in a
write down of £7.6 million (2021: £nil). Net administration expenses of
£1.9 million (2021: £2.1 million) reflect a lean corporate operation and the
allocation of a proportion of overheads to project assets.
The foreign exchange loss of £4.7million (2020: £3.4 million gain) reflects
realised and unrealised foreign exchange movements predominantly on the EUR
denominated Bond and the USD denominated rig contract recognised under lease
liabilities.
The total interest charged to the income statement was £11.1 million (2021:
£3.1 million). The increase of £8.0 million was mainly due to additional
interest expensed in the year, after capitalisation to qualifying assets, on
the bonds of £6.9 million (2021: £nil). The Bond interest attributable to
bringing capital projects on stream was capitalised in line with Company's
accounting policy. After the start of production in March 2022, the Bond
interest is being expensed. This resulted in a loss before taxation of £17.1
million.
The Group recognised a deferred tax liability of £11.4 million in 2022
following the introduction of an Energy Profits Levy (EPL) on the UK ring
fence profits of oil and gas producers with effect from 26 May 2022 and
reflects the exclusion of investment in the UK North Sea prior to this date
contained within the legislation. The Group therefore recognised a loss after
tax of £28.4 million (2021: £2.4 million).
On this basis, earning per share (EPS) were minus 5.4p. Adjusted EPS, removing
the impact of the asset impairments, were 4.3p.
Statement of financial position
Property, Plant and Equipment (PPE) oil and gas assets increased to £149.8
million (2021: £138.8 million) during the year, representing capital
expenditure activities on the Saturn Banks Project assets as well as
capitalisation of the right of use of leased assets over their lease term
under IFRS 16 and an increase in the decommissioning provision recognised
against the assets, partially offset by depletion of the producing assets and
the impairment of the Southwark field.
Total assets increased to £206.5 million (2021: £181.1 million), including
cash resources of £32.4 million (2021: £34.7 million) of which £5.7 million
is restricted (2021: £3.4 million).
Total liabilities have increased to £203.9 million (2021: £151.0 million),
with the Bond representing £ 87.6 million (2021: £82.4 million). Current
liabilities include trade payables of £11.1 million (2021: £7.7 million),
lease liabilities of £15.8 million (2021: £11.1 million), accruals and
operator advance accounts of £36.9 million (2021: £23.7 million) given the
high volume of work as the Phase 1 development progressed, and deferred
considerations in relation to acquisitions of £0.8 million (2021: £0.6
million).
Under IFRS 16, IOG is responsible for capitalising 100% of the lease cost of
its rig contract as well as certain vessel contracts, to its statement of
financial position. Based on the minimum contract durations and day-rates, IOG
has therefore recognised £12.2 million in Property, Plant and Equipment
(PP&E). IFRS 16 also requires recognition of the lease liability for
future payment obligations and interest on lease liabilities in the income
statement over the lease term. Based on the minimum contract duration and
day-rate, IOG has therefore recognised £15.8 million (net liability after
payments) in lease liabilities.
Non-current liabilities include decommissioning provisions net to IOG of
£29.8 million (2021: £15.8 million), including Saturn Banks Pipeline
decommissioning provision of £4.4 million (2021: £0.1 million), Saturn Banks
Reception Facilities decommissioning provision of £2.8 million and the
addition of further Phase 1 infrastructure of £22.5 million (see note 17).
Non-current liabilities also include long-term lease liabilities recognised
under IFRS 16 of £1.3 million (2021 £11.1 million) related to the Saturn
Banks Pipeline land lease and office leases, and a deferred tax liability
recognised following the introduction of the EPL of £11.4 million (2021:
£nil). This resulted in net assets of £2.6 million (2021: £30.2 million),
with the decrease predominantly driven by the impairment on Southwark during
the year.
The Group ended the year with a net debt position of £65.1 million (2021:
£56.6 million), primarily driven by the ongoing expenditure on the Phase 1
assets. Net debt is defined as total loans, primarily the EUR denominated
Bond, less restricted cash and cash equivalents.
Cash Flow
Net cash inflows of £71.8 million (2021: £20.0 million inflow) from
operations, net cash outflow of £49.6 million (2021: £3.6 million inflow)
used in investing activities and net cash outflow of £27.2 million (2021:
£8.2 million) used in financing resulted in a cash and equivalents position
of £26.7 million at year end (2021: £31.3 million). The increase of £71.8
million for cash generated by operations reflects the transition to a
production phase for the Company. At the end of the year £5.7 million (2021:
£3.4 million) of funds were also held as restricted cash in the DSRA and as
decommissioning security.
The Directors do not recommend payment of a dividend (2021: nil).
€100 million Bond
The Group's €100 million 5-year senior secured Bond was issued in 2019 in
the name of Independent Oil and Gas plc (the former name for the Company) to a
range of institutional investors across the Nordic region, Europe, UK and
Asia. The bond has a bullet repayment structure, with a maturity date of 20
September 2024, and an interest rate, payable quarterly, of 9.5 per cent per
annum over the three-month EURIBOR rate. The Bond has a senior secured
position over the Group's licences and infrastructure assets, as well as any
further licence in which the Group takes an ownership interest during the
tenure of the Bond. Permitted use of funds are Phase 1 capital expenditure,
financing costs and general corporate purposes.
The Bond has been listed since December 2019 on the Oslo Børs with the ISIN
NO0010863236. It is callable from September 2022, with an initial call premium
of 50% of the coupon (i.e. repayable at a cost of €104.75 million (£88
million) if the three month EURIBOR is at zero or lower), declining by 10%
every six months thereafter. The Bond documentation includes the option,
subject to conditions and investor appetite, to issue additional amounts up to
a maximum aggregate of €30 million (£25.2 million) ("Tap Issues"). Tap
Issues carry identical terms to the initial €100 million issue but may be
issued at different prices.
Commodity Risk Management Policy
The fundamental principle of the Group's commodity risk management policy is
to take a prudent approach to mitigating exposure to fluctuations in gas
prices and/or currencies to best protect cash flows. The Group will enter into
price fixing transactions only to manage genuine risks to cash flows,
factoring in relevant economic data and reasonable projections of its
production, costs and debt service profile, and never for the purposes of
investment or speculation. Commodity and foreign exchange (FX) exposures are
overseen by a Risk Management Committee (RMC) and decisions are taken by a
quorum of this RMC, which must include the CFO (with a second Executive
Director also required to approve transactions with a nominal value over a
certain threshold).
Over certain months in 2022, the Group fixed month ahead gas prices under its
gas sales agreement with BPGM, the designated gas offtaker, at a volume of
30,000 therms/day, as follows:
August 2022 310 p/therm
September 2022 444 p/therm
October 2022¹ 263 p/therm
December 2022 303 p/therm
At the current time, the Company expects to continue to fix prices for an
appropriate proportion of its production with BPGM. Details of the risks
arising from the Group's use of financial instruments can be found in Note 24
to the financial statements.
¹October 2022 price fix was closed out mid-month in light of the requirement
to temporarily suspend production in order depressurise the Saturn Banks
Pipeline System at that time.
Funding & Liquidity
The financial statements of the Group are prepared on a going concern basis.
In undertaking a going concern review, the Directors have given careful
consideration to the Group's financial projections prepared by management for
the period to 31 March 2024 (the review period). The Directors have also
considered significant known events beyond 31 March 2024. The projections
reflect the Company's best estimate of expenditures and receipts for the
period. The Directors have reviewed management's key assumptions on which
these projections are based, including a downside price and other risking
scenarios. The near-term cash forecasts are regularly updated and reviewed to
enable continuous monitoring and management of the Group's cash flow and
liquidity risk. The forecasts indicate that, including the expectation that
the Company can amend capital commitments under some of its licences and
taking into account other cost saving and capital management initiatives, the
Group has sufficient capital resources for a period of 12 months from the date
of approval of this annual report. The Group's debt matures in September 2024
and the forecasts currently show that the Group plans to refinance its debt.
As part of its analysis in making the going concern assumption, the Directors
have considered the range of risks facing the business on an ongoing basis, as
set out in the risk section of this Annual Report. The principal assumptions
made in relation to the going concern assessment include the continued
production from the Blythe H-1 well, the successful delivery of the Blythe H-2
well and subsequent gas production rates, the potential evolution of gas
prices and potential future capital allocations on its operated assets in the
UK Southern North Sea.
Following a disappointing result from the Southwark A2 well test and
remediation programme, the Company, in conjunction with its joint venture
partner CER, sanctioned the drilling of Blythe H-2, prioritising it ahead of
Southwark A1 as a lower risk option. Gas rates from H2 are expected to
initially be in the 30-40 mmscf/d range and the well is expected to be
completed and producing within a period of approximately three months from the
spud date of 5 March.
The Company takes regular external advice on gas price forecasts. The base
case uses the forward curve for near-term gas prices. The average gas price
used in the review period is 130p/therm. Since the end of 2022 gas prices have
fallen over 20%. This sustained fall in gas price during the review period
would result in a covenant breach in the interest cover ratio. At the year end
forward curve prices, no covenant breach was forecast. The Company's €100
million bond is subject to covenants that are measured biannually in June and
December, being minimum liquidity of €5 million, net debt to EBITDA of a
maximum of 2.5x and interest cover of a minimum of 5.0x, based on measures as
defined in the facility agreement. The ratio of net debt to EBITDA at 31
December 2022 was 1.1 times and interest cover was 7.0 times. In the downside
case, where gas prices are assumed to be 50% below the current forward curve,
both the leverage ratio and interest cover ratio are forecast to be breached.
In the event that a covenant is breached, an extension or waiver of this
covenant would need to be negotiated with the Bond Trustee. The Directors,
taking into account their assessment of Bondholders' interests and given the
Group would pass the minimum liquidity test, believe this would be likely to
be achieved, however it is not guaranteed.
The forecast also indicates in the base case the Group would need to minimise
capital expenditures in the review period. This may include the requirement to
agree revised work programmes or licence commitments with the UK authorities
on licences where the Group has capital commitments as well as discretionary
expenditures. If the Company is unsuccessful in agreeing revised terms this
may result in the need to raise alternative funds on whatever terms are
available at the time.
The Directors have concluded that the uncertainty around the volatility of the
gas price and future production levels from the Blythe H-2 well, as well as
the need to take other mitigating actions described above represent a material
uncertainty which may cast significant doubt on the Group's ability to
continue as a going concern.
As a result of their review, and despite the aforementioned material
uncertainty, the Directors have confidence in the Group's forecasts and have a
reasonable expectation that the Group will continue in operational existence
for the going concern review period and have therefore used the going concern
basis in preparing these consolidated financial statements.
John Arthur
Chief Financial Officer
15 March 2023
Consolidated Statement of Comprehensive Income for the Year Ended 31 December
2022
Notes 2022 2021
£000 £000
Revenue 3 75,406 -
Cost of Sales 4 (23,641) -
_________ _________
Gross Profit 51,765 -
Administration expenses 5 (1,879) (2,102)
Impairment of oil and gas properties 11 (51,007) (865)
Project, pre-licence and exploration expenses (182) (104)
Foreign exchange (loss) / gain 5 (4,736) 3,440
_________ _________
Operating (Loss) / Profit 5 (6,039) 369
Finance expense 7 (11,114) (3,066)
Finance income 70 29
Fair value gain - 260
Loss on PPE disposal (4) -
_________ _________
Loss for the year before taxation (17,087) (2,408)
Taxation 8 (11,362) -
_________ _________
Loss and total comprehensive loss for the year attributable to equity holders 9 (28,449) (2,408)
of the parent
_________ _________
Loss for the year per ordinary share - basic 9 (5.4p) (0.4p)
The loss for the year of £28.4 million (2021: £2.4 million loss) arose from
continuing operations.
The comparative amounts have been restated. For more details refer to note 1.
Consolidated and Company Statements of Changes in Equity for the Year Ended 31
December 2022
Share-based payment reserve
Share Share premium Accumulated losses Total
capital equity
Group: £000 £000 £000 £000 £000
At 1 January 2021 4,882 49,989 6,154 (38,227) 22,798
Loss for the year - - - (2,408) (2,408)
_____ _______ _______ ________ _______
Total comprehensive loss attributable to owners of the parent - - - (2,408) (2,408)
Issue of shares 338 8,112 8,450
Share based payment charge - - 1,272 - 1,272
Expiry of share options - - (20) 230 210
Exercise of share options 18 48 (210) - (144)
_____ _______ _______ ________ _______
At 31 December 2021 5,238 58,149 7,196 (40,405) 30,178
Loss for the year - - - (28,449) (28,449)
_____ _______ _______ ________ _______
Total comprehensive loss attributable to owners of the parent - - - (28,449) (28,449)
Share based payment charge - - 826 - 826
Expiry of share options - - (630) 630 -
Exercise of share options 12 24 (187) 187 36
_____ ______ _______ ________ _______
At 31 December 2022 5,250 58,173 7,205 (68,037) 2,591
_____ ______ _______ ________ _______
Company:
At 1 January 2021 4,882 49,989 6,154 (16,681) 44,344
Total comprehensive loss attributable to owners of the parent - - - (1,785) (1,785)
Lapse of warrants 338 8,112 - - 8,450
Share based payment charge - - 1,272 - 1,272
Expiry of share options - - (20) 230 210
Exercise of share options 18 48 (210) - (144)
_____ ______ ______ ________ _______
At 31 December 2021 5,238 58,149 7,196 (18,236) 52,347
Loss for the year - - - (17,561) (17,561))
_____ ______ ______ ________ _______
Total comprehensive loss attributable to owners of the parent - - - (17,561) (17,561)
Issue of Share Capital - - - - -
Share based payment charge - - 826 - 826
Expiry of share options - - (630) 630 -
Exercise of share options 12 24 (187) 187 36
_____ ______ _____ _______ _______
At 31 December 2022 5,250 58,173 7,205 (34,980) 35,648
_____ _______ ______ _______ _______
The comparative amounts have been restated. For more details refer to note 1.
Consolidated Statement of Financial Position at 31 December 2022
Notes 2022 2021
£000 £000
Non-current assets
Intangible assets: exploration & evaluation 10 3,161 994
Intangible assets: other 10 8 75
Property, plant and equipment: development & production assets 11 149,830 138,805
Property, plant and equipment: other 11 12,158 4,872
Restricted Cash 21 3,116 -
_________ _________
168,273 144,746
Current assets
Inventories 63 -
Trade and other receivables 15 8,906 1,705
Restricted cash 21 2,564 3,429
Cash and cash equivalents 21 26,693 31,255
_________ _________
38,226 36,389
_________ _________
Total assets 206,499 181,135
Current liabilities
Trade and other payables 16 (64,058) (43,468)
________ _________
(64,058) (43,468)
_________ _________
Non-current liabilities
Loans 17 (97,437) (91,257)
Provisions 17 (29,778) (15,837)
Other liabilities 17 (1,273) (395)
Deferred tax liability 8 (11,362) -
_________ _________
(139,850) (107,489)
_________ _________
Total liabilities (203,908) (150,957)
_________ _________
NET ASSETS 2,591 30,178
_________ _________
Capital and reserves
Share capital 19 5,250 5,238
Share premium 19 58,173 58,149
Share-based payment reserve 7,205 7,196
Accumulated losses (68,037) (40,405)
_________ _________
2,591 30,178
_________ _________
The comparative amounts have been restated. For more details refer to note 1.
