REG - IOG PLC - Final Results for the Year Ended 31 December 2021
17/03/2022 07:00
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RNS Number : 0677F IOG PLC 17 March 2022
17 March 2022
IOG plc
Final Audited Results for the Year Ended 31 December 2021
IOG plc ("IOG", or "the Company"), (AIM: IOG.L), the Net Zero UK gas and
infrastructure operator focused on high return projects, is pleased to
announce its final audited results for the Year Ended 31 December 2021.
2021 Highlights
Corporate and Operational
· Phase 1 Blythe and Southwark normally unmanned platform
installations were mechanically completed in April 2021 and safely installed
at their offshore field locations in May-June 2021
· Elgood well 48/22c-7 was successfully completed in July 2021,
testing at a surface-constrained maximum rate of 57.8 mmscf/d of gas and 959
bbl/d condensate through an 80/64(th) inch choke
o Reservoir encountered 39ft deep to prognosis and having integrated well
data into subsequent technical analysis, management has updated its gross
estimated 1P/2P/3P reserves to 9.7/14.1/18.3 billion cubic feet (BCF)
· Blythe development well 48/23a-H1 successfully drilled, cleaned
up and flow tested to a maximum gas rate of 45.5 mmscf/d through an 80/64(th)
inch choke within two months of spud
o Having integrated well data into subsequent technical analysis, management
has updated its gross estimated 1P/2P/3P reserves to 25.4/42.5/55.8 BCF
· Offshore subsea and hook-up scopes for Blythe and Elgood fields
completed in November 2021, with one million Phase 1 cumulative manhours
passed in September 2021
· First Southwark development well initially spudded in December
2021 following repair of the Noble Hans Deul rig leg in Dundee (Southwark
drilling subsequently suspended due to seabed scour issues and expected to
resume in March/April 2022 with Southwark First Gas targeted in Q3 2022).
· Phase 1 Duty Holder contract for Installation and Pipeline
Operator, as well as facilities operations and maintenance ("O&M"),
awarded to ODE Asset Management ("ODEAM")
· Inaugural Emissions Assessment released, projecting Phase 1
lifetime average Scope 1 and 2 emission intensity at under 4 kg kgCO2e/boe,
versus North Sea average of 20.2 kgCO2e/boe
· Commitment to Scope 1 and 2 Net Zero emissions from 2021 via
investment in accredited voluntary offsets
· Potential for valuable multi-field "Southern hub" demonstrated
with identification of Kelham North, Kelham Central, Thornbridge and
Thornbridge Deep prospects on the P2442 licence
· Collaboration agreement signed with GeoNetZero Centre for
Doctoral Training to support carbon capture & storage research on quads
48, 49, 52 & 53 (broader Bacton catchment area)
Financial
- Cash balance at period end of £34.7 million (2020:
£80.4million), including restricted cash of £3.4 million (2020: £67.0
million)
- Post tax loss for the year of £4.3 million (2020: £19.3 million)
- Group net debt(1) at year end £56.6 million (2020: £14.1 million)
- Remaining £11.7 million out of £60 million Phase 1 partner
development carry from CER fully utilised
- £140.0 million invested in the Phase 1 development, of which CER
funded £70.0 million for their non-operated share
- Remaining €65.8 million (£59.2 million) drawn down from Bond escrow
account
- €9.7 million (£8.9 million) in Bond interest payments, of which
€4.8 million (£4.4 million) was drawn from the Debt Service Retention
Account (DSRA)
- Gross proceeds of £8.5 million raised through placing and
subscription in September 2021 at 25p/share, a 1% premium to 30-day volume
weighted average price, primarily to fund the Kelham North/Central appraisal
well
(1)Net debt is defined as total loans, less restricted cash and cash and cash
equivalents, adding back the financial asset being the Company's holding of
its own bonds.
Board and Management
· David Gibson appointed as Chief Operator Officer (COO) in
February 2021
· Operational and technical teams further strengthened to support
Phase 1 and facilitate further phases of growth
Post Year End Developments
· Commissioning of onshore Saturn Banks Reception Facilities
completed on 4 March 2022, enabling backgassing of the offshore Saturn Banks
Pipeline System out to Blythe and Elgood
· Phase 1 First Gas was safely and successfully achieved from the
Blythe well on 13 March 2022
· Southwark drilling operations suspended in January 2022 pending
remediation of the drilling location seabed to ensure safe operations with
resumption expected by late Q1 or early Q2 2022
· New gas sales agreement (GSA) signed with BP Gas Marketing
Limited (BPGM), covering all of the Phase 1 fields as well as Nailsworth and
Elland, replacing the 2014 Blythe GSA
· Planning and contracting continuing for the appraisal wells at
Kelham North/Central (P2442: Block 53/1b) and Goddard (P2342: Block 48/11c and
12b), to be drilled by the Noble Hans Deul rig after the second Southwark well
on the same competitive day rate as the Phase 1 wells
o Petrofac appointed Well Operator for these wells and pre-drill site
surveys initiated in Q1 2022
· 3D seismic reprocessing to Pre-Stack Depth Migration underway on
licence P2589 (Panther / Grafton area adjacent to Elland), expected to provide
enhanced view of subsurface and commercial potential later in 2022
· Further to an ongoing comprehensive process of subsurface
re-evaluation of the Company's asset portfolio, revisions to management's
gross volumetric estimates have been made as follows:
o 1P/2P/3P reserves for the Blythe field revised to 25.4/42.5/55.8 BCF
o 1P/2P/3P reserves for the Elgood field revised to 9.7/14.1/18.3 BCF
o 1P/2P/3P reserves for the Southwark field revised to 46.3/71.2/104.7 BCF
o 1C/2C/3C contingent resources for the main Goddard discovery revised to
52.0/115.0/169.0 BCF
o Low/Mid/High prospective resources revised to 16/27/42 BCF and 30/50/73
BCF for the two Goddard flank structures, both with 71% Geological Chance of
Success (GCoS)
o Low/Mid/High prospective resources for the Kelham North and Kelham Central
prospects of 30.0/48.0/67.0 BCF and 12.0/21.0/32.0 BCF respectively, both with
72% GCoS
o Low/Mid/High prospective resources for the Thornbridge prospect estimated
at 19.0/35.0/57.0 BCF, with 64% GCoS
o Low/Mid/High prospective resources for the Thornbridge Deep prospect
revised to 55.0/107.0/167.0 BCF, with 18% GCoS
o 1C/2C/3C contingent resources for the part of the Orrell discovery lying
within the P2442 licence area estimated at 13.0/18.0/21.0 BCF
o No changes at the current time to the management estimates of reserves at
Nailsworth and Elland, to the contingent resources at Abbeydale, Panther and
Grafton, or to the prospective resources at Southsea
Andrew Hockey, CEO of IOG, commented:
"Last year saw an immense effort by the whole IOG team to progress towards
production, culminating in the safe and successful delivery of First Gas from
the Blythe and Elgood fields on 13 and 15 March 2022 respectively. I am very
proud of our team for overcoming the many challenges we've faced and achieving
this major milestone. By working closely together, guided by our core values
of resourcefulness, innovation, drive, efficiency, resilience and safety, we
have turned IOG from an unfunded micro-cap into a material UK gas producer
with exciting further growth plans.
We can now start to reap the benefits of our strategic focus on UK gas, which
has always had compelling economic logic: the UK remains highly dependent on
this commodity that will be pivotal in the global energy transition. Phase 1
production gives IOG both the operational platform and the financial capacity
to deliver incremental value for our shareholders.
I believe we have the right people, assets and partnerships to build on what
we have achieved so far and deliver exciting further phases of growth over the
years ahead: what I call our "project factory". I would like to thank the
whole team, our partner CER and all our contractors for their dedication in
making Phase 1 production a reality. I also owe all our shareholders my
sincere thanks for their continued support in helping us turn IOG, your
company, into a respected UK gas developer and producer. I believe this is
just the start and I look forward to delivering further growth on your
behalf."
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
Andrew Hockey (CEO)
Rupert Newall (CFO)
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 / Oliver Clark
About IOG:
IOG is a Net Zero UK gas and infrastructure operator focused on high-return
projects. The Company's operations are currently concentrated around its
offshore and onshore Saturn Banks infrastructure in the UK Southern North Sea.
Phase 1 of its Saturn Banks Project, which started production in March 2022,
entails the commercialisation of the Blythe, Elgood and Southwark gas fields
through this infrastructure. Phase 2 of the Saturn Banks Project entails the
Nailsworth, Goddard and Elland gas discoveries, which are subject to future
investment decisions and expected to be commercialised through the same export
infrastructure. The Company also holds further licences with additional assets
including the Abbeydale, Panther and Grafton gas discoveries, the Kelham
North, Kelham Central, Thornbridge and Thornbridge Deep prospects, and part of
the Orrell gas discovery. Currently, all IOG's licences are held 50:50 with
its joint venture partner CalEnergy Resources (UK) Limited and operated by
IOG. In addition, the Company continually evaluates further opportunities for
accretive portfolio additions to help generate additional shareholder returns.
Further details are available 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 Andrew Hockey, IOG's CEO, is the qualified person that has
reviewed the technical information contained in this document. Andrew Hockey
has an MSc in Petroleum Geology and has been a member of the Petroleum
Exploration Society of Great Britain since 1983. He has almost 40 years'
operating experience in the upstream oil and gas industry. Andrew Hockey
consents to the inclusion of the information in the form and context in which
it appears.
Chief Executive's Review
2021 Review
Last year saw an immense effort by the whole IOG team to progress towards
production, culminating in the safe and successful delivery of First Gas from
the Blythe and Elgood fields on 13 and 15 March 2022 respectively. I am very
proud of our team for overcoming the many challenges we've faced and achieving
this major milestone. By working closely together, guided by our core values
of resourcefulness, innovation, drive, efficiency, resilience and safety, we
have turned IOG from an unfunded micro-cap into a material UK gas producer
with exciting further growth plans.
I cannot understate the huge effort from all involved from Phase 1 Final
Investment Decision (FID) in late October 2019 to delivering First Gas less
than two and a half years later. However, First Gas has never been the
destination, it is just the first step on a very exciting journey. We can now
start to reap the benefits of our strategic focus on UK gas, which has always
had compelling economic logic: the UK remains highly dependent on this
commodity that will be pivotal in the global energy transition. Phase 1
production gives IOG both the operational platform and the financial capacity
to deliver incremental value for our shareholders.
To put this milestone in its strategic context: IOG is a Net Zero UK gas and
infrastructure operator focused on high-return projects. Each element of this
definition is important. We aim continually to reduce emissions courtesy of
our inherently low carbon intensity operating model and we set the standard as
the first London-listed E&P company to commit to Scope 1 and 2 Net Zero
from 2021. We play to our strengths with a focused but diverse portfolio in
the UK Southern North Sea. We are a specialist gas developer and producer but
also an infrastructure owner, leveraging our expanded offshore Saturn Banks
Pipeline System to capture further opportunities, supported by our onshore
presence at Bacton. We operate our entire offshore portfolio, giving us good
control, while benefitting from a constructive 50:50 joint venture partnership
with CalEnergy Resources (UK) Limited (CER), part of Berkshire Hathaway
Energy. Finally, we focus on maximising risked returns above all other
metrics, through synergistic incremental investments and selective portfolio
additions.
Achieving First Gas is undoubtedly a key step in delivering this strategy. Our
vision is a "project factory" whereby Phase 1 breeds several complementary
further phases: commercialising discovered assets, leveraging owned
infrastructure, maximising operating efficiencies, increasing cost synergies
and driving up returns. A key pillar of this strategy is our continued
investment in subsurface understanding to ensure the best technical
interpretation of all opportunities across our Saturn Banks catchment area.
That includes discovered resources like Nailsworth, Abbeydale, Panther and
Grafton, appraisal assets like Goddard, Kelham North and Kelham Central,
step-out exploration targets like Thornbridge and Southsea, or the many
potential inorganic opportunities that we continually review. While we take a
disciplined approach to screening potential acquisitions against our existing
portfolio, we can move quickly to capture opportunities we see as both
economically and environmentally synergistic.
There were a number of important operational firsts for IOG in 2021. We
progressed from engineering and construction activities to start putting
substantial infrastructure offshore and drilling key wells. The two Phase 1
normally unmanned platform (NUI) installations, Blythe and Southwark, were
completed at HSM Offshore's yard in Schiedam, Netherlands, and then installed
at their field locations over the summer. Delivering our first development
well at Elgood, which tested at a maximum rate of 57.8 mmscf/d gas and 959
bbl/d condensate, was another key milestone. As expected, it was technically
challenging, being the only subsea tie-back in the programme drilled
horizontally through the reservoir section to a Total Depth of 15,472 ft MD.
After Elgood we continued on to drill the Blythe development well, which
tested at a maximum rate of 45.5 mmscf/d. These first two development wells
were safely and successfully completed in six months thanks to the hard work,
resourcefulness and diligent collaboration of the IOG, Petrofac and Noble
Corporation teams. We were then able to complete the offshore subsea and
hook-up scopes later in the year, leaving the onshore recommissioning work to
be completed at Bacton before being able to safely start production. In light
of this tangible progress it was very pleasing to see a significant recovery
in the share price, ending the year at 36p (an increase of over 170% from the
13.2p close a year earlier) and strengthening further still since then.
The most important element of any strategy is of course the people who deliver
it. As with our portfolio, so with the organisation: focusing on quality
rather than quantity to best achieve our strategic plans. Our objective has
always been to build a dynamic culture of continuous improvement and effective
collaboration, with the agility to respond quickly to both threats and
opportunities, underpinned by fundamental respect for each other and for the
environment. Phase 1 has put this objective to the test in unprecedented
circumstances, with remote working and digital communications becoming a new
reality, and we have responded accordingly. With several high-calibre
post-Phase 1 FID appointments now well established, not least our COO David
Gibson who is just over a year into his role, we are now benefitting from
greater continuity and cohesion as we emerge from the Covid-era working
environment. The pandemic presented an undeniable challenge to all these
activities. In the face of Covid-19, our three primary objectives did not
change: protect our people, deliver the project and ensure business
continuity. This was tougher in 2021 with the highly transmissible Omicron
variant causing issues both onshore and offshore, but our team and our
contractors have shown resilience and adaptability to work around these
constraints.
Environmental differentiation is central to our values and strategy - and is a
fundamental pillar of our licence to operate. It has long been our intention
to build a high-return gas business in which low unit costs and low carbon
intensity deliver a sustainable competitive advantage. By promoting a mindset
of sustainability, responsibility, ethics and respect for people and the
environment throughout our activities, we can deliver shareholder returns that
are sustainable in every sense. In Q3 2021 I was very pleased to release our
initial Emissions Assessment report, a key Environmental, Social and
Governance (ESG) objective, which confirmed IOG as an exceptionally low carbon
intensity operator thanks to our small, remotely operated infrastructure. More
importantly, it enabled us to commit to Scope 1 and 2 Net Zero from 2021,
which we are fulfilling through appropriate voluntary carbon market offset
investments. We are also designing future phases of Saturn Banks to be as low
emission - correlating with low cost - as possible.
Our business model sits squarely within the UK's energy policy of meeting the
2050 Net Zero target while maximising the value of economically recoverable
resources. Gas is an essential transition fuel for balancing intermittent
renewable power generation while continuing to provide heating and hot water
to 23 million UK homes. The replacement of coal with gas-fired generation has
significantly advanced the UK's energy transition already, helping to reduce
the emissions of UK energy supply by 70% between 1990 and 2020. However, not
all gas is equal: domestic gas produced with negligible offshore power or
manning requirements is vastly superior from an environmental perspective to
imported LNG, on which the UK has recently become highly dependent. We firmly
believe that domestic gas produced at very low carbon intensity is an
indispensable part of the UK's energy transition: cleaner, more reliable and
better for the UK economy. We are also actively involved in plans to create a
long-term integrated energy hub around Bacton, synthesizing gas, wind,
hydrogen and carbon capture and storage.
2022 Outlook
Building on last year's progress, 2022 will be a really pivotal year for IOG,
with several key catalysts beyond our first production and cashflow.
Delivering Southwark First Gas is important not just in a Phase 1 context but
as the gateway to further phases within our broader area plan. Another key
objective this year is FID on Nailsworth, which is expected to be exported via
Southwark. After the first two Southwark wells the Noble Hans Deul rig will
drill the Goddard and Kelham North/Central appraisal wells, which each have
considerable resource and hub-opening potential. In parallel we are investing
in further 3D seismic reprocessing as the key to understanding the commercial
potential of the Panther-Grafton area. Its proximity to our other assets,
including Elland, creates clear scope for operational and economic synergies,
especially with CER as 50% non-operating partner across the full portfolio.
