Final Results for the Year Ended 31 December 2020

18 March 2021, 07:00

Source - LSE Regulatory

RNS Number : 6382S

Independent Oil & Gas PLC

18 March 2021

Independent Oil and Gas plc

Final Audited Results for the Year Ended 31 December 2020

Independent Oil and Gas plc ("IOG" or "the Company"), (AIM: IOG.L), the UK gas company targeting high returns via an infrastructure-led hub strategy, is pleased to announce its final audited results for the Year Ended 31 December 2020.

2020 Highlights

Corporate and Operational

· Phase 1 development works extensively progressed across all four key project elements: platforms, subsea, drilling and onshore, with a view to safely and successfully delivering first gas in Q3 2021

· EPCI contract signed with HSM for the Phase 1 Blythe and Southwark normally unmanned installation platforms

o Engineering and fabrication activities progressed through 2020 at HSM's yard in the Netherlands

· Phase 1 SURF scope EPCI contract signed with Subsea

o Fabrication, transportation, preparation and installation of Blythe 12" and Elgood 6" lines completed

· Extensive preparation, contracting and procurement undertaken for the five-well Phase 1 drilling programme

o Rig contract awarded to Noble Corporation's Noble Hans Deul jack-up following a competitive selection process

o Petrofac was awarded a well management contract and approved as Well Operator for Phase 1

o Detailed Well Design initiated and extensive Tier 1, 2 and 3 services and tangibles contracts awarded

· Engineering, procurement and construction work progressed at the Thames Reception Facilities (TRF) onshore at the Bacton Gas Terminal (BGT), where IOG's gas will land to shore

o Tie-ins to LAPS facilities successfully completed and TRF slugcatchers cleaned out for reuse

· Phase 1 Environmental Impact Assessment (EIA) and Field Development Plan (FDP) approved in April 2020

· Portfolio expanded via award of new licence P2589 (Panther and Grafton), operated by IOG (50%) with CER as non-operating partner (50%), in 32^nd Offshore Licensing Round

· Reprocessing of 3D seismic to PSDM across full portfolio to enhance subsurface understanding and optimise development planning

· New Climate Change and Sustainability Policy and Social Policy adopted; Health, Safety and Environment (HSE) Policy updated

· Adapted to Covid-19 restrictions throughout the year, maintaining three fundamental priorities: protecting our people, delivering the project and ensuring business continuity

Financial

· Cash balance at period end of £80.4 million (2019: £98.3 million), including restricted cash of £67.0 million (2019: £82.0 million)

· Post tax loss for the year of £19.3 million (2019: Profit £15.0 million)

· Group net debt¹ at year end £14.1 million (2019: £9.0 million net cash)

· £43.8 million of partner development carry from CER utilised in the period under Farm-out agreement, and £48.3 million in total since FID, out of a total of £60 million available

· €11.7 million (£10.0 million) drawn down from Bond escrow account in the period, leaving a balance of €66 million (£59.2 million) in escrow at year end, to be drawn at further milestones as laid out in Bond terms

· €9.7 million (£7.7 million) in Bond interest payments made from Debt Service Retention Account (DSRA)

Board and Management

· Operational and technical teams significantly strengthened, with all key discipline leads brought in-house, to optimise Phase 1 execution and prepare the way for further phases of growth

· Mark Hughes stepped down as Chief Operating Officer (COO) and Executive Director

Post Year End Developments

· Appointment of David Gibson as Chief Operating Officer in February 2021

· Guidance reaffirmed for first gas by late Q3 2021, with Phase 1 gross capex outturn projected to come within 10% of initial £306 million budget

· Phase 1 platforms set for mechanical completion in early Q2 ahead of installation later in Q2

· Detailed well design, final contracting and permitting being concluded before first of five development wells spuds in early Q2

· Further drawdown of €27.3 million (£23.7 million) from the Bond escrow account made in Q1

o The two final Bond drawdowns are expected to be made early in Q2

· Management estimated resources increased for the P2438 (Goddard) and P2442 (Abbeydale) licences based on interpretations of newly reprocessed seismic data

· Phase 1 gas sales tender process initiated, with Energy Contract Company as advisor, and over 10 integrated energy firms, utilities and trading houses formally expressing interest

· Independent emissions assessment for Phase 1 initiated in Q1, with initial results expected later in Q2

^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.

Andrew Hockey, CEO of IOG, commented:

"Last year we made tangible progress towards the safe, efficient and timely delivery of first gas, despite the challenges of Covid-19 and volatile industry conditions. That momentum is ramping up as we progress through 2021, with our strengthened team executing the platform, subsea, drilling and onshore project scopes. Following a rigorous recent cost and schedule review, we expect to achieve first gas in the latter part of Q3 2021, funded by our 2019 farm-out and bond issuance.

We see Phase 1 as the springboard for successive phases of growth under our infrastructure-led hub strategy, combining efficient development of nearby discovered resources with step-out exploration and appraisal activity. Our latest technical work has identified potential opportunities to develop additional gas hubs to build further shareholder value.

Besides generating strong returns, we believe IOG's strategy can contribute to the UK's Net Zero journey. By delivering domestic gas resources directly into the import-dependent UK market at low cost and with low carbon intensity via our reused infrastructure, we will be reducing reliance on more carbon-intensive imports."

THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION

Enquiries:

Independent Oil and Gas plc Andrew Hockey (CEO) Rupert Newall (CFO) James Chance (Head of Corporate Finance & IR)	+44 (0) 20 7036 1400
finnCap Ltd Christopher Raggett Simon Hicks	+44 (0) 20 7220 0500
Peel Hunt LLP Richard Crichton David McKeown	+44 (0) 20 7418 8900
Vigo Communications Patrick d'Ancona Chris McMahon Simon Woods	+44 (0) 20 7390 0230

About IOG

IOG owns and operates a 50% stake in substantial low risk, high value gas reserves in the UK Southern North Sea. The Company's Core Project targets a gross 2P peak production rate of 140 MMcfe/d (c. 24,000 Boe/d) from gross 2P gas reserves of 302 Bcfe¹ and management estimated 2C gas Contingent Resources of 132 Bcfe, via an efficient hub strategy based on co-owned infrastructure. In addition to its 2P reserves at Blythe, Elgood, Southwark, Nailsworth and Elland and 2C contingent resources at Goddard, it has management estimated gross 2C contingent resources of 23 Bcfe at Abbeydale and unrisked mid-case prospective resources of 66 Bcfe at Thornbridge, 31 Bcfe at Southsea, 31 Bcfe at Kelham, 27 Bcfe and 16 Bcfe in the two Goddard flank structures, and 21 Bcfe at Harvey. In December 2020 IOG also accepted a 50% operated stake in Licence P2589, containing the Panther and Grafton gas discoveries with management estimated gross mid-case contingent resources of 46 Bcfe and 35 Bcfe respectively. In addition IOG continues to pursue value accretive acquisitions to help generate significant shareholder returns.

¹ERC Equipoise Competent Persons Report: October 2017, adjusted by Management to account for updated project timing and compression

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

2020 Review

2020 was another year of real progress for Independent Oil and Gas plc (IOG), paving the way for first gas production from our Core Project in 2021, despite the challenges of Covid-19. With a strong financial footing in place after the Farm-out and Bond issue in 2019, our challenge in 2020 was to progress the safe, efficient and timely delivery of Phase 1 whilst also building out the organisation to deliver successive phases of growth. I am proud of our efforts on both these fronts.

IOG's value proposition remains compelling: a focused portfolio that leverages our ownership and operatorship of key infrastructure, delivering gas at low cost and with low carbon intensity directly into a heavily import-dependent UK market, to generate strong shareholder returns. Our infrastructure position both onshore and offshore is a critical differentiator, saving substantial time and cost in accessing the market.

We see Phase 1 as the springboard to execute an efficient hub strategy with successive phases of growth, commercialising gas assets across the full life cycle. We can enhance returns both via capital efficient development of nearby discovered gas but also, via advanced subsurface imaging, selecting the best step-out exploration and appraisal opportunities to feed our production system. We will continue to evaluate such growth opportunities through the lens of risked internal rates of return and value per share, rather than pure asset size or production volumes. We also view acquisition opportunities, whether asset level or otherwise, through the same disciplined lens of risk-adjusted value accretion versus our existing portfolio.

Through the combined expertise of our people, our purpose is to build a differentiated energy company, with a dynamic culture of continuous improvement and effective collaboration, underpinned by fundamental respect for people and the environment. By late 2020 we had completed our process of bringing in house all discipline lead positions and other specialist staff, from technical, operational and HSE to finance, legal, commercial and contracts and procurement. This comprehensive team strengthening is important not only for Phase 1 but for our wider strategic plans to generate and execute successive phases of growth. This process culminated in early 2021 with the appointment of David Gibson as our new Chief Operating Officer following Mark Hughes' retirement in late 2020.

While delivering strong financial returns to shareholders, we also believe these phases of growth will enable IOG to play a meaningful role in the UK's journey to Net Zero by 2050. Gas is a key fuel in the Energy Transition and domestic gas is especially impactful versus imported sources in reducing the carbon intensity of UK energy supply. Our Climate Change and Sustainability Policy adopted in 2020 reaffirms our ambition to be a safe, efficient, low-carbon intensity gas producer, delivering reliable domestic energy resources to UK homes and businesses.

Our goal is to establish IOG as one of the lowest carbon intensity operators in the North Sea. To that end we have commissioned an independent assessment of projected Phase 1 emissions, which benefit from existing infrastructure, low-impact normally unmanned platforms, automated operations and shallow-water drilling. This assessment will provide the baseline for further improvements, development of a carbon neutrality target and analysis of potential emissions mitigants. We also plan to integrate emissions benchmarks into future investment decisions, enabling further projects to be better by design, capturing both carbon and cost savings from the outset.

In 2020 we made important operational strides in successful Phase 1 execution, signing major contracts with recognised contractors for key workstreams. We aim to work with contractors with deep experience in their field, a strong value proposition, and who share our ethos of safe, efficient and responsible operatorship.

HSM, the Dutch contractor with extensive platform construction experience, won the engineering, procurement, construction and installation (EPCI) contract for the Blythe and Southwark normally unmanned installation (NUI) platforms, which we expect to operate in a low cost and low carbon way. We will shortly reach mechanical completion on both platforms and installation at their field locations is scheduled for Q2 2021. Operated by IOG and co-owned with our partner CalEnergy Resources (UK) Limited (CER), they form part of our infrastructure-led strategy, as potential hosts for further IOG-CER joint venture assets as well as a conduit into the Thames Pipeline for tariffed third-party gas.

The Phase 1 Subsea, Umbilicals, Risers and Flowlines (SURF) contract, incorporating key subsea project management, engineering, procurement, construction and installation activities, was awarded to leading contractor Subsea 7 in Q2 2020. An important element of this scope was then delivered with the welding, reeling and installation of the Blythe 12-inch and Elgood 6-inch lines during Q3 and Q4.

We also progressed the key objective of recommissioning the Thames Pipeline and associated Thames Reception Facilities (TRF) at Bacton. With its inherent capital cost savings and scope for both owned and third-party gas, this recommissioning is a fundamental enabler of our strategy. We safely and successfully completed all planned tie-ins to the onshore Perenco Lancelot Area Pipeline System (LAPS) facilities during the Bacton scheduled maintenance shutdown in Q4, and undertook rigorous clean-out and inspection of the TRF slugcatchers to prepare for their re-use. We are working closely with onshore EPC contractor ODE and Bacton operator Perenco UK Limited (PUK) to complete recommissioning works for first gas, and are also seeing healthy levels of interest in our gas sales tender process.

In 2020 we also accepted a 32nd Round offer as operator in 50:50 partnership with CER for the new licence P2589 containing the Panther and Grafton discoveries with initial management estimated recoverable gas resources of 46 BCF and 35 BCF respectively. This award reflects our good relationship with CER, who remain a strong and supportive Core Project partner. We also continue to operate the business development efforts across our Area of Mutual Interest (AMI) with CER, which may open up further opportunities for synergistic acquisitions.

We continue to assess our portfolio against rigorous technical and commercial standards, enabling us to focus our acreage position and deploy capital where it creates most value for shareholders. This philosophy underpins our extensive seismic reprocessing and remapping work over the past year, which is giving us the best possible subsurface understanding to progress our hopper of incremental investment opportunities. This has enabled us to recently update our resource estimates for the Goddard and Abbeydale licences.

From a finance perspective, through 2020 we continued to use the proceeds of our major 2019 funding transactions, the £165 million Farm-out and €100 million Bond issue. We benefitted from the £60 million Phase 1 partner development carry, which lasted into early 2021, with a further €66 million in undrawn Bond funds remaining at the year end.

In terms of the wider business risk environment, the Covid-19 pandemic and the UK's withdrawal from the EU were two major issues affecting the UK. Fortunately, Brexit is unlikely to significantly impact IOG given that our Phase 1 contracts are largely in place and relate to offshore UK or domestic activities. By contrast, Covid-19 presented obvious logistical challenges throughout 2020 and beyond, requiring effective closure of our offices for extended periods. Our three priorities have remained the same throughout: protect our people, deliver the project and ensure business continuity. We moved quickly to ensure a safe operating environment and minimise virus transmission risks, and implemented effective remote working practices with robust communication systems to ensure the team could continue to deliver our objectives effectively. The team's resilience and adaptability in these circumstances enabled us both to deliver our intended organisational growth in 2020 and maintain progress towards first gas by Q3 2021. I am pleased to say we have not furloughed or released any staff in light of Covid-19. However, as we ramp up our operational activities, notably development drilling, we remain very mindful of the challenges it continues to pose for our business. We are taking all reasonable precautions to manage these risks, and with the calibre of our people, our portfolio and our partnerships, I have never been more confident of our ability to overcome them.

2021 Outlook

We continue our strenuous efforts to deliver our Core Project in a safe, timely and cost-effective manner with a low carbon footprint. Over Q1 2021, with all major Phase 1 contracts in place or underway, we have undertaken a rigorous cost and schedule review, assessing progress against project budget and target timeline. This has reaffirmed our guidance on expected first gas by late Q3 2021, likely in September, to come initially from the Blythe hub fields. Delivering on this demanding timeline will be testament to our team's tireless efforts in testing external circumstances. Our cost and schedule review has indicated a final Phase 1 capex out-turn within 10% of the original £306 million (gross) budget. Most importantly, that means we expect to deliver Phase 1 within our existing resources, without requiring supplementary funding. While we continue to make every effort to manage cost across the project, we have seen cost increases in certain areas of the project although partially mitigated by savings in other areas. In particular, the highly mobile seabed sand waves on the route from the 24-inch Thames Pipeline extension to the Southwark platform location have made this a challenging installation environment. This operation is scheduled for early 2022 in parallel with batch drilling of the three Southwark development wells. Operating offshore in the midst of the Covid-19 pandemic has also led to incremental costs. At this stage of project delivery, with the five-well drilling programme starting imminently, scope naturally remains for further cost variations but our team is very focused on managing those risks.

Looking forward, I believe we have the right vision and right team for success. Getting into production will be a major milestone for IOG, but we believe it will be just one step in a greater journey, with a series of high-value, low-carbon gas projects delivering material shareholder returns and maximising the value of our Core Project infrastructure. We have demonstrated the growth potential within our current portfolio, including recent licensing additions, to achieve this.

Equally, we continue to work in a structured and disciplined way to capture genuinely value-adding inorganic opportunities to grow the portfolio. Fundamental to this strategy is our low-carbon operating philosophy that will enable IOG to contribute to the UK's Energy Transition.