The Notes below form part of these financial statements. The financial
statements were approved and authorised for issue by the Board of Directors on
15 March 2023 and are signed on its behalf by:
Rupert Newall
Chief Executive Officer
15 March 2023
Company Statement of Financial Position at 31 December 2022
Notes 2022 2021
£000 £000
Non-current assets
Intangible assets 10 8 75
Property, plant and equipment: Other 11 12,158 4,872
Investments 13 15,486 15,486
Amounts due from subsidiaries 13 104,457 109,641
_________ _________
132,109 130,074
_________ _________
Current assets
Other receivables and prepayments 15 568 1,705
Restricted cash 21 2,564 2,066
Cash and cash equivalents 21 26,693 31,255
_________ _________
29,825 35,026
_________ _________
Total assets 161,934 165,100
Current liabilities
Trade and other payables 16 (27,576) (21,101)
Non-current liabilities
Loans 17 (97,437) (91,257)
Other liabilities 17,23 (1,273) (395)
_________ _________
(98,710) (91,652)
_________ _________
Total liabilities (126,286) (112,753)
_________ _________
NET ASSETS 35,648 52,347
_________ _________
Capital and reserves
Share capital 19 5,250 5,238
Share premium 19 58,173 58,149
Share-based payment reserve 7,205 7,196
Accumulated losses (34,980) (18,236)
_________ _________
35,648 52,347
_________ _________
The comparative amounts have been restated. For more details refer to note 1.
The Company has taken advantage of the exemption allowed under Section 408 of
the Companies Act 2006 and has not presented its own Statement of
Comprehensive Income in these financial statements. The Company loss for the
year was £17.6 million (2021: restated £1.8 million loss).
The notes below form part of these financial statements.
The financial statements of IOG plc (Company number: 07434350) were approved
and authorised for issue by the Board of Directors on 15 March 2023 and are
signed on its behalf by:
Rupert Newall
Chief Executive Officer
15 March 2023
Consolidated Cash Flow Statement for the Year Ended 31 December 2022
Notes 2022 2021
£000 £000
Loss for the year (28,449) (2,408)
Depreciation, depletion and amortisation 11 13,050 519
Exploration asset write off 10 - 865
Impairment of development & production assets 11 51,007 -
Share based payments 817 1,225
Fair value (gain) / loss - (260)
Interest received (70) (18)
Deferred tax charge 8 11,362 -
Finance expense 7 11,114 3,066
Effect of exchange rate changes on Bond 4,620 (5,901)
Movement in trade and other receivables (6,993) (732)
Movement in trade and other payables 15,393 23,641
Movement in Inventory (63) -
_________ _________
Net cash generated from operating activities 71,788 19,997
Investing activities
Purchase of development & production assets (45,955) (58,269)
Purchase of exploration & evaluation assets (1,467) (506)
Purchase of intangible assets: other (39) (295)
Transfers (to) / from restricted cash (2,251) 61,172
Interest received 70 18
Decrease in financial assets - 1,520
_________ _________
Net cash (used in) / generated from investing activities (49,642) 3,640
Financing activities
Proceeds from issue of equity instruments of the Group 36 8,516
Lease liability payments 23 (18,608) (12,307)
Interest paid (8,590) (4,441)
Other finance costs paid (11) -
_________ _________
Net cash used in financing activities (27,173) (8,232)
Net (decrease) / increase in cash and cash equivalents (5,027) 15,405
Cash and cash equivalents at the beginning of the year 31,255 13,389
Effects of exchange rate changes on cash and cash equivalents 465 2,461
_________ _________
Cash and cash equivalents at end of year 21 26,693 31,255
_________ _________
The Notes below form part of these financial statements.
Company Cash Flow Statement for the Year Ended 31 December 2022
Notes 2022 2021
£000 £000
Loss for the year (17,561) (1,785)
Depreciation charges 178 519
Exploration asset write off - -
Share based payments 817 1,225
Fair value (gain) / loss - (260)
Interest received / (paid) (51) (5)
Finance expenses 10,613 3,280
Effect of exchange rate changes in Bond 4,620 (5,901)
Movement in trade and other receivables 1,137 761
Movement in trade and other payables 17,579 23,591
_________ _________
Net cash generated from operating activities 17,332 21,425
Investing activities
Purchase of property, plant and equipment (45) (253)
Transfers (to) / from restricted cash (377) 61,172
Loans to subsidiary undertakings (63,749) (60,247)
Repayments of loans from subsidiary undertakings 68,933 -
Interest received 51 5
Decrease in financial assets - 1,520
_________ _________
Net cash generated from investing activities 4,813 2,198
Financing activities
Proceeds from issue of equity instruments of the Company 36 8,516
Lease liability payments 23 (18,608) (12,307)
Interest paid (8,590) (4,441)
Finance Other finance costs paid 7 (11) -
_________ _________
Net cash used in financing activities (27,173) (8,232)
Net (decrease) / increase in cash and cash equivalents (5,028) 15,391
Cash and cash equivalents at the beginning of the year 31,255 13,389
Effects of exchange rate changes on cash and cash 466 2,475
Equivalents
_________ _________
Cash and cash equivalents at end of year 21 26,693 31,255
_________ _________
The Notes below form part of these financial statements
Notes forming part of the financial statements for the Year Ended 31 December
2022
1 Statement of Accounting Policies
General information
IOG plc (the "Company") is a public limited company incorporated and domiciled
in England and Wales. The principal activities of the Group are the appraisal,
development and production of gas assets, reserves and resources. The Group
operates through subsidiary undertakings, details of which are set out in note
14 to the financial statements. The Group's area of activity is in the United
Kingdom. The Group financial statements for the year ended 31 December 2022
consolidate the individual financial statements of the Company and its
subsidiaries (together referred to as "the Group"). The registered office
address is 6(th) Floor, 60 Gracechurch Street, London EC3V 0HR.
The Group's and Company's financial statements for the year ended 31 December
2022 were authorised for issue by the Board of Directors on 15 March 2023 and
the balance sheets were signed on the Board's behalf by the CEO, Rupert
Newall.
Basis of preparation
The principal accounting policies adopted in the preparation of the financial
statements are set out below. The policies have been consistently applied to
all years presented, unless otherwise stated. The consolidated financial
statements are presented in GBP Sterling, which is also the functional
currency of the Group. Amounts are rounded to the nearest thousand, unless
otherwise stated.
These financial statements have been prepared in accordance with UK adopted
International Accounting Standards and as applied in accordance with the
provisions of the Companies Act 2006. On 31 December 2020, IFRS as adopted by
the European Union at that date was brought into UK law and became UK-adopted
international accounting standards, with future changes being subject to
endorsement by the UK Endorsement Board. The preparation of financial
statements in compliance with adopted IFRSs requires the use of certain
critical accounting estimates. It also requires management to exercise
judgment in applying the Group's accounting policies. The areas where
significant judgments and estimates have been made in preparing the financial
statements and their effect are disclosed within this note 1.
The consolidated financial statements have been prepared on a historical cost
basis except for the valuation of hydrocarbon inventories.
Going concern
The financial statements of the Group are prepared on a going concern basis.
In undertaking a going concern review, the Directors have given careful
consideration to the Group's financial projections prepared by management for
the period to 31 March 2024 (the review period). The Directors have also
considered significant known events beyond 31 March 2024. The projections
reflect the Company's best estimate of expenditures and receipts for the
period. The Directors have reviewed management's key assumptions on which
these projections are based, including a downside price and other risking
scenarios. The near-term cash forecasts are regularly updated and reviewed to
enable continuous monitoring and management of the Group's cash flow and
liquidity risk. The forecasts indicate that, including the expectation that
the Company can amend capital commitments under some of its licences and
taking into account other cost saving and capital management initiatives, the
Group has sufficient capital resources for a period of 12 months from the date
of approval of this annual report. The Group's debt matures in September 2024
and the forecasts currently show that the Group plans to refinance its debt.
As part of its analysis in making the going concern assumption, the Directors
have considered the range of risks facing the business on an ongoing basis, as
set out in the risk section of this Annual Report. The principal assumptions
made in relation to the going concern assessment include the continued
production from the Blythe H-1 well, the successful delivery of the Blythe H-2
well and subsequent gas production rates, the potential evolution of gas
prices and potential future capital allocations on its operated assets in the
UK Southern North Sea.
Following a disappointing result from the Southwark A2 well test and
remediation programme, the Company, in conjunction with its joint venture
partner CER, sanctioned the drilling of Blythe H-2, prioritising it ahead of
Southwark A1 as a lower risk option. Gas rates from H2 are expected to
initially be in the 30-40 mmscf/d range and the well is expected to be
completed and producing within a period of three months from the spud date of
5(th) March.
The Company takes regular external advice on gas price forecasts. The base
case uses the forward curve for near-term gas prices. The average gas price
used in the review period is 130p/therm. Since the end of 2022 gas prices have
fallen over 20%. This sustained fall in gas price during the review period
would result in a covenant breach in the interest cover ratio. At the year end
forward curve prices, no covenant breach was forecast. The Company's €100
million bond is subject to covenants that are measured biannually in June and
December, being minimum liquidity of €5 million, net debt to EBITDA of a
maximum of 2.5x and interest cover of a minimum of 5.0x, based on measures as
defined in the facility agreement. The ratio of net debt to EBITDA at 31
December 2022 was 1.0 times and interest cover was 7.0 times. In the downside
case, where gas prices are assumed to be 50% below the current forward curve,
both the leverage ratio and interest cover ratio are forecast to be breached.
In the event that a covenant is breached, an extension or waiver of this
covenant would need to be negotiated with the Bond Trustee. The Directors,
taking into account their assessment of Bondholders' interests and given the
Group would pass the minimum liquidity test, believe this would be likely to
be achieved, however it is not guaranteed.
The forecast also indicates in the base case the Group would need to minimise
capital expenditures in the review period. This may include the requirement to
agree revised work programmes or licence commitments with the UK authorities
on licences where the Group has capital commitments as well as discretionary
expenditures. If the Company is unsuccessful in agreeing revised terms this
may result in the need to raise alternative funds on whatever terms are
available at the time.
The Directors have concluded that the uncertainty around the volatility of the
gas price and future production levels from the Blythe H-2 well, as well as
the need to take other mitigating actions described above represent a material
uncertainty which may cast significant doubt on the Group's ability to
continue as a going concern.
As a result of their review, and despite the aforementioned material
uncertainty, the Directors have confidence in the Group's forecasts and have a
reasonable expectation that the Group will continue in operational existence
for the going concern review period and have therefore used the going concern
basis in preparing these consolidated financial statements.
Change in accounting policies
i) New accounting standards, interpretations and amendments effective from 1
January 2022
A number of new or amended standards became applicable for the current
reporting period. The Group did not have to change its accounting policies or
make retrospective adjustments as a result of adopting these standards.
· Onerous Contracts - Cost of Fulfilling a Contract (Amendments to
IAS 37);
· Property, Plant and Equipment: Proceeds before Intended Use
(Amendments to IAS 16);
· Annual Improvements to IFRS Standards 2018-2020 (Amendments to
IFRS 1, IFRS 9, IFRS 16 and IAS 41); and
· References to Conceptual Framework (Amendments to IFRS 3).
ii) New standards, interpretations and amendments not yet effective
There are a number of standards, amendments to standards, and interpretations
which have been issued by the IASB that are effective in future accounting
periods that the Group has decided not to adopt early.
The following amendments are effective for the period beginning 1 January
2023:
· Disclosure of Accounting Policies (Amendments to IAS 1 and IFRS
Practice Statement 2);
· Definition of Accounting Estimates (Amendments to IAS 8); and
· Deferred Tax Related to Assets and Liabilities arising from a
Single Transaction (Amendments to IAS 12).
The following amendments are effective for the period beginning 1 January
2024:
· IFRS 16 Leases (Amendment - Liability in a Sale and Leaseback)
· IAS 1 Presentation of Financial Statements (Amendment -
Classification of Liabilities as Current or Non-current)
· IAS 1 Presentation of Financial Statements (Amendment -
Non-current Liabilities with Covenants)
The Group is currently assessing the impact of these new accounting standards
and amendments. The Group does not believe that the amendments to IAS 1 will
have a significant impact on the classification of its liabilities, as the
conversion feature in its convertible debt instruments is classified as an
equity instrument and therefore, does not affect the classification of its
convertible debt as a non-current liability.
The Group does not expect any other standards issued by the IASB, but not yet
effective, to have a material impact on the Group.
The principal accounting policies adopted are set out below.
Basis of consolidation
The Group Financial Statements consolidate the accounts of IOG plc and
entities controlled by the Company (its subsidiary undertakings) drawn up to
the statement of financial position date. Control is achieved where the
investor is exposed or has rights to variable returns from its involvement
with the investee and has the ability to affect those returns through its
power over the investee. The Company reassesses whether or not it controls an
investee if facts and circumstances indicate that there are changes to one or
more of the elements of control. The results of subsidiaries acquired or sold
are consolidated for the periods from or to the date on which control passed.
Where necessary, adjustments are made at the Group level to align the
accounting policies of the subsidiaries to the Group's accounting policies.
All intragroup assets and liabilities, equity, income, expenses and cash flows
relating to transactions between the members of the Group are eliminated on
consolidation.
Asset Acquisition
In the event of an asset acquisition, the cost of the acquisition is assigned
to the individual assets and liabilities based on their relative fair
values. All directly attributable costs are capitalised. Contingent
consideration is accrued for when these amounts are considered probable and
are discounted to present value based on the expected timing of payment.
Oil and gas exploration, development and producing assets
The Group adopts the following accounting policies for oil and gas asset
expenditure, based on the stage of development of the assets:
1) Pre-Licence
Expenditure incurred prior to the acquisition and/or award of a licence
interest is expensed to the Statement of Comprehensive Income as 'Exploration
Expenses'.
2) Exploration and evaluation ('E&E')
Capitalisation
Costs incurred after rights to explore have been obtained, such as geological
and geophysical surveys, drilling and commercial appraisal costs, and other
directly attributable costs of exploration and evaluation including technical
and overheads (including time writing as described under D&P
capitalisation), are capitalised as intangible exploration and evaluation
('E&E') assets. The assessment of what constitutes an individual E&E
asset is based on technical criteria but essentially either a single licence
area or contiguous licence areas with consistent geological features are
designated as individual E&E assets. Costs relating to the exploration and
evaluation of gas interests are carried forward until the existence, or
otherwise, of commercial reserves have been determined.
E&E costs are not amortised prior to the conclusion of appraisal
activities. Once active exploration and evaluation is completed the asset is
assessed for impairment. If commercial reserves are discovered then the
carrying value of the E&E asset is reclassified as a development and
production ('D&P') asset, within property, plant and equipment ('PPE'),
following development sanction by the Board, but only after the carrying value
is assessed for impairment at point of transfer and, where appropriate, its
carrying value adjusted. Following development sanction by the Board, a Field
Development Plan ('FDP') may be submitted. If it is subsequently assessed that
commercial reserves have not been discovered, the E&E asset is written off
to the Statement of Comprehensive Income. The Group's definition of commercial
reserves for such purpose is proven and probable ('2P') reserves on an
entitlement basis.