In the weeks leading up to this report, the world has witnessed the shocking
events unfolding in Ukraine and our thoughts are with all of those directly
affected. At the time of writing, it is impossible to be sure how this
conflict will play out and what its longer-term ramifications may be. However,
what is already clear is that it is sending shockwaves through the energy
industry and causing exceptional volatility in several commodity markets - not
least gas, for which current and forward prices have recently become very
elevated. Whilst as a gas producer IOG is clearly exposed to the upside, such
volatility is likely to have challenging economic impacts and is not conducive
to long-term stability in supply and demand. At IOG, despite witnessing both
extreme lows and highs in gas pricing since Phase 1 FID, our consistent view
has been that we must look through these cycles and plan our business around a
seasonally adjusted long-term 45p/therm price deck. Notwithstanding the
current geopolitical upheaval, we expect that prices will revert towards their
long-term historical averages over time.
In conclusion, I believe we have the right people, assets and partnerships to
build on what we have achieved so far and deliver exciting further phases of
growth over the years ahead: what I call our "project factory". I would like
to thank the whole team, our partner CER and all our contractors for their
dedication in making Phase 1 production a reality. I also owe all our
shareholders my sincere thanks for their continued support in helping us turn
IOG, your company, into a respected UK gas developer and producer. I believe
this is just the start and I look forward to delivering further growth on your
behalf.
Andrew Hockey
Chief Executive Officer
16 March 2022
Operational Update
Saturn Banks Phase 1
Phase 1 Infrastructure
In 2021 IOG renamed the 24" former Thames Pipeline and associated onshore
Thames Reception Facilities as the Saturn Banks Pipeline System (SBPS) and
Saturn Banks Reception Facilities (SBRF) respectively. Through its subsidiary
IOG Infrastructure Limited (IOGIL), IOG owns a 50% operated share in the SBPS
and SBRF, with CER as 50% non-operated partner in each asset. In keeping with
its new economic life, the old Thames Pipeline designation PL370 was replaced
with two new numbers: PL5079 for the inner section, the first 28.5km from
Bacton to the newly installed 24" valve skid, and PL5152 for the outer section
from the 24" valve skid to the 60km point, from where the further 6km
extension to the Southwark platform is planned to be laid in 2022.
In early 2021, installation of the 12" pipeline PL4956 from the SBPS tie-in
point to the Blythe platform and the 6" pipeline PL4955 from Blythe to the
subsea Elgood well were completed. Additionally, an umbilical PLU5039 was
installed and connected between the Blythe platform and the Elgood well.
During 2021 the Company significantly consolidated its technical and
operational capability, through both in-house additions to the team and the
establishment of key third-party relationships. For example, in Q2 2021 ODE
Asset Management (ODEAM) was awarded the contract to operate and maintain the
SBPS and act as Duty Holder for the Blythe and Southwark platforms, while
Petrofac were appointed as Well Operator for the Phase 1 development wells. In
the same quarter the fabrication of the Blythe and Southwark unmanned
platforms was completed, with installation then being undertaken by HSM and
their subcontractor Seaway 7. Once installed on location, both platforms were
powered up and put in communication with ODEAM's temporary onshore control
room, which was then switched over to the Perenco Bacton control room ahead of
First Gas. Importantly, in Q3 2021 the Safety Cases for both the Blythe and
Southwark platforms were also accepted by the UK Health and Safety Executive
(UK HSE).
In Q4 2021 the key offshore SURF and hook-up and commissioning (HUC) scopes
from the Emergency Shutdown Valve (ESDV) onshore at Bacton through to the
Blythe and Elgood wells were completed, demonstrating end-to-end system
integrity in preparation for First Gas from both fields. These scopes include
fabrication, installation and testing of the 24" valve skid at the Blythe-SBPS
tie-in point; connection of PL4956 (12" SBPS-Blythe) and PL4955 (6"
Blythe-Elgood) lines to the Blythe platform risers; tie-in of PL5079 at
Bacton; hook-up of the Blythe and Elgood wells; leak testing and dewatering of
the 6", 12" and 24" lines; and offshore system commissioning. "Walk-to-Work"
vessels were used wherever possible to enable longer shift durations and
minimise helicopter flights. In the meantime, refurbishment, construction and
commissioning of the onshore SBRF continued through 2021 via Bacton terminal
operator Perenco UK Limited (PUK). With all regulatory permits, licences,
approvals and consents in place for production and operation to commence
production at Blythe and Elgood, First Gas was then achieved on 13 March 2022.
Phase 1 Drilling
IOGNSL has a 50% working interest in and is operator of Licence P2260 (Block
48/22c), which was awarded in the 28th Licensing Round. The licence, which
lies immediately to the north-west of the Blythe licence, contains the Elgood
gas field in the Rotliegend Leman Sandstone Formation.
During Q2-3 2021 the subsea Elgood well 48/22c-7 was drilled horizontally
through the reservoir section to a Total Depth of 15,472ft Measured Depth
(MD), intersecting 1,080 ft of high-quality Permian Leman Sandstone reservoir
along hole between 14,290 ft MD and 15,370 ft MD, with a net:gross ratio of
91%, good porosity at 12.4% and average log-derived permeability of 13.3
milliDarcies (mD) versus the P50 prediction of 5mD.
The well was successfully cleaned up and flow tested at a maximum rate of 57.8
mmscf/d of gas and 959 bbl/d condensate through a 80/64th inch choke,
constrained by surface facilities on the rig. The Elgood reservoir was
encountered 39ft deep to prognosis and over the ensuing months the well data
was integrated into updated subsurface analysis as described in the Subsurface
section below.
The Blythe gas field in the Rotliegend Leman Formation, straddles Blocks
48/22b and 48/23a in the SNS in Licence P1736 in which IOGNSL has a 50%
working interest as operator.
In Q3 2021 the Blythe well 48/23a-H1 was drilled by the Noble Hans Deul
jack-up rig through the Blythe platform to a Total Depth of 10,750ft Measured
Depth (MD), intersecting 1,238 ft of good quality Permian Leman Sandstone
reservoir along hole between 9403 ft MD and 10,641 ft MD, with a net:gross
ratio of 95%, porosity at 10.6% and average log-derived permeability of 5.0
milliDarcies (mD). Over the ensuring months the well data was then used to
revise the Company's view of the asset, as described in the Subsurface section
below.
The well was successfully cleaned up and flow tested to a maximum gas rate of
45.5 mmscf/d through an 80/64th inch choke. An operational challenge
experienced during drilling was the loss of drilling mud due to natural
fracturing in the reservoir. This necessitated the use of Lost Circulation
Materials (LCM) down-hole which may have constrained the clean-up flow rate
with drilling mud being recovered to surface during clean-up.
The Southwark gas discovery in the Rotliegend Leman Sandstone Formation sits
in Block 49/21c in Licence P1915 in which IOGUKL has a 50% working interest as
operator. The Southwark Field Development Plan (FDP) envisages a three well
development tied back to the SBPS via a 6km extension to the Southwark
unmanned platform. Following seismic reprocessing to PSDM, seismic
reinterpretation and initial 3D subsurface modelling, the drilling plan was
updated to have the first two wells initially batch drilled after Blythe, with
the third well deferred to incorporate the data and conclusions from the first
two.
Following the Blythe well, one of the Noble Hans Deul jack-up drilling rig's
legs was damaged as it was being mobilised to the Southwark location. After
being repaired in Dundee port, the rig returned to the Southwark location and
the first Southwark well was spudded on 30 December 2021, before rig stability
issues resulted in the requirement to move off location again while a seabed
remediation plan is engineered and executed. These unexpected drilling issues
at Southwark are expected to cause increases to the total Phase 1 outturn
capital expenditure. Southwark drilling is currently expected to resume by
late Q1 or early Q2 2022 and Southwark first gas is therefore now targeted in
Q3 2022.
By the end of 2021 the Phase 1 project had passed significantly over one
million cumulative manhours worked.
Phase 1 Subsurface
Elgood and Blythe (P2260 and P1736)
Over the months following the completion of the Elgood and Blythe wells, the
3D static and dynamic reservoir models have been comprehensively updated for
these fields. Interpretation of the seismic data was revised with the
incorporation of previously unidentified additional faults encountered in
drilling the wells. The area depth conversions were also updated to
incorporate vertical and lateral thickness changes with the Zechstein
evaporitic sequence that were identified while drilling. This sequence sits
above the Rotliegend Leman Sandstone Formation and is a key interval when
converting time seismic data to depth due to rapid velocity changes based on
the lithologies encountered. The difference between the pre-drill modelled
velocities within the Zechstein and those encountered in the well are the
reason that the Elgood well came in 39 ft deep to prognosis. This has impacted
the Gross Rock Volume (GRV) above the Gas-Water Contact. The dynamic models
have also been updated and matched to the well performance observed during the
clean-up process. It was not possible to include dynamic production data from
Elgood or Blythe into the subsurface models in time for the publication of
this report, so the March 2022 volumetric assessments have been based on
static data alone.
Pre-drill management estimated gross 1P/2P/3P reserves for Elgood and Blythe
were 20.2/27.5/33.9 and 20.6/41.2/52.2 respectively. Based on the post well
technical evaluation detailed above, management's updated gross 1P/2P/3P
reserves estimate is 9.6/14.1/18.3 BCF for Elgood and 25.40/42.5/55.8 BCF for
Blythe. Following the initial phase of production, dynamic data will be
assessed and reserve estimates further refined.
Southwark (P1915)
During 2021 a regional evaluation of the Southwark and adjacent Vulcan
Satellite area was undertaken by the Company's subsurface team. This involved
review of the reprocessed PSDM seismic data that was completed in Q1 2021 and
the incorporation of other regional seismic and geological data sets. This new
technical work generated an updated view on the structural framework and top
reservoir geometry of the Southwark field, resulting in an improved
understanding of the location of the bounding faults separating Southwark from
the Leman gas field to the south. This has resulted in a reduction in GRV in
this southwestern area of the field and consequently the previous gross
1P/2P/3P management estimates have reduced from 61.2/94.2/137.7 to
46.3/71.2/104.7 BCF. It was not possible to include data from the Southwark
development wells into the subsurface models in time for the publication of
this report, so the March 2022 volumetric assessment above has been based on
existing reservoir modelling. This estimate is subject to further review based
on the data from the development wells which are due to resumed shortly and
subsequent initial production data.
Pre-Development Assets (PDAs)
Nailsworth (P130 & P2342)
IOGUKL has a 50% working interest and is operator of the P130 and P2342
licences, which contain the Nailsworth gas 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
reservoir modelling of the field, with dynamic reservoir modelling expected to
be completed by early Q2 2022. In its 2017 Competent Persons Report (CPR),
ERC Equipoise assessed gross 1P/2P/3P gas reserves to be 60.4/99.4/147.2 BCF
in Nailsworth. The current gross 1P/2P/3P management estimated Nailsworth gas
reserves are likewise 60.4/99.4/147.2 BCF.
The Nailsworth discovery is intended to be the first Phase 2 field to be
developed and has been under evaluation in stage two of IOG's Project
Governance Process, which assesses the optimal development concept for the
field within the context of the Saturn Banks infrastructure and the wider
asset portfolio. Based on this work, the Company expects to put Nailsworth
through the concept select gate in Q2 2022. This would be followed by
further Front-End Engineering and Design and development well planning work,
alongside the drafting of a Field Development Programme and an Environmental
Statement ahead of a Final Investment Decision expected in the second half of
2022.
The optimal development of the Nailsworth discovery is likely to be via
hydraulically stimulated production wells, which could be phased based on well
performance. To maximise operational and commercial synergies, Nailsworth
production is expected to be transported via a spur line to the Southwark
platform 19km to the southeast, for onward transportation to the Bacton Gas
Terminal via the IOG-owned and operated Saturn Banks Pipeline System.
Goddard and Goddard Flank structures (P2438)
IOGNSL has a 50% working interest and is operator of Licence P2438, which
contains the Goddard field, an undeveloped gas discovery, part of the planned
Phase 2 of the Saturn Banks Project.
In their 2018 CPR, ERC Equipoise assessed gross 1C/2C/3C contingent resources
to be 54.3/107.8/202.8 BCF within Goddard with Low/Best/High gross unrisked
prospective resources of 41.8/73.0/121.4 BCF. The chance of development of
Goddard was estimated by ERC Equipoise as being 75%, and the geological chance
of success of the prospective gas resources was 48%.
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 of 3D seismic data over the Goddard area was undertaken
in 2020. Reinterpretation of this data was completed in Q1 2021, updating the
gross 1C/2C/3C management resource estimate of the Goddard discovery to
57.0/132.0/258.0 BCF at that time.
Over recent months, additional seismic mapping was carried out that
incorporated further structural analysis of the PSDM seismic data. Improved
imaging has resulted in a clearer definition of the greater Goddard area and 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. Detailed mapping of these faults has
resulted in a reduction in GRV above maximum gas water contact. This led to
updated inputs to probabilistic volumetrics, resulting in management estimated
contingent resources for the main Goddard structure being revised to
52.0/115.0/169.0 BCF.
The 2020-21 mapping of the two Goddard flank structures initially indicated a
gross unrisked prospective resource range of Low/Mid/High 8/19/44 BCF and
14/28/68 BCF respectively, with 71% GCoS in each case. The further recent
Goddard mapping work has also resulted in increased management estimated
prospective resources in the Goddard flank structures to Low/Mid/High 16/27/42
BCF and 30/50/73 BCF, with no change to either GCoS. These increases in
volumes are associated with the positioning of the bounding fault between the
main Goddard structure and the flanks.
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 will test the full range of possible gas-water contacts resulting in
greater certainty of the Gas-Initially-in-Place (GIIP) within the Goddard
structure. The well will also 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.
The current term of the P2438 licence includes a firm work programme
commitment to drill and complete an appraisal well on the Goddard structure to
3,140m total depth by 30 September 2022. The Noble Hans Deul jack-up rig has
been contracted to drill the appraisal well after completion of the Southwark
field development wells. In early 2022, in light of unexpected delays to the
Southwark drilling programme, IOGNSL requested a 12-month extension to the
firm work programme commitment so that the well, as per the current Noble Hans
Deul drilling schedule, can be completed within the licence term. The outcome
of the extension request is expected after the publication of this report.
Southsea (P2438)
The 2020-21 seismic reinterpretation also identified an additional prospect
within Licence P2438 close to the south-east of Goddard, which the Company has
named Southsea. Mapping of this structure indicates gross prospective
resources of Low/Mid/High 13/31/76 BCF, with a 48% GCOS. Further detailed work
during 2021 has confirmed that Southsea is a robust structure. The results of
the Goddard appraisal well will be used to update our view of Southsea during
2022.
Abbeydale (P2442)
IOGNSL has a 50% working interest and is operator of Licence P2442, which
contains the Abbeydale gas discovery. The licence includes a firm work
programme commitment to reprocess 150 km2 of seismic data within two years,
and to either drill an appraisal well on the licence before 30 September 2023
or relinquish the licence.
The seismic reprocessing work programme was completed in Q1 2021. New
interpretation and mapping based on 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
remains at 19/23/25 BCF. The tight resource range reflects a well-defined
structure, constrained by well data from the 51/13a-13 appraisal well.
Kelham North and Central (P2442)
The recent technical work on the P2442 licence mentioned above includes 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 work has 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 derive updated management estimated gross Low/Mid/High contingent gas
resources of 30/48/67 BCF in Kelham North and 12/31/32 BCF in Kelham Central,
both with a 72% Geological Chance of success (GCoS). The Company intends to
drill an appraisal well and side-track to confirm these resource ranges in the
structures, as part of the appraisal well campaign that includes Goddard,
using the Noble Hans Deul jack-up rig after it has drilled the first two
Southwark development wells in 2022.
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
detailed below, enhancing the commercial potential of the area and providing
add-on development opportunities for the potential Southern Hub.
Thornbridge and Thornbridge Deep (P2442)
IOG has identified two further prospects on the P2442 licence, lying to the
northwest of Abbeydale, which it has named Thornbridge and Thornbridge Deep.
Subject to successful exploration drilling, these structures have the
potential to create material resource additions to the potential Southern Hub.
The Thornbridge structure has management estimated gross Low/Mid/High
prospective resources of 19/35/57 BCF, with a 64% GCoS. This GCoS is driven by
the potential communication of the Thornbridge structure with the Camelot
South field, which produced 201 BCF between 1989 and 2013.
