Full Year Results

RNS Number : 5939U

Igas Energy PLC

07 April 2021

THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION.

7 April 2021

IGas Energy plc (AIM: IGAS)

("IGas" or "the Company" or "the Group")

Full year results for the year ended 31 December 2020

IGas announces its full year results for the year ended 31 December 2020.

Results Summary

	Year ended 31 Dec 2020 £m	Year ended 31 Dec 2019 £m
Revenues	21.6	40.9
Adjusted EBITDA¹	4.0	13.8
Loss after tax	(42.1)	(49.8)
Operating cash flow before working capital adjustments	3.3	14.3
Net debt²	12.2	6.2
Cash and cash equivalents	2.4	8.2

Notes

¹ Adjusted EBITDA is considered by the Company to be a useful additional measure to help understand underlying performance.

² Net debt is borrowings less cash and cash equivalents excluding capitalised fees

Operational Summary

· Net production averaged 1,907 boepd for the year (2019: 2,325 boepd), within revised guidance, while operating costs for the year were c.$33/boe (at an average 2020 exchange rate of £1:$1.29) (2019: c.$30/boe).

· In 2021, we anticipate net production of between 2,150-2,350 boepd and operating costs of c.$32/boe (assuming an exchange rate of £1:$1.35), albeit subject to the ongoing challenges that COVID-19 presents.

· Reserves and resources upgraded in DeGolyer & MacNaughton (D&M) CPR as at 31 December 2020 - IGas net reserves and resources (MMboe)*

	1P	2P	2C
As at 31 Dec 2019	10.55	16.05	19.51
As at 31 Dec 2020	11.74	17.12	20.35

o 2P reserves replacement ~ 250% (1P ~275%)

o 1P NPV10 of $150 million: 2P NPV10 of $204 million*

*based on forward oil curve of: 2021 $53/bbl; 2022 $56/bbl; 2023 $58/bbl; 2024 $59/bbl; 2025 $62/bbl (for full price deck see CPR).

· Planning for Stoke-on-Trent geothermal project granted by Newcastle-under-Lyme, awaiting Stoke-on-Trent approval.

· The Renewable Energy Association (REA) and ARUP will launch a report in April 2021 into the economic opportunity of harnessing deep geothermal energy to solve the decarbonisation of heat in the UK.

· First sites for hydrogen production in South-east England identified

· Planning submissions Q2/3 2021

· Final Investment Decision to follow within 3 months of planning approval

· First production of hydrogen could be in 2022

Corporate and Financial Summary

· Successful redetermination under the Group's Reserve Based Lending facility (RBL) at 31 December 2020 confirming $31.7 million (£24.0 million) of debt capacity and headroom of $11.7 million (£8.9 million).

· Cash balances as at 31 December 2020 of £2.4 million and net debt of £12.2 million.

· The Group invested £8.5 million across its asset base during the year (2019: £6.4 million). Budgeted capex for 2021 is £5.3 million.

· Underlying loss of £2.7 million (2019: profit £4.6 million). Loss after tax of £42.1 million (2019: loss £49.8 million) due to an impairment of £38.5 million of oil and gas assets (2019: impairment of £53.9 million primarily relating to our shale assets) being recognised on oil and gas assets due to lower oil price forecasts. Ring fence tax losses of £256 million as at 31 December 2020.

· As at 31 December 2020, the Group had hedged a total of 369,600 bbls for 2021, using a combination of collars (166,800 bbls at an average downside protected price of $43.0/bbl) and fixed price swaps (202,800 bbls at an average fixed price of $44.7/bbl).

· Foreign exchange hedges in place at 31 December 2020 of $3 million for 2021 at an average rate of $1.20:£1.

Commenting today Stephen Bowler, Chief Executive Officer, said:

"2020 was an exceptionally difficult year for everyone. Despite these highly challenging circumstances, the Company has continued to make progress in a number of key areas and continues to adapt its business to operate, both in the current environment, and to develop its business strategies to deliver a long-term and sustainable business.