Intangible E&E assets that relate to E&E activities that are not yet
determined to have resulted in the discovery of commercial reserves remain
capitalised as intangible E&E assets at cost, subject to impairment
assessments as set out below.
Impairment
The Group's gas assets are analysed into cash generating units ('CGU') for
impairment reporting purposes, with E&E asset impairment testing being
performed at an individual asset level. E&E assets are reviewed for
impairment when facts and circumstances arise that suggest that the carrying
value of an E&E asset exceeds its recoverable amount. Such indicators
would include but are not limited to: (i) adequate and sufficient data exists
that render the resource uneconomic and unlikely to be developed; (ii) title
to the asset is compromised; (iii) budgeted or planned expenditure is not
expected in the foreseeable future; (iv) insufficient discovery of
commercially viable resources leading to the discontinuation of activities;
and (v) Rights to explore in an area have expired or will expire in the near
future without renewal.
The recoverable amount of the individual asset is determined as the higher of
its fair value less costs to sell and value in use. Impairment losses
resulting from an impairment review are separately recognised and written off
to the Statement of Comprehensive Income. Impaired assets are reviewed
annually to determine whether any substantial change to their fair value
amounts previously impaired would require reversal.
A previously recognised impairment loss is reversed if the recoverable amount
increases because of a change in the estimates used to determine the
recoverable amount, but not to an amount higher than the carrying amount that
would have been determined had no impairment loss been recognised in prior
periods. Recognition and reversal of impairments and impairment charges are
credited/(charged) to a separate line item within the Statement of
Comprehensive Income. Reversal of impairments and impairment charges are
credited/(charged) to a separate line item within the Statement of
Comprehensive Income.
3) Development and production ('D&P')
Capitalisation
Gas properties are stated at cost, less any accumulated depreciation and
accumulated impairment losses. Expenditures associated with gas properties
include the cost of facilities, pipelines, wells and sub-sea equipment
together with E&E expenditures incurred in finding commercial reserves
previously transferred from E&E assets as outlined in the policy above. An
individual field development can form a single D&P asset but there may be
cases, such as shared infrastructure, phased developments, or multiple fields
around a single production facility when fields are grouped together to form a
single D&P asset. The cost of development and production assets include
the cost of acquisitions and purchases of such assets, directly attributable
overheads, applicable borrowing costs for qualifying assets and the cost of
recognising provisions for future consideration payments (see Note 17). The
discounted cost for future decommissioning is also capitalised to the D&P
asset. Rig day rate costs attributable to changes or adjustments to the
drilling program due to rescheduling are considered as normal and inherent to
the activity of drilling wells that form part of the infrastructure and
therefore these costs are capitalised to the asset.
Depreciation and depletion
All costs relating to a development are accumulated and not
depreciated/depleted until the commencement of production. Gas assets are
depleted on a unit-of-production basis over the total proved and probable
reserves of the field concerned, except in the case of assets whose useful
life is shorter than the lifetime of the field, in which case the
straight-line method is applied. This method takes into account expenditures
incurred to date, together with estimated future capital expenditure expected
to be incurred. Changes in the estimates of commercial reserves or future
field development costs are accounted for prospectively. Significant items of
shared gas infrastructure including facilities, platforms and pipelines will
normally be depreciated on a straight-line basis over their expected useful
life. The expected useful life of current gas infrastructure is 17 years,
which corresponds to the assets design life.
Impairment
At each Statement of Financial Position date, the Group reviews the carrying
amounts of its property, plant and equipment to determine whether there is any
indication that those assets have suffered an impairment loss. If any such
indication exists, the recoverable amount of the asset is estimated in order
to determine the extent of the impairment loss (if any).
The recoverable amount is the higher of fair value less costs to sell and
value-in-use. For the purposes of assessing impairment, assets are grouped at
the lowest levels for which there are cash inflows that are largely
independent of the cash inflows from other assets or group of assets; cash
generating units (CGU). In assessing value-in-use, the estimated future cash
flows are discounted to their present value using a pre-tax discount rate that
reflects current market assessments of the time value of money and the risks
specific to the cash generating unit for which the estimates of future cash
flows have not been adjusted. The discount rate is derived from the Group's
weighted average cost of capital and is adjusted where applicable to consider
any specific risks relating to the country where the CGU is located. The
discount rates applied in assessments of impairment are reassessed each year.
The Company uses a risk adjusted discount rate of 9.38%, unless otherwise
stated. The estimated future net cash flows represent the present value of the
future cash flows expected to be derived from production of commercial
reserves. If the recoverable amount of a cash generating unit is estimated
to be less than the carrying amount, the carrying amount of the
cash-generating unit is reduced to its recoverable amount. An impairment loss
is recognised immediately in the Statement of Comprehensive Income. The CGU
basis is generally the field, however, gas assets, including shared
infrastructure assets may be accounted for on an aggregated basis where such
assets are economically inter-dependent.
Pipeline fill
Natural gas which is used to fill pipelines and is necessary to bring a
pipeline into working order is treated as a part of the cost of the related
pipeline on the basis that it is not held for sale or consumed in a production
process but is necessary for the operation of a facility during more than one
operating cycle. Also, its cost cannot be recouped through sale (or is
significantly impaired). This applies even if the part of inventory that is
deemed to be an item of property, plant and equipment cannot be separated
physically from the rest of inventory. It is valued at cost and is depreciated
over the useful life of related asset.
4) Borrowing costs
Borrowing costs directly attributable to the construction of qualifying
assets, which are assets that necessarily take a substantial period of time to
prepare for their intended use, are added to the cost of those assets, until
such time as the assets are substantially ready for their intended use. All
other borrowing costs are recognised as interest payable in the statement of
comprehensive income in accordance with the effective interest method.
Assets other than oil and gas interests
Assets other than oil and gas interests are stated at cost, less accumulated
depreciation and any provision for impairment. Depreciation is provided at
rates estimated to write off the cost, less estimated residual value, of each
asset over its expected useful life as follows: -
· Computer and office equipment: 33% straight line, with one full
year's depreciation in year of acquisition; and
· Tenants improvements: 20% straight line, with one full year's
depreciation in year of acquisition.
· Right of use assets: Straight line over the term of the lease
Provisions
Provisions are recognised when:
· the Group has a present legal or constructive obligation
resulting from past events;
· it is more likely than not that an outflow of resources will be
required to settle the obligation; and
· the amount can be reliably estimated.
Decommissioning
Provisions for decommissioning costs are recognised in accordance with IAS 37
Provisions, Contingent Liabilities and Contingent Assets. Provisions are
recorded at the present value of the expenditures expected to be required to
settle the Group's future obligations.
Provisions are reviewed at each reporting date to reflect the current best
estimate of the cost at present value. Any change in the date on which
provisions fall due will change the present value of the provision. These
changes are treated as an administration expense. The unwinding of the
discount is reflected as a finance expense.
In the case of a D&P and/or pipeline asset, since the future cost of
decommissioning is regarded as part of the total investment to gain access to
future economic benefits, this is included as part of the cost of the relevant
D&P and/or pipeline asset.
Revenue
During the period, the Group recognised the commencement of revenues from the
sale of gas and condensate and consequently adopted IFRS 15 Revenue from
Contracts with Customers. The Group is principally engaged in the exploration,
development and production of natural gas. The Group has concluded that it is
the principal in its contract with customer arrangements, because it controls
the goods before transferring them to the customer.
Revenue from contracts with customers is recognised when or as the Group
satisfies a performance obligation by transferring control of a promised good
or service to a customer. The transfer of control of natural gas and natural
gas liquids coincides with title passing to the customer and the customer
taking physical possession, generally on delivery of the natural gas or
condensate to the agreed delivery point specified in the contract. In respect
of gas sales, the delivery point is when the gas is delivered into the
National Transmission System downstream of the Bacton gas terminal. Condensate
is sold on an FCA basis when it is delivered onto the buyer's rail tank car
loading manifold. The Group satisfies its performance obligations at a point
in time.
When, or as, a performance obligation is satisfied, the Group recognises as
revenue the amount of the transaction price that is allocated to that
performance obligation. The Group's contracts with customers are deemed to
contain one performance, the provision of natural gas or condensate. The
transaction price is the amount of consideration to which the Group expects to
be entitled. The transaction price is allocated to the performance obligations
in the contract based on standalone selling prices of the goods promised.
Contracts for the sale of natural gas and condensate are priced by reference
to quoted prices. All revenue from these contracts is disclosed as revenue
from contracts with customers.
Consideration payable to a customer for certain costs, claims, demands,
liabilities and/or expenses suffered or incurred by the buyer under the sales
contract are recognised as a reduction of the transaction price and,
therefore, a reduction in revenue since the payment to the customer is not in
exchange for distinct goods that the customers transfer to the Company. The
credit terms range between 20-40 days after the month-end, depending on the
customer.
Cost of sales
Production expenditure, gas properties depletion and movements in inventory, a
result of under-lift of condensate production, are included in cost of sales.
The Group recognises an under-lift asset as inventory for condensate
production at the lower of cost and net realisable value, consistent with IAS
2, to represent a right to additional physical inventory. An under-lift of
production from a field is included in current receivables.
Disposals
Net proceeds from any disposal of an E&E, D&P or pipeline asset are
initially credited against the previously capitalised costs of that asset and
any surplus or shortfall proceeds are credited or debited to the Statement of
Comprehensive Income.
For the Farm down of an E&E, D&P or pipeline asset, proceeds from the
farm-down are credited against the previously capitalised costs of the asset
and any surplus or shortfall proceeds above or below the representative
percentage of the carrying value of the asset or assets being farmed down are
credited or debited to the Statement of Comprehensive Income accordingly.
Foreign currencies
The Group's presentational currency is GBP Sterling and has been selected
based on the currency of the primary economic environment in which the Group
operates. The Group's primary product is generally traded by reference to
its pricing in GBP Sterling. The functional currency of all companies in the
Group is also considered to be GBP Sterling. Transactions in currencies
other than the functional currency of a company are recorded at a rate of
exchange approximating to that prevailing at the date of the transaction. At
each balance sheet date, monetary assets and liabilities that are denominated
in currencies other than the functional currency are translated at the amounts
prevailing at the balance sheet date and any gains or losses arising are
recognised in the Consolidated Statement of Comprehensive Income.
Taxation
Current Tax
Tax is payable based upon taxable profit for the year. Taxable profit
differs from net profit as reported in the Statement of Comprehensive Income
because it excludes items of income or expense that are taxable or deductible
on other years and it further excludes items that are never taxable or
deductible. Any Group liability for current tax is calculated using tax
rates that have been enacted or substantively enacted by the reporting date.
Deferred Tax
Deferred tax is the tax expected to be payable or recoverable on differences
between the carrying amounts of assets and liabilities in the financial
statements and the corresponding tax bases used in the computation of taxable
profit. Deferred tax liabilities are generally recognised for all taxable
temporary differences and deferred tax assets are recognised to the extent
that it is probable that taxable profits will be available against which
deductible temporary differences can be utilised.
Deferred tax liabilities are recognised for taxable temporary differences
arising on investments in subsidiaries, except where the Group can control the
reversal of the temporary differences and it is probable that the temporary
difference will not reverse in the foreseeable future.
The carrying amount of deferred tax assets is reviewed at each reporting date
and reduced to the extent that it is no longer probable that sufficient
taxable profits will be available to allow all or part of the asset to be
recovered.
Deferred tax is calculated at the tax rates that are expected to apply in the
period when the liability is settled, or the asset is realised. Deferred tax
is charged or credited in the Statement of Comprehensive Income, except when
it relates to items charged or credited directly to equity, in which case the
deferred tax is also dealt with in equity. Deferred tax assets and
liabilities are offset when there is a legally enforceable right to set off
current tax assets against current tax liabilities and when they relate to
income taxes levied by the same taxation authority and the Group intends to
settle its current tax assets and liabilities on a net basis.
The amount of the asset or liability is determined using tax rates that have
been enacted or substantively enacted by the reporting date and are expected
to apply when the deferred tax liabilities/(assets) are settled/(recovered).
Deferred tax balances are not discounted.
Investments & Loans (Company)
Non-current investments in subsidiary undertakings are shown in the Company's
Statement of Financial Position at cost less any provision for permanent
diminution of value.
Loans to subsidiary undertakings are stated at amortised cost and recognised
in accordance with IFRS 9. The loans have no maturity date and are not
repayable until the respective subsidiary entity has sufficient cash to repay
the loan, however they are technically due on demand.
Leases
IFRS 16 sets out the principles for the recognition, measurement, presentation
and disclosure of leases and requires lessees to account for all leases, with
limited exceptions, under a single on-balance sheet model similar to the
accounting for finance leases under IAS 17. Under IFRS 16, at the commencement
date of a lease, a lessee is required to recognise a liability to make lease
payments ('lease liability') and an asset representing the right to use the
underlying asset during the lease term ('right-of-use asset', 'ROU'). Lease
liabilities are measured at the present value of future lease payments over
the reasonably certain lease term. Variable lease payments that do not depend
on an index or a rate are not included in the lease liability. Such payments
are expensed as incurred throughout the lease term.
Lessees are required to separately recognise the interest expense associated
with the unwinding of the lease liability and the depreciation expense on the
right-of-use asset. As the leases relate to D&P work scopes the
depreciation expense is capitalised and treated as the cost of the underlying
D&P asset. These costs replace amounts previously recognised as operating
expenditure in respect of operating leases in accordance with IAS 17. After
completion of Development phase, once the assets come into operation the
depreciation of the right of use asset will be charged to the income statement
on straight line basis over the course of the lease term.
The Group adopted IFRS 16 on 1 January 2019 using the modified retrospective
approach. The modified retrospective approach does not require restatement of
prior period financial information, instead recognising the cumulative effect
as an adjustment to opening retained earnings and the Group applied the
standard prospectively.
The Group has elected to apply the following optional practical expedients
under the standard:
• Short-term leases - those with terms of 12 months or
less at date of adoption
• Low-value leases - those with a value less than
£5,000
During 2022, the ROU assets and lease obligations classified in accordance
with IFRS 16, relate to office leases, the Saturn Banks Pipeline permission to
cross the foreshore, the Noble Hans Deul drilling rig contract, Charter of PSV
"VOS Paradise" and Charter of ERRV "Esvagt Champion". The incremental
borrowing rate of 10.9% (2021: 9.3%) was applied to the drilling rig and
support vessel ROU assets, and 9.3% (2021: 9.3%) for the office leases, in
arriving at net present value of future lease payments, recognising they
belong to similar asset classes with similar lease terms. The internal
borrowing rate for Saturn Banks Pipeline was retained at 11.5% as it belongs
to a different asset class and has longer lease term. The ROU for Noble Hans
Deul was increased in line with the extension option.