The Thornbridge Deep structure has management estimated gross Low/Mid/High
prospective resources of 55/107/167 BCF, with a relatively low GCoS of 18% due
to the uncertainty around the quality of the Zechstein formation fault seal.
Orrell (P2442)
A further discovery, which the Company has named Orrell, lies partly on the
P2442 licence, extending over its northern limit into an unlicensed area.
The management estimated gross Low/Mid/High prospective resources that lie
within the Orrell structure on the P2442 licence are 13/18/21 BCF.
Elland (P039)
IOGUKL has a 50% working interest and is operator of the P039 licence, which
contains the Elland gas discovery, designated as part of Phase 2 of the Saturn
Banks Project. In its 2017 CPR, ERC Equipoise assessed gross 1P/2P/3P gas
reserves to be 39.9/55.0/72.9 BCF in Elland. The current gross 1P/2P/3P
management estimated Elland gas reserves are likewise 39.9/55.0/72.9 BCF.
Management's technical view on Elland is expected to be updated as part of the
ongoing Nailsworth subsurface evaluation.
Further to the Elland suspended well 49/21-10A decommissioning review,
prepared by Acona in April 2015, IOGUKL has revisited the decommissioning
provision for the well. It is envisaged that permanent plugging and
abandonment of the well can be completed at a gross cost of £2.4 million
(£1.2 million net to IOG), due to savings through synergies associated with
an Elland development drilling programme.
Panther and Grafton (P2589)
IOG NSL has a 50% working interest and is operator of Licence P2589, which
contains the Panther and Grafton gas discoveries. The licence was awarded in
the 32nd Licensing Round, formally commencing on 1 December 2020. The
licence contains a firm work programme commitment to reprocess 79km2 of
seismic data within three years, which is in the process of being completed,
and to drill an appraisal well on the licence by 30 November 2025 or
relinquish the licence.
In 2020, IOG management initially estimated gross 1C/2C/3C contingent gas
resources at 38/46/55 BCF in Panther and 24/35/46 BCF in Grafton,
respectively. IOG has initiated a programme of 3D seismic reprocessing to PSDM
standard over the licence area, which is due to complete later this year. This
includes a more sophisticated depth conversion and mapping work programme than
previously undertaken and should enable a clearer view of Panther and
Grafton's commercial potential, and an understanding of the resource potential
across the rest of the licence.
Given the proximity of Panther and Grafton to Elland, subject to the ongoing
seismic reprocessing work programme, the Company would seek to evaluate the
potential to create an "Eastern Hub" incorporating some or all of these assets
with associated development synergies.
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
shareholder 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.
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/or emissions intensity from
2022 onwards whereby relevant emissions are measured against total annual
production). Other HSE performance indicators include securing all relevant
environmental permits, consent and approvals, maintaining a verified
Environmental Management System.
The main operational KPIs include the total reserves and resources in the
portfolio and, going forward, the production rate as compared with annual
guidance (noting that with Phase 1 start-up in Q1 2022, annual production
guidance for 2022 has not yet been issued as at the time of this report - this
is expected around the mid-year once the initial months of production have
been tracked and analysed). 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.
Corporate Hedging Policy
The fundamental principle of the Group's hedging policy is to take a prudent
approach to mitigating exposure to fluctuations in commodity prices and/or
currencies to best protect cash flows. The Group will enter into hedging
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 hedging 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).
No commodity hedging instruments were utilised in 2021, in view of the
excessive costs and risks of expending capital for this purpose before Group
production is established. With production having now commenced, the Group
expects to start executing an appropriate "wedge" commodity hedging strategy,
with a higher proportion of P90 forecast production hedged over earlier
periods reducing to a lower proportion hedged over later periods, on a rolling
basis, in order to reduce cashflow volatility whilst allowing shareholders to
retain an appropriate degree of gas price exposure.
The Group expects to use simple structures with a limited range of outcomes
for its commodity hedging programme, executed only with approved market
counterparties, including its designated Phase 1 offtaker BPGM. Entering any
swap transactions with the latter counterparties will require two months of
production data before execution. Where more complex structures (involving
combinations of swaps, puts and call options) may be proposed, specific Board
approvals would be required. Under its hedging policy, the Group may also take
positions to protect against the risks associated with further phase
investments or other transactions such as acquisitions.
Details of the risks arising from the Group's use of financial instruments can
be found in Note 1 to the financial statements.
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. Key risks and associated
mitigations are set out below.
Financial
Risk Mitigation
Access to capital · Management has a clear strategy for value realisation and
creation
· Capital providers are updated regularly as to corporate and
operational progress
· Phase 1 has now started production into a strong gas market and
the resulting cash flows will help to fund further phases of development
· There is an agreed £65 million Phase 2 development carry in
place with CER, whose credit risk is low and kept under review
· The Company's portfolio has robust economics and substantial
incremental value, as attested by third-party analyst reports
· The Company demonstrated it can raise incremental capital if
needed as it successfully raised new equity in Q3 2021 to fund the Kelham
North/Central appraisal well
Cost escalation · The Company actively manages its costs and has an appropriate
hedging policy which it will start executing at the appropriate time to
mitigate the risks of commodity price volatility (see "Corporate Hedging
Policy" section above)
· There is a limited remaining scope of work for Phase 1 compared
to the work already done
· Cost escalation risks are mitigated by very high current and
forward gas prices at the time of writing
Breach of Bond terms (including financial covenants: €2m minimum liquidity, · The Company makes consistent efforts to be fully aware of its
minimum 2.5x leverage ratio from 6 months after First Gas, minimum 5x interest responsibilities and obligations under the Bond terms
cover from 6 months after First Gas)
· The Company makes consistent efforts to minimise costs
· Management calibrates key project and corporate commitments
against bond conditions and covenants to ensure avoidance of any breach.
· Phase 1 is now on production in a strong gas market, helping to
minimise this risk
Gas price volatility · During 2021 the UK gas market, along with other global gas
benchmarks, rose significantly and has remained relatively high in 2022 year
to date, putting the Company at a tangible advantage versus its planning case
gas price assumption of 45p/therm (seasonally adjusted)
· While gas market volatility has increased over recent months and
particularly since the onset of the Russia-Ukraine conflict, fluctuations are
around very high price levels at the time of writing
· The Company actively manages its costs and has an appropriate
hedging policy which it will start executing at the appropriate time to
mitigate the risks of commodity price volatility (see "Corporate Hedging
Policy" section above)
· Hedging strategies may also be employed to derisk major
incremental capital commitments
· Budget planning considers a range of commodity pricing, taking
into account potential future price scenarios, and advice is taken from
independent third-party market experts
Fiscal change · The Company, along with its peer group and associated
organisations, continually engages with government and regulatory bodies, and
advocates for continued stability in the fiscal regime being in the long-term
interests of stable domestic energy supply
· The Company has significant tax losses and does not expect to
incur corporation tax liabilities in the initial years of production
Fluctuation in asset values · The Company seeks to limit its financial dependence on any one
single asset by holding a diversified portfolio of 6 discovered gas fields
across Phases 1 and 2 of the Saturn Banks Project, plus several further assets
which are being worked up for potential future additional developments
· The Company makes consistent efforts to keep its cost base as low
as reasonably possible
· In addition, the Company continues to undertake further technical
work to better understand each asset and narrow the range of potential values
· Asset values can increase as well as decrease
Operational
Risk Mitigation
Changes in reservoir volumes or characteristics · The Company undertakes a thorough programme for technical
evaluation for all of its licences, including subsurface mapping and reservoir
modelling
· This is carried out by a competent, highly qualified and
experienced in-house team supported where necessary by leading technical
consultancies, with independent third-party reports commissioned as
appropriate
· A prudent range of input assumptions and possible outcomes are
always considered within planning processes
· The Company aims to minimised reservoir risks through high
quality well design
· The Company seeks to itemise and apply lessons learned from
earlier wells when drilling subsequent wells
Departure from schedule and budget · The Company employs technically competent and experienced
personnel throughout the organisation
· The Company awards contracts to competent, recognised,
experienced contractors with a view to obtaining best value for money
· Rigorous checks and controls are applied to schedule and budget
to minimise any overruns as far as reasonably possible
· Any scope changes are required to go through the Management of
Change process
· The Company follows the gate process for project governance and
utilises peer reviews at appropriate project stages
Integrity of single point failure infrastructure · The Company has run extensive analysis and physical tests on its
key infrastructure in the build up to first production to ensure it is
satisfied as to its integrity
· The Company is in the process of rolling out an assurance plan
for both its platform and pipeline Duty Holder ODE and the Bacton terminal
operator PUK (reg 5 audits)
Fluctuation in market conditions for rig, vessels and offshore procurement · The Company seeks to utilise EPCI lump sum contracts for offshore
work as far as reasonably possible, where this constitutes best value for
money
· Competitive tendering processes are used for all material
contracting requirements
· Where appropriate, suitable incentivisation clauses are used
contracts in order to minimise delivered cost
Weather risks · There is a limited remaining scope of work for Phase 1 compared
to the work already done
· Remaining work primarily include drilling - the main weather
risks for the jack-up drilling rig are in mobilising to the field location
(which is a relatively short period); once on location the weather risks are
significantly lower
· The planned pipelay operation for the 24" extension to the Saturn
Banks Pipeline is only a relatively short period (circa 1 week)
· Hook-up and commissioning work on the Blythe platform is complete
and on Southwark is largely complete - access can be gained either via
helicopters or walk-to-work vessels
Cyber security · Control systems at Bacton gas terminal are tried and tested over
extended periods and considered to be very robust
· The Company has appointed a Duty Holder in ODE that has adequate
systems and processes in place to protect platform infrastructure
· The Company has developed an enhanced IT security plan and
supporting procedures, including improved access right to systems and
protocols, and enhanced onboarding and leaving processes
Regulatory and Legal
Risk Mitigation
Securing regulatory consents, approvals and permits · The Company works continually to foster positive relationships at
all levels with relevant government and regulatory bodies, including but not
limited to OGA, BEIS / OPRED and HSE
· There is frequent and detailed liaison at multiple levels with
these authorities to ensure good mutual understanding, minimise issues and
delays in approvals
· Relevant applications are reviewed in detail and submitted
promptly
Deficiency in Corporate Governance · The Company has developed and implemented a suitable suite of
corporate policies and procedures, covering Financial Operations, Anti-Bribery
and Corruption, Travel and Expenses, Climate Change and Sustainability, etc
· All contracts must be authorised by the Contracts and Procurement
function, Finance, General Counsel and above certain thresholds are subject to
Tender Committee and Board approval
Commercial
Risk Mitigation
Stakeholder misalignment · The Company undertakes very regular discussions and meetings with
key stakeholders, to build mutual understanding and maintain positive
relationships
· The Company continually seeks to understand stakeholders'
priorities, drivers and risk tolerance levels
Access to market · The Company has successfully undertaken a competitive gas sales
tendering process in 2021, with a good number of interested parties leading to
healthy competition
· There are a lot of credible and well-funded gas shippers in the
UK who can purchase IOG's gas. The UK gas market is deep and liquid,
especially in the short term.
· There is a single buyer for condensate at Bacton with whom IOG
has an agreed offtake contract
HSE and Sustainability
Risks Mitigation
Harm or injury to people or the environment · Compliance with the UK regulatory goal setting regime for safety
is established, implemented and maintained through the Company leadership,
HSE and Technical Committee, culture and management systems
· The Company continually reviews and updates its HSE Policy, which
can be read in full on its website
· The Company employs experienced in-house HSE practitioners to
ensure it meets all its related obligations, supported by appropriate external
subject matter experts and consultants
Adverse environmental effects of our activities including, in particular, · The Company has a Climate Change and Sustainability Policy, which
contributing to climate change can be read in full on its website
· Strategic focus on low carbon intensity domestic natural gas
resources as a key fuel for the Energy Transition with lower carbon content
than other hydrocarbons (including imported gas)
· Use of low carbon intensity facilities, including re-use of
existing infrastructure - as illustrated by its inaugural Emissions Assessment
(see ESG section above)
Human Resources
Risks Mitigation
Building and maintaining a fit for purpose team · The Company has over recent years established a competent,
experienced team across all key disciplines, which mitigates the risk of
losing any key individual
· The Company's Remuneration Committee regularly evaluates
incentivisation schemes to ensure they remain in line with market standards
· The Company undertakes annual external benchmarking for all roles
to ensure its salaries and benefits are appropriate and competitive
Disruption from the Covid-19 pandemic · Throughout the pandemic the Company has successfully implemented
logistical and organisational changes to underpin its resilience to Covid-19
disruption, with the key focus being protecting all personnel, minimising
impact on critical workstreams and ensuring business continuity
· The Company has proactively sought to mitigate the risks of
Covid-19 outbreaks involving its operations, for example through rigorous
testing before personnel go on site or travel offshore
· Senior management communicates regularly with all employees
around changes in the company protocols or government working guidance
· The Company continues to maintain Covid-19 protocols over and
above government regulation to maintain and safe working environment and to
mitigate risk to the business
Finance Review
From a financial as well as operational perspective the Company focused in
2021 on investing the proceeds of the significant funding transactions
undertaken in 2019, in particular the Farm-out and the €100 million senior
secured Bond which provided the capital for continued investment in Saturn
Banks Phase 1.
During 2021, a total of £140.0 million was invested in the Phase 1
development. Of this, the joint venture partner CER funded £70.0 million for
their 50% non-operating share in each asset and a further £11.7 million as
Phase 1 development carry for the Company's benefit under the terms of the
2019 Farm-out. The full £60 million of Phase 1 partner development carry was
thereby utilised in the year, with a further agreed carry of £65 million to
come for Phase 2 subject to FID.
The post-tax loss for the year was £4.2 million, which includes a £0.9
million write down of the remaining Harvey licence following relinquishment of
the licence (2020: loss of £19.3 million which included a £12.6 million
write down of the Harvey and Redwell assets).
The Company ended the year with a cash balance of £31.3 million (2020: £13.9
million) plus £3.4 million of restricted cash (2020: £67.0 million), £2.0
million of which is the minimum holding of Bond interest in the DSRA and £1.4
million of which is decommissioning security. Group net debt at the end of the
year was £56.6 million (2020: £14.1 million) (see note 17).
Under IFRS 16, IOG is responsible for capitalising 100% of the lease cost of
its contract with Noble Corporation for the Noble Hans Deul jack-up drilling
rig, as well as contracts for the marine supply vessel and
emergency rapid response marine (ERRV) vessel, to its statement of financial
position. Based on the minimum contract durations and day-rates, IOG has
therefore recognised £21.3 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 £11.1 million (net liability after
payments) in lease liabilities.
In September 2021 the Company raised gross proceeds of £8.5 million from new
and existing shareholders via a placing and subscription, the proceeds of
which are primarily intended to fund the drilling of the Kelham North/Central
appraisal well in the P2442 licence.
The £11.6 million long-term, unsecured, non-interest-bearing Loan Note
Instrument, convertible at 19p into 60,872,631 Ordinary Shares, remained in
place, with a maturity date of October 2024.
Income Statement
The Group made a loss for the year of £4.3 million (2020: £19.3 million,
driven primarily by a £12.6 million impairment charge on the Harvey and
Redwell assets). This includes £4.0 million of administration expenses,
finance expense of £3.1 million, £0.9 million of impairment and £0.1
million of project, pre-licence and exploration expenses, offset by a £3.4
million FX gain and fair value gain of £0.3 million.
Net administration expenses of £4.0 million (2020: £3.4 million) reflect a
lean corporate operation and the allocation of a proportion of overheads to
project assets.
The foreign exchange gain of £3.4 million (2020: £0.7 million loss) reflects
realised and unrealised foreign exchange movements on EUR denominated Bond,
provisions and trade creditors and loans.
The total interest paid on bonds for 2021 was £8.3 million (2020: £8.7
million), all of which was attributable to financing of capital projects and
hence fully capitalised in line with company's accounting policy.
Statement of financial position
Property, Plant and Equipment (PPE) oil and gas assets increased to £138.4
million (2020: £53.4 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.
Total assets increased to £180.7 million (2020: £154.2 million), including
cash resources of £34.7 million (2020: £80.4 million) of which £3.4 million
is restricted (2020: £67.0 million).