I would like to thank the whole IOG team and board for all their continued hard work to realise our ambitions. I also thank our shareholders, both institutional and individual, for their continued support. We will continue to do our very best to fulfil your belief in us.

Andrew Hockey

Chief Executive Officer

17 March 2021

Operational Update

Phase 1: Thames Pipeline and Thames Reception Facilities (TRF)

IOG owns a 50% operated share in the Thames Pipeline and associated onshore TRF, with CER holding the other 50% non-operated stakes. This follows the acquisition of both assets from Perenco UK Limited, Tullow Oil SK Limited and Spirit Energy Resources Limited in 2019 and the subsequent Farm-out transaction to CER which completed on 28 October 2019.

IOG Infrastructure Limited is the owner, user, holder and operator of the pipeline under the Pipeline Works Authority (PWA). On acquisition of the TRF, £2.0 million of security was posted and at completion of the Farm-out the £0.5 million pipeline security paid to Perenco in April 2019 was transferred to a Law Debenture Trust account for our benefit. Subsequently, 50% of these amounts were settled to IOG leaving a total of £1.25 million security now held against the TRF for IOG's share.

In 2020, an in-line inspection (ILI) was undertaken on the 60km length of the Thames Pipeline, which has a predominant wall thickness of 15.88mm, is concrete coated and trenched. The line was originally decommissioned in 2015 and is presently filled with inhibited seawater. This operation was in addition to the 150 bar strength test undertaken in 2018. Analysis of the ILI results by Baker Hughes indicated that all identified internal metal loss features in the pipeline are tolerable at the planned Maximum Allowable Operating Pressure (MAOP) of 129 bar. Further work is ongoing to refine this analysis, estimate mean rates of future internal corrosion and identify the corrosion protection management required to ensure a 15-year minimum pipeline operating life. IOG plans to run a further ILI two years after the pipeline goes back into operation which at that time will provide an updated understanding of the new economic life of the pipeline based on actual operating data pertaining to internal corrosion rates.

Key aspects of the onshore TRF refurbishment works undertaken in 2020 included the clean-out and inspection of the slugcatchers in order for them to be reused, and the tie-in activities to the LAPS facilities which were safely and successfully completed during the scheduled Bacton terminal shutdown in Q4 2020.

Preparations were also made in late 2020 for a competitive tendering process for the earlier years of the Phase 1 gas sales arrangements, which subsequently commenced post-year end.

Phase 1: Blythe, Elgood and Southwark

The Blythe gas discovery 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 and is operator. Blythe is planned to be developed with a single well tied back to the Thames Pipeline via an unmanned platform. In their 2017 CPR, ERC Equipoise assessed gross 1P/2P/3P Blythe gas reserves to be 23.3/33.4/46.8 BCF.

IOGNSL has 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 discovery in the Rotliegend Leman Sandstone. Elgood is being developed with a single well tied back subsea to the Thames Pipeline via the Blythe platform. In their 2017 CPR, ERC Equipoise assessed gross 1P/2P/3P Elgood gas reserves to be 13.3/21.4/34.4 BCF.

The Southwark gas discovery in the Rotliegend Leman Formation sits in Block 49/21c in licences P1915 in which IOGUKL has a 50% working interest and is the operator. Southwark is planned to be developed by three wells tied back to the Thames Pipeline via the Southwark unmanned platform. Reprocessing of seismic data undertaken in 2020 across the field has improved the structural imaging and aided development well planning. The Southwark development wells are expected to be batch drilled as part of the Phase 1 drilling campaign. In their 2017 CPR, ERC Equipoise assessed gross 1P/2P/3P Southwark gas reserves to be 55.2/93.3/144.1 BCF.

Following Phase 1 FID in October 2019, the Phase 1 FDP, comprising the Blythe, Elgood and Southwark fields, was approved by the OGA in April 2020, targeting first gas in Q3 2021. Intensive work continued in 2020 across all key elements of the Phase 1 development, with a view to successful start-up targeted in Q3 2021. In addition to the onshore works described above, the Company accelerated its offshore focused activities, i.e. Platform, SURF and Drilling. Fabrication of the Southwark and Blythe platforms at HSM's yard in Schiedam progressed substantially, working through Covid-19 restrictions, and remained on track to be installed offshore in Q2 2021. A key part of the Phase 1 Subsea, Umbilicals, Risers and Flowlines (SURF) scope was completed over the course of 2020 with the fabrication, transportation, welding, spooling and offshore installation of the 6-inch Elgood and Blythe 12-inch lines connecting to the Blythe platform and 24-inch Thames Pipeline respectively.

In November 2020 the Company signed a contract with Noble Corporation for the Noble Hans Deul jack-up rig to drill the five Phase 1 development wells (one at Blythe, one at Elgood, three at Southwark), with options for up to two further wells on favourable terms. Over the second half of 2020, detailed well design and permitting work continued to progress with a view to spudding the first development well by early Q2 2021, and a number of awards were made for drilling services and tangibles. The contract for Phase 1 well management was awarded to Petrofac in June 2020 and Petrofac was also subsequently approved as Phase 1 Well Operator by the OGA.

Pre-Development Assets (PDAs)

Nailsworth and Elland

IOGUKL has a 50% working interest and is operator of the P039, P130 and P2342 licences, which contain the Elland and Nailsworth gas discoveries. These fields are intended to be part of Phase 2 of the Core Project. In their 2017 Competent Persons Report (CPR), ERC Equipoise assessed 1P/2P/3P gas reserves to be 20.0/27.5/36.5 BCF in Elland and 30.2/49.7/73.6 BCF in Nailsworth (net to IOG).

The discoveries are now under evaluation in stage two of IOG's Project Governance Process, which assesses the optimal development concept for the fields within the context of the Phase 1 Core Project infrastructure and the wider PDA portfolio. Based on this work, the Company will seek to submit and obtain approvals for the FDP and EIA for these fields at the earliest opportunity. The remaining work programme commitment under the licences with the OGA is the submission of a Field Development Plan prior to the end of 2021.

Further to the Elland suspended well 49/21-10A decommissioning paper, prepared by Acona in April 2015, IOGUKL has revisited the decommissioning provision. It is envisaged that the decommissioning can be completed at a gross cost of £2.4 million due to savings with synergies associated with the Elland development drilling programme.

Goddard and Southsea

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 Core 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 (27.4/53.9/101.4 BCF net to IOG) with Low/Best/High gross unrisked prospective resources of 41.8/73.0/121.4 BCF (20.9/36.9/60.8 BCF net to IOG). 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 was initiated in 2020 over the Goddard area. This reprocessing was completed in Q1 2021 and substantially enhanced the Company's technical view of the Goddard discovery and surrounding area, with a clearer image indicating a larger structure than previously mapped. As a result of this work, the updated gross management resource estimate based on the new PSDM reinterpretation is 57.0/132.0/258.0 BCF, representing a 22% increase in the 2C number versus the 2018 CPR.

The two Goddard flank structures adjacent to the main discovery were estimated in the 2018 CPR as having Low/Mid/High gross unrisked prospective resources of 28/49/82 BCF and 14/24/40 BCF respectively, with GCOS for 48% in each case. The 2020-21 mapping of these two structures initially indicates gross unrisked prospective resource range of Low/Mid/High 7/16/35 BCF and 13/27/54 BCF, with 71% GCOS in each case.

The new seismic reinterpretation has also identified an additional prospect 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 technical work will be required to confirm these initial estimates and an exploration well would be required to prove gas in the structure.

The next technical priorities for the P2438 licence are to update the static and dynamic reservoir models with the interpretations of the reprocessed seismic which may further revise the resource range, ensuring that an FDP for Goddard is based on the most accurate technical understanding.

In addition to seismic reprocessing, the terms of the licence include a firm work programme commitment to drill an appraisal well on the Goddard structure to 3,140m TD by 30 September 2021. In early 2021, IOGNSL formally requested a 12-month extension to the well commitment to 30 September 2022, in order that sufficient analysis and planning can be undertaken based on the new seismic interpretation, prior to drilling. The outcome of the extension request is pending at the time of this report.

Abbeydale, Thornbridge and Kelham

IOGNSL has a 50% working interest and is operator of Licence P2442, which formally commenced on 1 October 2018 and contains the Abbeydale undeveloped gas discovery. Under the terms of the licence, a firm work programme commitment was made to reprocess 150 km² of seismic data within two years, and to either drill an appraisal well on the Abbeydale structure before the 30^th September 2023 or relinquish the licence.

The seismic reprocessing work commenced in 2020 and was completed in Q1 2021. New interpretation and mapping based on the reprocessed seismic data has enhanced the Company's view of the potential across the licence. The updated deterministic management estimate of gross 1C/2C/3C contingent resources at Abbeydale has increased to 19/23/25 BCF. The tight resource range reflects a well-defined structure with good well control from well 51/13a-13.

In addition to Abbeydale, several further prospects and leads have been identified across the P2442 licence. To the immediate north of Abbeydale lies the Camelot Complex, comprising several fields developed and produced by Mobil (and later Perenco). One of these is the Cador field, the western extension of which IOG proposes to rename Kelham. The new seismic work combined with available production data indicates recoverable gas volumes in Kelham of Low/Mid/High 22/31/36 BCF, with an 80% GCOS. As more detailed mapping and reservoir modelling is required to further clarify the potential, the Company has classified Kelham as a prospect.

IOG has also identified another prospect west of Abbeydale which it has named Thornbridge, with gross prospective resources of Low/Mid/High 54/66/73 BCF, and 32% GCOS. Again, further detailed mapping is required, with the key geological risk considered to be the quality of the Zechstein seal.

The technical work to date on P2442 has therefore demonstrated initial scope for a hub development that could be tied in to the Thames Pipeline. Any potential development will be assessed within the context of IOG's development opportunities hopper and Project Governance Process, to optimise the development concept within the context of the Phase 1 Core Project infrastructure and the wider PDA portfolio.

Panther and Grafton

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 32^nd Licensing Round, formally commencing on 1 December 2020, with a firm work programme commitment to reprocess 79km² of seismic data within three years, and to drill an appraisal well on the licence by 30 November 2025 or to relinquish the licence. In 2020, IOG management initially estimated gross Most Likely contingent gas resources to be 46 BCF (net 23 BCF) in Panther and 35 BCF (net 17.5 BCF) in Grafton, respectively. Reprocessing of seismic data is targeted to commence in 2021, in line with IOG's Project Governance Process.

Harvey

IOGNSL has a 100% working interest and is operator of Licence P2085, which contains the Harvey structure, an undeveloped gas discovery. The licence was awarded in the 27^th Licensing Round, formally commencing on the 20^th December 2013. A firm work programme commitment was fulfilled by the reprocessing of seismic data over the licence and drilling of the 48/24b-6 Harvey appraisal well in 2019. The remaining work programme commitment under the licence is to submit a Field Development Plan by 19 December 2021 or to relinquish the licence.

Reprocessing of seismic data in 2020 across the field has improved structural imaging, with reinterpretation aided by the integration of data from the 48/24b-6 well. IOG management currently estimate gross Minimum, Most Likely and Maximum contingent gas resources in Harvey at 12/21/35 BCF. As a low relief structure, the field remains challenging to evaluate due to its variability in size and structural configuration depending upon the seismic depth conversion methodology employed.

IOGNSL retained the core field area, the "Harvey-2 structure" and on 10 March 2021 completed the process of formally relinquishing the remainder of the P2085 licence to minimise future costs. The Company will undertake a detailed commercial assessment of Harvey-2 in 2021, in particular, evaluating a potential "Elgood lookalike" development concept. This entails a single well tied back subsea to the Blythe platform, which has been designed to have a spare 10-inch riser and j-tube. Harvey will then be assessed in line with IOG's Project Governance Process and ranked against the wider opportunities in the PDA portfolio for further evaluation and investment.

Acquisitions

The Company regularly screens for and evaluates possible acquisitions to add to its existing UK Southern North Sea asset portfolio, to help generate further development potential and increased shareholder value over time. This is an important element of the corporate strategy. There are a number of different types of possible acquisition opportunities that the Company pursues, but underlying each one is the potential to extract operating and economic synergies with the existing asset base. We look to add to our portfolio via both acquisitions and licensing activities, whether in formal licence rounds or by separation engagement with the OGA, which offers a low-cost and well established path to adding suitable incremental assets. The most recent example of this was the licensing of the Panther and Grafton gas discoveries in Licence P2589 which were awarded in the 32^nd Offshore Licensing Round. Further, there may at any given time be a number of possible acquisitions from other operators in the basin, who may be interested in selling or farming-out assets at various stages of maturity, including appraisal, development or also previously developed shut-in or decommissioned assets. We assess such opportunities under the primary criterion of its potential to add significant value relative to the Company's existing assets. Finally, the Company also regularly assesses 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, in due course, ensuring effective ongoing production operations.

Non-financial performance is tracked through the calibration of progress on these activities on an ongoing basis. The Company also carefully monitors its HSE performance in light of its two main KPIs, to sustain no Lost Time Incidents or environmental releases, and to manage all licence commitments relating to its portfolio during the year. These objectives were met in 2020. Other non-financial performance indicators which were successfully met in 2020 included securing all relevant environmental approvals, delivering a verified Environmental Management System (EMS), delivering effective relationships at all levels with JV partners with compliant Joint Operating Agreements (JOAs), implementing appropriate governance and HR policies, improving organisational diversity and ensuring all corporate legal obligations are met. The enactment of new ESG policies was a specific 2020 objective for the Group which was also achieved during the year.

Financial performance is tracked against established value metrics and budgets which are set according to carefully assessed cost estimates and the availability of funds raised from capital providers, with the overriding objective of creating value per share. Financial KPIs also include maintaining full compliance with terms of debt facilities and maintaining constructive relationships with debt providers and equity investors - again, these objectives were met in 2020. Specific finance-related objectives which were met in 2020 also included delivering half and full year results on time, building a fully resourced finance team fit for growing corporate and JV purposes, designing and implementing appropriate finance systems, updating relevant financial and corporate policies and delivering approved budgets for 2021.

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 or currencies to best protect cash flows. The Group enters 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 2020, in view of the excessive costs and risks of expending capital for this purpose before Group production is established. Once production has been established, the Group expects to follow 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. Where more complex structures (involving combinations of swaps, puts and call options) may be proposed, specific Board approvals are required. Under its hedging policy, the Group may take positions to protect against the risks associated with specific additional investments or transactions.

Details of the risks arising from the Group's use of financial instruments can be found in Note 24 to the financial statements.

Insurance

The Group insures the risks it considers appropriate for the Group's needs and circumstances. However, the Group may elect not to have insurance for certain risks, due to the high premium costs associated with insuring those risks or for various other reasons, including an assessment that the risks are remote.

Principal Risks and Uncertainties

The Group operates in the oil and gas industry, an environment subject to a range of inherent risks and uncertainties. Key risks and associated mitigation are set out below.