The Group has elected to utilise the practical expedient when accounting for
the Noble Rig, PSV and ERVV contract to not separate non-lease components from
lease components, and instead account for each lease component and any
non-lease component as a single component. The leases are for the benefit of
the joint operation operated by the Group. For leases related to joint
operations where the Group is the only party with the legal obligation to make
lease payments to the lessor, the full lease liability and ROU asset will be
recognised on the Group Statement of Financial Position. This is the case for
the drilling rig contract and associated support vessels described above, as
the Group, as operator of the joint operation, is the sole signatory to the
lease. As the underlying asset is used for the performance of the joint
operation agreement, the Group will recharge the associated costs in line with
the joint operating agreement.
The Company depreciates the ROU assets on a straight-line basis over the
length of the lease unless management determines this is not representative of
the useful life, in which case, management will estimate the useful life of
the asset to be used.
The liability is remeasured when there is a change in future lease payments
arising from a change in an index or rate or if the Group changes its
assessment of whether it will exercise a purchase, extension or termination
option. When the lease liability is remeasured in this way, a corresponding
adjustment is made to the carrying amount of the right-of-use asset or is
recorded in profit or loss if the carrying amount of the right-of-use asset
has been reduced to zero.
The right-of-use asset is measured at cost, which comprises the initial amount
of the lease liability adjusted for any lease payments made at or before the
commencement date, plus any initial direct costs incurred and an estimate of
costs to dismantle and remove the underlying asset or to restore the
underlying asset or the site on which it is located, less any lease incentives
received. Right-of-use assets are depreciated over the shorter period of lease
term and useful life of the underlying asset.
Financial Instruments
Financial instruments are recognised when the Group becomes a party to the
contractual provisions of the instrument and are subsequently measured at
amortised cost.
Classification and measurement of financial assets
The initial classification of a financial asset depends upon the Group's
business model for managing its financial assets and the contractual terms of
the cash flows. The Group's financial assets are measured at amortised cost
and are held within a business model whose objective is to hold assets to
collect contractual cash flows and its contractual terms give rise on
specified dates to cash flows that represent solely payments of principal and
interest.
The Group's cash and cash equivalents and other receivables are measured at
amortised cost. Other receivables are initially measured at fair value. The
Group holds other receivables with the objective to collect the contractual
cash flows and therefore measures them subsequently at amortised cost.
The Group has financial assets measured at FVOCI (Fair Value Through Other
Comprehensive Income) or FVTPL (Fair Value Through the Statement of Profit or
Loss).
Fair value measurement
A number of assets and liabilities included in the Group's financial
statements require measurement at, and/or disclosure of, fair value.
The fair value measurement of the Group's financial and non-financial assets
and liabilities utilises market observable inputs and data as far as possible.
Inputs used in determining fair value measurements are categorised into
different levels based on how observable the inputs used in the valuation
technique utilised are (the 'fair value hierarchy'):
- Level 1: Quoted prices in active markets for identical items (unadjusted)
- Level 2: Observable direct or indirect inputs other than Level 1 inputs
- Level 3: Unobservable inputs (i.e. not derived from market data).
The classification of an item into the above levels is based on the lowest
level of the inputs used that has a significant effect on the fair value
measurement of the item. Transfers of items between levels are recognised in
the period they occur.
Investment in and disposal of Norwegian bond
The company carried an investment in its Norwegian bond until September 2021.
These bonds were denominated in Euro's and were adjusted to mark-to-market and
revalued at period end rates. These holdings were sold in the open market at
spot price and a profit / loss on sale was recognised in the statement of
comprehensive income on disposal.
Restricted cash
Restricted cash includes cash balances that are subject to access restrictions
or have conditions attached to their drawdown. Included in this are monies
raised from its Norwegian bond placing held in Debt Servicing Retention
account and subject to defined conditions. Also included are balances held
as collateralised security in the Group's name for future expenditures such as
Decommissioning.
Cash and cash equivalents
Cash includes cash on hand and demand deposits with any bank or other
financial institution. Cash equivalents are short-term, highly liquid
investments that are readily convertible to known amounts of cash which are
subject to an insignificant risk of changes in value.
Impairment of financial assets
The Group recognises loss allowances for expected credit losses ('ECL's) on
its financial assets measured at amortised cost. Due to the nature of its
financial assets, the Group measures loss allowances at an amount equal to the
lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all
possible default events over the expected life of a financial asset. ECLs are
a probability-weighted estimate of credit losses. The Company has carried out
an analysis of the balances outstanding at the end of the period and assessed
the likelihood of repayment from its subsidiaries. It believes that there is
no significant increase in credit risk from the prior year and, if anything,
the position is strengthened with the sanction of the phase 1 project
resulting in future cashflows for its subsidiaries.
Classification and measurement of financial liabilities
A financial liability is initially classified as measured at amortised cost or
FVTPL. A financial liability is classified as measured at FVTPL if it is
held-for-trading, a derivative or designated as FVTPL on initial recognition.
The Group's accounts payable, accrued liabilities, operators balances and
long-term debt are measured at amortised cost.
Accounts payable, accrued liabilities and operators balances are initially
measured at fair value and subsequently measured at amortised cost. Accounts
payable and accrued liabilities are presented as current liabilities unless
payment is not due within 12 months after the reporting period.
Long-term debt is initially measured at fair value, net of transaction costs
incurred. The contractual cash flows of the long-term debt are made up of
solely principal and interest, therefore long-term debt is subsequently
measured at amortised cost. Long-term debt is classified as current when
payment is due within 12 months after the reporting period.
Where warrants are issued in lieu of arrangement fees on debt facilities, the
fair value of the warrants are measured at the date of grant as determined
through the use of the Black‑Scholes technique. The fair value determined at
the grant date of the warrants is recognised in the Group's warrant reserve
and is amortised as a finance cost over the life of the facility.
The outstanding LOG loans are unsecured against any assets or Company of the
Group.
Convertible loan notes
Upon issue, convertible notes are assessed as to whether it is necessary to
separate the loan into an equity and liability component at the date of
issue. If the bifurcation is considered material the liability component is
recognised initially at its fair value. Subsequent to initial recognition,
it is carried at amortised carrying value using the effective interest method
until the liability is extinguished on conversion or redemption of the
notes. The equity component is the residual amount of the convertible note
after deducting the fair value of the liability component. This is
recognised and included in equity and is not subsequently re-measured.
Contingent consideration payable
Where applicable, the consideration for the acquisition includes any asset or
liability resulting from a contingent consideration arrangement, measured at
its acquisition date fair value. Subsequent changes in the fair values are
adjusted against the cost of acquisition where they qualify as measurement
period adjustments (see below). All other subsequent changes in the fair value
of contingent considerations classified either as an asset or liability are
accounted for in accordance with relevant IFRSs with any gains or losses
recorded in the income statement unless it is classified as equity.
Equity
Equity instruments issued by the Company are recorded at the proceeds
received, net of direct issue costs, allocated between share capital and share
premium. The costs of issuing new share capital are written off against the
share premium account arising out of the proceeds of the new issue.
Share-based payments
The Company have applied the requirements of IFRS 2 Share-based payments.
The Company issues equity share options, to certain employees and contractors,
as direct compensation for both salary and fees sacrificed in lieu of such
share options. Other Long-Term Incentive Plan ('LTIP') and Company Share
Ownership Plan ('CSOP') share options may be awarded to incentivise and reward
successful corporate and individual performance. The fair value of these
awards has been determined at the date of the grant of the award allowing for
the effect of any market-based performance conditions.
The fair value of share options awarded, in lieu of salary sacrifice, is
expensed on the effective date of grant, with no vesting conditions applied.
The fair value is deemed to be the actual salary sacrificed.
For LTIP and CSOP share option awards, based upon incentive and performance,
the fair value, adjusted by the estimate of the number of awards that will
eventually vest because of non-market conditions, is expensed uniformly over
the vesting period and is charged to the Statement of Comprehensive Income,
together with an increase in equity reserves, over a similar period. The
fair values are calculated using an option pricing model with suitable
modifications to allow for early exercise. The inputs to the model include:
the share price at the date of grant; exercise price; expected volatility;
expected dividends; risk-free rate of interest; and patterns of exercise of
the plan participants. Where the terms and conditions of options are
modified before they vest, the increase in the fair value of the options,
measured immediately before and after the modification, is also charged to the
Statement of Comprehensive Income over the remaining vesting period. Share
options issued by the Company that are subject to market-based vesting
conditions, as defined in IFRS 2, are ignored for the purposes of estimating
the number of equity shares that will vest; these conditions have already been
taken into account when fair valuing the share options.
Non-market vesting conditions are not taken into account when estimating the
fair value of share options at the grant date; such conditions are taken into
account through adjusting the number of equity instruments included in the
measurement of the amount charged to the Statement of Comprehensive Income
over the vesting period so that, ultimately, the amount recognised equates to
the number of equity instruments that actually vest. The expense in the
Statement of Comprehensive Income in relation to share options represents the
product of the total number of options anticipated to vest and the fair value
of these options at the date of grant.
Share options where the performance conditions are service-related and
non-market in nature, the cumulative charge to the income statement is
reversed only where an employee in receipt of share options leaves the Group
prior to completion of the service period and forfeits the options granted
and/or performance conditions are not expected to be satisfied. Where an
equity-settled award is cancelled, it is treated as if it had vested on the
date of cancellation, and any expense not yet recognised for the award is
recognised immediately.
The proceeds received by the Company on the exercise of share entitlements are
credited to share capital and share premium. When share options which have not
been exercised reach the end of the original contractual life, the value of
the share options is transferred from the share option reserve to retained
earnings.
The fair value of warrants issued to third parties is calculated by reference
to the service provided, or if this is not considered possible, calculated in
the same way as for LTIP share options as detailed above. Typically, these
amounts are related to debt issues and are included in the effective interest
rate calculation of borrowings.
Earnings or Loss per share
Earnings or Loss per share is calculated as profit/loss attributable to
shareholders divided by the weighted average number of ordinary shares in
issue for the relevant period. Diluted earnings per share is calculated
using the weighted average number of ordinary shares in issue plus the
weighted average number of ordinary shares that would be in issue on the
conversion of all relevant potentially dilutive shares to ordinary shares
adjusted for any proceeds obtained on the exercise of any options and
warrants. Where the impact of converted shares would be anti-dilutive, they
are excluded from the calculation.
Critical accounting judgements and key sources of estimation uncertainty
The preparation of financial statements in conformity with IFRS requires
management to make judgements, estimates and assumptions that affect the
application of policies and reported amounts of assets and liabilities, income
and expenses. The estimates and associated assumptions are based on
historical experience and factors that are believed to be reasonable under the
circumstances, the results of which form the basis of making judgements about
carrying values of assets and liabilities that are not clear from other
sources. Actual results may differ from these estimates.
The following are the critical judgements that management has made in the
process of applying the entity's accounting policies and that have the most
significant effect on the amounts recognised in financial statements.
Critical accounting judgements
Where judgements have been applied, these can affect the outcome and results
within the Financial Statements.
Determination of cash-generating units ("CGUs") (note 10 & 11)
The determination of the appropriate grouping of assets into a CGU for
impairment purposes require significant management judgement when defining an
asset, or group of assets that generate cash inflows that are largely
independent of the cash inflows from other assets or groups of assets. For
example, individual gas properties may form separate CGUs whilst certain gas
properties with shared infrastructure may be grouped together to form a single
CGU. Alternative groupings of assets or CGUs may result in a different outcome
from impairment testing. CGUs are determined by consideration to similar
geological structure, shared infrastructure, geographical proximity, commodity
type, similar exposure to market risks and materiality. The Group's cash
generating units are normally, but not always, single development or
production areas. With respect to the Group's Southern North Sea gas
production and development assets, the CGU is considered by field or Groups of
proximate fields which supports the value of shared infrastructure assets. In
the prior year, the D&P Phase 1 assets were treated as one CGU, however,
following production from the Blythe and Elgood CGU, and the results on the
Southwark CGU during the year, these fields are now considered to generate
independent cashflows that support the share gas infrastructure network.
E&E assets are considered to form a single CGU on a "hub" basis that
corresponds to geographical proximity for the purposes of an impairment
assessment under IFRS 6.
Carrying value of intangible exploration and evaluation assets (note 10)
The amounts for intangible exploration and evaluation assets represent active
evaluation projects. These amounts will be written off to the income statement
as exploration costs unless commercial reserves are established, or the
determination process is not completed and there are no indications of
impairment in accordance with the Group's accounting policy. The process of
determining whether there is an indicator for impairment or impairment
reversal and the subsequent calculation requires critical judgement. The key
areas in which management has applied judgement are as follows: the Group's
intention to proceed with a future work programme for a licence; the
likelihood of licence renewal or extension; the review of new legislation or
regulations that may impact the economic terms of the Group's licence
interests: the assessment of whether sufficient data exists to indicate that,
although a development in the specific area is likely to proceed, the carrying
amount of the exploration and evaluation asset is unlikely to be recovered in
full from successful development or by sale and the success of a well result
or geological or geophysical survey.
Impairment of property plant and equipment assets (note 11)
Management is required to assess its gas assets for indicators of impairment.
D&P assets are reviewed for impairment by reference to indicators set out
in IAS 36, which is inherently judgemental. Indicators of D&P assets
include, but are not limited to:
· Significant downward trend changes long term gas price
· Any information available that would lead to a reduction in the
reservoir estimates, either performance or via an updated reserves assessment
by a competent person
· Significant cost overruns that would impact the economics of the
CGU / asset
· Any commercial changes that would impact the economics of the CGU
/ asset
· Any regulatory, governance or environmental changes that would
impact the asset's ability to function as previously envisaged.
During the year, the Elgood and Southwark reserves were downgraded following
the results of production from the Elgood field and the Southwark A-2 well
which the Group determined was an indicator of impairment (see note 11). The
results of future developments of the Group's assets may be different to
current management expectations and may result in further impairment or an
impairment reversal dependent on the outcome of those developments, which
would have an impact on the Group's financial statements. The carrying value
of D&P gas assets is disclosed in note 11. The carrying value of related
investments in the Company Statement of Financial Position is disclosed above.
Recognition of finance leases (note 23)
An area that carries significant judgement is around the accounting for the
finance lease assumptions for the Shelf Perseverance rig contract, charter of
support vessels, the PSV supply vessel & charter of ERRV (emergency rapid
response vessel). These contracts have been assessed to fall within the scope
of IFRS 16 and judgements around the initial contract length, subsequent
extension (in case of rig contract) and the incremental borrowing rate have
been made by Management.
Critical accounting judgements and key sources of estimation uncertainty
(continued)
Critical accounting judgements (continued)
Going concern
Refer to above.
Key sources of estimation uncertainty
The key assumptions concerning the future and other key sources of estimation
uncertainty at the balance sheet date that have a significant risk of causing
a material adjustment to the carrying amounts of assets and liabilities within
the next financial year are discussed below.