Total liabilities have increased to £152.4 million (2020: £131.1 million),
with the Bond representing £82.4 million (2020: £87.8 million). Liabilities
also include trade creditors £8.1 million (2020: £1.0 million), lease
liabilities of £11.1 million (2020: £13.8 million), accruals and operator
advance accounts of £25.7 million (2020: £7.2 million) given the high volume
of work as the Phase 1 development progressed, and deferred considerations in
relation to acquisitions of £0.6 million (2020: £2.3 million).
Decommissioning provisions net to IOG increased to £15.8 million (2020: £6.2
million), including the Elland suspended well decommissioning provision of
£1.2 million, Saturn Banks Pipeline decommissioning provision of £0.1
million (2020: £1.0 million), Saturn Banks Reception Facilities
decommissioning provision of £2.9 million and the addition of further Phase 1
infrastructure of £11.6 million (see Note 16). Lease liabilities recognised
under IFRS 16 were £11.1 million (2020 £17.6 million) predominantly driven
by the inclusion of the contract for the Noble Hans Deul drilling rig as well
as the marine supply vessel and ERRV.
The Group ended the year with a net debt position of £56.6 million (2020:
£14.1 million), primarily driven by the ongoing expenditure on Phase 1. Net
debt is defined as total loans, primarily the EUR denominated Bond, less
restricted cash and cash equivalents.
Cash Flow
Net cash inflows of £20.0 million (2020: £8.0 million inflow) from
operations, net cash inflow of £3.6 million (2020: £1.2 million) generated
from investing activities and net cash outflow of £8.2 million (2020: £10.5
million) from financing resulted in a cash and equivalents position of £31.3
million at year end. There were no loan repayments (2020: Nil). At the end of
the year £3.4 million (2020: £67.0 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 (2020: 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 (with a floor of zero when this rate
is negative, as it is at the time of writing). 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, such as the newly acquired P2589 Panther-Grafton licence.
Bond funds can be used to fund 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. The pricing on the secondary market was impacted heavily in
early 2020 at the onset of the Covid-19 pandemic which had a major impact on
markets. However, since this time the trading price has steadily recovered and
in late Q3 2021 it started to trade at a premium to par. Since then to the
time of writing it has traded within a range of 100-102 cents (with 100 cents
being par value), indicating investors' confidence that the Bond will be
repaid in full.
At settlement of the Bond in September 2019, the first eight quarterly
payments were set aside in a Debt Service Reserve Account (DSRA). Over the
course of 2021, a total of €9.7 million was drawn down quarterly as planned
from the DSRA to fund the four coupon payments in March, June, September and
December. Further to this the DSRA balance at the end of the period was €2.5
million (£2.1 million).
As laid out in the Bond terms, drawdown from the Bond escrow account was
subject to a series of progress milestones. During the course of 2021, three
drawdowns of €27.3 million (£24.2 million), €19.5 million (£16.6
million) and €18.9 million (£16.1 million) were made in February, April and
April 2021 respectively further to the relevant Phase 1 operational
milestones. This extinguished the Bond escrow account leaving no further
balance to be drawn down.
The Bond is callable from 3 years after issuance, i.e. in or after 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 3month EURIBOR is at zero or
lower), declining by 10% every six months thereafter.
The Company has the option, subject to conditions and investor commitments, 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.
Funding & Liquidity
The Consolidated Statement of Financial Position at 31 December 2021 details a
net debt position for the Group of £56.6 million (2020: 14.1 million). Net
debt is defined as total loans, primarily the Bond, less restricted cash and
cash equivalents.
In assessing the Group's and Parent Company's current financial position and
reaching its conclusion as to going concern status up until September 2023, as
laid out in the Annual Report, the Board has, by necessity, utilised a set of
reasonable assumptions around activities, costs, timings, asset performance
and other relevant economic factors in order to develop an accurate
perspective. These assumptions are summarised in this paper.
The primary consideration is progress of the Phase 1 development. On 14 March,
the Company announced that Phase 1 First Gas had successfully been delivered
on the previous day, with Blythe field producing gas into the Saturn Banks
infrastructure and Bacton terminal. This is a key turning point for the
Company in transitioning from a developer into a cash-generative producer,
with significant cashflow expected to be generated point forward under the
Company's current base case gas price assumptions.
The gas price assumptions used for these purposes are based on a long-term
average realised price of 45p/therm, which management confirms to be a
sensible baseline in the context of average realised UK gas prices over the
past decade, having taken advice from independent market experts engaged by
the Group. This is seasonally adjusted to more accurately replicate the actual
seasonal fluctuations in the UK gas market (higher prices over October-March,
lower prices over April-September), rather than use an unrealistic flat price
assumption. Importantly, to remain as realistic as reasonably possible, the
assumptions also factor in recent gas market developments as reflected in the
NBP forward curve. Whilst over recent weeks UK spot and forward gas prices
have reached unprecedented highs due to several factors, primarily the risk of
global gas supply constraints as a result of the Russia-Ukraine conflict, the
Company's assumptions over 2022-23 are based on 35-45% discounts to the
forward curve on 23 February 2022, prior to recent extreme pricing
dislocations.
The Company has a gas sales agreement in place with a very well established,
highly creditworthy offtaker in BPGM and also has a condensate sales agreement
in place with the single condensate offtaker at the Bacton terminal. Under its
GSA, gas is sold on a day-ahead nomination basis at a price linked to the
National Balancing Point (NBP, the UK traded gas benchmark). First payments
for the Phase 1 gas are contractually scheduled to be received on 20 April
2022. As an additional liquidity backstop measure the Company has also
executed a €5 million working capital facility from a respected
international bank, which can be drawn as needed after First Gas subject to
market standard conditions and is repayable by March 2023.
Management calibrates key project and corporate commitments against bond
conditions and covenants to ensure avoidance of any breach. The Company makes
consistent efforts to manage the business within budget. Phase 1 capital costs
underlying the going concern assessment flow from the baseline project plan as
recently reviewed and reaffirmed by senior management. At this stage there is
a detailed understanding of the expected further expenditure based on existing
commitments as Phase 1 reaches its final stages of execution, with the
Southwark drilling and extension to the Saturn Banks Pipeline System being key
final elements of the scope. The latest cost estimates have in turn been
interrogated and subsequently approved at both executive and Board level.
Similarly, operating cost assumptions, including offshore Operations and
Maintenance (O&M) costs, onshore Saturn Banks Reception Facilities
operation costs and Bacton processing tariff costs, have been established
using the latest estimates provided by internal operational personnel and
relevant external parties (ODEAM and Perenco).
Decommissioning cost assumptions are drawn directly from the independent
Competent Persons Report (CPR) undertaken by reserve auditor ERC Equipoise in
2017.
Pre-development assets and General and Administrative (G&A) cost
assumptions are based on approved internal budgets, which are based on
estimates and are reviewed and derived from comparable activities and relevant
past actual costs. G&A budgets are constructed with an iterative
methodology that factors in historical expenditure trends adjusted with
appropriate forward-looking modifications and expected trends in underlying
activity (e.g. changes in organisation headcount). Forecasts are reviewed by
the senior finance team and the CFO on a monthly basis in order to assess the
appropriateness of budget versus actual outturn and reviewed and when
appropriate are discussed at Board level. Finally, prudent assumptions have
been taken in respect of the Group's treasury management, including the policy
of minimising foreign exchange exposures as far as possible. Foreign exchange
exposures are forecast and compared to the available currency held as cash
balances or JV cash calls, which allows any exposure to be actively managed.
The nature of the Group's operations inherently involves a range of potential
outcomes and in that context, as demonstrated above, the Group uses prudent
assumptions to develop its view of most likely outcomes, as well as
identifying measures to mitigate or eliminate potential risks that may affect
cash flows. Management undertakes detailed financial modelling to generate
stress test scenarios, including changes in gas prices and/or production
levels, which are reviewed by the Board. Under all reasonable forecast
scenarios, the Group is expected to be able to remain within its Bond
covenants and to have sufficient cash resources to continue with its planned
business strategy.
Conclusions
Based on the above, and particularly in light of the recent announcement of
the First Gas milestone for Phase 1 amid a very elevated gas market, the Board
have a reasonable expectation that the Group has adequate resources which will
continue to grow off the back of Phase 1 delivery and to progress to FID on
further phases, providing long-term business continuity with stable cash
generation for the foreseeable future. To this end, the Board believe that the
Group and Company can be represented as being a going concern without any
modification of material uncertainty for the 2021 Annual Report and Accounts.
The financial statements do not include any adjustments that would result if
the Group and the Parent Company were unable to continue as a going concern.
Rupert Newall
Chief Financial Officer
16 March 2022
Consolidated Statement of Comprehensive Income
Notes 2021 2020
£000 £000
Administration expenses (3,960) (3,410)
Impairment of oil and gas properties 8 (865) (12,598)
Project, pre-licence and exploration expenses (104) (180)
Foreign exchange gain / (loss) 3,440 (701)
_________ _________
Operating (loss) 3 (1,489) (16,889)
Finance expense 5 (3,066) (2,203)
Finance income 29 20
Fair value gain / (loss) 12 260 (265)
_________ _________
(Loss) for the year before taxation (4,266) (19,337)
Taxation 6 - -
_________ _________
(Loss) and total comprehensive (loss) for the year attributable to equity 7 (4,266) (19,337)
holders of the parent
_________ _________
(Loss)/earnings for the year per ordinary share - basic 7 (0.0p) (4.0p)
(Loss)/earnings for the year per ordinary share - diluted 7 (0.0p) (4.0p)
The loss for the year (£4.3 million) (2020: Loss £19.3 million) arose from
continuing operations.
Consolidated and Company Statements of Changes in Equity
Share capital Share premium Share-based payment reserve Accumulated losses Total equity
Group: £000 £000 £000 £000 £000
At 1 January 2020 4,802 49,423 6,352 (20,029) 40,548
Loss for the year - - - (19,337) (19,337)
_____ ________ ________ ________ _______
Total comprehensive loss attributable to owners of the parent - - - (19,337) (19,337)
Lapse of warrants - - (401) 401 -
Exercise of warrants 78 566 (727) 727 644
Issue of share options - - 941 - 941
Expiry of share options - - (1) 1 -
Exercise of share options 2 - (10) 10 2
_____ ________ ________ ________ _______
At 31 December 2020 4,882 49,989 6,154 (38,227) 22,798
Loss for the year - - - (4,266) (4,266)
_____ ________ ________ ________ _______
Total comprehensive loss attributable to owners of the parent - - - (4,266) (4,266)
Issue of shares 338 8,112 8,450
Issue of share options - - 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 (42,263) 28,320
_____ ________ _______ ________ _______
Company:
At 1 January 2020 4,802 49,423 6,352 (11,535) 49,042
Loss for the year - - - (6,285) (6,285)
_____ ________ ________ ________ _______
Total comprehensive loss attributable to owners of the parent - - - (6,285) (6,285)
Lapse of warrants - - (401) 401 -
Exercise of warrants 78 566 (727) 727 644
Issue of share options - - 941 - 941
Expiry of share options - - (1) 1 -
Exercise of share options 2 - (10) 10 2
_____ ________ ________ ________ _______
At 31 December 2020 4,882 49,989 6,154 (16,681) 44,344
Loss for the year - - - (3,643) (3,643)
_____ ________ ________ ________ _______
Total comprehensive loss attributable to owners of the parent - - - (3,643) (3,643)
Lapse of warrants 338 8,112 - - 8,450
Issue of share options - - 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 7196 (20,094) 50,489
______ ________ _______ ________ _______
Share capital - Amounts subscribed for share capital at nominal value.
Share premium - Amounts received on the issue of shares, in excess of the
nominal value of the shares.
Share-based payment reserve - Amounts reflecting fair value of options and
warrants issued.
Accumulated losses - Cumulative net losses recognised in the Statement of
Comprehensive Income net of amounts recognised directly in equity.
Consolidated Statement of Financial Position
Notes 2021 2020
£000 £000
Non-current assets
Intangible assets: exploration & evaluation 8 950 1,309
Intangible assets: other 8 75 170
Property, plant and equipment: development & production assets 9 138,403 53,422
Property, plant and equipment: other 9 4,872 16,541
_________ _________
144,300 71,442
_________ _________
Current assets
Financial asset 12 - 1,260
Other receivables and prepayments 14 1,705 1,099
Restricted cash 19 3,429 67,049
Cash and cash equivalents 19 31,255 13,389
_________ _________
36,389 82,797
_________ _________
Total assets 180,689 154,239
Current liabilities
Trade and other payables 15 (44,880) (22,131)
_________ _________
(44,880) (22,131)
_________ _________
Non-current liabilities
Loans 16, 20 (91,257) (95,813)
Other liabilities 16 (16,232) (13,497)
_________ _________
(107,489) (109,310)
_________ _________
Total liabilities (152,369) (131,441)
_________ _________
NET ASSETS 28,320 22,798
_________ _________
Capital and reserves
Share capital 18 5,238 4,882
Share premium 18 58,149 49,989
Share-based payment reserve 7,196 6,154
Accumulated losses (42,263) (38,227)
_________ _________
28,320 22,798
_________ _________
The financial statements were approved and authorised for issue by the Board
of Directors on 16(th) March 2022 and were signed on its behalf by:
Rupert Newall
Chief Financial Officer
16 March 2022
Company Number: 07434350 Notes 2021 2020
£000 £000
Non-current assets
Intangible assets 8 75 170
Property, plant and equipment: Development & Production 9 - 1,959
Property, plant and equipment: Other 9 4,872 16,541
Investments 11 15,486 15,486
Amounts due from subsidiaries 11 109,195 44,906
_________ _________
129,628 79,062
_________ _________
Current assets
Financial asset 12 - 1,260
Other receivables and prepayments 14 1,705 2,466
Restricted cash 19 2,066 65,699
Cash and cash equivalents 19 31,255 13,389
_________ _________
35,026 82,814
_________ _________
Total assets 164,654 161,876
Current liabilities
Trade and other payables 15 (22,513) (16,138)
Non-current liabilities
Loans 16,20 (91,257) (95,813)
Other liabilities 16,21 (395) (5,581)
_________ _________
(91,652) (101,394)
_________ _________
Total liabilities (114,165) (117,532)
_________ _________
NET ASSETS 50,489 44,344
_________ _________
Capital and reserves
Share capital 18 5,238 4,882
Share premium 18 58,149 49,989
Share-based payment reserve 7,196 6,154
Accumulated losses (20,094) (16,681)
_________ _________
50,489 44,344
_________ _________
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 (£3.6) million (2020: loss £6.3 million).
The financial statements were approved and authorised for issue by the Board
of Directors on 16(th) March 2022 and were signed on its behalf by: -
Rupert Newall
Chief Financial Officer
16 March 2022
Consolidated Cash Flow Statement
Notes 2021 2020
£000 £000
(Loss) for the year (4,266) (19,337)
Depreciation, depletion and amortisation 9 519 559
Exploration asset write off 8 865 12,598
Share based payments 1,225 941
Fair value (gain) / loss 12 (260) 265
Interest received (18) (20)
Finance expense 5 3,066 2,203
Effect of exchange rate changes on Bond (5,901) 4,792
Movement in trade and other receivables (732) 3,993
Movement in trade and other payables 25,499 1,974
_________ _________
Net cash generated from operating activities 19,997 7,968
Investing activities
Development & Production assets (58,269) (11,735)
Exploration & Appraisal assets (write off) (506) -
ROU, Lease improvements, Computer hardware etc (295) -
Movement in restricted cash 61,172 15,017
Interest received 18 20
Decrease / (Increase) in financial assets 1,520 (1,260)
Deferred consideration payments - (875)
_________ _________
Net cash generated from investing activities 3,640 1,167
Financing activities
Proceeds from issue of equity instruments of the Group 8,516 2
Proceeds from issue of warrant instruments of the Group - 644
Lease liability payments (12,307)
Finance fees paid (4,441) (11,116)
_________ _________
Net cash used in financing activities (8,232) (10,470)
Net increase / (decrease) in cash and cash equivalents 15,405 (1,335)
Cash and cash equivalents at the beginning of the year 13,389 16,197
Effects of exchange rate changes on cash and cash equivalents 2,461 (1,473)
_________ _________
Cash and cash equivalents at end of year 19 31,255 13,389
_________ _________
( )
Notes forming part of the financial statements
1. Accounting policies
General information
IOG plc is a public limited company incorporated and domiciled in England and
Wales. The Group's and Company's financial statements for the year ended 31
December 2021 were authorised for issue by the Board of Directors on 16 March
2022 and the balance sheets were signed on the Board's behalf by the CFO,
Rupert Newall.
Basis of preparation and accounting
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 Company and its subsidiaries. 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 Group 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.