We still retain a sharp focus on costs and conserving cash but as commodity prices improve we will continue to invest in our assets where appropriate and to move ahead purposefully with our geothermal and hydrogen projects ."

A results presentation will be available at http://www.igasplc.com/investors/presentations.

Ross Pearson, Technical Director of IGas Energy plc, and a qualified person as defined in the Guidance Note for Mining, Oil and Gas Companies, March 2006, of the London Stock Exchange, has reviewed and approved the technical information contained in this announcement. Mr Pearson has 20 years oil and gas exploration and production experience.

For further information please contact:

IGas Energy plc Tel: +44 (0)20 7993 9899

Stephen Bowler, Chief Executive Officer

Ann-marie Wilkinson, Director of Corporate Affairs

Investec Bank plc (NOMAD and Joint Corporate Broker) Tel: +44 (0)20 7597 5970

Sara Hale/Jeremy Ellis/Virginia Bull

Canaccord Genuity (Joint Corporate Broker) Tel: +44 (0)20 7523 8000

Henry Fitzgerald-O'Connor/James Asensio

Vigo Communications Tel: +44 (0)20 7390 0230

Patrick d'Ancona/Chris McMahon/Charlie Neish

Chairman's Statement

At the time of writing, England is slowly emerging from its third national lockdown in less than 12 months. This reporting period has seen extraordinary challenges for individuals and businesses alike, as we all respond to the global public health emergency - COVID-19 - which has impacted, and continues to impact, all aspects of our lives.

As the scale and seriousness of the COVID-19 pandemic emerged, the initial focus and principal concern for the Company was, and remains, the health and safety of its employees, contractors, and communities. In this regard, all office-based employees have been working from home where possible since March 2020. The Company has established procedures and plans to ensure the continued safe operation of its production sites whilst adapting operations to enable and implement social distancing. Oil and gas workers are classified as 'key workers', recognising the importance of maintaining oil and gas supply to meet the UK's energy demands.

The oil price had already been impacted early in the year by OPEC's failure to reach an agreement on supply. The end of the first quarter saw a further significant reduction in commodity prices, principally due to COVID-19 related drop in demand for oil and gas, which affected both our revenues and profitability. We took swift action to reduce costs and preserve cash in the business always being mindful of the longer-term effects those measures may have.

Despite these highly challenging circumstances, the Company has continued to make progress in a number of key areas and continues to adapt its business to operate, both in the current environment, and to develop its business strategies.

In 2020, we delivered production within the revised guidance, brought our waterflood projects online, which will bring increased production in 2021 and beyond, and completed a significant transaction with the acquisition of the geothermal energy developer, GT Energy (GTE).

The geothermal acquisition is a major strategic milestone for IGas. It provides us with an exciting entry point into this highly attractive growth market, one that has seen material progress in Europe over the past five years. The decarbonisation of electricity generation has already made significant steps forwards with renewables and gas replacing coal. The next significant area that must be addressed, namely to achieve the UK's net zero ambitions, is the decarbonisation of heat. We anticipate that this will dramatically increase the development of deep geothermal heating plants in the UK and across Europe.

There are considerable growth opportunities for IGas as we continue to look at ways of maximising returns from our existing operations and engineering expertise, repurposing our extensive infrastructure and seeking to high-grade potential opportunities for other forms of energy, including electricity generation and storage.

In October 2020, we announced a partnership with BayoTech, a leading technologies business in hydrogen generation systems. We have identified existing sites where the gas resource can be reformed into hydrogen which will then be sold to local or national customers.

In November 2020, the Government announced its "Ten Point Plan" for a green industrial revolution setting out a roadmap for the country's economic recovery: Building back better, supporting green jobs, and accelerating our path to net zero. We welcomed the long awaited Energy White Paper which was released the following month which acknowledges that the UK's domestic oil and gas industry has a critical role in maintaining the country's energy security and is a major contributor to the economy.