Finance: Management seeks to generate shareholder returns by developing and producing a portfolio of offshore gas assets. This primarily entails construction and installation of production, transportation and processing infrastructure and drilling of production wells. These activities entail a number of associated financial risks.
Risk	Mitigation
Investor support may reduce, impacting the Company's market value and potentially hindering any necessary or desired fundraising activities	· Management has a clear strategy for value realisation and creation, which is regularly communicated to shareholders · The Company's asset portfolio has robust inherent economics as well as substantial incremental value, as attested by third-party analyst reports · CER's credit risk is low and kept under review
Volatility in macroeconomic conditions may hinder delivery of the Company's business plan	· The Company funded its Phase 1 development prior to Final Investment Decision in 2019, to ensure sufficient funding available for planned activities · The Company seeks to actively manage its costs and has an appropriate hedging policy which it is planning to execute at the appropriate time to mitigate the risks of commodity price volatility · As a buyer of products and services, the Company faces both risks and opportunities from fluctuations in these costs
Each asset carries a range of potential values	· The Company has a healthily diversified portfolio of 6 proven gas fields in its Core Project, plus further assets which could potentially be added, therefore there is limited financial dependence on a single asset. · The Company makes consistent efforts to keep its cost base as low as reasonably possible. · In addition, the Company has been undertaking further technical work to help narrow the range of potential values.
The Company may not be able to raise funds to develop its assets	· The Company successfully undertook equity, debt and farm-out funding in 2019 to fund its Phase 1 activities. It anticipates that cash flows from Phase 1 will help to fund further phases of development, with Phase 2 also benefitting from an agreed £65.0 million of partner development carry.
The Company may breach the terms of its Bond funding	· The Company makes consistent efforts to be fully aware of its responsibilities and obligations under the Bond terms. · The Company makes consistent efforts to manage the business within budget. · Management calibrates key project and corporate commitments against bond conditions and covenants to ensure avoidance of any breach.
The administrators of London Oil and Gas Ltd (LOG) may be obliged to divest its holding, creating downward pressure on the Company's market value	· The Company notes that the administrators of London Capital & Finance (LCF), with respect to LOG's holding in IOG, have stated publicly in December 2019 that they saw the market value of the Company at the time as a "significant discount to IOG's estimated net asset value". Management continues to have a positive engagement with the administrators and believe they intend to maximise the value of the LOG holding in IOG.

Operations: Operations may not go to plan, leading to damage, pollution, cost overruns and poor outcomes
Risk	Mitigation
There are a range of potential performance outcomes for each reservoir	· Thorough subsurface mapping and reservoir modelling · High quality well design · Lessons learned during early wells applied to subsequent wells
Developments may deviate from expected schedule and budget	· The Company has hired competent, experienced personnel throughout the organisation · The Company awards contracts to competent, experienced contractors · Rigorous checks and controls are applied to schedule and budget · The Company follows gate process for project governance and utilises peer reviews at appropriate project stages
Market conditions for rig and marine vessel procurement may harden	· Installation costs for platforms and subsea equipment are in EPCI contracts · Competitive tendering processes are used for all such requirements · Where possible, incentivisation clauses are used contracts in order to minimise delivered cost
Scope creep in required works at the Thames Reception Facilities and Bacton Terminal	· FEED scope is defined and stress tested · Any scope changes need to go through the Management of Change process · The Company makes consistent efforts to apply rigorous cost and schedule controls in onshore works
Cyber Security risks	· The Company has developed an enhanced IT security plan and supporting procedures, including in particular: · Improved access right to systems and protocols · Enhanced onboarding and leaving processes
Resource estimates may be misleading curtailing actual reserves recovered	· The Company employs competent, experienced personnel, and also commissions independent third-party reports where appropriate · A prudent range of possible outcomes are considered within planning processes

Regulatory and Legal: The Group may be unable to meet its licence and regulatory obligations
Risk	Mitigation
Delay in obtaining relevant regulatory consents, approvals and permits	· The Company has established solid relationships at all levels with relevant government and regulatory bodies, including OGA, BEIS / OPRED and HSE · There is frequent and detailed liaison with these authorities to minimise issues and delays in approvals · Relevant applications are reviewed in detail and submitted promptly
Deficiency in Corporate Governance	· The Company has developed and implemented a suitable suite of corporate policies and procedures, covering Financial Operations, Anti-Bribery and Corruption, Travel and Expenses, Climate Change and Sustainability, etc · All contracts must be authorised by the Contracts and Procurement function, Finance, General Counsel and above certain thresholds are subject to Tender Committee and Board approval

Human Resources: The Company relies upon a pool of experienced and motivated personnel to identify and execute successful investment strategies
Risks	Mitigation
Key personnel may be lost to other companies	· The Company has established a competent, experienced team across all key disciplines, which mitigates the risk of losing any one key person · The Remuneration Committee regularly evaluates incentivisation schemes to ensure they remain competitive
Difficulty in attracting the necessary talent as the Group moves into development of its projects	· The Company has established a competent, experienced team across all key disciplines · The Company continues to review and adopt appropriate packages for both staff and contractors

HSE and Sustainability: The Company faces a number of Health, Safety and Environmental risks as an operator, and relies on several experienced in-house HSE practitioners and suitable consultants to ensure it meets all its related obligations
Risks	Mitigation
Personal harm to those that may be affected by our undertakings	· Compliance with the UK regulatory goal setting regime for safety is established, implemented and maintained through the Company leadership HSE and Technical Committee, culture and management systems for safety · The Company continually reviews and updates its HSE Policy, which can be read in full on its website
Adverse environmental effects of our activities including, in particular, contributing to Climate Change	· The Company has established a Climate Change and Sustainability Policy, which can be read in full on its website · Strategic focus on domestic natural gas resources as a key fuel for the Energy Transition with lower carbon content than other hydrocarbons (including imported gas) · Use of low carbon intensity facilities, including re-use of existing infrastructure

Commercial environment: World and regional markets continue to be volatile with fluctuations and infrastructure access issues that might hinder the Company's business success
Risk	Mitigation
Stakeholder misalignment	· Regular discussions and meetings with key stakeholders, to build and maintain relationships · Understand stakeholders' priorities, drivers and risk tolerance levels
Volatility in commodity prices, particularly gas	· The Company has an established hedging policy which it intends to execute as it moves into production · The policy revolves around prudent management of commodity price risks with the proportionate use of sensible hedging structures · Hedging strategies may also be employed to derisk major incremental capital commitments · Budget planning considers a range of commodity pricing and advice is taken from independent third-party market experts
Risks arising from Brexit	· Major contracts for Phase 1 were awarded in 2020. · There is no clear exposure to customs-related risks to cross-border movement of goods through the supply chain. · The Company has primary exposure to only three currencies, GBP, EUR and USD, and has raised finance in both GBP and EUR. · The Company proactively assesses and manages FX risks.
The Company may not be able to get access, at reasonable cost, to infrastructure and product markets when required	· The Company is undertaking a competitive gas sales tendering process in 2021 with a substantial number of interested parties

Covid-19 Pandemic: The pandemic has created severe economic upheaval and unforeseeable disruptions to normal working practices around the world

Risks

Mitigation

Covid-19 Pandemic and associated economic volatility materially disrupts the Company's ability to deliver its key corporate objectives

· The Company has already secured Phase 1 funding prior to the pandemic

· The Company has implemented logistical and organisational changes to underpin its resilience to severe economic disruption driven by Covid-19, with the key focus being protecting all personnel, minimising impact on critical workstreams and ensuring business continuity.

Finance Review

From a financial as well as operational perspective 2020 was a year focused on utilising 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 Phase 1 of the Core Project.

Over the course of 2020, a total of £109.5 million was invested in the Phase 1 development. Of this, our partner CER funded £54.8 million for their 50% non-operating share in each asset and a further £43.8 million as Phase 1 development carry for the Company's benefit under the terms of the Farm-out.

The post-tax loss for the year was £19.3 million (2019: Profit £15.0 million), which included a £12.6 million (2019: £nil) write down of the Harvey and Redwell assets following technical evaluation in 2020 of the data from the appraisal well and the decision in Q4 2020 to partially redetermine the P2085 licence.

The Company ended the year with a cash balance of £13.4 million plus £67.0 million of restricted cash relating to the Bond issue, held in the Bond escrow and DSRA. A total of £48.3 million of partner Phase 1 development carry had been utilised from Phase 1 FID in October 2019 to 31 December 2020, leaving a remaining Phase 1 carry balance of £11.7 million, in addition to a Phase 2 development carry of £65 million. Group net debt at the end of the year was £14.1 million (see note 21).

In November 2020, the Company signed a contract for Noble Corporation's Noble Hans Deul jack-up drilling rig to drill a five-well programme during 2021 and 2022. Under IFRS 16, IOG is responsible for capitalising 100% of the lease cost to its statement of financial position. Based on the minimum contract duration and day-rate, IOG has therefore recognised £17.6 million upon initial recognition in fixed assets.

No new equity or debt capital was raised in 2020 subsequent to the transactions completed in the previous year. 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.

Finally, in keeping with its growing status as operator of a significant development project, the Company made suitable investments in its systems during the course of 2020 which have ensured more robust, efficient and reliable corporate and joint venture accounting and procurement processes.

Income Statement

The Group made a loss for the year of £19.3 million (2019: £15.0 million gain, resulting from the CER Farm-out transaction), driven primarily by a £12.6 million (2019: £nil) impairment charge on the Harvey and Redwell assets.

Net administration expenses were £3.4 million (2019: £2.6 million) reflecting a lean corporate operation and the allocation of a proportion of overheads to project assets.

The foreign exchange loss of £0.7 million (2019: £0.2 million gain) reflects realised and unrealised foreign exchange movements on non-GBP denominated loans, provisions and trade creditors and loans.

Finance expense of £2.2 million (2019: £7.9 million) includes accrued interest payable on loans (net of capitalised interest of £8.7 million (2019: £1.5 million)). These expenses relate to fees and interest incurred on both loan finance facilities and those trade creditors subject to deferred payment and equity conversion terms.

Statement of financial position

The Goddard, Abbeydale and Harvey exploration and evaluation ('E&E') assets represent the majority of the E&E portfolio at 31 December 2020, with a net book value of £1.3 million (2019: £13.1 million) to the Group at that date following the write down of Harvey by £12.6 million (2019: £nil).

Property, Plant and Equipment (PPE) oil and gas assets increased to £53.4 million (2019: £28.9 million) during the year, representing capital expenditure activities on the Core Project assets.

Total assets have increased to £154.2 million (2019: £146.5 million), including cash resources of £80.4 million (2019: £98.3 million) of which £67.0 million is restricted (£82.0 million).

Total liabilities have increased to £131.1 million (2019: £106.0 million), with the Bond representing long-term loans of £87.8 million (2019: £82.4 million). Liabilities also include trade creditors £1.0 million (2019: £3.9 million), other creditors £7.4 million (2019: £1.4 million), deferred consideration in relation to acquisitions of £2.3 million (2019: £3.1 million). Decommissioning provisions decreased to £6.2 million (2019: £7.2 million), including the Elland suspended well decommissioning provision of £1.2 million, the Thames Pipeline decommissioning provision of £1.0 million (2019: £1.0 million) and the Thames Reception Facilities at Bacton of £3.1 million and the addition of further subsea pipelines laid in 2020 of £0.9 million. There were accruals of £3.1 million (2019: £1.6 million) due to increased volume of work as the Phase 1 development progresses. Lease liabilities recognised under IFRS 16 were £17.6 million (2019 £0.9 million) predominantly driven by the inclusion of the contract for the Noble Hans Deul drilling rig.

The Group ended the year with a net debt position of £14.1 million (2019: £9.0 million net cash), primarily driven by the ongoing expenditure on Phase 1. Net debt is defined as total loans, less restricted cash and cash equivalents, adding back the financial asset being the IOG Norwegian bonds which are held by the Company.

Cash Flow

Net cash inflows of £8.0 million (2019: £15.9 million outflow) from operations, £1.2 million (2019: £83.3 million used in) generated from investing activities and £10.5 million (2019: £109.0 million generated from) used in financing activities. There were no loan repayments (2019: £17.1 million). At the end of the year £67.0 million (2019: £82.0 million) of funds were held as restricted cash in the Bond escrow and DSRA accounts.

An amount of £0.6 million was received during the year pursuant to the exercise of warrants over ordinary shares in the Company.

The Directors do not recommend payment of a dividend (2019: nil).

€100 million Bond

The Group's €100 million 5-year senior secured Bond, issued in 2019 in the name of Independent Oil and Gas plc to a range of institutional investors across the Nordic region, Europe, UK and Asia, remains listed on the Oslo Børs with the ISIN NO0010863236. It 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.

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 2020, 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 €7.2 million (£6.5 million).

As laid out in the Bond terms, drawdown from the Bond escrow account is subject to a series of progress milestones. In Q1 2020, a drawdown of €11.7 million (£10.0 million) was made, further to the operational milestone of start of Phase 1 platform fabrication. At the year end there was a balance of €66.0 million (£59.2 million) in the Bond escrow account, to be drawn down subject to three remaining milestones, all of which were expected to occur in 1H2021. Post-period end, a €27.3 million (£23.7 million) drawdown was made in February 2021, leaving two further drawdowns to be made in 2021.

The Bond is callable from 3 years after issuance, i.e. in September 2022, with an initial call premium of 50% of the coupon (i.e. repayable at a cost of €104.75 million (£91.9 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 (£26.3 million) ("Tap Issues"). Tap Issues carry identical terms to the initial €100 million issue, but may be issued at different prices.

Funding & Liquidity

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 2020 details a net debt position for the Group of £14.1 million (2019: net cash 9.0 million). Net debt is defined as total loans, less restricted cash and cash equivalents, adding back the financial asset being the Company's holding in its own bonds.

In assessing the Group's and Parent Company's current financial position and reaching its conclusion as to going concern status up until September 2022, 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 including the potential impact of Covid-19, in order to develop an accurate perspective. These assumptions are summarised in this paper.

The Phase 1 capital cost and schedule assumptions underlying the going concern assessment flow from the baseline project plan as recently reviewed and reaffirmed by the various lead project managers and the COO, which has led to a revised risked mid-case forecast of final outturn Phase 1 capital expenditure profile finishing in mid-2022. Each key discipline area within the project has undertaken an exercise of rebasing the Phase 1 cost estimates based on existing commitments and better definition of future spend as the project reaches its final stages of execution. These updated cost estimates have in turn been interrogated and subsequently approved at both executive and Board level. Similarly, operating cost assumptions, which include both offshore Operations and Maintenance (O&M) costs, onshore Thames Reception Facilities operation costs and Bacton processing tariff costs, have been established using the latest and most accurate available estimates provided by internal operational personnel and relevant external parties, including IOG's designated O&M contractor ODE and Bacton terminal operator Perenco UK Limited. Decommissioning cost assumptions are drawn directly from the independent Competent Persons Report (CPR) undertaken by reserve auditor ERC Equipoise in 2017.

In terms of project performance and timing assumptions, based on the latest re-baselined management assessments of project readiness and current expectations of the five-well development drilling programme, the timing of field start-ups for Phase 1 are as follows: Elgood and Blythe in September 2021, and Southwark in May 2022. The Phase 1 schedule has also been reviewed and approved by the executive and the Board based on detailed planning schedules managed by our dedicated project planner who has the full collaboration and oversight of the wider project team.

The gas price assumptions underlying the base case economic assessment is based on an 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. The price assumption is seasonally adjusted based on a recent forward curve, 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.

For pre-development assets and General and Administrative (G&A) costs, all assumptions are based on approved internal budgets, which in turn are based on reasonable estimates 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 discussed at Board level. The Group's holding of its own bonds, which have a nominal value of €1.7 million, are assumed to be sold by the end of 2021 at a price no higher than the current market value. Since its listing the bond has seen active trading and therefore the Board consider this to be a reasonable assumption. 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, JV cash calls and Bond drawdowns which allows any exposure to be actively managed.