Going concern
The Board has reviewed the Group's cash flow forecasts having regard to its
current financial position and operational objectives.
The Consolidated Statement of Financial Position at 31 December 2021 details a
net debt position for the Group of £56.6 million (2020: 14.1 million). Net
debt is defined as total loans, primarily the Bond, less restricted cash and
cash equivalents.
In assessing the Group's and Parent Company's current financial position and
reaching its conclusion as to going concern status up until September 2023, as
laid out in the Annual Report, the Board has, by necessity, utilised a set of
reasonable assumptions around activities, costs, timings, asset performance
and other relevant economic factors in order to develop an accurate
perspective. These assumptions are summarised in this paper.
The primary consideration is progress of the Phase 1 development. On 14 March,
the Company announced that Phase 1 First Gas had successfully been delivered
on the previous day, with Blythe field producing gas into the Saturn Banks
infrastructure and Bacton terminal. This is a key turning point for the
Company in transitioning from a developer into a cash-generative producer,
with significant cashflow expected to be generated point forward under the
Company's current base case gas price assumptions.
The gas price assumptions used for these purposes are based on a long-term
average realised price of 45p/therm, which management confirms to be a
sensible baseline in the context of average realised UK gas prices over the
past decade, having taken advice from independent market experts engaged by
the Group. This is seasonally adjusted to more accurately replicate the actual
seasonal fluctuations in the UK gas market (higher prices over October-March,
lower prices over April-September), rather than use an unrealistic flat price
assumption. Importantly, to remain as realistic as reasonably possible, the
assumptions also factor in recent gas market developments as reflected in the
NBP forward curve. Whilst over recent weeks UK spot and forward gas prices
have reached unprecedented highs due to several factors, primarily the risk of
global gas supply constraints as a result of the Russia-Ukraine conflict, the
Company's assumptions over 2022-23 are based on 35-45% discounts to the
forward curve on 23 February 2022, prior to recent extreme pricing
dislocations.
The Company has a gas sales agreement in place with a very well established,
highly creditworthy offtaker in BPGM and also has a condensate sales agreement
in place with the single condensate offtaker at the Bacton terminal. Under its
GSA, gas is sold on a day-ahead nomination basis at a price linked to the
National Balancing Point (NBP, the UK traded gas benchmark). First payments
for the Phase 1 gas are contractually scheduled to be received on 20 April
2022. As an additional liquidity backstop measure the Company has also
executed a €5 million working capital facility from a respected
international bank, which can be drawn as needed after First Gas subject to
market standard conditions and is repayable by March 2023.
Management calibrates key project and corporate commitments against bond
conditions and covenants to ensure avoidance of any breach. The Company makes
consistent efforts to manage the business within budget. Phase 1 capital costs
underlying the going concern assessment flow from the baseline project plan as
recently reviewed and reaffirmed by senior management. At this stage there is
a detailed understanding of the expected further expenditure based on existing
commitments as Phase 1 reaches its final stages of execution, with the
Southwark drilling and extension to the Saturn Banks Pipeline System being key
final elements of the scope. The latest cost estimates have in turn been
interrogated and subsequently approved at both executive and Board level.
Similarly, operating cost assumptions, including offshore Operations and
Maintenance (O&M) costs, onshore Saturn Banks Reception Facilities
operation costs and Bacton processing tariff costs, have been established
using the latest estimates provided by internal operational personnel and
relevant external parties (ODEAM and Perenco).
Decommissioning cost assumptions are drawn directly from the independent
Competent Persons Report (CPR) undertaken by reserve auditor ERC Equipoise in
2017.
Pre-development assets and General and Administrative (G&A) cost
assumptions are based on approved internal budgets, which are based on
estimates and are reviewed and derived from comparable activities and relevant
past actual costs. G&A budgets are constructed with an iterative
methodology that factors in historical expenditure trends adjusted with
appropriate forward-looking modifications and expected trends in underlying
activity (e.g. changes in organisation headcount). Forecasts are reviewed by
the senior finance team and the CFO on a monthly basis in order to assess the
appropriateness of budget versus actual outturn and reviewed and when
appropriate are discussed at Board level. Finally, prudent assumptions have
been taken in respect of the Group's treasury management, including the policy
of minimising foreign exchange exposures as far as possible. Foreign exchange
exposures are forecast and compared to the available currency held as cash
balances or JV cash calls, which allows any exposure to be actively managed.
The nature of the Group's operations inherently involves a range of potential
outcomes and in that context, as demonstrated above, the Group uses prudent
assumptions to develop its view of most likely outcomes, as well as
identifying measures to mitigate or eliminate potential risks that may affect
cash flows. Management undertakes detailed financial modelling to generate
stress test scenarios, including changes in gas prices and/or production
levels, which are reviewed by the Board. Under all reasonable forecast
scenarios, the Group is expected to be able to remain within its Bond
covenants and to have sufficient cash resources to continue with its planned
business strategy.
Conclusions
Based on above, and particularly in light of the recent announcement of the
First Gas milestone for Phase 1 amid a very elevated gas market, the Board
have a reasonable expectation that the Group has adequate resources which will
continue to grow off the back of Phase 1 delivery and to progress to FID on
further phases, providing long-term business continuity with stable cash
generation for the foreseeable future. To this end, the Board believe that the
Group and Company can be represented as being a going concern without any
modification of material uncertainty for the 2021 Annual Report and Accounts.
The financial statements do not include any adjustments that would result if
the Group and the Parent Company were unable to continue as a going concern.
New and revised accounting standards
For annual reporting periods beginning on or after 1 January 2021, the
following is a newly effective requirement:
IFRS IASB Effective Date Note in financial statements EU Endorsement status
IBOR reform and its Effects on Financial Reporting - phase 2 1 January 2021 Endorsed
Interest Rate Benchmark Reform - Phase 2 introduces amendments to IFRS 9, IAS
39, IFRS 7, IFRS 4 and IFRS 16 and is not mandatorily effective until annual
periods beginning on or after 1 January 2021,however, many entities were
expected to adopt the amendments early. As such, these financial statements
include the effect of the adoption of these amendments from the comparative
period i.e. financial year ended 31 December 2020.
Early adoption of Standards and Amendments
The table below lists all pronouncements with a mandatory effective date in
future accounting
Mandatorily effective for Mandatorily effective for Mandatorily effective for periods
periods beginning on or after 1 periods beginning on or after 1 beginning on or after 1 January
April 2021 January 2022 2023
IFRS 16 Leases: Covid-19-Related Annual Improvements to IFRSs - IFRS 17 Insurance Contracts
Rent Concessions beyond 30 June 2018-2020 cycle
2021*
IAS 16 Property, Plant and IAS 1 Presentation of Financial
Equipment (Amendment - Statements (Amendment -
Proceeds before Intended Use) Classification of Liabilities as
Current or Non-current)
IAS 37 Provisions, Contingent IAS 1 Presentation of Financial
Liabilities and Contingent Assets Statements and IFRS Practice
(Amendment - Onerous Contracts Statement 2
- Cost of Fulfilling a Contract) (Amendment - Disclosure of
Accounting Policies)
IFRS 3 Business Combinations (Amendment - Reference to the Conceptual IAS 8 Accounting policies, Changes
Framework)
in Accounting Estimates and Errors
(Amendment - Definition of
Accounting Estimates)
IAS 12 Income Taxes (Amendment -
Deferred Tax related to Assets and
Liabilities arising from a Single
Transaction)
*The Group has early adopted the amendment to IFRS 16 Covid-19-Related Rent
Concessions beyond 30 June 2021
from annual reporting period beginning on 1 January 2021, as permitted by the
amendment. The effects of this amendment to IFRS 16 on the recognition and
measurement of items in the financial statements are disclosed in note 1.
Basis of consolidation
Where the Company has control over an investee, it is classified as a
subsidiary. The Company controls an investee if all three of the following
elements are present: power over the investee, exposure to variable returns
from the investee, and the ability of the investor to use its power to affect
those variable returns. Control is reassessed whenever facts and
circumstances indicate that there may be a change in any of these elements of
control.
The consolidated financial statements present the results of the Company and
its subsidiaries as if they formed a single entity. Inter-company
transactions and balances between Group companies are therefore eliminated in
full. The financial statements of subsidiaries are included in the Group's
financial statements from the date that control commences until the date that
control ceases.
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 appraisal including technical
and administrative 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 oil and 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 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 oil and 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 circumstances arise which indicate that the carrying value of
an E&E asset exceeds the recoverable amount. Such indicators would
include but 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, and
(iv) insufficient discovery of commercially viable resources leading to the
discontinuation of activities
(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 (net of depletion or amortisation) had no
impairment loss been recognised in prior periods. 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
Costs of bringing a field into production, including the cost of facilities,
wells and sub-sea equipment together with E&E assets reclassified in
accordance with the above policy, are capitalised as a D&P asset within
PPE. Normally each individual field development will form an individual
D&P asset but there may be cases, such as 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
also include the cost of acquisitions and purchases of such assets, directly
attributable overheads, applicable borrowing costs and the cost of recognising
provisions for future consideration payments - see Note 16. The discounted
cost for future decommissioning is also added to the D&P asset. Personnel
/ staff costs are charged to D&P assets based on a time writing system
where all identified staff input their time across assets and activities, they
work on during any given period at a precalculated hourly rate which takes
into account various elements of staff costs and seniority of the
organisational position.
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. Depletion is
calculated on a UOP basis based on the 2P reserves of the asset. Any
re-assessment of reserves affects the depletion rate prospectively.
Significant items of plant and equipment will normally be fully depreciated
over the life of the field; however, these items are assessed to consider if
their useful lives differ from the expected life of the D&P asset and
should this occur a different depreciation rate may be charged. The key
areas of estimation regarding depletion and the associated unit of production
calculation for oil and gas assets are recoverable reserves and future capital
expenditures.
Impairment
A review is carried out for any indication that the carrying value of the
Group's D&P assets may be impaired. If any indicators are identified, a
review of D&P assets is carried out on an asset by asset basis and
involves comparing the carrying value with the recoverable value of an
asset. The recoverable amount of an asset is determined as the higher of its
fair value less costs to sell and value in use. The value in use is
determined from estimated future net cash flows, being the present value of
the future cash flows expected to be derived from production of commercial
reserves. Impairment resulting from the impairment testing is charged to a
separate line item within the Statement of Comprehensive Income.
The pre-tax future cash flows are adjusted for risks specific to the CGU and
are discounted using a pre-tax discount rate. The discount rate is derived
from the Group's post-tax weighted average cost of capital and is adjusted
where applicable to consider any specific risks relating to the country where
the CGU is located, although other rates may be used if appropriate to the
specific circumstances. The discount rates applied in assessments of
impairment are reassessed each year. The Company uses a risk adjusted
discount rate of 10%, unless otherwise stated.
The CGU basis is generally the field, however, oil and gas assets, including
infrastructure assets may be accounted for on an aggregated basis where such
assets are economically inter-dependent.
4) Offshore Pipelines
Capitalisation
Costs of commissioning an offshore pipeline to transport hydrocarbons,
including the cost of related onshore facilities and subsea equipment are
capitalised as a tangible asset within PPE. Each contiguous pipeline will form
an exclusive individual asset but there may be cases, such as phased
developments, when pipelines are grouped together to form a single tangible
pipeline asset. The cost of offshore pipeline assets also includes the cost of
acquisitions and purchases of such assets, directly attributable overheads,
applicable borrowing costs and the discounted cost of future decommissioning.
Depreciation
All costs relating to pipeline commissioning are not depreciated until the
commencement of transportation of hydrocarbons. Depreciation is calculated
on a straight-line basis over the period in which transportation is likely to
take place. Any re-assessment of this timeline will impact on the
depreciation rate prospectively. The key areas of estimation regarding
depreciation are future capital expenditures and recoverable reserves for
those fields where such pipelines are utilised for the transportation of oil
and gas production.
Impairment
A review is carried out for any indication that the carrying value of the
pipeline asset may be impaired. If any indicators are identified, such as
the pipeline's inability to continue to operate safely and effectively in its
current environment, a review of the pipeline asset is carried out. Impairment
resulting from the impairment review is charged to a separate line item within
the Statement of Comprehensive Income.
5) 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.
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
In 2021 the ROU assets and lease obligations related to the adoption of 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 approximately 9.25% was used for all ROU (except Saturn Banks Pipeline
permission)n in arriving at net present value of future lease payments as they
belong to the same asset class and 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 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.
Share issue expenses and share premium account
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 and Group 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. No
expense is recognised for options that do not ultimately vest except where
vesting is only conditional upon a market condition.
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 have 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 estimates and judgements
The Group makes certain estimates and assumptions regarding the future.
Estimates and judgements are continually evaluated based on historical
experience and other factors, including expectations of future events that are
believed to be reasonable under the circumstances. In the future, actual
experience may differ from these estimates and assumptions. The estimates
and assumptions 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.
Judgements
Where judgements have been applied, these can affect the outcome and results
within the Financial Statements. An area that carries significant judgement is
around the accounting for the IFRS 16 assumptions for the Noble Hans Deul rig
contract, charter of 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 Noble Hans Deul) and the incremental borrowing rate have
been made by Management.
The Group capitalises the borrowing cost, so far as the monies borrowed are
utilised towards financing capital expenditures in engineering, construction,
and procurement of its onshore and offshore facilities, drilling wells. The
rate of capitalisation of interest is based on the level of actual capital
expenditure incurred on each of the identified assets. Capitalisation of
interest costs ceases when the asset is considered available for use.
The right of use assets recognised under IFRS 16 for lease with terms
extending over a year are depreciated over the lease term on straight line
method. The 3 main leases relate to equipment and facilities (Rig, Platform
supply vessel, Emergency Rapid Response vessel) that are used in carrying out
field Development activities and the amount equal to the depreciation is
capitalised and to that extent the estimated value of work done accruals are
adjusted to reflect the most accurate asset values. Management has made
judgements as to the lease period, estimate of cash outflows and application
of appropriate internal borrowing rate.
The Group capitalises a certain proportion of its personnel / staff costs as
D&P tangible assets or E&E intangible assets based on a system of time
writing. This system requires identified staff to input their hourly details
based on work performed to against the specific assets and/or activities. An
hourly rate has been defined based on components of staff costs and varies
depending on staff seniority. The definition of hourly rate and time writing
involves management judgement.
Estimates and assumptions
− Impairment Exploration, Development and Producing assets - Estimate of
future cash flows and determination of the discount rate (see note 10).
− 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 (note 23)
− The determination of the incremental borrowing rate used to measure lease
liabilities (note 1)
Impairment of assets
Management is required to assess oil and gas assets for indicators of
impairment and has considered the economic value of individual E&E and
D&P assets. The carrying value of oil and gas assets is disclosed in
Notes 11.
E&E assets are subject to a separate review for indicators of impairment,
by reference to the impairment indicators set out in IFRS 6, which is
inherently judgmental.
Indicators of impairment include, but are not limited to:
• Rights to explore in an area have expired or will
expire in the near future without renewal
• No further exploration or evaluation is planned or
budgeted
• A decision to discontinue exploration and evaluation
in an area because of the absence of commercial reserves
• Sufficient data exists to indicate that the book value
will not be fully recovered from future development and production.
D&P assets are reviewed for impairment by reference to indicators set out
in IFRS 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.
Key estimates used in the assessment of value in use and fair value less costs
to sell assessments
As noted in the accounting policy the carrying value of the assets is assessed
against the higher of a value-in-use calculation and a fair value less costs
to sell assessment.
The calculation of value-in-use for oil and gas assets under development or in
production is most sensitive to the following assumptions:
· Commercial reserves;
· production volumes/recoverable reserves;
· commodity prices;
· fixed and variable operating costs;
· capital expenditure; and
· discount rates
In assessing value in use, estimated future cash flows are discounted to their
present value using a discount rate appropriate to the specific asset or cash
generating unit. If the recoverable amount of an asset or cash-generating unit
is estimated to be less than its carrying amount, the carrying amount of the
asset or cash-generating unit is reduced to its recoverable amount. Impairment
losses are recognised immediately in the statement of comprehensive income.
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, oil and
gas asset impairments, as well as the valuation of assets in use. Estimates
of commercial reserves include estimates of the amount of oil and 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 oil and gas price.
Production volumes/recoverable reserves
Annual estimates of oil and gas reserves are generated internally by the Group
with external input from operator profiles and/or a Competent Person. These
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 UKNBP gas and Brent oil
are used for future cash flows in accordance with the Group's corporate
assumptions. Field specific discounts and prices are used where applicable.
