IOG.L Regulatory News (IOG)

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 80/64th 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 80/64th 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 debt1 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

1Net 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:

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.

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 27th, 30th and 32nd 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.

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

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 - 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

The financial statements were approved and authorised for issue by the Board of Directors on 16th March 2022 and were signed on its behalf by:

Rupert Newall

Chief Financial Officer

16 March 2022

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 16th March 2022 and were signed on its behalf by: -

Rupert Newall

Chief Financial Officer

16 March 2022

Consolidated Cash Flow Statement

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:

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

\* 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:

4. Personnel costs and directors' remuneration

During the year, the average number of personnel, including contract personnel, for both the Company and Group was:

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).

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:

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:

5. Finance expense