As demonstrated above, the Group uses prudent assumptions to develop its view of most likely outcomes. In its detailed financial modelling it also stress tests a number of different possible future scenarios to evaluate the likely impacts of potential schedule and cost overruns. The stress test scenarios run by Management and reviewed by the Board, include changes in the timing of first gas, changes in the gas pricing assumptions and changes in expected production levels. These stress test scenarios may individually and in combination impact the Group's available cash resources and ability to remain within its bond covenants. Under the forecast scenarios the Group is expected to be able to stay within its current cash resources until May 2022 after which a potential breach of one of the bond covenants may occur.

The nature of the Group's operations inherently involves a range of potential outcomes and in that context the Group has identified mitigation measures to mitigate or eliminate potential risks that may affect cash flows.

Conclusions

After a review of these forecasts the Board have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future and to deliver Phase 1 on time. Accordingly, the Directors continue to adopt the going concern basis in preparing the consolidated financial statements. However, the Directors acknowledge that at the date of approval of these consolidated financial statements, the potential future impact of the reverse stress test scenarios noted above, indicate the existence of a material uncertainty which may cast significant doubt about the Group's and Parent Company's ability to continue as a going concern and therefore it may be unable to realise its assets and discharge its liabilities in the normal course of business.

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

17 March 2021

Consolidated Statement of Comprehensive Income

	Notes	2020	2019
		£000	£000


Administration expenses		(3,410)	(2,622)
Impairment of oil and gas properties	10	(12,598)	-
Project, pre-licence and exploration expenses		(180)	(4,027)
Profit on farm-down of assets	6	-	24,340
Foreign exchange (loss) / gain		(701)	238
		_________	_________

Operating (loss)/profit	3	(16,889)	17,929

Finance expense	5	(2,203)	(7,939)
Finance income		20	34
Gain on loan modification	7	-	5,005
Fair value loss	14	(265)	-
		_________	_________

(Loss)/profit for the year before taxation		(19,337)	15,029

Taxation	8	-	-
		_________	_________

(Loss)/Profit and total comprehensive (loss)/profit for the year attributable to equity holders of the parent	9	(19,337)	15,029
		_________	_________


(Loss)/earnings for the year per ordinary share - basic	9	(4.0p)	5.1p
(Loss)/earnings for the year per ordinary share - diluted	9	(4.0p)	3.7p

The (loss) for the year £19.3 million (2019: Profit £15.0 million) arose from continuing operations.

Consolidated and Company Statements of Changes in Equity

	Share capital	Share premium	Share-based payment reserve	Accumulated losses	Total equity
	Share capital	Share premium	Share-based payment reserve	Accumulated losses	Total equity
Group:	£000	£000	£000	£000	£000

At 1 January 2019	1,269	22,337	6,308	(35,690)	(5,776)
Profit for the year	-	-	-	15,029	15,029
	_____	________	________	________	_______
Total comprehensive loss attributable to owners of the parent	-	-	-	15,029	15,029
Issue of share capital	3,483	27,086	-	-	30,569
Lapse of warrants	-	-	(31)	31	-
Issue of share options	-	-	676	-	676
Exercise of share options	50	-	(601)	601	50
	_____	________	________	________	_______
At 31 December 2019	4,802	49,423	6,352	(20,029)	40,548

Loss for the year	-	-	-	(19,337)	(19,337)
	_____	________	________	________	_______
Total comprehensive loss attributable to owners of the parent	-	-	-	(19,337)	(19,337)
Lapse of warrants	-	-	(401)	401	-
Exercise of warrants	78	566	(727)	727	644
Issue of share options	-	-	941	-	941
Expiry of share options	-	-	(1)	1	-
Exercise of share options	2	-	(10)	10	2
	_____	______	________	________	_______
At 31 December 2020	4,882	49,989	6,154	(38,227)	22,798
	_____	________	_______	________	_______
Company:
At 1 January 2019	1,269	22,337	6,308	(5,157)	24,757
Loss for the year	-	-	-	(7,010)	(7,010)
	_____	________	________	________	_______
Total comprehensive profit attributable to owners of the parent	-	-	-	(7,010)	(7,010)
Issue of share capital	3,483	27,086	-	-	30,569
Lapse of warrants	-	-	(31)	31	-
Issue of share options	-	-	676	-	676
Exercise of share options	50	-	(601)	601	50
	_____	________	________	________	_______
At 31 December 2019	4,802	49,423	6,352	(11,535)	49,042

Loss for the year	-	-	-	(6,285)	(6,285)
	_____	________	________	________	_______
Total comprehensive loss attributable to owners of the parent	-	-	-	(6,285)	(6,285)
Lapse of warrants	-	-	(401)	401	-
Exercise of warrants	78	566	(727)	727	644
Issue of share options	-	-	941	-	941
Expiry of share options	-	-	(1)	1	-
Exercise of share options	2	-	(10)	10	2
	_____	________	_______	_______	_______
At 31 December 2020	4,882	49,989	6,154	(16,681)	44,344
	______	________	_______	________	_______

Share capital - Amounts subscribed for share capital at nominal value.

Share premium - Amounts received on the issue of shares, in excess of the nominal value of the shares.

Share-based payment reserve - Amounts reflecting fair value of options and warrants issued.

Accumulated losses - Cumulative net losses recognised in the Statement of Comprehensive Income net of amounts recognised directly in equity.

Consolidated Statement of Financial Position

	Notes	2020	2019
		£000	£000

Non-current assets
Intangible assets: exploration & evaluation	10	1,309	13,099
Intangible assets: other	10	170	80
Property, plant and equipment: development & production assets	11	53,422	28,921
Property, plant and equipment: other	11	16,541	1,071
Restricted cash	21	-	49,230
		_________	_________
		71,442	92,401
		_________	_________
Current assets
Financial asset	14	1,260	-
Other receivables and prepayments	16	1,099	5,092
Restricted cash	21	67,049	32,836
Cash and cash equivalents	21	13,389	16,197
		_________	_________
		82,797	54,125
		_________	_________

Total assets		154,239	146,526

Current liabilities
Trade and other payables	17	(22,131)	(7,231)
		_________	_________
		(22,131)	(7,231)
		_________	_________
Non-current liabilities
Loans	22,23	(95,813)	(89,243)
Other liabilities	18,23	(13,497)	(9,504)
		_________	_________
		(109,310)	(98,747)
		_________	_________

Total liabilities		(131,441)	(105,978)
		_________	_________
NET ASSETS		22,798	40,548
		_________	_________
Capital and reserves
Share capital	20	4,882	4,802
Share premium	20	49,989	49,423
Share-based payment reserve		6,154	6,352
Accumulated losses		(38,227)	(20,029)
		_________	_________
		22,798	40,548
		_________	_________

The financial statements were approved and authorised for issue by the Board of Directors on 17 March 2021 and were signed on its behalf by:

Rupert Newall

Chief Financial Officer

17 March 2021

Company Statement of Financial Position

Company Number: 07434350	Notes	2020	2019
		£000	£000
Non-current assets
Intangible assets	10	170	80
Property, plant and equipment: Development & Production	11	1,959	-
Property, plant and equipment: Other	11	16,541	1,071
Investments	13	15,486	15,486
Amounts due from subsidiaries	13	44,906	28,710
Restricted cash	21	-	49,230
		_________	_________
		79,062	94,577
		_________	_________
Current assets
Financial asset	14	1,260	-
Other receivables and prepayments	16	2,466	2,513
Restricted cash	21	65,699	31,586
Cash and cash equivalents	21	13,389	16,197
		_________	_________
		82,814	50,296
		_________	_________
Total assets		161,876	144,873

Current liabilities
Trade and other payables	17	(16,138)	(5,944)

Non-current liabilities
Loans	22,23	(95,813)	(89,243)
Other liabilities	18,23	(5,581)	(644)
		_________	_________
		(101,394)	(89,887)
		_________	_________

Total liabilities		(117,532)	(95,831)
		_________	_________
NET ASSETS		44,344	49,042
		_________	_________

Capital and reserves
Share capital	20	4,882	4,802
Share premium	20	49,989	49,423
Share-based payment reserve		6,154	6,352
Accumulated losses		(16,681)	(11,535)
		_________	_________
		44,344	49,042
		_________	_________

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 £6.3 million (2019: loss £7.0 million).

The financial statements were approved and authorised for issue by the Board of Directors on 17 March 2021 and were signed on its behalf by: -

Rupert Newall

Chief Financial Officer

17 March 2021

Consolidated Cash Flow Statement

	Notes	2020	2019
		£000	£000

(Loss)/profit for the year		(19,337)	15,029

Depreciation, depletion and amortisation	11	559	244
Exploration asset write off	10	12,598	-
Share based payments		941	675
Fair value loss	14	265	-
Profit on disposal of fixed assets	6	-	(24,340)
Interest received		(20)	(35)
Gain on loan modification	7	-	(5,005)
Finance expense	5	2,203	7,939
Effect of exchange rate changes on Bond		4,792	(5,366)

Movement in trade and other receivables		3,993	(4,420)
Movement in trade and other payables		1,974	(620)
		_________	_________

Net cash generated/(used) in operating activities		7,968	(15,899)

Investing activities
Purchase of intangible and tangible assets		(11,735)	(17,048)
Movement in restricted cash		15,017	(87,646)
Interest received		20	35
Increase in Financial assets		(1,260)	-
Deferred consideration payments		(875)	-
Farm out proceeds received ¹		-	22,389
Initial Thames Reception Facilities ("TRF") decommissioning security		-	(2,000)
Farm out proceeds received in respect of ("TRF") decommissioning security		-	1,000
Initial Thames Pipeline decommissioning security		-	250
Lease liability payments		-	(236)
		_________	_________

Net cash generated by / (used in) investing activities		1,167	(83,256)

Financing activities
Proceeds from issue of equity instruments of the Group		2	18,675
Proceeds from issue of warrant instruments of the Group		644	-
Issue costs in relation to issue of equity		-	(1,288)
Proceeds from issue of Norwegian Bond		-	90,439
Cash received from loans		-	3,925
Finance fees paid		(11,116)	(2,705)
		_________	_________

Net cash (used in) / generated from financing activities		(10,470)	109,046

Net increase in cash and cash equivalents		(1,335)	9,891

Cash and cash equivalents at the beginning of the year		16,197	702
Effects of exchange rate changes on cash and cash equivalents		(1,473)	5,604
		_________	_________

Cash and cash equivalents at end of year	21	13,389	16,197
		_________	_________

^{1 Proceeds from the farm out were received net of funds which were settled to LOG for loans and interest totalling £17,139k and legal fees £472k}

Company Cash Flow Statement

	Notes	2020	2019
		£000	£000

Loss for the year	7	(6,285)	(7,010)

Depreciation charges		559	244
Exploration asset write off		180	-
Share based payments		941	675
Fair value loss		265	-

Inter-company service charge uplift		-	(165)
Interest received		(20)	(35)
Finance expenses		2,137	6,596
Gain on loan modification		-	(5,005)
Effect of exchange rate changes in Bond		4,792	(5,366)
Movement in trade and other receivables		47	(1,841)
Movement in trade and other payables		2,879	(2,205)


Net cash used in operating activities		5,495	(14,112)

Investing activities
Purchase of intangible and tangible assets		(629)	(297)
Movement in restricted cash		17,979	(87,646)
Loans to subsidiary undertakings		(11,681)	(19,339)
Proceeds from subsidiary undertakings		-	22,389
Interest received		20	35
Increase in financial assets		(1,260)	-
Deferred consideration payments		(875)	-
Lease liability payments		(129)	(236)


Net cash used in investing activities		3,425	(85,094)

Financing activities
Proceeds from issue of equity instruments of the Company		646	18,675
Issue costs in relation to issue of equity		-	(1,288)
Proceeds from issue of Norwegian Bond (net of costs)		-	90,439
Cash received from loans		-	3,925
Finance fees paid		(11,116)	(2,705)


Net cash generated from financing activities		(10,470)	109,046

Net (decrease) / increase in cash and cash equivalents		(1,550)	9,840
Cash and cash equivalents at the beginning of the year		16,197	702
Effects of exchange rate changes on cash and cash Equivalents		(1,258)	5,655

Cash and cash equivalents at end of year	21	13,389	16,197

Notes forming part of the financial statements

1. Accounting policies

General information

Independent Oil and Gas 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 2020 were authorised for issue by the Board of Directors on 17 March 2021 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 International Financial Reporting Standards applied in accordance with the provisions of the Companies Act 2006, International Accounting Standards and Interpretations (collectively 'IFRSs') and with those parts of Companies Act 2006 applicable to companies preparing their accounts under IFRS.

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 Note 1.

The consolidated financial statements have been prepared on a historical cost basis.

The Company has reclassified certain items in the prior year consolidated and company cash flow statement to align with the current year disclosure.

Going concern

Foreign exchange exposures are forecast and compared to the available currency held as cash balances, JV cash calls and Bond drawdowns which allows any exposure to be actively managed.

Conclusions

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

(i) New and amended standards adopted by the Group:-

The accounting policies adopted are consistent with those of the previous financial year. New or amended financial standards or interpretations adopted during the year and that have a significant impact upon the financial statements are detailed below.

(ii) The following standards, amendments and interpretations, which are effective for reporting periods beginning after the date of these financial statements, have not been adopted early: -

Standard	Description	Effective date
IAS 1	Presentation of Financial Statements	1 January 2020
IAS 8	Accounting Policies, Changes in Accounting Estimates and Errors (Amendment - Disclosure Initiative - Definition of Material)	1 January 2020
IFRS 3	Business Combinations (Amendment - Definition of Business)	1 January 2020
	Conceptual Framework for Financial Reporting (Revised)	1 January 2020
	IBOR Reform and its Effects on Financial Reporting - Phase 1	1 January 2020
IFRS 16	Covid-19-Related Rent Concessions	1 June 2020
IFRS 17	Insurance Contracts	1 January 2021

In reviewing the above standards, the Company does not believe that there will be a material impact on the financial statements.

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, 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.

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.

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 11. The discounted cost for future decommissioning is also added to the D&P 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.

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

IOG adopted IFRS 16 Leases ('IFRS 16') with effect from 1 January 2019. IFRS 16 was issued in January 2016 to replace IAS 17 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. These costs replace amounts previously recognised as operating expenditure in respect of operating leases in accordance with IAS 17.

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

On 1 January 2019, the Group recognised a cumulative increase to ROU assets of £1.1 million for leases previously classified as operating leases, directly offset to the lease obligations. The weighted average incremental borrowing rate used to determine the lease obligation at adoption was approximately 11.5%. In 2020 the Noble Hans Deul drilling rig contract was accounted for as a lease using an incremental borrowing rate of approximately 9.6%. The ROU assets and lease obligations related to the adoption of IFRS 16, relate to office leases, the Thames Pipeline permission to cross the foreshore and the Noble Hans Deul drilling rig contract.

The Group has elected to utilise the practical expedient when accounting for the Noble Rig 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.

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

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 escrow and subject to defined drawdown 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 and long-term debt are measured at amortised cost.

Accounts payable and accrued liabilities 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 Group has financial assets in the form of €1.7 million (£1.3 million) Norwegian bonds measured at FVTPL.

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.

During the prior year, the Company re-negotiated the terms of is February 2019 convertible loan. The loan was considered to have been redeemed under the provisions of IFRS 9 and the resulting improvement in terms created a £5.0 million gain on loan redemption. The loan redemption gain was assessed by reference to the fair value of the remaining cashflows of the 2019 convertible loan note. The gain reflected the improvement in terms between the 2019 and the replacement 2020 loan due to the zero coupon rate attached to the 2020 loan and the extended maturity date to redemption.