Fixed and variable operating costs
Typical examples of variable operating costs are pipeline tariffs, treatment
charges and freight costs. Commercial agreements are in place for most of
these costs and the assumptions used in the value-in-use calculation are
sourced from these where available. Examples of fixed operating costs are
platform costs and operator overheads. Fixed operating costs are based on
operator and/or third-party duty holder budgets.
Capital expenditure
Field development is capital intensive and future capital expenditure has a
significant bearing on the value of an oil and 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.
Capitalisation of the 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 is substantially ready for their intended use.
Although a significant progress has been made in the Engineering, construction
and installation of the qualifying assets they were not fully tested and
commissioned at the end of the year nor at the assets been put to their
intended use and hence directly attributable borrowing costs continued to be
capitalised.
Discount rates
Discount rates reflect the current market assessment of the risks specific to
the oil and 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 9.25% for the current year (2020: 10%).
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 production volumes (linked to
recoverable reserves) and commodity prices.
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.
Decommissioning
At 31 December 2021, the Group has obligations in respect of decommissioning a
suspended well on the Southwark, Nailsworth and Elland D&P assets,
together with the offshore Saturn Banks Pipeline and the acquired Saturn Banks
Reception Facilities at Bacton.
The extent to which a provision is recognised depends on the legal
requirements at the date of decommissioning, regulatory activity required to
ensure such infrastructure meets safety and environmental requirements, the
estimated costs and timing of the work and the discount rate applied.
A full decommissioning estimate for the Blyth, Southwark, Nailsworth and
Elland D&P assets remains uncertain until all development infrastructure
has been installed and production volumes and time to decommissioning has been
considered. Until all development infrastructure has been installed and
production volumes and time to abandonment has been considered, there is
significant estimation uncertainty when providing a decommissioning estimate.
The Blythe Offshore Gas Field: (Platform, well and 12" pipeline) - the site
decommissioning and restoration obligation is specified in the license
agreement, with approvals from the OGA. An internal assessment has been made
at FDP and reassessed recently and based on the assessment the decommissioning
costs are estimated to be £3.9 million nominal value (IOG net share 50%). As
per the current development plans this asset will be in use until 2038 with
decommissioning occurring the year after in 2039.
Elgood Offshore Oilfield: (Well, subsurface structure and 6" pipeline): The
site decommissioning and restoration obligation is specified in the license
agreement, with approvals from the OGA. An internal assessment has been made
at FDP and based on this the decommissioning costs are estimated to be £1.9
million nominal value (IOG net share 50%). As per the current development
plans this asset will be in use until 2038 with decommissioning occurring the
year after in 2039.
Southwark Offshore Oilfield: (Platforms, wells, subsurface structures, and
pipelines): The site decommissioning and restoration obligation is specified
in the license agreement with approvals from the OGA. An internal assessment
has been made at FDP and based on this the decommissioning costs are estimated
to be £7.5 million nominal value (IOG net share 50%). As per the current
long-term plans of IOG this asset will be in use until 2038 with
decommissioning expected the year after in 2039.
Elland Offshore Oilfield: As licensee and operator, IOG UK Ltd is responsible
for the decommissioning liability with respect to the Elland (former Vulcan
East) suspended well 49/21-10A located within Licence P039. An internal
assessment has been made in 2021 and based on this the decommissioning costs
are estimated to be £1.2 million nominal value (IOG net share 50%). As per
the current plans of IOG this well will be decommissioned in 2023.
On acquisition of the Saturn Banks Pipeline, the Group assumed the
decommissioning liability for the pipeline, which is based upon a regulatory
framework determined by the OGA. The expected useable life of the pipeline,
along with the structural integrity were assessed when calculating the
provision. A discounted cost estimate provision has been made in the financial
statements as at 31 December 2021 and this provision will continue to be
reviewed on an annual basis, given the regulatory framework is subject to
constant change and is inherently uncertain over future years.
On acquisition of the Saturn Banks Reception Facilities at Bacton, the Group
assumed the initial decommissioning liability for the asset which was cash
collateralised, which is based upon a contractual obligation with Perenco. A
provision has been made in the financial statements as at 31 December 2021.
This provision will be reviewed on an annual basis and reassessed once the
development has been completed. The estimates and underlying assumptions are
reviewed on an ongoing basis. Revisions to accounting estimates are
recognised in the period in which the estimate is revised, if the revision
only affects that period, or, in the period of revision and future periods, if
the revision affects both current and future periods.
The Decommissioning cost estimates for are based on assumptions made at the
time of FDP and have been adjusted for more thorough understanding of
decommissioning engineering specifications, these cost estimates have been
refined based on near term experience of similar activities and awarded
contracts and prices.
Management has also performed a review of appropriate discounting factor based
on a pre tax risk free rate as a starting point with reference to UK
Government bond rate for term similar to that of decommissioning obligation
adjusted for specific risks inherent to the cash flow under consideration.
Management performed sensitivity analysis to assess the impact of changes to
the risk-free rate on the Group's decommissioning provision balance. A 0.5%
decrease in the risk-free rate assumption would result in an increase in the
decommissioning provision by £1 million.
Contingent Consideration
The Group was required under the terms of the 2016 acquisition of the
additional 50% of Blythe, the 2016 acquisition of Vulcan Satellites, to make
further amounts payable on both the FDP approval (Vulcans), and first gas
(Blythe and Vulcans).
These milestone events triggering deferred consideration payments were
considered to be more certain than not and a non-current amount of £2.3
million was recognised. These amounts were provided for and the payments
discounted to the point where the Board expect the milestones to be achieved
based on the current development programme.
However during 2021 the administrators of the counter party have instructed
the company that the deferred consideration is deemed to have expired and the
administrators do not consider this to be payable any longer by the company.
Management have therefore taken the judgement to reverse the non-current
liability.
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.
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. Operating (loss)
The Group's operating loss (2020: loss) is stated after charging/(crediting)
the following:
2021 2020
£000 £000
Fees payable to the Company's auditor: 128 99
- for the audit of the Group's financial
statements
Non-audit services 7 24
Of which
for the audit of the Company's financial statements 62 62
( )
( )
Depreciation, depletion and amortisation 519 559
Project, pre-licence and exploration expenses 104 180
Impairment of oil and gas properties 865 12,598
Effect of exchange rate changes on Bond (5,901) (4,792)
Effects of exchange rate changes on cash and cash equivalents 2,461 5,493
4. Personnel costs and directors' remuneration
During the year, the average number of personnel, including contract
personnel, for both the Company and Group was:
2021 2020
Number Number
Management / technical / operations 52 52
of which: Directors 5 6
Personnel costs Group and Company £000 £000
Wages, salaries, fees and other direct costs 6,379 4,018
Social security costs 850 509
Pension costs 298 232
Share-based payments 1,284 941
________ ________
8,811 5,700
________ ________
Note that project contract personnel, capitalised directly to project cost
centres, are excluded from the above personnel cost figures.
Key management personnel are deemed to be the Directors, the Chief Operating
Officer, the General Counsel & Company Secretary and the Head of Capital
Markets & ESG.
Of the total personnel costs of £8,811k (2020: £5,700k), was capitalised to
the balance sheet under PP&E £6,332k (2020: £3,107k) and Intangibles
£655k (2020: £2,593k).
Directors' remuneration Salary/ Fees Salary/Fees Sacrificed Bonus Benefits ((1)) Share-based payment 2021 Salary/ Salary/Fees Sacrificed Bonus Benefits ((1)) Share-based payment 2020
Total Fees Total
£000 £000 £000 £000 £000 £000 £000 £000 £000 £000 £000 £000
Fiona MacAulay(2) 113 7 - - - 120 113 7 - - - 120
Esa Ikaheimonen 17 33 - - - 50 - 50 - - - -
Neil Hawkings 42 3 - - - 45 42 3 - - - 45
Andrew Hockey 308 22 146 43 - 519 308 22 - 38 - 368
Rupert Newall 234 17 163 31 - 445 234 16 - 29 - 279
Mark Hughes(3) - - - - - 171 15 - 23 - 209
______ _______ _____ _____ ______ ______ _____ _______ ____ ____ ______ ______
714 82 309 74 - 1,179 898 113 - 90 - 1071
_____ _____ _____ _____ ______ ______ _____ _______ ____ ____ ______ ______
Other key management personnel 557 22 66 74 - 719 399 21 40 45 12 517
Total key management personnel 1,271 104 375 148 - 1,898 1,267 134 40 135 12 1,588
( )
(1 Benefits includes pension contributions, healthcare and life cover.)
(2 Fiona MacAulay sacrifices £10,000 of her fees to a personal pension plan,
paid directly into by the company.)
(3 Mark Hughes resigned on 11 November 2020)
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 £237k
(2020 - £189k).
The share-based payment amounts represent the charges for share options during
the year.
For the current Directors at 31 December 2021, the service agreements provide
that the full contractual amount will be paid in cash. In addition, there is
the option to voluntarily elect to sacrifice up to 100% cash and receive the
equivalent amount in share options. The salary sacrifice option was
reintroduced for all Directors with effect from May 2020 and ended in August
2021, except for Esa Ikaheimonen who sacrificed all his fees for share options
since joining the Company which also ended in August 2021.
The average proportions of monthly salaries paid in cash and share options in
2021 for all Directors is as follows:
Cash Shares
Fiona MacAulay 93% 7%
Andrew Hockey 93% 7%
Rupert Newall 93% 7%
Esa Ikaheimonen 33% 67%
Neil Hawkings 93% 7%
For each six-month interval, ending on 28 (or 29) February and 31 August
respectively, the Company settles the difference between the reduced rate and
the full rate through the granting of options over ordinary shares of the
Company at the volume-weighted average share price over the period to which
they relate.
Amounts of salary and/or fees outstanding at 31 December 2021 to which these
terms relate totalled £nil (31 December 2020 - £43k) for Directors and key
management personnel and £nil (2020 - £16k) for other personnel. These share
options are yet to be issued.
Directors' interests in options on 1p ordinary shares of the Company at 31
December 2021 were as follows:
Granted Type Total Awarded in 2021 Total Exercise price Expiry date
31 Dec 2020 31 Dec 2021
Andrew Hockey 01-Mar-18 LTIP 1,600,000 - 1,600,000 20p 28-Feb-28
01-May-19 CSOP 1,600,000 - 1,600,000 12.75p 30-Apr-29
31-Aug-19 Salary Sacrifice 267,740 - 267,740 1p 31-Aug-24
02-Jan-20 CSOP 2,256,410 - 2,256,410 1p 01-Jan-30
01-Apr-20 Salary Sacrifice 62,460 - 62,460 1p 01-Apr-25
31-Aug-20 Salary Sacrifice 103,248 - 103,248 1p 05-Oct-25
28-Jan-21 CSOP 2,314,166 2,314,166 1p 27-Jan-31
28-Feb-21 Salary Sacrifice 135,437 135,437 1p 28-Feb-26
31-Aug-21 Salary Sacrifice 90,908 90,908 1p 28-Sep-26
5,889,858 2,540,511 8,430,369
Rupert Newall 01-May-19 CSOP 1,200,000 - 1,200,000 12.75p 30-Apr-29
31-Aug-19 Salary Sacrifice 240,966 - 240,966 1p 31-Aug-24
02-Jan-20 CSOP 1,709,402 - 1,709,402 1p 01-Jan-30
01-Apr-20 Salary Sacrifice 56,214 - 56,214 1p 01-Apr-25
31-Aug-20 Salary Sacrifice 78,218 - 78,218 1p 05-Oct-25
28-Jan-21 CSOP 1,753,156 1,753,156 1p 27-Jan-31
28-Feb-21 Salary Sacrifice 102,604 102,604 1p 28-Feb-26
31-Aug-21 Salary Sacrifice 68,869 68,869 1p 28-Sep-26
3,284,800 1,924,629 5,209,429
Esa Ikaheimonen 01-May-19 LTIP 600,000 - 600,000 12.75p 30-Apr-29
31-Aug-19 Salary Sacrifice 136,606 - 136,606 1p 31-Aug-24
29-Feb-20 Salary Sacrifice 114,152 - 114,152 1p 31-Mar-25
01-Apr-20 Salary Sacrifice 39,974 - 39,974 1p 01-Apr-25
31-Aug-20 Salary Sacrifice 234,627 - 234,627 1p 05-Oct-25
28-Feb-21 Salary Sacrifice 205,208 205,208 1p 28-Feb-26
31-Aug-21 Salary Sacrifice 137,739 137,739 1p 28-Sep-26
1,125,359 342,947 1,468,306
Fiona MacAulay 01-May-19 LTIP 1,000,000 - 1,000,000 12.75p 30-Apr-29
31-Aug-20 Salary Sacrifice 34,416 - 34,416 1p 05-Oct-25
28-Feb-21 Salary Sacrifice 45,146 45,146 1p 28-Feb-26
31-Aug-21 Salary Sacrifice 30,303 30,303 1p 28-Sep-26
1,034,416 75,449 1,109,865
Neil Hawkings 24-May-19 LTIP 600,000 - 600,000 13.5p 28-Feb-24
31-Aug-19 Salary Sacrifice 18,061 - 18,061 1p 31-Aug-24
31-Aug-20 Salary Sacrifice 14,079 - 14,079 1p 05-Oct-25
28-Feb-21 Salary Sacrifice 18,469 18,469 1p 28-Feb-26
31-Aug-21 Salary Sacrifice 12,396 12,396 1p 28-Sep-26
632,140 30,865 663,005
5. Finance expense
2021 2020
£000 £000
Interest on loans (14) 103
Amortisation of loan finance charges - 2
Current year loan finance charges 560 540
Current year finance charges on deferred payment creditors - 19
Unwinding of discount on convertible loan 1,001 1,027
Unwinding of deferred consideration provisions (118) 158
Unwinding of discount on lease liability 1,637 354
Interest on bonds 8,253 8,668
Capitalisation of interest on bonds(1) (8,253) (8,668)
( ) ________ ________
3,066 2,203
________ _________
(1 During the Phase 1 development, all interest paid in the Norwegian bonds is
capitalised to the Phase 1 assets proportionately based on their capital
expenditure during the year)
During 2021 there were no interest bearing loans outstanding other than the
Norwegian Bonds. The interest associated with the Bond is capitalised to
project costs as the bond drawdowns are purposefully used to finance the
development of the project assets.
6. 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:
2021 2020
£000 £000
Loss for the year (4,266) (19,337)
Income tax expense - -
_________ _________
Loss before income taxes (4,266) (19,337)
Expected tax expense/(credit) based on the standard rate of United Kingdom (1,706) (7,735)
corporation tax at the domestic rate of 40%(1) (2020: 40%)
Difference in tax rates 1,168 1,952
Expenses not deductible for tax purposes (77) 260
Income not taxable (7,618) (4,590)
Group relief claimed (2) -
Unrecognised taxable losses carried forward 8,235 10,113
_________ _________
Total tax expense - -
_________ _________
( )
(1)( The standard rate of corporation tax of 40% (2020: 40%) , including the
supplemental corporation tax charge of 10% (2020:10%) is levied in respect of
UK ring fence profit. Non-ring fenced profits are taxed at the standard rate
of corporation tax of 19%. 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.)
b) Deferred taxation
Due to the nature of the Group's exploration 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 £ 220.6 million (2020:£122.7 million). There are also
accelerated capital allowances of £111.0 million (2020:£35.7 million)
The Group has not recognised a deferred tax asset at 31 December 2021 on the
basis that the Group would expect the point of recognition to be when the
Group has some level of production history showing that the Group is making
profits in line with the underlying economic model which would support the
recognition.
The group has carried forward ring fence tax losses of £196.4 million (2020:
£111. 5 million) and non-ring fence tax losses of £16.6 million (2020: £
13.4 million). In addition the group has pre- trading revenue expenditure of
£4.8 million ( 2020: £2.9 million) (to the extent that the company commences
a trade within seven years from the time the expenditure was incurred) and
pre-trading capital expenditure of £20.7 million (2020:£5.3 million) that
would be available upon commencement of the trade in the respective group
company.
7. Loss per share
2021 2020
£000 £000
(Loss) for the year attributable to shareholders (Numerator) (4,266) (19,337)
___________ ___________
Weighted average number of ordinary shares: basic (Denominator) 513,584,870 488,211,155
Add potentially dilutive shares:
Convertible loan notes 60,872,631 60,872,631
Salary/Fee sacrifice options 4,325,027 4,480,836
LTIP/CSOP 26,369,136 20,809,486
Warrants 20,000,000 20,000,000
625,151,664 594,374,108
diluted
___________ ___________
Loss / Earnings per share in pence: nil (4.0p)
basic
nil (4.0p)
diluted
Diluted loss 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.