Decommissioning estimates (note 17)
Provisions for decommissioning obligations are made on the best estimate of
the likely committed cash outflow. The Company engages specialist input from
third party consultancy experts to estimate the cost to perform the necessary
remediation work at the reporting date. The third-party expert has experience
in the industry and location where the Group operates and has assisted the
Group's operations in the past. This enables a degree of knowledge of
conditions specifically relevant to the Group. The third-party conducted a
detailed review, provided a range of cost estimates for decommissioning of
wells and infrastructure and site remediation. Management review and challenge
the method and cost ranges where appropriate, using its own external sources
through current contractors and market. The third-party expert estimates are
on an undiscounted basis. Provision for environmental clean-up and remediation
costs is based on current legal and contractual requirements, technology and
management's estimate of costs with reference to current price levels.
Changes to the type of remediation method, legislation, including in relation
to climate change, well condition, technology and equipment available in the
Group's country of operation can all have a significant impact on the cost
estimate that may result in the cost being higher than the current upper-range
of the estimate provided.
The estimation of the timing of well abandonment, inflation and discount rates
is also considered to be judgemental and can have a significant impact on the
net present value of the obligation. Abandonment timing is forecast to occur
at the expiration, or if planned renewal, expected expiration of the licence
term. In respect of inflation, management references UK long-term inflation
targets published by the OBR, and the risk-free discount rate estimate
references the UK and Europe central banks when making such estimates (see
note 22).
Impairment of property plant and equipment - development & production
assets (note 11)
At each Statement of Financial Position date, the Group reviews the carrying
amounts of its CGUs to determine whether there is any indication that those
assets have suffered an impairment. The Group generally assesses the
recoverable amount of a CGU through the value-in-use method, using the
estimated future cash flows which are discounted to their present value using
a pre-tax discount rate that reflects current market assessments of the time
value of money and the risks specific to the asset or CGU. The following are
key estimates used in that assessment when calculating development &
production assets recoverable amount:
Commercial Reserves
Commercial reserves are proven and probable ('2P') oil and gas reserves,
calculated on an entitlement basis. Estimates of commercial reserves
underpin the calculation of depletion and amortisation on a UOP basis, gas
asset impairments, as well as the value-in-use calculation. Estimates of
commercial reserves include estimates of the amount of gas in place,
assumptions about reservoir performance over the life of the field and
assumptions about commercial factors which, in turn, will be affected by the
future gas price. The Group prepares Proved and Probable reserves estimates in
accordance with the reserve definitions guidelines defined in SPE Petroleum
Resources Management System 2018 (PRMS 2018). Reserves estimates are reported
annually by the Board. The self-certified estimated future production
profiles are used in the life of the fields which in turn are used as a basis
in the value-in-use calculation.
Commodity prices
A seasonally adjusted long-term assumption for natural UK NBP gas prices are
used for future cash flows in accordance with the Group's corporate
assumptions. Field specific premiums and discounts are used where
applicable.
Capital expenditure
Field development is capital intensive and future capital expenditure has a
significant bearing on the value of a gas development asset. In addition,
capital expenditure may be required for producing fields to increase
production and/or extend the life of the field. Cost assumptions are based
on operator and/or service contractor cost estimates or specific contracts
where available.
Critical accounting judgements and key sources of estimation uncertainty
(continued)
Key sources of estimation uncertainty (continued)
Impairment of property plant and equipment - development & production
assets (note 11)
Discount rates
Discount rates reflect the current market assessment of the risks specific to
the upstream gas sector and are based on the weighted average cost of capital
for the Group. Where appropriate, the rates are adjusted to reflect the
market assessment of any risk specific to the field for which future estimated
cash flows have not been adjusted. The Group has applied a risk adjusted
discount rate of 9.38% for the current year (2021: 9.25%). A one per cent
increase in the discount rate does not result in an additional impairment.
Sensitivity to changes in assumptions
A potential change in any of the above assumptions may cause the estimated
recoverable value to be lower than the carrying value, resulting in an
impairment loss. The assumptions which would have the greatest impact on the
recoverable amounts of the fields are commercial reserves volumes (linked to
recoverable reserves) and commodity prices. In respect of the D&P Phase 1
assets, sensitivity analysis indicates that if gas prices were to fall by 10%
below forecast there an additional post-tax impairment of £24.4 million would
have occurred, and an increase of 10% would result in an £18.6 million
increase in recoverable amount.
Investments in subsidiaries
If circumstances indicate that impairment may exist, investments in and the
value of any loans to subsidiary undertakings of the Company are evaluated
using market values, where available, or the discounted expected future cash
flows of the investment. If these cash flows are lower than the Company's
carrying value of the investment or loan amount due, an impairment charge is
recorded in the Company. Evaluation of impairments on such investments
involves significant management judgement and may differ from actual results.
Finance leases
− The determination of lease term for some lease contracts in which the
Group is a lessee, including whether the Company is reasonably certain to
exercise lessee options (see note 23).
− The determination of the incremental borrowing rate used to measure lease
liabilities (see note 1).
Fair value of share options and warrants
The fair value of options and warrants is calculated using appropriate
estimates of expected volatility, risk free rates of return, expected life of
the options/warrants, the dividend growth rate, the number of options expected
to vest and the impact of any attached conditions of exercise. See above for
further details of these assumptions.
Prior period adjustment
An error was identified in the accounting for prior period prior period
personnel costs recognised in 2021 financial statements. An over accrual of
personnel costs of £1.9 million was recognised in previously reported 2021
administration expenses of £4.0 million, which formed part of operating loss
of £1.5 million, and total comprehensive loss for the year of £4.3
million. Due to performance measures not being met during 2021, total
personnel costs incurred in the period was £1.4 million lower. As these
personnel costs predominantly related to the development of the Group's
E&E and D&P assets, the costs were subsequently charged to Intangible
and PPE assets and adjusted through the restated prior year accounts, as
presented in the table below.
The restated 2021 personnel costs has an impact on all primary statements and
certain notes to the accounts on both a consolidated and Company basis.
The 2021 comparatives have been restated in these financial statements to
include the effect of the adjustments noted above. A third consolidated
statement of financial position as at 1 January 2021 is not required under
paragraph 10(f) of IAS 1 Presentation of financial statements, as the
restatement has had no effect on the statement of financial position as at
that date.
The adjustment has been corrected as at 31 December 2021 as per tables below:
31 December 2021 Adjustment Restated
31 December 2021
Consolidated Statement of Financial Position £000 £000 £000
Intangible assets 950 44 994
Property, plant, and equipment: D&P assets 138,403 402 138,805
- Trade and other payables (44,880) 1,412 (43,468)
Accumulated losses 42,263 (1,858) 40,405
Consolidated Statement of Comprehensive Income
Administrative expenses (3,960) 1,858 (2,102)
Total comprehensive loss for the year (4,266) 1,858 (2,408)
Operating (loss)/ profit (1,489) 1,858 369
Consolidated Cash Flow Statement
Loss for the year (4,266) 1,858 (2,408)
Movement in trade and other payables 25,499 (1,858) 23,641
31 December 2021 Adjustment Restated
31 December 2021
Company Statement of Financial Position £000 £000 £000
- Amounts due from subsidiaries 109,195 446 109,641
- Trade and other payables (22,513) 1,412 (21,101)
Accumulated losses 20,094 (1,858) 18,236
Company Cash Flow Statement
Loss for the year (3,643) 1,858 (1,785)
Movement in trade and other payables 25,499 (1,858) 23,641
2 Segmental information
The Group complies with IFRS 8, Operating Segments, which requires operating
segments to be identified based upon internal reports about components of the
Group that are regularly reviewed by the Directors to allocate resources to
the segments and to assess their performance. In the opinion of the
Directors, the operations of the Group comprise one class of business, being
the development, production and exploration of oil and gas opportunities in
the UK Southern North Sea.
3 Revenue
The Group's total revenue is stated from its contracts with customers relating
to the following sales:
2022 2021
£000 £000
Gas sales 71,840 -
Condensate sales 3,566 -
_________ _________
Total Revenue 75,406 -
_________ _________
Included in revenues arising from gas sales are revenues of £71.8 million
(2021: £nil) which arose from sales to BP Gas Marketing Limited, the Group's
largest customer. No other single customers contributed 10 per cent or more to
the Group's revenue in either 2022 or 2021.
4 Cost of sales
2022 2021
£000 £000
Operating Costs (10,078) -
Increase in Inventory 40 -
Depletion (13,188) -
Other Operating Expenditure (415) -
_________ _________
(23,641) -
_________ _________
Cost of sales for 2022 is £23.6 million (2021: £nil), representing operating
costs of £10.1 million (2021: £nil), an increase in condensate inventory of
£40,000 (2021: £nil), depletion of £13.2 million (2021: £nil) and other
operating expenditure of £0.4 million (2021: £nil).
5 Operating loss
The Group's operating loss (2021: loss) is stated after charging / (crediting)
the following:
2022 2021
£000 £000
Fees payable to the Company's auditor: 150 128
- for the audit of the Group's financial
statements
Non-audit services 41 7
Of which
for the audit of the Company's financial statements 77 62
( )
( )
Depreciation, depletion and amortisation 13,686 519
Project, pre-licence and exploration expenses 182 104
Impairment of oil and gas properties 51,007 865
Effect of exchange rate changes on Bond 4,620 (5,901)
Effects of exchange rate changes on cash and cash equivalents 465 2,461
Effects of exchange rate changes on Leases (341) -
Foreign exchange loss of £4.7 million (2021: gain of £3.4 million) relates
mostly to EUR strengthening affecting the €100 million Norwegian Bonds.
6 Personnel costs
During the year, the average number of personnel, including contract
personnel, for both the Company and Group was:
2022 2021
Number Number
Management / technical / operations 51 52
of which: Directors 5 5
Personnel costs Group and Company £000 £000
Wages, salaries, fees and other direct costs 6,904 4,655
Social security costs 1,028 613
Pension costs 343 298
Share-based payments 844 1,284
________ ________
9,119 6,850
________ ________
Note that project contract personnel, capitalised directly to project cost
centres, are excluded from the above personnel cost figures.
Of the total personnel costs of £9.1 million (2021: £6.8 million) plus the
other admin pool costs of £2.5 million (2021: £2.3 million), £6.0 million
was capitalised to the balance sheet under PP&E (2021: £6.3 millions),
£972,000 to Intangibles (2021: £655,000), and £2.2 million expensed to
operating costs (2021: £nil).
Key management personnel are deemed to be the Directors, the Chief Financial
Officer, the General Counsel & Company Secretary and the Head of Capital
Markets & ESG.
Total key management personnel remuneration is:
2022 2021
Group and Company £000 £000
Wages, salaries, fees and other direct costs 1,442 1,646
Social security costs 347 237
Pension costs and other benefits 343 148
Share-based payments 505 776
________ ________
2,637 2,807
________ ________
Directors' emoluments (which are included in administration expenses) and
interests are shown in the Directors' Remuneration Report on pages 26 to 27.
Short term benefits are deemed to be salary/fees, salary/fees sacrificed,
bonus and benefits. No post-employment, long term or termination payments were
made during the year.
The salary amounts are those cash amounts paid to Directors and key management
personnel during the year. Social security costs for the year for key
management personnel were £347,000 (2021: £237,000). Amounts of salary
and/or fees outstanding at 31 December 2022 to which these terms relate
totalled £nil (31 December 2021: £nil) for Directors and key management
personnel and £nil (2021: £nil) for other personnel.
The share-based payment amounts represent the charges for share options during
the year. For the current Directors at 31 December 2022, the service
agreements provide that the full contractual amount will be paid in cash.
Personnel costs in 2021 have been restated; see note 1 for details.
7 Finance expense
2022 2021
£000 £000
Interest on loans 206 -
Other finance charges 23 -
Current year loan finance charges 560 560
Unwinding of discount on decommissioning provision 449 (14)
Unwinding of discount on convertible loan 1,000 1,001
Unwinding of deferred consideration provisions 91 (118)
Unwinding of discount on lease liability 1,882 1,637
Interest on bonds 8,756 8,253
Capitalisation of interest on bonds(1) (1,853) (8,253)
( ) ________ ________
11,114 3,066
________ _________
(1) During the Phase 1 development, 1st quarter 2022 interest paid in the
Norwegian bonds was capitalised to the Phase 1 assets proportionately based on
capital expenditure during the quarter. The capitalisation of the bond
interest has cessed on the commencement of Blythe and Elgood production in
2022.
As at 31 December 2022, there were no interest-bearing loans outstanding other
than the Norwegian Bonds (see note 22). During the year, the interest
associated with the Bond was capitalised to D&P project costs as the bond
drawdowns are purposefully used to finance the development of the project
assets, until the assets became substantially available for their intended
use. Interest on the Bond is no longer capitalised to D&P project costs
but expensed to the Statement of Comprehensive Income as incurred.
8 Taxation
a) Current taxation
There was no tax charge during the year as the Group loss was not chargeable
to corporation tax. Applicable expenditures to date will be accumulated for
offset against future tax charges. The reasons for the difference between
the actual tax charge for the year and the standard rate of corporation tax in
the United Kingdom applied to profits for the year are as follows:
2022 2021
£000 £000
(Loss)/profit before income taxes (17,087) (2,408)
_________ _________
Expected tax expense/(credit) based on the standard rate of United Kingdom (6,834) (1,706)
corporation tax at the domestic rate of 40%(1) (2021: 40%)
Difference in tax rates 3,476 1,168
Expenses not deductible for tax purposes 1,289 (77)
Excess allowances (17,117) -
Deferred Energy Profits Levy 11,362 -
Income not taxable - (7,618)
Group relief claimed - (2)
Unrecognised taxable losses carried forward 19,186 8,235
_________ _________
Total tax expense 11,362 -
_________ _________
( )
(1) The standard rate of corporation tax of 40% (2021: 40%), including the
supplemental corporation tax charge of 10% (2021:10%) is levied in respect of
UK ring fence profit. Non-ring fenced profits are taxed at the standard rate
of corporation tax of 19% (changing to 25% from 1 April 2023). Given that the
Group's activities are primarily focused on activities which will generate
income within the UK ring fence the 40% has been regarded as the appropriate
rate for the reconciliation above. On 26 May 2022 the government announced a
new Energy Profits Levy (EPL), 25% surcharge, will apply to ring fence oil and
gas profits generated from that day until 31 December 2025. It was then
announced that the EPL the rate will increase to 35% for ring fence oil and
gas profits generated from 1 January 2023 to 31 March 2028. These laws have
now been enacted by balance sheet date.
( )
b) Deferred taxation
Due to the nature of the Group's exploration and appraisal activities there is
a long lead time in either developing or otherwise realising exploration
assets. The amount of deductible temporary differences, unused tax losses and
unused tax credits for which no deferred tax asset is recognised in the
statement of financial position is £258.6 million (2021: £220.6 million).
There are also accelerated capital allowances of £116.4 million (2021:
£111.0 million).
The Group has not recognised a deferred tax asset at 31 December 2022 (2021:
£nil) on the basis that the Group would expect the point of recognition to be
when the Group has some level of certainty of production showing that the
Group is making profits in line with the underlying economic model which would
support the recognition. A deferred tax asset has only been recognised on
deductible temporary differences up to the amount of taxable temporary
differences.