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 effect 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. The contract has been assessed to fall within the scope of IFRS 16 and judgements around the initial contract length and the incremental borrowing rate have been made by Management.

Estimates and assumptions

− Impairment Exploration 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. The carrying value of related investments is disclosed in the Company Statement of Financial Position. 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.

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.

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 10% for the current year (2019: 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 2020, the Group has obligations in respect of decommissioning a suspended well on the Southwark, Nailsworth and Elland D&P assets, together with the offshore Thames Pipeline and the acquired Thames 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 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.

On acquisition of the Thames 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 2020 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 Thames 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 2020. 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.

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 exploration and development of oil and gas opportunities in the UK Southern North Sea.

3. Operating (loss) / profit

The Group's operating loss (2019: profit) is stated after charging/(crediting) the following:

	2020	2019
	£000	£000

Fees payable to the Company's auditor: - for the audit of the Group's financial statements	99	80
Non-audit services	24	-

Of which
for the audit of the Company's financial statements	62	50

Depreciation, depletion and amortisation	559	244
Project, pre-licence and exploration expenses Impairment of oil and gas properties	180 12,598	4,027 -
Profit on farm-down of assets	-	(24,340)
Personnel costs - direct expenses ¹	5,700	2,060

Effect of exchange rate changes on Bond	(4,792)	5,366
Effects of exchange rate changes on cash and cash equivalents	5,493	(5,655)

^{1 Personnel costs are shown gross, before the reallocation via the time writing process of the costs to the specific assets to which they relate in Intangible assets and PP&E.}

4. Personnel costs and directors' remuneration

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

	2020	2019
	Number	Number
Management / technical / operations	52	26
of which: Directors	6	6

Personnel costs Group and Company	£000	£000

Wages, salaries, fees and other direct costs	4,018	2,440
Social security costs	509	344
Pension costs	232	3
Share-based payments	941	675
	________	________
	5,700	3,462
	________	________

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 Directors, General Counsel & Company Secretary and the Head of Corporate Finance & Investor Relations. Subsequent to the year end the Chief Operating Officer joined in a non-Board capacity on 8^th February 2021 and is considered to be part of the key management personnel.

Of the total personnel costs of £5,700k, £3,107k was capitalised to the balance sheet under PP&E £2,889k and Intangibles £218k.

Directors' remuneration	Salary/ Fees	Salary/Fees Sacrificed	Bonus	Benefits ⁽¹⁾	Share-based payments	2020 Total	Salary/ Fees	Salary/Fees Sacrificed	Bonus	Share-based payment	2019 Total

	£000	£000	£000	£000	£000	£000	£000	£000	£000	£000	£000

Fiona MacAulay²	113	7	-	-	-	120	125	-	-	-	125
Esa Ikaheimonen	-	50	-	-	-	50	-	34	-	-	34
Neil Hawkings	42	3	-	-	-	45	25	4	-	-	29
Andrew Hockey	308	22	-	38	-	368	211	57	266	94	628
Rupert Newall	234	16	-	29	-	279	13	-	-	-	13

Mark Hughes³	171	15	-	23	-	209	144	39	181	31	395
Mark Routh	-	-	-	-	-	-	-	-	-	159	159
Martin Ruscoe	-	-	-	-	-	-	-	13	-	-	13
Charles Hendry	-	-	-	-	-	-	5	12	-	-	17
	______	_______	_____	_____	______	______	_____	_______	____	______	______
	868	113	-	90	-	1,071	523	159	447	284	1,413
	______	_______	_____	_____	______	______	_____	_______	____	______	______

Other key management personnel	399	21	40	45	12	517	691	80	363	12	1,146

Total key management personnel	1,267	134	40	135	12	1,588	1,214	239	810	296	2,559

^{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 £189k (2019 - £240k).

The share-based payment amounts represent the gains on options exercised in the year.

For the current Directors at 31 December 2020, 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, except for Esa Ikaheimonen who has sacrificed all his fees for share options since joining the Company.

The average proportions of monthly salaries paid in cash and share options in 2020 for all Directors is as follows:

	Cash	Shares
Fiona MacAulay	94%	6%
Andrew Hockey	94%	6%
Mark Hughes	92%	8%
Rupert Newall	94%	6%
Esa Ikaheimonen	0%	100%
Neil Hawkings	93%	7%

For each six-month interval, ending on 28 (or 29) February and 31 August respectively, the Company settles the difference between the reduced rate and the full rate through the granting of options over ordinary shares of the Company at the volume-weighted average share price over the period to which they relate.

Amounts of salary and/or fees outstanding at 31 December 2020 to which these terms relate totalled £43k (31 December 2019 - £34k) for Directors and key management personnel and £16k (2019 - £17k) 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 2020 were as follows:

	Granted	Type	Total 31 Dec 2019	Awarded in 2020	(Exercised) in 2020	Total 31 Dec 2020	Exercise price	Expiry date

Andrew Hockey	01-Mar-18	LTIP	1,600,000	-	-	1,600,000	20p	28-Feb-28
	01-May-19	CSOP	1,600,000	-	-	1,600,000	12.75p	30-Apr-29
	31-Aug-19	Salary Sacrifice	267,740	-	-	267,740	1p	31-Aug-24
	02-Jan-20	CSOP	-	2,256,410	-	2,256,410	1p	01-Jan-30
	01-Apr-20	Salary Sacrifice	-	62,460	-	62,460	1p	01-Apr-25
	31-Aug-20	Salary Sacrifice	-	103,248	-	103,248	1p	05-Oct-25
			3,467,740	2,422,118		5,889,858

Mark Hughes	27-Jul-18	LTIP	1,000,000	-	-	1,000,000	35p	27-Jul-28
	01-May-19	CSOP	1,000,000	-	-	1,000,000	12.75p	30-Apr-29
	31-Aug-19	Salary Sacrifice	183,063	-	-	183,063	1p	31-Aug-24
	02-Jan-20	CSOP	-	1,572,650	-	1,572,650	1p	01-Jan-30
	01-Apr-20	Salary Sacrifice	-	42,473	-	42,473	1p	01-Apr-25
	31-Aug-20	Salary Sacrifice	-	71,961	-	71,961	1p	05-Oct-25
			2,183,063	1,687,084	-	3,870,147

Rupert Newall	01-May-19	CSOP	1,200,000	-	-	1,200,000	12.75p	30-Apr-29
	31-Aug-19	Salary Sacrifice	240,966	-	-	240,966	1p	31-Aug-24
	02-Jan-20	CSOP	-	1,709,402	-	1,709,402	1p	01-Jan-30
	01-Apr-20	Salary Sacrifice	-	56,214	-	56,214	1p	01-Apr-25
	31-Aug-20	Salary Sacrifice	-	78,218	-	78,218	1p	05-Oct-25
			1,440,966	1,843,834	-	3,284,800

Esa Ikaheimonen	01-May-19	LTIP	600,000	-	-	600,000	12.75p	30-Apr-29
	31-Aug-19	Salary Sacrifice	136,606	-	-	136,606	1p	31-Aug-24
	29-Feb-20	Salary Sacrifice	-	114,152	-	114,152	1p	31-Mar-25
	01-Apr-20	Salary Sacrifice	-	39,974	-	39,974	1p	01-Apr-25
	31-Aug-20	Salary Sacrifice	-	234,627	-	234,627	1p	05-Oct-25
			736,606	388,753	-	1,125,359

Fiona MacAulay	01-May-19	LTIP	1,000,000	-	-	1,000,000	12.75p	30-Apr-29
	31-Aug-20	Salary Sacrifice	-	34,416	-	34,416	1p	05-Oct-25
			1,000,000	34,416	-	1,034,416

Neil Hawkings	24-May-19	LTIP	600,000	-	-	600,000	13.5p	28-Feb-24
	31-Aug-19	Salary Sacrifice	18,061	-	-	18,061	1p	31-Aug-24
	31-Aug-20	Salary Sacrifice	-	14,079	-	14,079	1p	05-Oct-25
			618,061	14,079	-	632,140

5. Finance expense

	2020	2019
	£000	£000

Interest on loans	103	1,928
Interest on deferred payment creditors	-	140
Amortisation of loan finance charges	2	4,357
Current year loan finance charges	540	566
Current year finance charges on deferred payment creditors	19	54
Unwinding of discount on convertible loan	1,027	258
Unwinding of deferred consideration provisions	158	636
Unwinding of discount on lease liability	354	-
Interest on bonds	8,668	2,545
Capitalisation of interest on bonds¹	(8,668)	(2,545)
	________	________
	2,203	7,939
	________	_________

^{1 During the Phase 1 development, all interest paid in the Norwegian bonds is capitalised to the Phase 1 assets proportionately based on their capital expenditure during the year}

During 2020 there were no interest bearing loans outstanding, excluding the Bond. The interest associated with the Bond is capitalised to project costs as the bond drawdowns are purposefully used for the project.

6. Profit on Farm-down of assets

	2020	2019
	£000	£000

Proceeds	-	40,000

Disposals:
Intangible Assets	-	(150)
Property, plant & equipment	-	(15,510)
	________	________
Profit on Farm-down of assets	-	24,340
	________	_________

7. Gain on loan modification

In October 2019, the Company completed a restructuring of its remaining debt with London Oil and Gas Limited. The convertible debt and interest (£11.6 million) pertaining to the £10.0 million facility dated 21 February 2018 was restructured into a new convertible loan which allows for the conversion of the loan into 60,872,631 shares at a strike price of 19 pence until maturity. The new loan had an extended maturity date of 23 September 2024, was unsecured, subordinated to other debt the Group holds and incurred interest at the rate of zero percent. The Company calculated the gain reflecting the improvement in terms between the 2018 and 2019 loan under the provisions of IFRS 9 to be £5.0 million, using an effective interest rate of 11.5%, and had recognised this gain in the Statement of Comprehensive Income.

8. Taxation

a) Current taxation

There was no tax charge during the year as the Group loss was not chargeable to corporation tax. Applicable expenditures to-date will be accumulated for offset against future tax charges.

The reasons for the difference between the actual tax charge for the year and the standard rate of corporation tax in the United Kingdom applied to profits for the year are as follows:

	2020	2019
	£000	£000

Profit/ (loss) for the year	(19,337)	15,029
Income tax expense	-	-
	_________	_________
Loss before income taxes	(19,337)	15,029

Expected tax expense/(credit) based on the standard rate of United Kingdom corporation tax at the domestic rate of 40%¹ (2019: 40%)	(7,735)	6,012

Difference in tax rates	1,952	1,892
Expenses not deductible for tax purposes	260	1,552
Income not taxable	(4,590)	(4,199)
Disposal	-	(22,722)
Unrecognised taxable losses carried forward	10,113	17,465
	_________	_________
Total tax expense	-	-
	_________	_________

^{1 The standard rate of corporation tax of 40% (2019: 40%) , including the supplemental corporation tax charge of 10% (2019:10%) is levied in respect of UK ring fence profit. Non-ring fenced profits are taxed at the standard rate of corporation tax of 19%. Given that the group's activities are primarily focused on activities which will generate income within the UK ring fence the 40% has been regarded as the appropriate rate for the reconciliation above.}

b) Deferred taxation

Due to the nature of the Group's exploration activities there is a long lead time in either developing or otherwise realising exploration assets. The amount of deductible temporary differences, unused tax losses and unused tax credits for which no deferred tax asset is recognised in the statement of financial position is £122.7 million (2019: £124.7 million). There are also accelerated capital allowances of £35.7 million (2019: £33.4 million)

The Group has not recognised a deferred tax asset at 31 December 2020 on the basis that the Group would expect the point of recognition to be when the Group has some level of production history showing that the Group is making profits in line with the underlying economic model which would support the recognition.

The group has carried forward ring fence tax losses of £111.5 million (2019: £ 82.3 million) and non-ring fence tax losses of £13.4 million (2019: £ 7.9 million). In addition the group has pre- trading revenue expenditure of £2.9 million ( 2019: £1.3 million) (to the extent that the company commences a trade within seven years from the time the expenditure was incurred) and pre-trading capital expenditure of £5.2 million (2019: £3.9 million) that would be available upon commencement of the trade in the respective group company.

9. Earnings/(loss) per share

	2020	2019
	£000	£000

(Loss) / Earnings for the year attributable to shareholders (Numerator)	(19,337)	15,029
	___________	___________

Weighted average number of ordinary shares: basic (Denominator)	488,211,155	297,560,956

Add potentially dilutive shares:
Convertible loan notes	60,872,631	60,872,631
Salary/Fee sacrifice options	4,480,836	3,511,871
LTIP/CSOP	20,809,486	10,900,000
Warrants	20,000,000	33,277,310

diluted	594,374,108	406,122,768
	___________	___________

Loss / Earnings per share in pence: basic	(4.0p)	5.1p
diluted	(4.0p)	3.7p

Diluted loss per share is calculated based upon the weighted average number of ordinary shares plus the weighted average number of ordinary shares that would be issued upon conversion of potentially dilutive share options, convertible loan notes and warrants into ordinary shares.

As the current year result for the year was a loss, the options and warrants outstanding would be anti-dilutive. Therefore, the dilutive loss per share is considered as the same as the basic loss per share.

In 2019, there were no anti-dilutive instruments that were not included in the calculations that would have had a material impact on the basic earnings per share.

There are no significant ordinary share issues post the reporting date, save for those disclosed in note 28 that would materially affect this calculation.

10. Intangible assets

Group

	Exploration & evaluation assets	Company & IT software assets	Total	Exploration & evaluation assets	Company & IT software assets	Total

	2020	2020	2020	2019	2019	2019
	£000	£000	£000	£000	£000	£000
At cost
At beginning of the year	35,466	120	35,586	24,719	7	24,726
Additions	808	201	1,009	10,897	113	11,010
Disposals	-	-	-	(150)	-	(150)
	_________	_________	________	_________	_________	________
At end of the year	36,274	321	36,595	35,466	120	35,586
	_________	_________	________	_________	_________	________

Impairments and write-downs
At beginning of the year	(22,367)	(40)	(22,407)	(22,367)	(4)	(22,371)
Amortisation	-	(111)	(111)	-	(36)	(36)
Impairment	(12,598)	-	(12,598)	-	-	-
	________	________	________	________	________	________
At end of the year	(34,965)	(151)	(35,116)	(22,367)	(40)	(22,407)
	_________	_________	________	________	________	________

Net book value
At 31 December 2020	1,309	170	1,479
At 1 January 2020	13,099	80	13,179
At 1 January 2019	2,352	3	2,355

Exploration and evaluation assets at 31 December 2020 comprise the Group's reduced interest in the Harvey licence following partial relinquishment, Abbeydale appraisal and the Goddard pre-development prospects.

The affected E&E assets are tested for impairment once indicators have been identified.

After completing the technical analysis of Harvey, IOG has impaired the drilling costs of Harvey well and proportionally reduced the accumulated capitalised cost for the Harvey licence. The Redwell licence, which was fully determined in March 2021, has been fully impaired in the period as no further investment on this licence is planned.