As the current year result for the year was a loss, the options and warrants
outstanding would be anti-dilutive. Therefore, the dilutive loss per share
is considered as the same as the basic loss per share.
In 2020 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.
8. Intangible assets
Group
Exploration & evaluation assets Company & IT software assets Total Exploration & evaluation assets Company & IT software assets Total
2021 2021 2021 2020 2020 2020
£000 £000 £000 £000 £000 £000
At cost
At beginning of the year 36,274 321 36,595 35,466 120 35,586
Additions 506 15 521 808 201 1,009
Disposals - - - - - -
_________ _________ ________ _________ _________ ________
At end of the year 36,780 336 37,116 36,274 321 36,595
_________ _________ ________ _________ _________ ________
Impairments and write-downs
At beginning of the year (34,965) (151) (35,116) (22,367) (40) (22,407)
Amortisation - (110) (110) - (111) (111)
Impairment (865) - (865) (12,598) - (12,598)
________ ________ ________ ________ ________ ________
At end of the year (35,830) (261) (36,091) (34,965) (151) (35,116)
_________ _________ ________ ________ ________ ________
Net book value
At 31 December 2021 950 75 1,025
At 1 January 2021 1,309 170 1,479
At 1 January 2020 13,099 80 13,179
Exploration and evaluation assets at 31 December 2021 comprise the Group's
interest in the Abbeydale appraisal, the Goddard pre-development prospects and
Panther and Grafton.
The affected E&E assets are tested for impairment once indicators have
been identified.
After completing the technical analysis of Harvey, IOG has fully determined
the Harvey licence in December 2021. The Redwell licence, was fully determined
(surrendered) in March 2021, both the licences have been fully impaired in
2021 as no further investment is planned on these licences.
9. Property, plant and equipment
Group
D&P assets Phase 1 D&P assets Phase 2 Pipeline assets Right of use assets Admin assets Total
2020 2020 2020 2020 2020 2020
£000 £000 £000 £000 £000 £000
At cost
At beginning of the year 13,847 4,062 11,012 1,054 258 30,233
On transition - - - - - -
Additions 19,828 3,088 2,499 17,496 379 43,290
Change in estimate of decommissioning asset (note 18) - - (1,850) - - (1,850)
- - 936 - - 936
Decommissioning asset (note 18)
Disposals - - - - - -
Saturn Banks Pipeline decommissioning security - - - - - -
______ ______ ______ ______ ______ _____
At end of the year 33,675 7,150 12,597 18,550 637 72,609
______ ______ ______ ______ ______ _____
Accumulated depreciation
At beginning of the year - - - (145) (96) (241)
DD&A - - - (2,231) (174) (2,405)
At end of the year - - - (2,376) (270) (2,646)
D&P assets D&P assets Phase 2 Pipeline assets Right of use assets Admin assets Total
Phase 1
2021 2021 2021 2021 2021 2021
£000 £000 £000 £000 £000 £000
At cost
At beginning of the year 33,675 7,150 12,597 18,550 637 72,609
On transition - - - - - -
Additions 57,673 263 17,274 2,753 17 77,979
Change in estimate of decommissioning asset (note 18) - - (1,824) - - (1,824)
11,613 (17) - - - 11,596
Decommissioning asset (note 18)
Disposals - - - - - -
Saturn Banks Pipeline decommissioning security - - - - - -
______ ______ ______ ______ ______ _____
At end of the year 102,961 7,396 28,047 21,303 654 160,360
______ ______ ______ ______ ______ _____
Accumulated depreciation
At beginning of the year - - - (2,376) (270) (2,646)
DD&A - - - -(14,276) (163) (14,439)
At end of the year - - - (16,652) (433) (17,085)
Net book value
At 31 December 2021 102,961 7,396 28,046 4,650 221 143,275
At 1 January 2021 33,675 7,150 12,597 16,174 367 69,963
At 1 January 2020 13,847 4,062 11,012 909 162 29,992
Phase 2 development and production assets are currently scheduled for Final
Investment Decision in 2H 2022.
The £200k paid as decommissioning security guarantees in 2018 in respect of
both the Elland P039 Licence suspended well and the Initial Pipeline
Decommissioning Security were classified as fixed assets at 31 December 2019.
In 2019, a further £2.0 million Saturn Banks was paid upon acquisition as
security against the Saturn Banks Facilities Decommissioning Security.
Following the farm-down to CER, the above amounts were reduced by 50%
resulting in £100k held against the Elland P039 licence, £250k against the
Saturn Banks Pipeline, and £1.0 million against the Saturn Banks Reception
Facilities. At the year end, £1.25 million for the Saturn Banks Pipeline
and Saturn Banks Reception Facilities classified as Restricted cash on the
balance sheet.
In 2020, due to the 12" and 6" pipeline laying campaign, a further £0.9
million was recognised as a decommissioning liability. A re-assessment of
the Saturn Banks Reception Facilities decommissioning liability was also
conducted and the amount reduced to £3.2 million.
All assets were assessed for impairment under IAS 36, no impairment has been
recognised during the year (2020: nil).
Company
D&P assets Right of use assets Admin assets Total D&P assets Phase 1 Right of use assets Company & admin assets Total
Phase 1
2021 2021 2021 2021 2020 2020 2020 2020
£000 £000 £000 £000 £000 £000 £000 £000
At cost
At beginning of the year 1,959 18,550 637 21,146 - 1,054 258 1,312
Additions - 2,753 17 2,770 1,959 17,496 379 19,834
______ ______ ______ _____ ______ ______ ______ _____
At end of the year 1,959 21,303 654 23,916 1,959 18,550 637 21,146
______ ______ ______ _____ ______ ______ ______ _____
Accumulated depreciation
At beginning of the year - (2,376) (270) (2,646) - (145) (96) (241)
DD&A (1,959) (14,276) (163) (16,398) - (2,231) (174) (2,405)
______ ______ ______ _____ ______ ______ ______ _____
At end of the year (1,959) (16,652) (433) (19,044) - (2,376) (270) (2,646)
______ ______ ______ _____ ______ ______ _____ _____
Net book value
At 31 December 2021
- 4,651 221 4,872
At 1 January 2021 1,959 16,174 367 18,500
At 1 January 2020 - 909 162 1,071
Phase 1 assets for the Company relate to the depreciation of the right of use
asset in relation to the Noble Hans Deul rig contract. The depreciation on
right of use asset is capitalised as D&P assets for the group.
All assets were assessed for impairment, but no impairment indicators were
identified.
10. Convertible Loans
The table below sets out the opening, movement and closing position of the LOG
loans in 2020.
Loan Facility 2020 B/fwd Balance 2020 Drawdown 2020 Interest 2020 Cash Settlement 2020 Converted to ordinary shares 2020 Gain on loan modification Carrying Value at 31 December 2020
2020
Unwinding discount
£000 £000 £000 £000 £000 £000 £000 £000
£10.00 million facility 6,819 - - - - - 1,218 8,037
6,819 - - - - - 1,218 8,037
The table below sets out the opening, movement and closing position of the LOG
loans in 2021.
Loan Facility 2021 B/fwd Balance 2021 Drawdown 2021 Interest 2021 Cash Settlement 2021 Converted to ordinary shares 2021 Gain on loan modification Carrying Value at 31 December 2021
2021
Unwinding discount
£000 £000 £000 £000 £000 £000 £000 £000
£10.00 million facility 8,037 - - - - (216) 1,001 8,822
8,037 - - - - (216) 1,001 8,822
11. Investments
Shares Loans
in Group to Group
Company companies companies Total
£000 £000 £000
At cost
At 1 January 2020 15,486 28,710 44,196
Additions - 16,196 16,196
_________ _________ _________
At 31 December 2020 15,486 44,906 60,392
Additions - 64,289 64,289
Disposals
_________ _________ _________
At 31 December 2021 15,486 109,195 124,681
Net book value
At 1 January 2020 15,486 28,710 44,196
At 1 January 2021 15,486 44,906 60,392
At 31 December 2021(1) 15,486 109,195 124,681
(1There were no impairments in the 2021 period. Although the Harvey (P2085)
licence was impaired during the period by IOG North Sea Limited, the Company
has assessed the subsidiaries ability to repay its loans and believes there is
sufficient cash flow from other assets held by the subsidiary to fulfil its
obligation.)
The Company has undertaken not to seek repayment of loans from other Group
subsidiary companies until each subsidiary has sufficient funds to make such
payments, however they are technically due on demand. The repayment of the
subsidiary loans is expected to begin once each entity generates revenues from
gas sales and transportation. The Company expects these loans to begin to be
repaid in 2022 and is supported by its detailed cash flow modelling. These
loans are non-interest bearing.
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.
12. Financial Asset
IOG held €1.7 million (£1.3 million) of its Norwegian bonds, which were
sold during the year in the open market and the gain on sale has been
recognised in the statement of comprehensive income.
2021 2020
£000 £000
At 1 January 1,260 -
Additions - 1,525
Fair value adjustment 199 (265)
Disposal (1,459) -
________ ________
At 31 December - 1,260
________ _________
13. Interests in production licences
At 31 December 2021, 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. Harvey and Redwell have been fully determined
(surrendered).
14. Other receivables and prepayments
2021 2020
£000 £000
Group
VAT recoverable 1,455 869
Prepayments 245 205
Other receivables 5 25
_________ _________
1,705 1,099
_________ _________
Company
VAT recoverable 1,455 2,236
Prepayments 246 205
Other receivables 5 25
_________ _________
1,706 2,466
_________ _________
The 2021 prepayments relate to rental charges for its 189 Endeavour House
office space in London and general administration.
The Company has considered the carrying value of 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 future cash flows from the entities and concluded there is no
material ECL provision required.
15. Current liabilities
2021 2020
£000 £000
Group
Accruals 13,350 3,106
Operator advance accounts 11,728 4,100
Lease liabilities 11,068 13,781
Trade payables 7,708 979
Contingent consideration payable 659 -
Tax payable 367 165
_________ _________
44,880 22,131
_________ _________
Company
Lease liabilities 11,070 13,781
Trade payables 7,708 979
Accruals 2,709 1,213
Contingent consideration payable 659 -
Tax Payable 367 165
_________ _________
22,513 16,138
_________ _________
Current liabilities include:
· Lease liabilities under IFRS 16 relate to the future payment
obligation within the year.
· Accruals relate to estimates of value of work carried out under
engineering, construction, procurement and commissioning activities and
contracts related therewith.
· Operators advance accounts is the balance due to JV partners and
is the difference between cash calls received and billing statements at the
balance sheet date.
· Trade payables relate to unpaid invoices to various suppliers and
service providers at the balance sheet date.
· Contingent consideration relates to an additional consideration
payable 3 months after first gas as part of the acquisition of the Southwark
asset.
· Tax payable is the outstanding balance due to HMRC at the end of
the year.
16. Non-current liabilities
2021 2020
£000 £000
Group
Long-term loans 91,257 95,813
Lease liability 395 4,968
Contingent consideration payable - 2,302
Decommissioning provision 15,837 6,227
_________ _________
107,489 109,310
_________ _________
Company
Long-term loans 91,257 95,813
Lease liability 395 4,968
Contingent consideration payable - 613
_________ _________
91,652 101,394
_________ _________
Long-term loans:
The Nordic bond issued in 20 September 2019 represents £82.4 million (2020:
87.8 million) of the long-term loans balance with the LOG loan of £8.8
million being the balance of the total of £91.3 million. See note 20 for
further details of the Nordic bond.
The amounts drawn on LOG loans at 31 December 2021 and 31 December 2020 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 £11.6 million Nil
23 September 2024
See note 10 for information relating to the outstanding LOG loan.
Contingent consideration payable:
The Group is required under certain terms its acquisitions to make further
amounts payable upon first gas.
The deferred consideration which was considered to be certain expired under
the terms of the contract and consequently the non-current liability has been
released in 2021.
The movements in the year are as follows:
2021 2020
£000 £000
At 1 January 2,302 3,114
Settlement of liability (1) - (875)
Foreign exchange - (96)
Unwinding of discount - 159
Lapsed (2,302) -
At 31 December - 2,302
(1 Payment made following the FDP approval of Phase 1 by the OGA.)
The liability expired under the terms of the contract on 9(th) of January 2021
and therefore the balance due is now NIL:
2021 2020
£000 £000
Non-Current contingent consideration - 2,302
- 2,302
Decommissioning provision:
2021 2020
£000 £000
At 1 January 6,226 7,239
Revision in estimates (1,948) (1,850)
Discount unwinding 10 (99)
Additions 11,549 936
At 31 December 15,837 6,226
The Group has regulatory and financial obligations in respect of
decommissioning for a suspended well on the Elland Licence P039 - Gross £2.4
million (2020: £2.4 million), net to the Company £1.2 million.
Decommissioning the Saturn Banks Pipeline - £0.1 million (2020: £2.0
million). For the Saturn Banks Reception Facilities at Bacton the company
holds further decommissioning liabilities totalling £3.3 million net to the
Company. The Company, as a result of its work program in 2021 has
decommissioning liabilities of £13.2 million (net) for the addition to Phase
1 construction project and drilling program.
A full decommissioning estimate for the Elland suspended well remains
uncertain until an appropriate drilling programme has been reviewed and
considered for the Elland development, which may include the decommissioning
of that particular well. The timing and thus payment of this decommissioning
program remains inherently uncertain.
The current £0.1 million provision for the Saturn Banks Pipeline
decommissioning obligation has been calculated on a discounted cash flow
basis, whereby the present value of the regulatory marine surveys has been
inflated at 2% and then discounted at the risk-free discount rate of 2.75%. It
has been estimated that the Saturn Banks Pipeline has a useful life over the
next 25 years; however, the judgements made on this and other variables,
currently provided by the OGA, are inherently uncertain and this is reflected
in the fact that the provision in 2021 net to the company was £0.1 million
The £7.6 million (2020) provision for the Saturn Banks Reception Facilities
decommissioning obligation has been reduced to £6.7 million recognised on the
basis of the SPA, then reduced to reflect the Farm-out to CER (£3.35 million
net). Resulting in a net £3.35 million liability. An initial payment of
£2.0 million was made by the Company as security for the liability on
completion of the Saturn Banks Reception Facilities transaction which was then
reduced for CER's 50% share to £1.0 million. The Group is due to pay a
further eight quarterly payments of £0.5 million as security six months after
the start of gas production. The Group has chosen to recognise the full amount
of the liability represented in the SPA as there is no material difference of
discounting the payments back to the balance sheet date.
17. Net (Debt) / Cash
IOG uses the following definition of net (debt)/cash - restricted cash and
cash equivalents plus the financial asset, less total loans.
2021 2020
£000 £000
Restricted cash 3,429 67,049
Cash and cash equivalents 31,255 13,389
Fair value asset - 1,260
Loans (91,257) (95,813)
Net (debt) (56,573) (14,115)
18. Share capital
Share Share
capital premium Total
Number £000 £000 £000
Authorised, allotted, issued and fully paid
At 1 January 2020
- Ordinary shares of 1p each 480,173,245 4,802 49,423 54,225
Equity issued:
- December 2020, Ordinary shares of 1p, London Oil & Gas Ltd, Warrant 7,877,310 78 566 644
exercise (2)
- Other LTIP and Salary sacrifice share exercises (1) 160,600 2 - 2
488,211,155 4,882 49,989 54,871
At 31 December 2020 488,211,155 4,882 49,989 54,871
- Ordinary shares of 1p each
Equity issued:
- September 2021, Ordinary shares of 1p, (3) 33,800,000 338 8,112 8,450
- Other LTIP and Salary sacrifice share exercises 1,753,057 18 48 66
( ) _________ _________ _________ _________
At 31 December 2021 523,764,212 5,238 58,149 63,387
- Ordinary shares of 1p each
_________ _________ _________ _________
( )
(1 For further details, see related party transactions note 24 )
(2 During 2020, London Oil & Gas Ltd exercised 7,500,000 of their warrants
at 8 pence per share and 377,310 warrants at 11.9 pence per share. )
(3 During 2021, the carried out a share placement of 33,800,00 at 25 pence per
share. )
Share Placing
In September 2021, the Group raised gross proceeds of £8.5 million through
the issue of ordinary shares at 10 pence. The two components of shares were
issued:
Ordinary Shares £000
Placement 33,800,000 8,450
Directors Subscription 200,000 50
34,000,000 8,500
The Company successfully raised gross proceeds of £8.5 million through a
placing (the "Placing") and subscription (together, the "Fundraise"). The
Company has placed 33,800,000 new Ordinary Shares at a price of 25 pence per
New Ordinary Share (the "Issue Price") with existing and new investors and a
further 200,000 new Ordinary Shares at a price of 25 pence per share to
Directors of the Company.