Energy Profit Levy
The Energy (Oil and Gas) Profits Levy was announced on 26 May 2022 and
legislated for in July 2022. This was a new, temporary 35% levy on ring fence
profits of oil and gas companies. This was in addition to Ring Fence
Corporation Tax which is charged at 30% and the Supplementary Charge which is
charged at 10%. The levy included a new 80% investment allowance and was due
to expire by 31 December 2025. This measure increases the rate of the levy to
35% and extends the time that the levy applies to 31 March 2028. In respect of
Energy Profits Levy (EPL) a net deferred tax liability of £11.4 million has
been recognised.
The Group has carried forward ring fence tax losses of £239.3m (2021: £196.4
million), EPL losses of £21.0 million (2021: £nil) and non-ring fence tax
losses of £24.2 million (2021: £16.6 million).
2022 2021
Deferred tax £000 £000
Net book value in excess of capital allowances 79,852 55,718
Decommissioning provision (8,869) -
Investment allowance (394) -
Tax losses (59,227) (55,718)
_________ _________
Net deferred tax loss 11,362 -
9 Loss per share
2022 2021
£000 £000
Loss for the year attributable to shareholders (Numerator) (28,449) (2,408)
___________ ___________
Weighted average number of Ordinary Shares: basic (Denominator) 525,037,353 513,584,870
Add potentially dilutive shares:
Convertible loan notes 60,872,631 60,872,631
Salary/Fee sacrifice options 3,198,288 4,325,027
LTIP/CSOP 30,206,628 26,369,136
Warrants 20,000,000 20,000,000
Diluted 639,314,900 625,151,664
___________ ___________
Loss per share in pence: basic (5.4p) (0.4p)
Diluted earnings per share is calculated based upon the weighted average
number of Ordinary Shares plus the weighted average number of Ordinary Shares
that would be issued upon conversion of potentially dilutive share options,
convertible loan notes and warrants into Ordinary Shares.
There is no difference between the basic loss per Ordinary Share and the
diluted loss per Ordinary Share for the years ended 31 December 2022 and 2021
as all potential Ordinary Shares outstanding are anti-dilutive. In 2022, there
were no anti-dilutive instruments that were not included in the calculations
that would have had a material impact on the basic earnings per share.
There are no significant Ordinary Share issues post the reporting date, save
for those disclosed in note 28 that would materially affect this calculation.
10 Intangible assets
Group
Exploration Company & IT software assets Total Exploration & evaluation assets Company & IT software assets Total
& (Restated) (Restated)
evaluation assets
2022 2022 2022 2021 2021 2021
£000 £000 £000 £000 £000 £000
At cost
At beginning of the year (restated)(1) 994 336 1,330 13,875 321 14,196
Additions 2,167 5 2,172 549 15 564
Disposals - (29) (29) - - -
Disposals prior periods(2) - (13,430) - (13,430)
_________ _________ ________ _________ _________ ________
At end of the year 3,161 312 3,473 994 336 1,330
_________ _________ ________ _________ _________ ________
Amortisation
At beginning of the year (restated)(1) - (261) (261) (12,565) (151) (12,716)
Amortisation - (43) (43) - (110) (110)
Impairment - - - (865) - (865)
Disposals prior periods(2) - - - 13,430 - 13,430
________ ________ ________ ________ ________ ________
At end of the year - (304) (304) - (261) (261)
_________ _________ ________ ________ ________ ________
Net book value
At 31 December 2022 3,161 8 3,169
At 1 January 2022 994 75 1,069
At 1 January 2021 1,309 170 1,479
(1) Skipper licence was relinquished and impaired in 2019 Both Skipper related
costs and accumulated impairments of £22.3M have been derecognised from the
2021 opening balance. There is £nil impact on Group Statement of Financial
Position in 2022.
(2) After completing the technical analysis of Harvey, the Group fully
determined the Harvey licence in December 2021. Harvey licence cost of £13.4
million were fully impaired in 2021. Both the costs and accumulated
impairments of the Harvey licence of £13.4 million have been derecognised in
the comparative period in the above table. There is £nil impact on Group
Statement of Financial Position in 2022.
The Group does not hold any property, plant and equipment within exploration
and evaluation assets.
The additions to E&E assets during the year relate predominantly to
geological and geophysical surveys, well planning and contracting activities
in respect to the Goddard and Kelham North/Central appraisal wells.
The amount for Exploration and evaluation assets represents active exploration
and appraisal projects. These will ultimately be written off to the Income
Statement as exploration costs if commercial reserves are not established but
are carried forward in the Statement of Financial Position whilst the
determination process is not yet completed and there are no indications of
impairment having regard to the indicators under IFRS 6.
In accordance with its accounting policies each CGU is evaluated annually for
impairment, with an impairment test required when a change in facts and
circumstances, in particular with regard to the remaining licence terms,
likelihood of renewal, likelihood of further expenditures and ongoing acquired
data for each area, result in an indication of impairment. Exploration and
evaluation assets at 31 December 2022 comprise the Group's interest in the
Abbeydale appraisal, the Goddard pre-development prospects and Panther and
Grafton.
11 Property, plant and equipment
Group
D&P assets Phase 1 D&P assets Phase 2 Pipeline assets Right of use assets Admin Total
£000 £000 £000 £000 Assets £000
£000
Cost
At 1 January 2021 33,675 7,150 12,597 18,550 637 72,609
Additions in the year(1) 57,959 289 17,487 2,753 17 78,505
Decommissioning asset revisions (note 17) restated 11,613 (17) (1,948) - - 9,648
______ ______ ______ _____ ______ ______
At 31 December 2021(1) 103,247 7,422 28,136 21,303 654 160,762
______ ______ ______ _____ ______ ______
Additions in the year 54,757 960 5,603 22,383 60 83,763
Decommissioning asset revisions (note 17) 10,559 (806) 4,148 - - 13,901
Asset Impairment and write downs (43,432) (7,576) - - (52) (51,060)
______ ______ ______ _____ ______ ______
At 31 December 2022 125,131 - 37,887 43,686 662 207,366
______ ______ ______ _____ ______ ______
Depreciation
At 1 January 2021 - - - (2,376) (270) (2,646)
Charge for the year - - - (14,276) (163) (14,439)
______ ______ ______ _____ ______ ______
At 31 December 2021 - - - (16,652) (433) (17,085)
Charge for the year (11,694) - (1,494) (15,006) (99) (28,293)
______ ______ ______ _____ ______ ______
At 31 December 2022 (11,694) - (1,494) (31,658) (532) (45,378)
______ ______ ______ _____ ______ ______
Net book value
At 31 December 2022 113,437 - 36,393 12,028 130 161,988
At 31 December 2021 103,247 7,422 28,136 4,651 221 143,677
(1) See Note 1 of the notes forming part of the financial statements for more
details on the prior year restatement.
Following completion of the Saturn Banks Reception Facilities (SBRF) at the
Bacton terminal in early 2022, the Blythe and Elgood fields commenced
production, resulting in depletion and depreciation charge during the year.
Depletion charges on gas assets are classified within Cost of Sales (see note
4). Decommissioning asset revisions reflect updated cost estimates for the
year (see note 17).
Following the operational delays and disappointing results of the Southwark
drilling campaign, which resulted in a downgrade of 2P reserves associated
with the field, and the downgrade in Elgood reserves, the Group has tested
D&P Phase 1 assets for impairment. For each CGU, the recoverable amount
has been determined using the value in use method which constitutes a level 3
valuation within the fair value hierarchy. The recoverable amount is supported
by the fair value derived from a discounted cash flow valuation of the 2P
production profile. As disclosed in note 1, under 'critical judgements', key
estimates include 2P commercial reserves, production profiles, gas price,
capital expenditure estimates and discount rate. The 2P reserves downgrade on
the Southwark gas field CGU, which represents investment to date in the A-1
and A-2 wells on Southwark, to 10.0 BCF (2021: 71.2 BCF) resulted in a £43.4
million (2021: £nil) impairment to D&P Phase 1 assets. The Directors were
satisfied that no further provision for impairment against the remaining
carrying value of the D&P Phase 1 assets.
Phase 2 development and production assets (which include Nailsworth and
Elland) reserves were reclassified to 2C resources. This resulted in a full
impairment of £7.6 million (2021: £nil) for the Phase 2 assets during the
year of due to the value in use calculation supported by 2P reserves under the
Groups accounting policy (see note 1).
Right of use assets predominantly relate to the Shelf Perseverance drilling
rig contract and support vessels. The Group's net share of £7.4 million
(2021: £8.0 million) of depreciation of these right of use assets is
capitalised to the development & production assets of the Group. Thames
pipeline and office right of use assets depreciation is expensed. All leases
are accounted for by recognising a right-of-use asset and a lease liability
except for:
• Leases of low value assets; and
• Leases with a duration of 12 months or less.
See Note 23 for disclosures around the Group's lease liabilities.
Company
D&P assets Right of use assets Admin assets Total D&P assets Phase 1 Right of use assets Admin assets Total
Phase 1
2022 2022 2022 2022 2021 2021 2021 2021
£000 £000 £000 £000 £000 £000 £000 £000
Cost
At beginning of the year - 21,303 654 21,957 1,959 18,550 637 21,146
Additions - 22,383 8 22,391 - 2,753 17 2,770
______ ______ ______ _____ ______ ______ ______ _____
At end of the year - 43,686 662 44,348 1,959 21,303 654 23,916
______ ______ ______ _____ ______ ______ ______ _____
Depreciation
At beginning of the year - (16,652) (433) (17,085) - (2,376) (270) (2,646)
Charge for the year - (15,006) (99) (15,105) (1,959) (14,276) (163) (16,398)
______ ______ ______ _____ ______ ______ ______ _____
At end of the year - (31,658) (532) (32,190) (1,959) (16,652) (433) (19,044)
______ ______ ______ _____ ______ ______ _____ _____
Net book value
At 31 December 2022
- 12,028 130 12,158
At 1 January 2022
- 4,651 221 4,872
Right of use assets predominantly relate to the Shelf Perseverance drilling
rig contract and support vessels. The depreciation of these right of use
assets is capitalised to the development & production assets of the Group.
Other minor right of use assets include land and property leases of the
Company. All leases are accounted for by recognising a right-of-use asset and
a lease liability except for:
· Leases of low value assets; and
· Leases with a duration of 12 months or less.
See Note 23 for disclosures around the Company's lease liabilities.
All Company assets were assessed for impairment, but no impairment indicators
were identified.
12 Convertible Loans
The table below sets out the opening, movement and closing position of the LOG
loan.
2022 2021
£000 £000
Balance at the beginning of the year 8,822 8,037
Unwinding of the discount 1,000 1,001
Gain on loan modification - (216)
_______ _______
9,822 8,822
_______ _______
The £11.6 million long-term, unsecured, subordinated to other debt the Group
holds, non-interest-bearing Loan Note Instrument allows for conversion of the
loan into 60,872,631 Ordinary Shares at a strike price of 19 pence per share
until maturity. The maturity date of the loan is 23 September 2023 and
remained in place during the year.
13 Investments
Shares Loans
in Group to Group
Company companies companies Total
£000 £000 £000
At cost
At 1 January 2021 15,486 44,906 60,392
Additions(1) - 64,735 64,735
_________ _________ _________
At 31 December 2021(1) 15,486 109,641 125,127
Additions - 63,749 63,749
Repayments - (68,933) (68,933)
_________ _________ _________
At 31 December 2022 15,486 104,457 119,943
_________ _________ _________
(1) See Note 1 of the notes forming part of the financial statements for more
details on the prior year restatement.
Loans to Group subsidiaries are interest free and repayable on demand. During
the year, repayments of £68.9 million were made to the Company from revenues
generated by the Group's gas asset and the balance of the Loans are expected
to be recovered from future revenues generated by the Group's UK gas assets.
At the year end, the Company reviewed the loan balances for impairment. In
line with the requirements of IFRS 9, the Company calculated an expected
credit loss equivalent to the lifetime expected credit losses using the value
in use methodology. The Company reviewed the recoverability scenarios of each
loan to subsidiaries. The Company applies no discounting to the expected
credit loss calculation as the effective interest rate is considered to be nil
as the loans are interest free and payable on demand. For exploration and
evaluation assets, estimated discounted cash flows are risk-weighted for costs
and future exploration success. After taking into account these scenarios, the
Directors believe the carrying value of these loans to be fully recoverable.
The Company's subsidiaries, all registered at 60 Gracechurch Street, London
EC3V 0HR, are as follows:
Country of Area of
Directly held incorporation operation %
IOG Infrastructure Limited United Kingdom United Kingdom 100
IOG North Sea Limited United Kingdom United Kingdom 100
IOG UK Ltd United Kingdom United Kingdom 100
Avalonia Energy Limited (dormant) United Kingdom United Kingdom 100
Held by Avalonia Energy Limited
Avalonia Goddard Limited (dormant) United Kingdom United Kingdom 100
Avalonia Abbeydale Limited (dormant) United Kingdom United Kingdom 100
Avalonia Energy Appraisal Limited (dormant) United Kingdom United Kingdom 100
All three active subsidiaries are engaged in the business of oil and gas
appraisal, development and/or operations in the UK North Sea.
The four dormant companies were incorporated in 2018 and 2019 and have been
made available to support any potential Group restructure following
refinancing of the Group.
The financial reporting periods for each subsidiary entity are consistent with
the Company and end on 31 December.
14 Interests in production licences
As at 31 December 2022, all nine Group UK Offshore Production Licences, were
owned 50% by either IOG North Sea Limited or IOG UK Ltd. The Saturn Banks
Pipeline PL370 and Bacton Gas Terminal assets are owned 50% by IOG
Infrastructure Limited.
15 Trade and other receivables
2022 2021
£000 £000
Group
Trade receivables 6,515 -
VAT recoverable 297 1,455
Prepayments 1,920 245
Other receivables 174 5
______ ______
8,906 1,705
______ ______
Company
VAT recoverable 296 1,455
Prepayments 263 245
Other receivables 9 5
______ ______
568 1,705
______ ______
Trade debtors represent receivable balances for December 2022 gas sales from
BP Gas Marketing Limited of £6.5 million (2021: £nil) and for condensate
sales from Haltermann Carless UK Limited of £60,000 (2021: £nil). Both
amounts were received in January 2023. Prepayments of £1.9 million relate to
advance payments made to ODE Asset Management who act as Duty Holder for IOG's
operated assets and minor prepayments for other general administrative
services.
The Company has considered the carrying value of its trade debtors in the
context of IFRS 9 and has assessed the debtors ability to repay the amount
due. In assessing the expected credit loss ('ECL') of the receivables, the
Company considered expected future cash flows from the counterparties, their
creditworthiness, any increase in credit risk, past payment performance and
concluded there is no material ECL provision required.