11. Property, plant and equipment

Group

	D&P assets Phase 1	D&P assets Phase 2		Pipeline assets		Right of use assets		Admin assets		Total	D&P assets Phase 1	D&P assets Phase 2	Pipeline assets	Right of use assets	Admin assets	Total
	2020	2020		2020		2020		2020		2020	2019	2019	2019	2019	2019	2019
	£000	£000		£000		£000		£000		£000	£000	£000	£000		£000	£000
At cost
At beginning of the year	13,847	4,062		11,012		1,054		258		30,233	22,444	8,136	10,947	-	74	41,601
On transition	-	-		-		-		-		-	-	-	-	703	-	703
Additions	19,828	3,088		2,499		17,496		379		43,290	3,521	869	668	351	184	5,593
Change in estimate of decommissioning asset (note 18)	-	-		(1,850)		-		-		(1,850)	-	(1,198)	-	-	-	(1,198)
Decommissioning asset (note 18)	-	-		936		-		-		936	-	-	10,000	-	-	10,000
Disposals	-	-		-		-		-		-	(12,118)	(3,745)	(10,353)	-	-	(26,216)
Thames Pipeline decommissioning security	-	-		-		-		-		-	-	-	(250)	-	-	(250)
	______	______		______		______		______		_____	______	______	______	______	______	_____
At end of the year	33,675	7,150		12,597		18,550		637		72,609	13,847	4,062	11,012	1,054	258	30,233
	______	______		______		______		______		_____	______	______	______		______	_____
Accumulated depreciation
At beginning of the year	-	-		-		(145)		(96)		(241)	-	-	-	-	(33)	(33)
DD&A	-	-		-		(2,231)		(174)		(2,405)	-	-	-	(145)	(63)	(208)
	______	______		______		______		______		_____	______	______	______	______	______	_____
At end of the year	-	-		-		(2,376)		(270)		(2,646)	-	-	-	(145)	(96)	(241)
	______	______		______		______		______		_____	______	______	______		_____	_____
Net book value
At 31 December 2020	33,675	7,150	12,597		16,174		367		69,963
At 1 January 2020	13,847	4,062	11,012		909		162		29,992
At 1 January 2019	22,444	8,136	10,947		-		41		41,568

Phase 1 development and production assets received Final Investment Decision in October 2019 and are awaiting approval of the final Field Development Plan from the OGA, expected by 30 April 2020

Phase 2 development and production assets are currently scheduled for Final Investment Decision in Q3 2021.

The £200k paid as decommissioning security guarantees in 2018 in respect of both the Elland P039 Licence suspended well and the Initial Thames Pipeline Decommissioning Security were classified as fixed assets at 31 December 2019. In 2019, a further £2.0 million was paid upon acquisition as security against the Thames Reception Facilities Decommissioning Security.

Following the farm-down to CER, the above amounts were reduced by 50% resulting in £100k held against the Elland P039 licence, £250k against the Thames Pipeline, and £1.0 million against the Thames Reception Facilities. At the year end, £1.25 million for the Thames Pipeline and Thames Reception Facilities classified as Restricted cash on the balance sheet.

In 2020, due to the 12" and 6" pipeline laying campaign, a further £0.9 million was recognised as a decommissioning liability. A re-assessment of the Thames Reception Facilities decommissioning liability was also conducted and the amount reduced to £3.2 million.

All assets were assessed for impairment under IAS 36, but no impairment indicators were identified and therefore no impairment has been recognised during the year (2019: nil).

Company

	D&P assets Phase 1	Right of use assets		Admin assets		Total	D&P assets Phase 1	Right of use assets	Company & admin assets	Total
	2020	2020		2020		2020	2019	2019	2019	2019
	£000	£000		£000		£000	£000	£000	£000	£000
At cost
At beginning of the year	-	1,054		258		1,312	-	-	74	74
On transition	-	-		-		-	-	703	-	703
Additions	1,959	17,496		379		19,834	-	351	184	535
	______	______		______		_____	______	______	______	_____
At end of the year	1,959	18,550		637		21,146	-	1,054	258	1,312
	______	______		______		_____	______	______	______	_____
Accumulated depreciation
At beginning of the year	-	(145)		(96)		(241)	-	-	(33)	(33)
DD&A	-	(2,231)		(174)		(2,405)	-	(145)	(63)	(208)
	______	______		______		_____	______	______	______	_____
At end of the year	-	(2,376)		(270)		(2,646)	-	(145)	(96)	(241)
	______	______		______		_____	______	______	_____	_____
Net book value
At 31 December 2020	1,959	16,174	367		18,500
At 1 January 2020	-	909	162		1,071
At 1 January 2019	-	-	-		41

Phase 1 assets for the Company relate to the depreciation of the right of use asset in relation to the Noble Hans Deul rig contract.

All assets were assessed for impairment, but no impairment indicators were identified.

12. Restructuring and Farm-out

Debt Restructuring of Loans and Convertible Loans

At the beginning of 2019, the following loans were outstanding.

Loan Facility	Entity	Effective Date	Principal £000	Accumulated interest £000	31 December 2019 £000
£2.75 million facility	IOG North Sea Limited	7 December 2015	2,750	654	3,404
£0.80 million facility	IOG North Sea Limited	11 December 2015	800	192	992
£10.00 million facility	IOG North Sea Limited	5 February 2016	10,000	1,671	11,671
£10.00 million facility	IOG plc	21 February 2018	10,000	672	10,672
£15.00 million facility	IOG plc	13 September 2018	7,150	142	7,292
		Capitalised fees			(4,213)
					29,818

In April 2019 the Group restructured its debt with the Company's main creditor London Oil and Gas Limited ("LOG") with a Debt Repayment and Discharge Agreement ('DRDA') to defer each 2020 maturity by 12 months.

LOG also converted £1.6 million of the outstanding balance of the February 2016 loan in to 20,497,204 ordinary shares.

On 28 October 2019, at the completion of the Farm-out, £17.1 million of cash proceeds were used to repay in full all non-convertible loans and £79,000 of the February 2016 convertible loan, with the balance of the latter loan being converted into 135,464,155 new Ordinary Shares.

The 2019 secured convertible loan which accrued interest at 9% above LIBOR was restructured into a £11.6 million Convertible Loan Note Instrument. This instrument was unsecured, subordinated to other Group debt, accrued no interest, had a maturity date of 23 September 2024 and was convertible at 19p into 60,872,361 Ordinary Shares.

The table below sets out the opening, movement and closing position of the LOG loans in 2019.

Loan Facility	2019 B/fwd Balance	2019 Drawdown	2019 Interest	2019 Cash Settlement	2019 Converted to ordinary shares	2019 Gain on loan modification³	2019 Other	Carrying Value at 31 December 2019
	£000	£000	£000	£000	£000	£000	£000	£000
£2.75 million facility	3,404	-	252	(3,656)	-	-	-	-
£0.80 million facility	992	-	82	(1,074)	-	-	-	-
£10.00 million facility	11,671	-	885	(79)	(12,477)	-	-	-
£10.00 million facility	10,672	-	894	-	-	(5,005)	258¹	6,819
£15.00 million facility	7,292	3,925	1,113	(12,330)	-	-	-	-
Capitalised Fees	(4,213)	-	-	-	-	-	4,213²
	29,818	3,925	3,226	(17,139)	(12,477)	(5,005)	4,471	6,819

^{1 2019 unwinding discount of the convertible loan}

^{2 Fees expensed to Statement of Comprehensive Income in 2019}

^{3 See note 7}

The table below sets out the opening, movement and closing position of the LOG loans in 2020.

Loan Facility	2020 B/fwd Balance	2020 Drawdown	2020 Interest	2020 Cash Settlement	2020 Converted to ordinary shares	2020 Gain on loan modification	2020 Unwinding discount	Carrying Value at 31 December 2020
	£000	£000	£000	£000	£000	£000	£000	£000
£10.00 million facility	6,819	-	-	-	-	-	1,218	8,037
	6,819	-	-	-	-	-	1,218	8,037

Share Placing, Open Offer and Subscription

In April 2019, the Group raised gross proceeds of £18.9 million through the issue of ordinary shares at 10 pence. The three components of shares were issued:

	Ordinary Shares	£000
Placement	165,795,050	16,580
Subscription	3,250,000	325
Open Offer	20,141,129	2,014
	189,186,179	18,919

Farm-out and Phase 1 FID

On 28 October 2019 the Company announced that it completed the farm-out of 50 per cent of its SNS Assets (excluding Harvey) to CalEnergy Resources Limited ("CER"). IOG and CER took Phase 1 FID and submitted confirmation of full funding to the OGA in support of the Phase 1 FDP approval.

CER paid the initial cash consideration of £40m to IOG under the terms of the farm-out. CER will also pay for up to £125m of IOG's development costs, usable against 80 per cent of IOG's 50 per cent share of Core Project costs, up to caps of £60m for Phase 1 and £65m for Phase 2. IOG will pay CER a royalty of 20.2 per cent of its net revenues from the Phase 1 fields only (i.e. 10.1 per cent of gross Phase 1 revenues, net of National Transmission System entry charges and applicable marketing fees), up to a cap of £91m over field life.

In addition, IOG will receive an effective royalty interest equating to £0.50/MCF on CER's 50 per cent share of production from certain sections of the Goddard Field after 70 BCF gross has been produced from the field, up to a maximum royalty of £9.75m. With its experienced SNS development team, IOG has retained Operatorship of the Core Project.

CER also had the option to acquire 50 per cent of the Harvey licences within three months of completion of the Harvey appraisal well 48/24b-6. The Company announced that this option expired on 27 February 2020.

Upon completion of the Farm-out, the company settled three of its outstanding LOG loans including interest with £17.1 million of the £40 million proceeds received.

13. Investments

	Shares	Loans
	in Group	to Group
Company	companies	companies	Total

	£000	£000	£000
At cost
At 1 January 2019	17,197	29,526	46,723
Disposals	(1,711)	(816)	(2,527)
	_________	_________	_________
At 31 December 2019	15,486	28,710	44,196
Additions	-	16,196	16,196
	_________	_________	_________
At 31 December 2020	15,486	44,906	60,392


Net book value
At 1 January 2019	17,197	29,526	46,723

At 1 January 2020	15,486	28,710	44,196

At 31 December 2020 ¹	15,486	44,906	60,392

^{1 There were no impairments in the 2020 period. Although the Harvey (P2085) licence was impaired during the period by IOG North Seal Limited, the Company has assessed the subsidiaries ability to repay its loans and believes there is sufficient cash flow from other assets held by the subsidiary to fulfil its obligation.}

The Company has undertaken not to seek repayment of loans from other Group subsidiary companies until each subsidiary has sufficient funds to make such payments, however they are technically due on demand. The repayment of the subsidiary loans is expected to begin once each entity generates revenues from gas sales and transportation. The Company expects these loans to begin to be repaid in 2022 and is supported by its detailed cash flow modelling. These loans are non-interest bearing.

The Company's subsidiaries, all registered at 60 Gracechurch Street, London EC3V 0HR, are as follows:

	Country of	Area of
Directly held	incorporation	operation	%
IOG Infrastructure Limited	United Kingdom	United Kingdom	100
IOG North Sea Limited	United Kingdom	United Kingdom	100
IOG UK Ltd	United Kingdom	United Kingdom	100
Avalonia Energy Limited (dormant)	United Kingdom	United Kingdom	100

Held by Avalonia Energy Limited
Avalonia Goddard Limited (dormant)	United Kingdom	United Kingdom	100
Avalonia Abbeydale Limited (dormant)	United Kingdom	United Kingdom	100
Avalonia Energy Appraisal Limited (dormant)	United Kingdom	United Kingdom	100

All three active subsidiaries are engaged in the business of oil and gas appraisal, development and/or operations in the UK North Sea.

The four dormant companies were incorporated in 2018 and 2019 and have been made available to support any potential Group restructure following refinancing of the Group.

The financial reporting periods for each subsidiary entity are consistent with the Company and end on 31 December.

14. Financial Asset

IOG holds €1.7 million (£1.3 million) of its Norwegian bonds, which are classed as a financial asset.

At 31 December 2020 the bonds were valued at 82.5% of their par value.

	2020	2019
	£000	£000

At 1 January	-	-
Additions¹	1,525	-
Fair value adjustment	(265)
	________	________
At 31 December	1,260	-
	________	_________

^{1 In 2019 the bonds were disclosed within other debtors as title had not transferred to the Group.}

15. Interests in production licences

At 31 December 2020, all eleven Group UK Offshore Production Licences, apart from Harvey and Redwell (100%), were owned 50% by either IOG North Sea Limited or IOG UK Ltd. The Thames Pipeline PL370 and Bacton Gas Terminal assets are owned 50% by IOG Infrastructure Limited.

Subsequent to the year end (10 March 2021), the Redwell licence, held by IOG North Sea Limited was determined and returned to the OGA.

16. Other receivables and prepayments

	2020	2019
	£000	£000
Group
VAT recoverable	869	759
Prepayments	205	257
Operator advance accounts	-	2,579
Other receivables	25	1,497
	_________	_________
	1,099	5,092
	_________	_________
Company
VAT recoverable	2,236	759
Prepayments	205	257
Other receivables	25	1,497
	_________	_________
	2,466	2,513
	_________	_________

The 2020 prepayments relate to rental charges for its 10 Arthur Street and 189 Endeavour House office space in London and general administration.

The debtors balance of £25k represents an amount receivable from Chrysaor. The reduction in other receivables resulted from a reclassification to financial assets, being the €1.7m (£1.3 million) Norwegian bonds held in IOG plc by the Company.

The Company has considered the carrying value of Debtors in the context of IFRS 9 and has assessed the debtors ability to repay the amount due. In assessing the expected credit loss ('ECL') of the receivables, the Company considered future cash flows from the entities and concluded there is no material ECL provision required.

17. Current Liabilities

	2020	2019
	£000	£000
Group
Trade payables	979	3,856
Lease liabilities	13,781	939
Accruals	3,106	1,588
Operator advance accounts	4,100	-
Tax payable	165	-
Contingent consideration payable	-	848
	_________	_________
	22,131	7,231
	_________	_________

Company
Trade payables	979	3,856
Lease liabilities	13,781	939
Accruals	1,213	301
Tax Payable	165	-
Contingent consideration payable	-	848
	_________	_________
	16,138	5,944
	_________	_________

18. Non-current liabilities

	2020	2019
	£000	£000
Group
Long-term loans	95,813	89,243
Lease liability	4,968	-
Contingent consideration payable	2,302	2,267
Decommissioning provision	6,227	7,237
	_________	_________
	109,310	98,747
	_________	_________
Company
Long-term loans	95,813	89,243
Lease liability	4,968	-
Contingent consideration payable	613	644
	_________	_________
	101,394	89,887
	_________	_________

Long-term loans:

The Nordic bond issued in 20 September 2019 represents £87.8 million (2019: 82.4 million) of the long-term loans balance with the LOG loan of £8.0 million being the balance of the total of £95.8 million. See note 22 for further details of the Nordic bond.

The amounts drawn on LOG loans at 31 December 2020 and 31 December 2019 were as follows:

Loan Facility

Entity

Effective Date

Maturity Date

Principal

Interest

£11.6 million convertible loan, 5 year facility

IOG plc

28 September 2019

23 September 2024

£11.6 million

Nil

See note 12 for information relating to the outstanding LOG loan.

Contingent consideration payable:

The Group is required under certain terms its acquisitions to make further amounts payable upon first gas.

As disclosed in the 2019 financial statements, these milestone events triggering deferred consideration payments are now considered to be more certain than not and a non-current amount of £2.3 million is recognised. These amounts have been provided for and the payments discounted to the point where the Board expect the milestones to be achieved based on the current development programme.