The Issue Price represents a premium of approximately 1.0% to the 30-day
volume weighted average price of an Ordinary Share to 22 September 2021 of
24.75 pence and a discount of approximately 8.3% to the closing mid-market
price of an Ordinary Share of 27.25 pence on 22 September 2021. The New
Ordinary Shares will represent 6.5% of the Company's Enlarged Issued Share
Capital.
Share options and warrants
During the current and prior year, the Company granted share options under its
share option plans as follows:
Number Price Date of Grant Expiry
1 January 2020 14,111,871 13.03p
Salary/fee sacrifice options 114,152 1p 29 Feb 2020 31 Mar 25
CSOP cancelled/expired (395,279) 1p
CSOP options 10,274,102 1p Various dates in 2020 Various dates in 2023
Salary/fee sacrifice options 1,046,076 1p 31 Aug 2020 05 Oct 25
Options exercised (160,600)
31 December 2020 25,290,322 7.70p
Salary/fee sacrifice options 972,685 1p 28 Feb 2021 28 Feb 26
CSOP cancelled/expired (2,875,284) 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
Of the remaining staff options, 14,111,871 outstanding at 31 December 2019,
126,497 were exercised during the year. Of those personnel options granted
during 2020, 34,103 were exercised during 2020. Total personnel options
exercised in 2020 is thus 160,600.
Of the remaining staff options, 25,290,322 outstanding at 31 December 2020,
2,072,252 were exercised during the year.
The fair value of these options exercised was transferred from the Share-based
Payment Reserve to Accumulated Loss
CSOP Valuation
The 2021 CSOP valuation is based on a Log-normal Monte-Carlo stochastic model.
The valuation model assumes:-
- Share price at date of grant 22.50p
- Exercise price of 1.00p
- Option life of 10 years
- The risk-free rate and volatility of the underlying are known and
constant (0.17%, 3 year UK government bond at grant date)
- Share price volatility is 64.56%
- 10,000 iterations
LTIP Valuation
There were no LTIP shares granted in 2021 and 2020. The LTIP valuation is
based on a Log-normal Monte-Carlo stochastic model.
The valuation incorporates a forecast employee turnover to establish the
number of options expected to vest, the charge requires recalculation each
year to take account of any revised estimates regarding employee turnover and
any new grants of share options.
- Efficient markets (i.e., market movements cannot be predicted)
- No commissions
- 10,000 iterations
- The risk-free rate and volatility of the underlying are known and
constant (-0.09%, 3 year UK government bond at grant date)
- Share price volatility is 64.56%
All LTIP and CSOP options outstanding at 31 December 2021 were issued to
option holders with, other than the target price, several performance criteria
including 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 30,694,163 options outstanding
at 31 December 2021 (2020 - 25,290,322) was 4.2 years at that date (2020: 5.2
years) of which 4,480,836 were exercisable at 31 December 2021 (2020:
4,480,836).
The weighted average exercise price of the options remaining was 6.53p at 31
December 2021 (2020 - 7.7p).
The Company calculates the value of personnel salary/fee sacrificed
share-based compensation as the actual value of the sacrificed amount. This
is deemed to be the fair value of such awards. The fair value of sacrificed
salary/fee share options granted in 2021 is calculated as £104k (2020:
£161k) and this has been charged to the Statement of Comprehensive Income.
The exercise price of such awards was determined as 1p (2020: 1p).
Further details for Directors are provided in Note 4.
The Company did not grant any warrants in the current year (2020: nil). No
warrants were exercised during the year (2020: 7,877,310 ) and no
warrants lapsed during the year (2020: 5,400,000 ) and are shown as follows:
Number Price Date of Grant Expiry
1 January 2021 20,000,000 32.18p
31 December 2021 20,000,000 32.18p 13/09/2018 31/08/2023
The Company calculates the value of share-based compensation using the
Black-Scholes option pricing model to estimate the fair value of warrants at
the date of grant.
The fair value of 20,000,000 warrants granted to London Oil & Gas Limited
on 13 September 2018 was calculated 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 2021 (2020 - 20,000,000) was 1.66 years at that date (2020 -
2.66 years). All such warrants were exercisable at 31 December 2021.
The weighted average exercise price of the warrants remaining was 32.18p at 31
December 2021 (2020 - 32.18p). No further warrants have been issued or
exercised as at 16 March 2022.
19. Restricted cash, Cash and cash equivalents
2021 2020
Group £000 £000
Restricted cash 3,429 67,049
Cash at bank 31,255 13,389
Company
Restricted cash 2,066 65,699
Cash at bank 31,255 13,389
Restricted cash at 31 December 2021 includes £2.1 million (2020: £66.0
million) of restricted deposits in Euro escrow and Debt Service Reserve
Accounts following the Norwegian Bond issue and a £1.4 million (2020: £1.4
million) deposit secured against decommissioning provisions of its
infrastructure assets. Total restricted cash balances of £3.4 million for the
Group and £2.1 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 £31.3 million (2020:
£13.4 million).
20. Bonds payable
On 20 September 2019, the Company issued €100 million Norwegian Bonds on the
Oslo Børs to fund the Phase 1 development program.
2021 2020
£000 £000
Balance at the beginning of the year 87,777 82,423
Amortisation of transaction fees 560 562
Interest charged 8,253 8,668
Interest Paid (8,253) (8,668)
Currency revaluation (5,901) 4,792
_________ _________
82,436 87,777
_________ _________
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 3m EURIBOR
is at zero or lower), declining by 10% every six months thereafter.
Bond covenants
· Minimum liquidity - €2 million up to, and including, 6 months
from the first gas date and €5 million thereafter.
· Minimum leverage ratio - a minimum of 2.5 : 1 from the first
reporting date following 6 months after the first gas date.
· Minimum interest cover ratio - a minimum of 5 times cover of
interest to EBITDA from the first reporting date following 6 months after the
first gas date.
As part of the original Bond issue, the Company has the option to issue a
further €30 million of bonds, though these would be at the prevailing market
rate at the time of any issue and would not be on any carry any favourable
terms to the market pricing at the time.
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)
21. Lease liabilities
2021 2020
£000 £000
Current
At 1 January 13,781 939
Interest expenses 1,754 381
Lease payments (12,307) (192)
Additions 7,840 12,653
At 31 December 11,068 13,781
Long term
At 1 January 4,968 -
Additions 395 4,968
Move to current (4,968) -
At 31 December 395 4,968
Lease payments represent the Group and Company's share of Drilling Rig rental,
PSV marine supply vessel rental, ERVV marine emergency rapid response vessel
rental, office lease rental payments at Endeavour House, 189 Shaftesbury
Avenue, London, together with the Crown Estate lease for the rights for the
Saturn Banks Pipeline to cross the foreshore at Bacton. During 2021 the
Company continued with drilling rig contract with Noble Corporation for the
Noble Hans Deul drilling rig for which payments commenced in 2021 additionally
in 2021 to new contracts were awarded one for marine supply vessel and another
one for marine emergency rapid response vessel.
22. 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
• 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, Bond
proceeds in escrow and joint venture partner carry receipts from CER.
Greater than Greater Total
6 months 6 months, less than undiscounted Carrying
or less than 12 months 12 months amount
2021 Group £000 £000 £000 £000 £000
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
________ _________ ________ _________ ________
2020 Group
Current financial liabilities
Trade and other payables 5,244 - - 5,244 5,244
Lease liability 4,631 9,015 - 13,646 13,356
Accruals 5,244 - - 5,244 5,244
Non-current financial liabilities
Deferred Consideration - - 2,370 2,370 2,370
Loans - - 11,566 11,566 8,037
Lease liability - - 5,616 5,616 4,968
Bonds 4,264 4,264 123,451 131,979 87,777
________ _________ ________ _________ ________
17,242 13,279 143,003 173,524 124,855
________ _________ ________ _________ ________
Greater than Greater Total
6 months 6 months, less than undiscounted Carrying
or less than 12 months 12 months amount
2021 Company £000 £000 £000 £000 £000
Current financial liabilities
Trade and other payables 7,708 - - 7,708 7,708
Lease liability 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
________ _________ ________ _________ ________
2020 Company
Current financial liabilities
Trade and other payables 1,145 - - 1,145 1,145
Deferred Consideration 4,631 9,015 - 13,646 13,356
Accruals 1,216 - - 1,216 1,216
Non-current financial liabilities
Deferred Consideration - - 750 750 681
Loans - - 11,566 11,566 8,037
Lease liability - - 5,616 5,616 4,968
Bonds 4,264 4,264 123,451 131,979 87,777
________ _________ ________ _________ ________
11,256 13,279 141,383 165,918 117,180
________ _________ ________ _________ ________
Credit risk
Credit risk arises principally from the Group's and Company's 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 EUR Escrow and DSRA funds. 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 expects to recover these loans when these Projects
start to generate positive cash flows. 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 and Company had £0.005 million external
receivables (2020: £0.9 million).
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. 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 oil 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 and that there has been no
significant increase in credit risk that would warrant the recognition of a
material provision. 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
2021 2020 2021 2020
£000 £000 £000 £000
Other receivables 1,445 894 1,445 894
Loans to subsidiaries - 109,779 45,196
Restricted cash 3,429 67,049 2,066 65,699
Cash and cash equivalents 31,255 13,389 31,255 13,389
Commodity price risk
The Group currently has not entered into any commodity price hedging
instruments.
Although there is no gas production, 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
Save for restricted EUR denominated cash held in escrow and DSRA accounts
which attract a nominal negative cost to hold, cash is essentially
non-interest bearing. Loans and trade payables are subject only to fixed
interest rates; accordingly, commercial interest rates would have no
significant impact upon the Group's and Company's result for the year ended 31
December 2021 (nor 31 December 2020).
In relation to the EUR denominated cash held in escrow, which currently
attracts a nominal negative cost to hold, a 10% fluctuation in the cost to
hold rate (currently 0.612%) would increase/reduce the charge by £52k per
annum.
Foreign exchange risk
Save for restricted EUR denominated cash held in escrow and DSRA accounts
which attract a nominal negative cost to hold, cash is essentially
non-interest bearing. Loans and trade payables are subject only to fixed
interest rates; accordingly, commercial interest rates would have no
significant impact upon the Group's and Company's result for the year ended 31
December 2021 (nor 31 December 2020).
In relation to the EUR denominated cash held in escrow, which currently
attracts a nominal negative cost to hold, a 10% fluctuation in the cost to
hold rate (currently 0.612%) would increase/reduce the charge by £0.1 million
per annum.
At 31 December 2021, the Group's and Company's monetary assets and liabilities
are denominated in GBP Sterling Euro and US Dollars, converted to GBP the
functional currency of the Group and each of its subsidiaries.
The Company holds (€0.00 million) in EUR from proceeds of the Bond issue,
held in escrow. The remaining balances are held in GBP £19.5 million, EUR
€9.1 million and USD 5.5 million. This exposure gives rise to net currency
gains and losses recognised in the Statement of Comprehensive Income.
A 10% fluctuation in the GBP sterling rate compared to EUR would give rise to
a £0.9 million gain or £0.9 million loss in the Group and Company's
Statement of Comprehensive Income
The Group has no current revenues. 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 deposits with
small balances held in USD to settle any USD liabilities. No formal policies
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 20. The
Group raised an additional £8.5 million of equity by way of a placement, open
offer and subscription in 2021.
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 and milestone draw down the
Directors provide representation that the terms of the bond are satisfied.
Borrowing facilities
The Group had £91.3 million of borrowings outstanding at 31 December 2021
(2020: £95.8 million).
Hedges
The Group did not hold any hedge instruments at the reporting date (2020:
none).
23. Financial commitments and contingent liabilities
The Group has contracted capital expenditure in the current period as part of
the phase 1 development work program for the licences in which it
participates:
2021 2020
£000 £000
Authorised but not contracted 9,045 118,000
Contracted 376,166 56,758
_________ _________
385,211 174,758
_________ _________
All 2021 contracted amounts relate to contracted UKCS licence fees and
associated OGA levy payments (estimate) together with contracted service
awards to suppliers procured for the development of the Group's phase 1
project assets (Blythe, Southwark, Elgood, Saturn Banks Facilities and Saturn
Banks Pipeline).
At the year end, authorised commitments (approved expenditure) to complete the
phase 1 project totalled £385.2 million. £376.2 million of the authorised
amount had been contracted at 31 December 2021 with the remaining expenditures
to be contracted during 2022. All expenditures are shown gross, 100% and
have not been scaled back for any joint venture share.
Saturn Banks Pipeline System:
Security in the sum of £0.5 million, the Initial Saturn Banks Pipeline
Decommissioning Security Amount, 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 £1.25 million, the Saturn Banks Pipeline
Decommissioning Security Amount, is to be provided on the earlier of:
· one month after the variation issued by the OGA to the Pipeline
Works Authorisation to allow for the tie-in of one or more of the Group's
fields; or
· at the date of sale or alternative use of the Saturn Banks
Pipeline
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'.
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 IFRS4.
24. Related party transactions
Details of Directors' and key management personnel remuneration are provided
in Note 4.
Andrew Hockey, CEO, at 31 December 2021 held 830,729 ordinary shares of 1p
each in the capital of the Company. Andrew is also the current holder of
7,770,576 share options at 31 December. Andrew was also entitled to 659,793
share options through salary sacrifice at 31 December 2021.
Rupert Newall, CFO, and persons closely associated, at 31 December 2021 held
3,807,050 ordinary shares of 1p each in the capital of the Company. Rupert was
also the current holder of 4,662,558 share options at 31 December. Rupert is
also entitled to 546,871 share options through salary sacrifice at 31 December
2021.
Fiona MacAulay, Chair, at 31 December 2021 held 220,000 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 2021.
Esa Ikaheimonen, Non-Executive Director, at 31 December 2021 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 2021. Esa is also
entitled to 868,306 share options through salary sacrifice at 31 December
2021.
Neil Hawkings, Non-Executive Director, at 31 December 2021 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 2021. Neil is also
entitled to 63,005 share options through salary sacrifice at 31 December 2021.
Details of loans and interest charged (only relevant to 2019) by LOG are
detailed in Note 10. The relevant loans outstanding at the end of the year
related to the Company.
25. Notes supporting statements of cash flows
Details of significant non-cash transactions
2021 2020
£000 £000
Equity consideration for settlement of liabilities - 161
Group - Loans and borrowings
Current Non-current Total
loans and borrowings
loans and borrowings
loans and borrowings
£000
£000
£000
At 1 January 2020 939 6,820 7,759
Lease Liability additions 12,653 4,968 17,621
Repayments (192) - (192)
Gain on modification of convertible loan - - -
Unwinding of discount 381 1,217 1,598
At 31 December 2020 13,781 13,005 26,786
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
Company - Loans and borrowings
Current Non-current Total
loans and borrowings
loans and borrowings
loans and borrowings
£000
£000
£000
At 1 January 2020 939 6,820 7,759
Lease Liability additions 12,653 4,968 17,621
Unwinding of discount 381 1,217 1,598
Repayments (192) - (192)
At 31 December 2020 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
26. Subsequent events
The key events after 31 December 2021 are as follows:
On 4 March commissioning of onshore Saturn Banks Reception Facilities
completed. enabling backgassing of the offshore Saturn Banks Pipeline System
out to Blythe and Elgood
On 13 March 2022 Phase 1 First Gas was safely and successfully achieved from
the Blythe well and on 15 March 2022 for Elgood.
On 16 March 2022 the Company signed a five-year lease contract for its 3rd
floor, Endeavour House, London office.
Southwark drilling operations are expected to resume in late Q1 or early Q2
2022 with remediation of the drilling location seabed to ensure safe
operations.
New gas sales agreement (GSA) signed with BP Gas Marketing Limited (BPGM),
covering all of the Phase 1 fields as well as Nailsworth and Elland, replacing
the 2014 Blythe GSA
Planning and contracting continuing for the appraisal wells at Kelham
North/Central (P2442: Block 53/1b) and Goddard (P2342: Block 48/11c and 12b),
to be drilled by the Noble Hans Deul rig after the second Southwark well on
the same competitive day rate as the Phase 1 wells.
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