16 Trade and other payables
2022 2021
£000 £000
Group
Accruals 21,080 11,933
Operator advance accounts 15,843 11,728
Lease liabilities 14,609 11,068
Trade payables 11,099 7,713
Contingent consideration payable 750 659
Tax payable 268 367
Decommissioning liability 409 -
_______ _______
64,058 43,468
_______ _______
Company
Lease liabilities 14,609 11,068
Trade payables 11,099 7,713
Accruals 850 1,294
Contingent consideration payable 750 659
Tax payable 268 367
_______ ______
27,576 21,101
_______ ___ ___
Current liabilities represent £21.1 million (2021: £11.9 million) of
accruals for the value of work carried out under engineering, construction,
procurement and commissioning activities and contracts, £15.8 million (2021:
£11.7 million) operators advance accounts representing the balance due to JV
partners, being the difference between cash calls received and billing
statements, £14.6 million (2021: £11.1 million) lease liabilities under IFRS
16 relate to the future payment obligations within the year, £11.1 million
(2021: £7.7 million) trade payables of unpaid invoices to various suppliers
and service providers, £750,000 (2021: £659,000) contingent consideration
for an additional consideration payable 3 months after first gas as part of
the acquisition of the Southwark asset, £268,000 (2021: £367,000) Employer
tax payable is due to HMRC at end of the year. Elland suspended well
decommissioning of £409,000 (2021: £nil) is scheduled to take place in 2023.
Trade and other payables in 2021 have been restated; see note 1 for details.
17 Non-current liabilities
2022 2021
£000 £000
Group
Long-term loans 97,437 91,257
Lease liability 1,273 395
Deferred tax liability 11,362 -
Decommissioning provision 29,778 15,837
_______ _______
139,850 107,489
_______ _______
Company
Long-term loans 97,437 91,257
Lease liability 1,273 395
_______ _______
98,710 91,652
_______ _______
Long-term loans:
The Nordic bond issued on 20 September 2019 represents £87.6 million (2021:
£82.4 million) of the long-term loans balance with the LOG loan of £9.8
million being the balance of the total of £97.4 million. See note 22 for
further details of the Nordic bond.
The amounts drawn on LOG loans at 31 December 2022 and 31 December 2021 were
as follows:
Loan Facility Entity Effective Date Maturity Date Principal Interest
£11.6 million convertible loan, 5 year facility IOG plc 28 September 2019 23 September 2024 £11.6 million Nil
See note 12 for information relating to the outstanding LOG loan.
Decommissioning provision:
2022 2021
£000 £000
At 1 January 15,837 6,226
New provisions and changes in estimates 13,901 9,601
Unwinding of decommissioning provision discount 449 10
Reclassification to short term liability (409) -
_______ _______
At 31 December 29,778 15,837
_______ _______
The Group provides for the present value of estimated future decommissioning
costs for its gas properties in the UK Southern North Sea. These costs are
updated annually based upon a review of both estimated cost, inflation and
discount rates. Periodically, the Group will undertake a more detailed
technical assessment by both internal and external specialists as appropriate.
The amounts shown are expected to crystallise in 2038. The inflation rate used
in the calculation of the decommissioning provision at 31 December 2022 was
2.0% (2021: 2.0%). The discount rate used in the calculation of the
decommissioning provision at 31 December 2022 was 4.03% (2021: 2.75%).
The reclassification to short term liability relates to the decommissioning
for a suspended well on the Elland Licence P039. During 2022, the Elland
abandonment scope was reviewed and it was been established that abandonment
can be completed using a vessel instead of a rig, which has significantly
reduced the costs. The abandonment expenditure was revised to £0.8 million
gross (2021: £2.4 million), which is £0.4 million net to the Company (2021:
£1.2 million).
18 Net Debt
IOG uses the following definition of net debt - restricted cash and cash
equivalents plus the financial asset, less total loans.
2022 2021
Notes £000 £000
Restricted cash 2,564 3,429
Non-current restricted cash 21 3,116 -
Cash and cash equivalents 26,693 31,255
Loans (97,437) (91,257)
_______ _______
Net debt (65,064) (56,573)
_______ _______
19 Share capital
Share Share
capital premium Total
Number £000 £000 £000
Authorised, allotted, issued and fully paid
At 1 January 2021
- Ordinary Shares of 1p each 488,211,155 4,882 49,989 54,871
Equity issued:
- September 2021, Ordinary Shares of 1p,(1) 33,800,000 338 8,112 8,450
- Other LTIP and Salary sacrifice share exercises 1,753,057 18 48 66
523,764,212 5,238 58,149 63,387
At 31 December 2021 523,764,212 5,238 58,149 63,387
- Ordinary shares of 1p each
Equity issued:
( )
- Other LTIP and Salary sacrifice share exercises 1,273,141 12 24 36
( ) _________ _________ _________ _________
At 31 December 2022 525,037,353 5,250 58,173 63,423
- Ordinary Shares of 1p each
_________ _________ _________ _________
( )
(1) During 2021, the Company carried out a share placement of 33,800,00 at 25
pence per share.
20 Share based payments
IOG plc operates a Company Share Option Plan (CSOP) under which all its share
options are granted. The Company has outstanding share options issued which
are not exercised under previously established plans that are no longer used
by the Company. The following expenses have been recognised for share option
grants under the Company's CSOP in the Statement of Comprehensive Income
arising on share-based payments and included within administrative expenses:
2022 2021
£000 £000
Share based payment charge 844 1,284
The Company granted the following share options under its share option plans
as follows:
Number Price Date of Grant Expiry
1 January 2021 25,290,322 7.70p
Salary/fee sacrifice options 972,685 1p 28 Feb 2021 28 Feb 26
CSOP cancelled/expired (3,175,284) 1p
CSOP options 9,199,640 1p Various dates in 2021 Various dates in 2031
Salary/fee sacrifice options 479,052 1p 31 Aug 2021 28 Sept 26
Options exercised (2,072,252)
31 December 2021 30,694,163 6.53p
CSOP cancelled/expired (1,596,434) 1p
CSOP options 5,580,328 1p Various dates in 2022 Various dates in 2032
Options exercised (1,273,141)
31 December 2022 33,404,916 4.98 p
Of the remaining staff options, 33,404,916 outstanding at 31 December 2022,
1,273,141 were exercised during the year, 5,580,328 issued and 1,596,434 have
been cancelled. Of the remaining staff options, 30,694,163 outstanding at 31
December 2021, 2,072,252 were exercised during the year and 3,175,284 have
been cancelled. The fair value of these options exercised was transferred from
the Share-based Payment Reserve to Accumulated Loss.
All salary/fee sacrifice options outstanding at 31 December 2022 were issued
at an exercise price of 1p per share and carry no additional performance
conditions. These shares were issued at a volume calculated by taking the
amount owing and dividing by the volume weighted average price for the period
to which the salary/fee sacrifice pertains.
CSOP Valuation
The 2022 CSOP valuation is based on a Log-normal Monte-Carlo stochastic
model. The valuation model assumes:
11 November 17 March
2022 2022 2021
£000 £000 £000
Share price at date of grant 12.40p 37.70p 22.50p
Exercise price 1.00p 1.00p 1.00p
Option life 10 years 10 years 10 years
Risk-free rate 3.23% 1.31% 0.17%
Share price volatility 76.35% 55.71% 64.56%
Iterations 10,000 10,000 10,000
All share options outstanding at 31 December 2022 were issued to option
holders with, other than the target price, several non-market based
performance criteria. Non-market based performance criteria included the
delivery, measurement, control and management of an appropriate HSE statement
and policy together with a Group-wide HSE focussed culture.
The remaining average contractual life of the 33,404,916 options outstanding
at 31 December 2022 (2021: 30,694,163) was 3.2 years at that date (2021: 4.2
years) of which 5,798,288 were exercisable at 31 December 2022 (2021:
4,480,836).
The weighted average exercise price of the options remaining was 4.98p at 31
December 2022 (2021: 6.53p).
Further details for Directors are provided on pages 26 and 27.
The Company did not grant any warrants in the current year (2021: nil). No
warrants were exercised during the year (2021: nil) and no warrants lapsed
during the year (2021: nil) and are shown as follows:
Number Price Date of Grant Expiry
1 January 2022 20,000,000 32.18p 13/09/2018 31/08/2023
31 December 2022 20,000,000 32.18p 13/09/2018 31/08/2023
The fair value of 20,000,000 warrants granted to London Oil & Gas Limited
on 13 September 2018 was calculated using the Black-Scholes option pricing
model, as £4.2 million, all of which was recognised as an issue cost of the
£15 million LOG loan facility, held at amortised cost using the effective
interest method. The exercise price of these warrants was determined as
32.18p.
The following assumptions were applied in the LOG warrant award calculation:
Risk free interest rate 1.50%
Dividend yield nil
Weighted average life expectancy 4 years
Volatility factor 96.45%
A volatility of 96.45% has been applied based upon the Company's share price
over the period from the Company's listing on AIM on 30 September 2013 until
13 September 2019.
The remaining average contractual life of the 20,000,000 warrants outstanding
at 31 December 2022 (2021: 20,000,000) was 0.66 years at that date (2021: 1.66
years). All such warrants were exercisable at 31 December 2022.
The weighted average exercise price of the warrants remaining was 32.18p at 31
December 2022 (2021: 32.18p). No further warrants have been issued or
exercised as at 16 March 2023.
21 Restricted cash, Cash and cash equivalents
2022 2021
Group £000 £000
Restricted cash - Long term 3,116 -
Restricted cash - Short term 2,564 3,429
Cash at bank 26,693 31,255
Company
Restricted cash 2,564 2,066
Cash at bank 26,693 31,255
Restricted cash at 31 December 2022 includes £2.6 million (2021: £3.4
million) of restricted deposits in a Euro-denominated Debt Service Reserve
Account following the Norwegian Bond issue and a £3.1 million (2021: £1.4
million) deposit secured against decommissioning provisions of its
infrastructure assets. Restricted cash balances of £2.6 million for the Group
and £2.6 million for the Company are available within 1 year.
Cash and cash equivalents comprise cash in hand, deposits and other short-term
money market deposit accounts that are readily convertible into known amounts
of cash. The fair value of cash and cash equivalents is £26.7 million (2021:
£31.3 million).
22 Bonds payable
On 20 September 2019, the Company issued €100 million Norwegian Bonds on the
Oslo Børs to fund the Phase 1 development program.
2022 2021
£000 £000
Balance at the beginning of the year 82,436 87,777
Amortisation of transaction fees 560 560
Interest charged 8,452 8,253
Interest Paid (8,452) (8,253)
Currency revaluation 4,620 (5,901)
_______ _______
87,616 82,436
_______ _______
The secured callable bonds were issued on 20 September 2019 by IOG plc at an
issue price of par. The bonds have a term of five years and will be repaid in
full at maturity. The bonds carry a coupon of 9.5% plus 3 month EURIBOR with a
EURIBOR floor of 0% and were issued at par. The Bond is callable 3 years after
issuance with an initial call premium of 50% of the coupon (i.e. repayable at
a cost of €104.75 million if 3 month EURIBOR is at zero or lower), declining
by 10% every six months thereafter.
Bond covenants
· Minimum liquidity of €2 million up to, and including, six
months from the first gas date and €5 million thereafter at all times.
· Minimum leverage ratio of 2.5:1 from the first reporting date
following six months after the first gas date.
· Minimum interest cover ratio of five times cover of interest to
EBITDA from the first reporting date following six months after the first gas
date.
As at 31 December 2022, the ratio of net debt to EBITDA at 31 December 2022
was 1.1 times and interest cover was 7.0 times. Full terms and conditions of
the Bonds can be seen in 'Bond Terms' document which is publicly available at:
https://www.iog.co.uk/media/1237/bond-terms-execution-version-190919.pdf
(https://www.iog.co.uk/media/1237/bond-terms-execution-version-190919.pdf)
23 Lease liabilities
2022 2021
£000 £000
Current
At 1 January 11,068 13,781
Interest expenses 1,882 1,754
Lease payments (18,608) (12,307)
Additions 20,267 7,840
_______ _______
At 31 December _______ _______
14,609 11,068
_______ _______
Long term
At 1 January 395 4,968
Additions 941 395
Move to current (63) (4,968)
At 31 December _______ _______
1,273 395
_______ _______
Lease payments represent the Group and Company's share of Drilling Rig rental,
PSV marine supply vessel rental, ERV marine emergency rapid response vessel
rental, office lease rental payments at the London and Norwich offices,
together with the Crown Estate lease for the rights for the Saturn Banks
Pipeline to cross the foreshore at Bacton. During 2022, the Company continued
with drilling rig contract with Shelf Drilling (UK) Ltd (contract transferred
from Noble Corporation during the year) for the Noble Hans Deul jack-up
drilling rig (to be renamed the Shelf Perseverance) for which payments
commenced in 2021 and therefore subsequently continued with both the marine
supply vessel and marine emergency rapid response vessel. Additionally, in
2022 the Company entered a lease for the Norwich office.
24 Financial instruments
Significant accounting policies
Details of the significant accounting policies in respect of financial
instruments are disclosed in Note 1 of the financial statements.
Financial risk management
The Board seeks to minimise its exposure to financial risk by reviewing and
agreeing policies for managing each financial risk and monitoring them on a
regular basis. At this stage, no formal policies have been put in place to
hedge the Group and Company's activities to the exposure to currency risk or
interest risk and no derivatives or hedges were entered during the year.
General objectives, policies and processes
The Board has overall responsibility for the determination of the Group and
Company's risk management objectives and policies and, whilst retaining
ultimate responsibility for them, it has delegated the authority for designing
and operating processes that ensure the effective implementation of its
objectives and policies to the Group's finance function. The Board receives
regular reports from the Chief Financial Officer through which it reviews the
effectiveness of the processes put in place and the appropriateness of the
objectives and policies it sets.
The Group is exposed through its operations to the following financial risks:
• Liquidity risk;
• Credit risk;
• Commodity price risk;
• Cash flow interest rate risk; and
• Foreign exchange risk
The overall objective of the Board is to set policies that seek to reduce risk
as far as possible without unduly affecting the Group and Company's
competitiveness and flexibility. Further details regarding these policies
are set out below.
Principal financial instruments
The principal financial instruments used by the Group and Company, from which
financial instrument risk may arise are as follows:
• Cash and cash equivalents
• Restricted cash
• Loans
• Other financial assets
• Trade and other receivables
• Trade and other payables
• Bonds
Liquidity risk
The Group and Company's policy is to ensure that it will always have
sufficient cash to allow it to meet its liabilities when they become due. To
achieve this aim, it seeks to maintain readily available cash balances
supplemented by borrowing facilities sufficient to meet expected requirements
for a period of at least twelve to eighteen months for personnel costs,
overheads, working capital and as commitments dictate for capital spend.
Rolling cash forecasts, which are essentially the current budgeting and
reforecasting process, identifying the liquidity requirements of the Group and
Company, are produced frequently. These are reviewed and approved regularly
by management and the Board to ensure that sufficient financial resources are
made available. The Group's oil and gas exploration and development activities
are currently funded through the Company with existing cash balances,
operating cash flow generated in the period and joint venture partner cash
call receipts from CER.