The movements in the year are as follows:

	2020	2019
	£000	£000
At 1 January	3,114	6,187
Disposal to CER	-	(3,092)
Prospective adjustment for change in payment dates	-	(493)
Settlement of liability¹	(875)	-
Foreign exchange	(96)	30
Unwinding of discount	159	482
At 31 December	2,302	3,114

^{1 Payment made following the FDP approval of Phase 1 by the OGA.}

Given the timing of the expected payments, the total balance is split between current and non-current as set out below:

	2020	2019
	£000	£000
Current contingent consideration payable (FDP approval)	-	847
Non-Current contingent consideration payable (first gas)	2,302	2,267
	2,302	3,114

Decommissioning provision:

	2020	2019
	£000	£000
At 1 January	7,239	5,640
Revision in estimates	(1,850)	(1,130)
Discount unwinding	(99)	(32)
Additions	936	10,000
Disposals	-	(7,239)
At 31 December	6,226	7,239

The Group has regulatory and financial obligations in respect of decommissioning for a suspended well on the Elland Licence P039 - Gross £2.4 million (2019: £2.4 million), net to the Company £1.2 million. Decommissioning the Thames Pipeline - £2.0 million (2019: £2.0 million). For the Thames Reception Facilities at Bacton the company holds further decommissioning liabilities totalling £3.15 million net to the Company. The Company, as a result of it's work program in 2020 has decommissioning liabilities of £0.9 million (net) for the additional 12" and 6"pipelines it has laid on the sea bed in 2020.

A full decommissioning estimate for the Elland suspended well remains uncertain until an appropriate drilling programme has been reviewed and considered for the Elland development, which may include the decommissioning of that particular well. The timing and thus payment of this decommissioning program remains inherently uncertain.

The £1.0 million provision for the Thames Pipeline decommissioning obligation has been calculated on a discounted cash flow basis, whereby the present value of the regulatory marine surveys has been inflated at 2% and then discounted at the risk-free discount rate of 1.8%. It has been estimated that the Thames Pipeline has a useful life over the next 25 years; however, the judgements made on this and other variables, currently provided by the OGA, are inherently uncertain.

The initial £10.0 million provision for the Thames Reception Facilities decommissioning obligation has been recognised on the basis of the SPA, then reduced to reflect the Farm-out to CER (£5.0 million net). Resulting in a net £5.0 million liability. An initial payment of £2.0 million was made by the Company as security for the liability on completion of the Thames Reception Facilities transaction which was then reduced for CER's 50% share to £1.0 million. The Group is due to pay a further eight quarterly payments of £0.5 million as security six months after the start of gas production. The Group has chosen to recognise the full amount of the liability represented in the SPA as there is no material difference of discounting the payments back to the balance sheet date.

19. Net (Debt) / Cash

IOG uses the following definition of net (debt)/cash - restricted cash and cash equivalents plus the financial asset, less total loans.

	2020	2019
	£000	£000

Restricted cash	67,049	82,066
Cash and cash equivalents	13,389	16,197
Fair value asset	1,260	-
Loans	(95,813)	(89,243)

Net (debt)/cash	(14,115)	9,020

20. Share Capital

		Share	Share
		capital	premium	Total
	Number	£000	£000	£000

Authorised, allotted, issued and fully paid
At 1 January 2019
- Ordinary shares of 1p each	126,868,156	1,269	22,337	23,606
Equity issued:
- April 2019, Ordinary shares of 1p - Placing, Open offer, Subscription and LOG conversion	209,670,834	2,097	17,173	19,270
- October 2019, Ordinary shares of 1p - London Oil & Gas Ltd debt conversion	135,464,155	1,355	9,482	10,837
- October 2019, Ordinary shares of 1p - Edimis Energy Limited settlement ¹	3,147,139	31	431	462
Equity issued ²	5,022,961	50	-	50
	_________	_________	_________	_________
At 31 December 2019 - Ordinary shares of 1p each	480,173,245	4,802	49,423	54,225
Equity issued:
- December 2020, Ordinary shares of 1p, London Oil & Gas Ltd, Warrant exercise ³	7,877,310	78	566	644
- Other LTIP and Salary sacrifice share exercises	160,600	2	-	2
	_________	_________	_________	_________
At 31 December 2020 - Ordinary shares of 1p each	488,211,155	4,882	49,989	54,871
	_________	_________	_________	_________

^{1 For further details, see related party transactions note 26}

^{2 During 2019, the Company issued 5,022,961 ordinary shares at a subscription price of 1p from the exercise of management and other personnel share options.}

^{3 During 2020, London Oil & Gas Ltd exercised 7,500,000 of their warrants at 8 pence per share and 377,310 warrants at 11.9 pence per share.}

Share options and warrants

During the current and prior year, the Company granted share options under its share option plans as follows:

	Number	Price	Date of Grant	Expiry

1 January 2019	10,282,725	9.11p

Salary/fee sacrifice options	628,496	1p	28 Feb 2019	28 Feb 2024
LTIP options	600,000	13.25p	24 May 2019	23 May 2029
LTIP options	1,600,000	12.75p	1 May 2019	30 Apr 2029
CSOP options	5,100,000	12.75p	1 May 2019	30 Apr 2029
Salary/fee sacrifice options	1,223,611	1p	31 Aug 2019	31 Aug 2024
Options exercised	(5,022,961)

31 December 2019	14,111,871	13.03p
Salary/fee sacrifice options	114,152	1p	29 Feb 2020	31 Mar 25
CSOP cancelled/expired	(395,279)	1p
CSOP options	10,274,102	1p	Various dated in 2020	Various dated in 2023
Salary/fee sacrifice options	1,046,076	1p	31 Aug 2020	05 Oct 25
Options exercised	(160,600)
31 December 2020	25,290,322

Of the remaining staff options, 10,282,725, outstanding at 31 December 2018, 4,519,233 were exercised during 2019. Of those staff options granted during 2019, 503,728 were exercised during 2019. Total personnel options exercised in 2019 is thus 5,022,961.

Of the remaining staff options, 14,111,871 outstanding at 31 December 2019, 126,497 were exercised during the year. Of those personnel options granted during 2020, 34,103 were exercised during 2020. Total personnel options exercised in 2020 is thus 160,600.

The fair value of these options exercised was transferred from the Share-based Payment Reserve to Accumulated Loss.

All salary/fee sacrifice options outstanding at 31 December 2020 were issued at an exercise price of 1p per share and carry no additional performance conditions. These shares were issued at a volume calculated by taking the amount owing and dividing by the volume weighted average price for the period to which the salary/fee sacrifice pertains.

CSOP Valuation

The 2020 CSOP valuation is based on a Log-normal Monte-Carlo stochastic model.

The valuation model assumes:-

- Share price at date of grant 15.63p

- Exercise price of 1.00p

- Option life of 10 years

- The risk-free rate and volatility of the underlying are known and constant (0.53%, 3 year UK government bond at grant date)

- Share price volatility is 70.00%

- 10,000 iterations

LTIP Valuation

There were no LTIP shares granted in 2020. The 2019 LTIP valuation is based on a Log-normal Monte-Carlo stochastic model.

The valuation incorporates a forecast employee turnover to establish the number of options expected to vest, the charge requires recalculation each year to take account of any revised estimates regarding employee turnover and any new grants of share options.

- Efficient markets (i.e., market movements cannot be predicted)

- No commissions

- 10,000 iteration

- The risk-free rate and volatility of the underlying are known and constant (0.62%, 3 year UK government bond at grant date)

- Share price volatility is 84.19%

All LTIP and CSOP options outstanding at 31 December 2020 were issued to option holders with, other than the target price, several performance criteria including the delivery, measurement, control and management of an appropriate HSE statement and policy together with a Group-wide HSE focussed culture.

The remaining average contractual life of the 25,290,322 options outstanding at 31 December 2020 (2019 - 14,111,871) was 5.2 years at that date (2019: 7.7 years) of which 4,480,836 were exercisable at 31 December 2020 (2019: 1,062,893).

The weighted average exercise price of the options remaining was 7.8p at 31 December 2020 (2019 - 13.03p).

A further 593,735 options are due to be issued in 2020 relating to 2020 salary/fee sacrifice; however, these have not been issued as at the date of this report.

The Company calculates the value of personnel salary/fee sacrificed share-based compensation as the actual value of the sacrificed amount. This is deemed to be the fair value of such awards. The fair value of sacrificed salary/fee share options granted in 2020 is calculated as £161k (2019: £299k) and this has been charged to the Statement of Comprehensive Income. The exercise price of such awards was determined as 1p (2019: 1p).

The Company calculates the fair value of LTIP share-based compensation using a Log-normal Monte-Carlo stochastic model. The fair value of LTIP options granted in 2020 is calculated as £nil (2019: £750k), of which £nil (2019: £166k) has been charged to the Statement of Comprehensive Income, being the amortised amount over the vesting period attributable to the current year. The exercise price of these options has been determined as 20p for those issued on 1 March 2019 and 35p for those issued on 27 July 2019. On 1 May 2019 the Company announced that it had cancelled the future awards under the 2019 LTIP options scheme.

Further details for Directors are provided in Note 4.

The Company did not grant any warrants in the current year (2019: nil). Warrants for 7,877,310 were exercised during the year (2019: nil) and warrants for 5,400,000 lapsed during the year (2019: 500,000) and are shown as follows:

	Number	Price	Date of Grant	Expiry

1 January 2019	33,777,310	22.98p

London Oil & Gas Ltd	(500,000)	8.0p	29 Mar 2016	31 Mar 2019

31 December 2019	33,277,310	23.21p

Exercised warrants	(7,500,000)	8.0p	11 Dec 2015	31 Dec 2020
Exercised warrants	(377,310)	11.9p	4 Dec 2015	31 Dec 2020
Lapsed warrants	(5,400,000)	11.9p	29 Mar 2016	31 Dec 2020

31 December 2020	20,000,000	32.18p

The Company calculates the value of share-based compensation using the Black-Scholes option pricing model to estimate the fair value of warrants at the date of grant.

The fair value of 20,000,000 warrants granted to London Oil & Gas Limited on 13 September 2018 was calculated as £4.2 million, all of which was recognised as an issue cost of the £15 million LOG loan facility, held at amortised cost using the effective interest method. The exercise price of these warrants was determined as 32.18p.

The following assumptions were applied in the LOG warrant award calculation:


Risk free interest rate	1.50%
Dividend yield	nil
Weighted average life expectancy	4 years
Volatility factor	96.45%

A volatility of 96.45% has been applied based upon the Company’s share price over the period from the Company’s listing on AIM on 30 September 2013 until 13 September 2019.

During the year 5,400,000 warrants granted to London Oil & Gas Limited lapsed,

The remaining average contractual life of the 20,000,000 warrants outstanding at 31 December 2020 (2019 - 33,277,310) was 2.66 years at that date (2019 - 2.23 years). All such warrants were exercisable at 31 December 2020.

The weighted average exercise price of the warrants remaining was 32.18p at 31 December 2020 (2019 - 23.21p). No further warrants have been issued or exercised as at 17 March 2021.

21. Restricted cash, Cash and cash equivalents

	2020	2019
Group	£000	£000

Restricted cash	67,049	82,066

Cash at bank	13,389	16,197
Company
Restricted cash	65,699	80,816

Cash at bank	13,389	16,197

Restricted cash at 31 December 2020 includes £67.0 million (2019: £82.0 million) of restricted deposits in Euro escrow and Debt Service Reserve Accounts following the Norwegian Bond issue and a £1.4 million (2019: £1.3 million) deposit secured against decommissioning provisions of its infrastructure assets. Total restricted cash balances for £67.0 million for the Group and £65.7 million for the Company are available within 1 year. The restricted cash balances are subject to agreed milestones set out in the Bond issue document and include;

· Fully utilising the CER Phase 1 carry of £60.0 million This was achieved subsequent to the year end in February 2021

· Completion of construction of the Blythe and Southwark NUI platforms

· Arrival of the drilling rig at its first drilling location

Cash and cash equivalents comprise cash in hand, deposits and other short-term money market deposit accounts that are readily convertible into known amounts of cash. The fair value of cash and cash equivalents is £13.4 million (2019: £16.2 million).

22. Bond payable

On 20 September 2019, the Company issued €100 million Norwegian Bonds on the Oslo Børs to fund the Phase 1 development program.

	2020	2019
	£000	£000

Balance at the beginning of the year	82,423	-
Bonds Issued (€100m)	-	90,439
Transaction fees	-	(2,793)
Amortisation of transaction fees	562	-
Interest charged	8,668	2,545
Interest Paid	(8,668)	(2,545)
Currency revaluation	4,792	(5,223)
	_________	_________
	87,777	82,423
	_________	_________

The secured callable bonds were issued on 20 September 2019 by Independent Oil and Gas plc at an issue price of par. The bonds have a term of five years and will be repaid in full at maturity. The bonds carry a coupon of 9.5% plus 3 month EURIBOR with a EURIBOR floor of 0% and were issued at par.

The Bond is callable 3 years after issuance with an initial call premium of 50% of the coupon (i.e. repayable at a cost of €104.75 million if 3m EURIBOR is at zero or lower), declining by 10% every six months thereafter.

Bond covenants

· Minimum liquidity - €2 million up to, and including, 6 months from the first gas date and €5 million thereafter.

· Minimum leverage ratio - a minimum of 2.5 : 1 from the first reporting date following 6 months after the first gas date.

· Minimum interest cover ratio - a minimum of 5 times cover of interest to EBITDA from the first reporting date following 6 months after the first gas date.

As part of the original Bond issue, the Company has the option to issue a further €30 million of bonds, though these would be at the prevailing market rate at the time of any issue and would not be on any carry any favourable terms to the market pricing at the time.

Full terms and conditions of the Bonds can be seen in 'Bond Terms' document which is publicly available at: https://www.iog.co.uk/media/1237/bond-terms-execution-version-190919.pdf

23. Lease liabilities

	2020	2020
	£000	£000
Current
At 1 January	939	1,054
Interest expenses	381	121
Lease payments	(192)	(236)
Additions	12,653	-
At 31 December	13,781	939

Long term
At 1 January	-	-
Additions	4,968	-
At 31 December	4,968	-

Lease payments represent the Group and Company's share of office lease rental payments at 10 Arthur Street, London and Endeavour House, 189 Shaftesbury Avenue, London, together with the Crown Estate lease for the rights for the Thames Pipeline to cross the foreshore at Bacton. During 2020 the Company signed a drilling rig contract with Noble Corporation for the Noble Hans Deul drilling rig for which payments will commence in 2021.

24. Financial instruments

Significant accounting policies

Details of the significant accounting policies in respect of financial instruments are disclosed in Note 1 of the financial statements.

Financial risk management

The Board seeks to minimise its exposure to financial risk by reviewing and agreeing policies for managing each financial risk and monitoring them on a regular basis. At this stage, no formal policies have been put in place to hedge the Group and Company's activities to the exposure to currency risk or interest risk and no derivatives or hedges were entered during the year.

General objectives, policies and processes

The Board has overall responsibility for the determination of the Group and Company's risk management objectives and policies and, whilst retaining ultimate responsibility for them, it has delegated the authority for designing and operating processes that ensure the effective implementation of its objectives and policies to the Group's finance function. The Board receives regular reports from the Chief Financial Officer through which it reviews the effectiveness of the processes put in place and the appropriateness of the objectives and policies it sets.

The Group is exposed through its operations to the following financial risks:

• Liquidity risk;

• Credit risk;

• Commodity price risk;

• Cash flow interest rate risk; and

• Foreign exchange risk

The overall objective of the Board is to set policies that seek to reduce risk as far as possible without unduly affecting the Group and Company's competitiveness and flexibility. Further details regarding these policies are set out below.

Principal financial instruments

The principal financial instruments used by the Group and Company, from which financial instrument risk may arise are as follows:

• Cash and cash equivalents

• Restricted cash

• Loans

• Other financial assets

• Other receivables

• Trade and other payables

• Convertible loan notes

• Bonds

Liquidity risk

The Group and Company's policy is to ensure that it will always have sufficient cash to allow it to meet its liabilities when they become due. To achieve this aim, it seeks to maintain readily available cash balances supplemented by borrowing facilities sufficient to meet expected requirements for a period of at least twelve to eighteen months for personnel costs, overheads, working capital and as commitments dictate for capital spend.

Rolling cash forecasts, which are essentially the current budgeting and reforecasting process, identifying the liquidity requirements of the Group and Company, are produced frequently. These are reviewed and approved regularly by management and the Board to ensure that sufficient financial resources are made available. The Group's oil and gas exploration and development activities are currently funded through the Company with existing cash balances, Bond proceeds in escrow and joint venture partner carry receipts from CER.

		Greater than	Greater	Total
	6 months	6 months, less	than	undiscounted	Carrying
	or less	than 12 months	12 months		amount
2020 Group	£000	£000	£000	£000	£000


Current financial liabilities
Trade and other payables	5,244	-	-	5,244	5,244
Lease liability	4,631	9,015	-	13,646	13,356
Accruals	3,103	-	-	3,103	3,103


Non-current financial liabilities
Deferred Consideration	-	-	2,370	2,370	2,370
Loans	-	-	11,566	11,566	8,037
Lease liability	-	-	5,616	5,616	4,968
Bonds	4,264	4,264	123,451	131,979	87,777

	________	_________	________	_________	________

	17,242	13,279	143,003	173,524	124,855
	________	_________	________	_________	________

2019 Group


Current financial liabilities
Trade and other payables	3,856	-	-	3,856	3,856
Lease liability	188	158	1,218	1,564	939
Deferred consideration	875	-	-	875	848
Accruals	1,588	-	-	1,588	1,588
Loans	-	-	-	-	-

Non-current financial liabilities
Deferred Consideration	-	-	2,674	2,674	2,267
Loans	-	-	11,566	11,566	6,819
Bonds	4,108	4,108	113,179	121,395	82,424
	________	_________	________	_________	________

	10,615	4,266	128,637	143,518	98,741
	________	_________	________	_________	________

		Greater than	Greater	Total
	6 months	6 months, less	than	undiscounted	Carrying
	or less	than 12 months	12 months		amount
2020 Company	£000	£000	£000	£000	£000


Current financial liabilities
Trade and other payables	1,145	-	-	1,145	1,145
Lease liability	4,631	9,015	-	13,646	13,356
Accruals	1,216	-	-	1,216	1,216


Non-current financial liabilities
Deferred Consideration	-	-	750	750	681
Loans	-	-	11,566	11,566	8,037
Lease liability	-	-	5,616	5,616	4,968
Bonds	4,264	4,264	123,451	131,979	87,777
	________	_________	________	_________	________

	11,256	13,279	141,383	165,918	117,180
	________	_________	________	_________	________
2019 Company


Current financial liabilities
Trade and other payables	3,856	-	-	3,856	3,856
Deferred Consideration	848	-	-	848	848
Accruals	1,240	-	-	1,240	1,240

Non-current financial liabilities
Deferred Consideration	-	-	750	750	644
Loans	-	-	11,566	11,566	6,819
Bonds	4,108	4,108	113,179	121,395	82,424
	________	_________	________	_________	________

	10,052	4,108	125,495	139,655	95,831
	________	_________	________	_________	________

Credit risk

Credit risk arises principally from the Group's and Company's other receivables, restricted cash, cash and cash equivalents, and loans to subsidiaries (Company). It is the risk that the counterparty fails to discharge its obligation in respect of the instrument. The credit risk on liquid funds is limited because the counterparties are banks with credit ratings assigned by international credit rating agencies. The Group places funds only with selected organisations with ratings of 'A' or above as ranked by Standard & Poor's for both long and short-term debt. Funds are currently placed with the National Westminster Bank plc and DNB Bank ASA for the EUR Escrow and DSRA funds. Under IFRS 9 there is no material impact for both the Group and Company when assessing expected credit losses of its receivables.

The Group made investments and advances into subsidiary undertakings during the year and these mostly relate to the funding of the SNS Hub Development Projects, and the Company expects to recover these loans when these Projects start to generate positive cash flows. Loans to subsidiary undertakings are recognised at amortised cost in accordance with IFRS 9. The loans have no maturity date and are not repayable until the respective subsidiary entity has sufficient cash to repay the loan. The Board has accordingly assessed the expected repayment dates based on the strategic forecasts approved by the Board.

As at the reporting date, the Group and Company had £0.9 million external receivables (2019: £1.5 million).

IFRS 9 introduced a new impairment model that requires the recognition of ECLs on financial assets at amortised cost. The ECL computation considers forward looking information to recognise impairment allowances earlier. Intercompany exposures, where appropriate, are also in scope under IFRS 9. The Company assesses the loans made to subsidiary undertakings on the basis of the relevant subsidiaries' long-term strategic forecasts and alongside the Board's commercial rationale for providing the specific loan. The loans are not repayable on demand and are expected to be repaid once the underlying assets progress into the production phase when cash inflows are generated. Based on the methodology set out by the standard, the Board has for each intercompany loan, assessed the probability of the default, the loss given default and the expected exposure to compute the ECLs. The Board has incorporated relevant medium and long-term macroeconomic forecasts in their assessment which is included as a principle consideration in the entity's strategic forecasts. Such factors include oil price sensitivities, funding requirements, reserve and resource estimates. The Board has concluded that any ECLs to be recognised are not material to these financial statements and that there has been no significant increase in credit risk that would warrant the recognition of a material provision. Accordingly, the Company has not recognised any expected credit loss for the balances owed by subsidiary undertakings recognised on the Balance Sheet at amortised cost. The Group and Company do not hold any collateral as security for any external financial instruments, or otherwise.

The maximum exposure to credit risk is the same as the carrying value of these items in the financial statements as shown below.

	Group		Company

	2020	2019	2020	2019
	£000	£000	£000	£000


Other receivables	1,099	1,497	1.099	1,497
Loans to subsidiaries	-	-	45,196	28,710
Restricted cash	67,049	82,066	65,699	80,816
Cash and cash equivalents	13,389	16,197	13,389	16,197

Commodity price risk

The Group currently has not entered into any commodity price hedging instruments.

Although there is no gas production, the Group's asset valuations and cash flow modelling make assumptions on the anticipated gas price for the period of expected production. The Group uses a seasonally adjusted flat pricing structure that is not inflated over the expected production life of the asset.

Cash flow interest rate risk

Save for restricted EUR denominated cash held in escrow and DSRA accounts which attract a nominal negative cost to hold, cash is essentially non-interest bearing. Loans and trade payables are subject only to fixed interest rates; accordingly, commercial interest rates would have no significant impact upon the Group's and Company's result for the year ended 31 December 2020 (nor 31 December 2019).

In relation to the EUR denominated cash held in escrow, which currently attracts a nominal negative cost to hold, a 10% fluctuation in the cost to hold rate (currently 0.612%) would increase/reduce the charge by £52k per annum.

Foreign exchange risk

At 31 December 2020, the Group's and Company's monetary assets and liabilities are denominated in GBP Sterling Euro and US Dollars, converted to GBP the functional currency of the Group and each of its subsidiaries.

The Company holds significant balances (€65.9 million) in EUR from proceeds of the Bond issue, held in escrow. The remaining balances are held in GBP £10.8 million, EUR €2.9 million and USD $0.1 million. This exposure gives rise to net currency gains and losses recognised in the Statement of Comprehensive Income.

A 10% fluctuation in the GBP sterling rate compared to EUR would give rise to a £6.9 million gain or £5.6 million loss in the Group and Company's Statement of Comprehensive Income

The Group has no current revenues. The Group and the Company's cash balances are maintained primarily in GBP Sterling (which is the functional and reporting currency of each Group company) and EUR for the Bond deposits with small balances held in USD to settle any USD liabilities. No formal policies have been put in place to hedge the Group and Company's activities to the exposure to currency risk. It is the Group's policy to ensure that individual Group entities enter transactions in their functional currency wherever possible. The Group considers this minimises any foreign exchange exposure.

Management regularly monitor the currency profile and obtain informal advice to ensure that the cash balances are held in currencies which minimise the impact on the results and position of the Group and the Company from foreign exchange movements.

Capital management

The primary objective of the Group's capital management is to maintain appropriate levels of funding to meet the commitments of its forward programme of appraisal and development expenditure, and to safeguard the entity's ability to continue as a going concern and create shareholder value. The Director's consider capital to include equity as described in the Statement of Changes in Equity, and loan notes, as disclosed in Notes 12 and 20. The Group raised an additional £18.9 million of equity by way of a placement, open offer and subscription in 2019.

The Group manages compliance of the Bond and the covenants by reviewing on a monthly basis its cash flow modelling which incorporates the bond terms and covenants. Norwegian advisors are also engaged to ensure that any regulatory requirements are met. At each reporting date and milestone draw down the Directors provide representation that the terms of the bond are satisfied.

Borrowing facilities

The Group had £95.8 million of borrowings outstanding at 31 December 2020 (2019: £85.0 million).

Hedges

The Group did not hold any hedge instruments at the reporting date (2019: none).

25. Financial commitments and contingent liabilities

	2020	2019
	£000	£000

Authorised but not contracted	118,000	30,066
Contracted	56,758	1,250
	_________	_________

	174,758	31,316
	_________	_________

All 2020 contracted amounts relate to contracted UKCS licence fees and associated OGA levy payments (estimate) together with contracted service awards to suppliers procured for the development of the Group's phase 1 project assets (Blythe, Southwark, Elgood, Thames Reception Facilities and Thames Pipeline).

At the year end, authorised commitments (approved expenditure) to complete the phase 1 project totalled £174.8 million. £56.8 million of the authorised amount had been contracted at 31 December 2020 with the remaining expenditures to be contracted during 2021. All expenditures are shown gross, 100% and have not been scaled back for any joint venture share.

Thames Pipeline:

Security in the sum of £0.5 million, the Initial Thames Decommissioning Pipeline Security Amount, was provided on completion of the Thames Pipeline SPA in April 2018. In October 2019, following the completion of the farm-out to CER, this amount was reduced to £0.25 million.

Further security in the sum of £1.25 million, the Thames Decommissioning Pipeline Security Amount, is to be provided on the earlier of:

· one month after the variation issued by the OGA to the Pipeline Works Authorisation to allow for the tie-in of one or more of the Group's fields; or

· at the date of sale or alternative use of the Thames Pipeline

Thames Reception Facilities ("TRF"):

Security in the sum of £2.0 million, the Initial TRF Decommissioning Security Amount, was provided on completion of the TRF SPA in October 2019. Following the completion of the farm-out to CER, this amount was reduced to £1.0 million.

Further security in the sum of £4.0 million, the TRF Decommissioning Security Amount, is to be provided 2.5 years following the announcement of 'first gas'. This additional amount is payable in 8 quarterly instalments of £0.5 million with the first instalment payable 6 months after the declaration of 'first gas'.

Cross-Guarantees:

The Company acts as guarantor to its subsidiary IOG North Sea Limited and its facilities with LOG. These cross guarantees are considered insurance contracts in accordance with IFRS4.

26. Related party transactions

Details of Directors' and key management personnel remuneration are provided in Note 4.

Andrew Hockey, CEO, at 31 December 2020 held 790,729 ordinary shares of 1p each in the capital of the Company. Andrew is also the current holder of 5,456,410 share options at 31 December 2020 and a further 2,314,166 were granted in February 2021. Andrew was also entitled to 443,448 share options through salary sacrifice at 31 December 2020 and a further 90,291 which at the date of this report have not yet been granted.

Rupert Newall, CFO, and persons closely associated, at 31 December 2020 held 3,767,050 ordinary shares of 1p each in the capital of the Company. Rupert was also the current holder of 2,909,402 share options at 31 December 2020 and a further 1,753,156 were granted in February 2021. Rupert is also entitled to 319,184 share options through salary sacrifice at 31 December 2020 and a further 68,403 which at the date of this report have not yet been granted.

Fiona MacAulay, Chair, at 31 December 2020 held 200,000 ordinary shares of 1p each in the capital of the Company. Fiona is also the current holder of 1,000,000 share options at 31 December 2020. Fiona is also entitled to 34,416 share options through salary sacrifice at 31 December 2020 and a further 30,097 which at the date of this report have not yet been granted.

Esa Ikaheimonen, Non-Executive Director, at 31 December 2020 held 500,000 ordinary shares of 1p each in the capital of the Company. Esa is also the current holder of 600,000 share options at 31 December 2020. Esa is also entitled to 525,359 share options through salary sacrifice at 31 December 2020 and a further 138,805 which at the date of this report have not yet been granted.

Neil Hawkings, Non-Executive Director, is also the current holder of 600,000 share options at 31 December 2020. Neil is also entitled to 28,055 share options through salary sacrifice at 31 December 2020 and a further 12,312 which at the date of this report have not yet been granted.

Details of loans and interest charged (only relevant to 2019) by LOG are detailed in Note 12. The relevant loans outstanding at the end of the year related to the Company.

27. Notes supporting statements of cash flows

Details of significant non-cash transactions

	2020	2019
	£000	£000

Equity consideration for settlement of liabilities	161	624

Group - Loans and borrowings
	Current loans and borrowings £000	Non-current loans and borrowings £000	Total loans and borrowings £000
At 1 January 2019	6,934	22,884	29,818
Drawdowns (Repayments) -	-	3,925	3,925
Lease liability on transition	1,054	-	1,054
Amortisation of finance fees	-	4,213	4,213
Interest accruing in period	528	2,698	3,226
Debt converted into ordinary shares	(3,644)	(8,833)	(12,477)
Repayments	(4,054)	(13,321)	(17,375)
Gain on modification of convertible loan	-	(5,005)	(5,005)
Unwinding of discount	121	259	380
At 31 December 2019	939	6,820	7,759

At 1 January 2020	939	6,820	7,759
Lease Liability additions	12,653	4,968	17,621
Repayments	(192)	-	(192)
Unwinding of discount	381	1,217	1,598
At 31 December 2020	13,781	13,005	26,786

Company - Loans and borrowings
	Current loans and borrowings £000	Non-current loans and borrowings £000	Total loans and borrowings £000
At 1 January 2019	-	14,054	14,054
Drawdowns (Repayments)	-	3,925	3,925
Lease liability on transition	1,054	-	1,054
Amortisation of finance fees	-	3,910	3,910
Gain on modification of convertible loan	-	(5,005)	(5,005)
Unwinding of discount	121	259	380
Repayments	(236)	(12,330)	(12,566)
Interest accruing in period	-	2,007	2,007
At 31 December 2019	939	6,820	7,759
Lease Liability additions	12,653	4,968	17,621
Repayments	(192)	-	(192)
Unwinding of discount	381	1,217	1,598
At 31 December 2020	13,781	13,005	26,786

28. Subsequent events

The key events after 31 December 2020 are as follows:

On 28 January 2021 the Company announced it had awarded 8,578,907 ordinary shares at 1p to Executive Directors and staff under its Company Share Ownership Plan.

On 3 February 2021, the Company drew down €27.3 million from the escrow funds account after completing the third milestone event (exhaustion of the Phase 1 CER carry) of the terms of the bond.

On 10 March 2021, OG North Sea Limited received confirmation from the OGA of partial relinquishment of the P2085 (Harvey) licence, maintaining 16.5 km2, and fully determining the P2441 (Redwell) licence.

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