Greater than Greater Total
6 months 6 months, less than undiscounted Carrying
or less than 12 months 12 months amount
2022 Group £000 £000 £000 £000 £000
Current financial liabilities
Trade and other payables 11,098 - - 11,098 11,098
Lease liability - 14,609 - 14,609 14,609
Accruals 21,077 - - 21,077 21,077
Deferred consideration 750 - - 750 750
Non-current financial liabilities
Loans - - 11,566 11,566 9,822
Lease liability - - 1,273 1,273 1,273
Deferred tax liability - - 11,362 11,362 11,362
Bonds 5,171 5,200 96,398 106,769 87,615
________ _________ ________ _________ ________
38,096 19,809 120,599 178,504 157,606
________ _________ ________ _________ ________
2021 Group
Current financial liabilities
Trade and other payables 7,708 - - 7,708 7,708
Lease liability 10,372 1,083 - 11,455 11,068
Accruals 13,345 - - 13,345 13,345
Non-current financial liabilities
Deferred Consideration - 750 - 750 659
Loans - - 11,566 11,566 8,821
Lease liability - - 414 414 395
Bonds 4,034 4,034 97,485 105,554 82,435
________ _________ ________ _________ ________
35,459 5,867 109,465 150,792 124,431
________ _________ ________ _________ ________
Greater than Greater Total
6 months 6 months, less than undiscounted Carrying
or less than 12 months 12 months amount
2022 Company £000 £000 £000 £000 £000
Current financial liabilities
Trade and other payables 11,098 - - 11,098 11,098
Lease liability - 14,609 - 14,609 14,609
Accruals 828 - - 828 828
Deferred consideration 750 - - 750 750
Non-current financial liabilities
Loans - - 11,566 11,566 9,822
Lease liability - - 1,273 1,273 1,273
Bonds 5,171 5,200 96,398 106,769 87,615
________ _________ ________ _________ ________
17,847 19,809 109,237 146,893 125,995
________ _________ ________ _________ ________
2021 Company
Current financial liabilities
Trade and other payables 7,708 - - 7,708 7,708
Deferred Consideration 10,372 1,083 - 11,455 11,068
Accruals 2,723 - - 2,723 2,723
Non-current financial liabilities
Deferred Consideration - 750 - 750 659
Loans - - 11,566 11,566 8,821
Lease liability - 414 414 395
Bonds 4,034 4,034 97,485 105,554 82,435
________ _________ ________ _________ ________
24,837 5,867 109,465 140,170 113,809
________ _________ ________ _________ ________
Credit risk
Credit risk arises principally from the Group's and Company's trade and other
receivables, restricted cash, cash and cash equivalents, and loans to
subsidiaries (Company). It is the risk that the counterparty fails to
discharge its obligation in respect of the instrument. The credit risk on
liquid funds is limited because the counterparties are banks with credit
ratings assigned by international credit rating agencies. The Group places
funds only with selected organisations with ratings of 'A' or above as ranked
by Standard & Poor's for both long and short-term debt. Funds are
currently placed with the National Westminster Bank plc and DNB Bank ASA for
the DSRA. Under IFRS 9 there is no material impact for both the Group and
Company when assessing expected credit losses of its receivables.
The Group made investments and advances into subsidiary undertakings during
the year and these mostly relate to the funding of the SNS Hub Development
Projects, and the Company commenced recovery of these loans in the period from
production from the Blythe and Elgood gas fields held by IOG North Sea
Limited. The Company expects to recover the outstanding loans through future
gas sales under the licences held by its subsidiaries from current and future
developments. Loans to subsidiary undertakings are recognised at amortised
cost in accordance with IFRS 9. The loans have no maturity date and are not
repayable until the respective subsidiary entity has sufficient cash to repay
the loan. The Board has accordingly assessed the expected repayment dates
based on the strategic forecasts approved by the Board.
As at the reporting date, the Group had £9.0 million external receivables
(2021: £nil).
IFRS 9 introduced a new impairment model that requires the recognition of ECLs
on financial assets at amortised cost. The ECL computation considers forward
looking information to recognise impairment allowances earlier. In accordance
with IFRS 9, the Group calculated its ECL based on its exposure to credit risk
on its trade receivables at the end of the year and did not recognise an ECL
(see note 15). Intercompany exposures, where appropriate, are also in scope
under IFRS 9. The Company assesses the loans made to subsidiary undertakings
on the basis of the relevant subsidiaries' long-term strategic forecasts and
alongside the Board's commercial rationale for providing the specific loan.
The loans are not repayable on demand and are expected to be repaid once the
underlying assets progress into the production phase when cash inflows are
generated. Based on the methodology set out by the standard, the Board has for
each intercompany loan, assessed the probability of the default, the loss
given default and the expected exposure to compute the ECLs. The Board has
incorporated relevant medium and long-term macroeconomic forecasts in their
assessment which is included as a principle consideration in the entity's
strategic forecasts. Such factors include gas price sensitivities, funding
requirements, reserve and resource estimates. The Board has concluded that any
ECLs to be recognised are not material to these financial statements.
Accordingly, the Company has not recognised any expected credit loss for the
balances owed by subsidiary undertakings recognised on the Balance Sheet at
amortised cost. The Group and Company do not hold any collateral as security
for any external financial instruments, or otherwise.
The maximum exposure to credit risk is the same as the carrying value of these
items in the financial statements as shown below.
Group Company
2022 2021 2022 2021
£000 £000 £000 £000
Trade receivable 6,515 - - -
Other receivables 2,454 1,445 568 1,705
Loans to subsidiaries - - 104,457 109,641
Restricted cash 5,680 3,429 2,564 2,066
Cash and cash equivalents 26,693 31,255 26,693 31,255
Commodity price risk
The Group currently has not entered into any commodity price hedging
instruments. The Group does occasionally fix month ahead gas prices under its
Gas Sales Agreement over a portion of its production for which it is not
required to post collateral. As at 31 December 2022, the Group had fixed the
gas price for January at 319 pence per therm for 30,000 therms of its daily
production.
The Group commenced gas production during the year. The Group's asset
valuations and cash flow modelling make assumptions on the anticipated gas
price for the period of expected production. The Group uses a seasonally
adjusted flat pricing structure that is not inflated over the expected
production life of the asset.
Cash flow interest rate risk
The Group's exposure to interest rate risk arises from its Bond (see note 22)
and restricted cash, cash and cash equivalents. The Group has a €100 million
Bond that carries a coupon of 9.5% plus 3 month EURIBOR with a EURIBOR floor
of 0%. An increase of 100 basis points or a decrease of 25 basis points in
interest rates at the reporting date would have had the following effect on
the income statement for the Group and Company. This analysis assumes all
other variables, in particular foreign currency, remain constant.
100 bps increase 25 bps 100 bps increase 25 bps
2022 decrease 2021 decrease
2022 2021
£000 £000 £000 £000
Restricted cash 57 (14) 34 (9)
Cash and cash equivalents 267 (67) 313 (78)
Long-term loans (886) 221 (840) 210
The other financial instruments of the Group that are not included in the
above tables are non-interest bearing and are therefore not subject to
interest rate risk.
Foreign exchange risk
The Group is exposed to foreign currency risk arising from movements in
currency exchange rates. Such exposures arise predominantly from purchases in
currencies other than the Group's functional currency and the Bond which is
denominated in Euros. In relation to the euro denominated Bond and cash held
in DSRA, a 5% strengthening or weakening in the value of euro against sterling
would result in an decrease by £4.5 million or an increase by £4.1 million.
The Company cash balances, included restricted cash, are held in GBP £23.8
million, EUR €8.6 million and USD $1.2 million. This exposure gives rise to
net currency gains and losses recognised in the Statement of Comprehensive
Income. A 5% fluctuation in the GBP sterling rate compared to EUR would give
rise to a £0.4 million gain or £0.4 million loss in the Group and Company's
Statement of Comprehensive Income.
The Group has two current revenue streams. Gas sales are contracted to BP Gas
Marketing Limited and denominated in GBP. Condensate sales are contracted to
Haltermann & Carless UK Limited and are denominated in USD. Condensate
sales represent 5% of total sales of £75.4 million (2021: £nil). The Group
and the Company's cash balances are maintained primarily in GBP Sterling
(which is the functional and reporting currency of each Group company) and EUR
for the Bond DSRA with small balances held in USD to settle any USD
liabilities. No formal contracts have been put in place to hedge the Group and
Company's activities to the exposure to currency risk. It is the Group's
policy to ensure that individual Group entities enter transactions in their
functional currency wherever possible. The Group considers this minimises
any foreign exchange exposure.
Management regularly monitor the currency profile and obtain informal advice
to ensure that the cash balances are held in currencies which minimise the
impact on the results and position of the Group and the Company from foreign
exchange movements.
Capital management
The primary objective of the Group's capital management is to maintain
appropriate levels of funding to meet the commitments of its forward programme
of appraisal and development expenditure, and to safeguard the entity's
ability to continue as a going concern and create shareholder value. The
Director's consider capital to include equity as described in the Statement of
Changes in Equity, and loan notes, as disclosed in Notes 12 and 22.
The Group manages compliance of the Bond and the covenants by reviewing on a
monthly basis its cash flow modelling which incorporates the bond terms and
covenants. Norwegian advisors are also engaged to ensure that any regulatory
requirements are met. At each reporting date the Directors provide
representation that the terms of the bond are satisfied.
25 Financial commitments and contingent liabilities
The Group had outstanding commitments of £5.7 million gross to the joint
operations (the Group's net share is £2.8 million) as at 31 December 2022.
All 2022 committed amounts relate to contracted service awards to suppliers
procured for the development and operation of the Group's phase 1 project
assets (Blythe, Southwark, Elgood, Saturn Banks Facilities and Saturn Banks
Pipeline).
Under the terms of the licences to explore for gas, the Company has certain
commitments that are generally defined by activity rather than expenditure
requirements. The Goddard and Kelham appraisal wells have been approved by the
joint operating committee operated by the Group in a 50%/50% joint
arrangement, and these appraisal wells are committed to be drilled by 30
September 2023 under the current licence terms.
Saturn Banks Pipeline System:
Security in the sum of £0.5 million, the Initial Saturn Banks Pipeline
Decommissioning Security Amount (DSA), was provided on completion of the
Saturn Banks Pipeline SPA in April 2018. In October 2019, following the
completion of the farm-out to CER, this amount was reduced to £0.25
million.
Further security in the sum of £1.8 million was transferred during 2022 to
the Saturn Banks Pipeline Decommissioning Security Amount. The total security
held is £3.1 million (2021: £1.4 million)
Saturn Banks Reception Facilities ("SBRF"):
Security in the sum of £2.0 million, the Initial SBRF Decommissioning
Security Amount, was provided on completion of the SBRF SPA in October 2019.
Following the completion of the farm-out to CER, this amount was reduced to
£1.0 million.
Further security in the sum of £4.0 million, the SBRF Decommissioning
Security Amount, is to be provided 2.5 years following the announcement of
'first gas'. This additional amount is payable in 8 quarterly instalments of
£0.5 million with the first instalment payable 6 months after the declaration
of 'first gas'. During the year, £1.8 million was transferred into security
deposit account to meet the requirement of SBRF Decommissioning Security
Agreement.
Cross-Guarantees:
The Company acts as guarantor to its subsidiary IOG North Sea Limited and its
facilities with LOG. These cross guarantees are considered insurance contracts
in accordance with IFRS 4.
26 Related party transactions
Details of Directors' and key management personnel remuneration are provided
in Note 4.
Rupert Newall, CEO, and persons closely associated, at 31 December 2022 held
4,953,921 ordinary shares of 1p each in the capital of the Company. Rupert was
also the current holder of 5,570,461 share options at 31 December 2022.
Dougie Scott, COO, at 31 December 2022 held 192,289 ordinary shares of 1p each
in the capital of the Company. Dougie was also the current holder of 1,690,141
share options at 31 December 2022.
Fiona MacAulay, Chair, at 31 December 2022 held 269,178 ordinary shares of 1p
each in the capital of the Company. Fiona is also the current holder of
1,000,000 share options at 31 December 2021. Fiona is also entitled to 109,865
share options through salary sacrifice at 31 December 2022.
Esa Ikaheimonen, Non-Executive Director, at 31 December 2022 held 500,000
ordinary shares of 1p each in the capital of the Company. Esa is also the
current holder of 600,000 share options at 31 December 2022. Esa is also
entitled to 868,306 share options through salary sacrifice at 31 December
2022.
Neil Hawkings, Non-Executive Director, at 31 December 2022 held 20,000
ordinary shares of 1p each in the capital of the Company. Neil is also the
current holder of 600,000 share options at 31 December 2022. Neil is also
entitled to 72,999 share options through salary sacrifice at 31 December 2022.
Details of loans and interest charged (only relevant to 2019) by LOG are
detailed in Note 12. The relevant loans outstanding at the end of the year
related to the Company.
27 Notes supporting statements of cash flows
Details of significant non-cash transactions
2022 2021
£000 £000
Equity consideration for settlement of liabilities - -
Group - Loans and borrowings
Current Non-current Total
loans and borrowings
loans and borrowings
loans and borrowings
£000
£000
£000
At 1 January 2021 13,781 13,005 26,786
Lease Liability additions 7,840 395 8,235
Repayments (12,307) - (12,307)
Unwinding of discount 1,754 785 2,539
Move to current loans & borrowings - (4,968) (4,968)
________ ________ ________
At 31 December 2021 11,068 9,217 20,285
Lease Liability additions 20,267 877 21,157
Repayments (18,608) - (18,608)
Unwinding of discount 1,882 1,001 2,871
Move to current loans & borrowings - - -
________ ________ ________
At 31 December 2022 14,609 11,095 25,705
________ ________ ________
Company - Loans and borrowings
Current Non-current Total
loans and borrowings
loans and borrowings
loans and borrowings
£000
£000
£000
At 1 January 2021 13,781 13,005 26,786
Lease Liability additions 7,840 395 8,235
Repayments (12,307) - (12,307)
Unwinding of discount 1,754 785 2,539
Move to current loans & borrowings - (4,968) (4,968)
________ ________ ________
At 31 December 2021 11,068 9,217 20,285
Lease Liability additions 20,279 877 21,157
Repayments (18,608) - (18,608)
Unwinding of discount 1,870 1,001 2,871
Move to current loans & borrowings - - -
________ ________ ________
At 31 December 2022 14,609 11,095 25,705
________ ________ ________
28 Subsequent events
On 5 March 2023, the Blythe H2 well spudded, intended to increase gas
production, limit water production and maximise reserve recovery from the
Blythe reservoir
On 24 February 2023, the Company announced, Fiona MacAulay, who has been Chair
of IOG since December 2018 having first joined the Board in July 2018, has
chosen not to stand for re-election as a director of the Company at the 2023
Annual General Meeting (AGM), which is expected in May. She will therefore be
retiring as Chair and resigning as a Director following the AGM. It is the
Board's intention that, following the AGM, Esa Ikaheimonen will become Chair
of IOG initially on an interim basis. Esa has been the Senior Independent
Non-Executive Director at IOG since March 2019 and is the current Chair of the
Audit Committee.
On 6 February 2023, the Company announced the decision to suspend the
Southwark A2 well following the remediation programme that although
successfully reduced water production from 1,500 bbls/d to an average rate of
380 bbl/d, stabilised gas rates were limited to 2.5 mmscf/d, at a flowing
wellhead pressure of 1186 psi. and evaluate the feasibility of cycled
production and alternative longer-term remediation strategies.
On 12 January 2023, the Group submitted for nine Southern North Sea blocks
across five licences areas in the 33rd UK Offshore Licensing Round, as
operator of the 50:50 joint venture with CER.
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