The projection for demand for oil and gas, though much reduced, is still forecast to continue for decades to come and whilst Government stresses the importance of sourcing lower emission fuels, it does not tackle the issue of growing imports of oil and gas. According to the most recent analysis by the Climate Change Committee (CCC) for the Sixth Carbon Budget using their 'Balanced' and 'Headwinds' scenarios, import dependencies will rise to between 61% and 83% for gas and up to 40% for oil by 2050.

As we broaden our energy portfolio, engaging effectively with all our stakeholders helps inform our future plans. Listening and responding to the views of communities, regulators, policy makers and shareholders helps us better refine our business objectives and deliver value. A sustainable and responsible company is one that is committed to protecting and enhancing the wider environment and working with communities to provide them with lasting socio-economic benefits. Last year, we aligned ourselves with a number of the UN Sustainable Development Goals and we will continue to develop and grow our environmental KPIs.

Despite the significant challenges the pandemic has presented us with, IGas's operations were safe and environmentally responsible. It is a reflection of our high standards that led to us again receiving the RoSPA President's Award, representing 14 consecutive years of commitment to Occupational Health and Safety. Our ISO9001 and ISO14001 accreditation was also renewed during 2020, important benchmarks in managing our production processes and environment responsibilities.

People

The great majority of IGas staff who are able to work from home are still doing so and appropriate precautions in operations and offices have been implemented.

I am deeply impressed by the resilience our people have shown as we have adapted to new ways of working, while retaining an unrelenting focus on safety and delivery. I want to thank each and every one of our hardworking colleagues for their commitment and determination during such a tough year.

Outlook

The ongoing impacts of the COVID-19 pandemic continue to present a volatile and challenging trading environment. Whilst the International Energy Agency expects a strong oil price recovery in the second half of 2021, it has warned that fresh restrictions related to the SARS-CoV-2 virus will depress demand in the short term.

We remain firmly focused on cost and capital discipline, controlling what is within our power in the near-term, whilst still continuing to build our business for the future. Given that the shape and pace of economic recovery is uncertain, it would be imprudent to rule out future impacts on the business.

That said, we will continue to invest in our existing assets where appropriate to realise future benefits and to move ahead purposefully with our geothermal and hydrogen projects. What is clear, is that the UK has set out a pathway to net zero and recognising there is a role for oil and gas, as part of that evolution, IGas is committed to maximise the value of its extensive skillset and existing infrastructure to further progress its own energy transition pathway.

Chief Executive's Statement

Introduction

The announcement by the World Health Organisation in March 2020, declaring the coronavirus outbreak a pandemic was an intensely sobering moment for everyone. As a company, we made clear from the outset that our overriding priority was the health and safety of all our employees, contractors and other visitors to sites, maintaining operations and supporting the safe and reliable production of energy.

Like every other company operating in the UK, we are not immune from the wider economic impacts of coronavirus and the significant reduction in global demand for oil and gas impacted our financial results. It is our job to guide the Company through this continued period of uncertainty and ensure it is well-placed for the economic recovery when it comes.

We moved quickly to mitigate the immediate impacts of COVID-19 and the fall in oil price by shutting in sites to preserve cash and as low commodity prices continued we undertook a further, in-depth review of costs. The outcome of that exercise resulted in a redundancy programme, salary replacement for the Board and senior executives, and a reduction in benefits across the organisation. These measures, coupled with the cost savings made in the first half of the year, have amounted to a cash saving in 2020 of £0.6 million. Further savings of £1.0 million are expected in 2021. We vacated our London premises at the earliest opportunity, at the end of March 2021, and until there is more certainty, our London based employees will continue to work remotely.

2020 was a pivotal year for the company. Last year, I outlined our desire to position IGas to deliver a variety of energy sources to the UK and, in September, we took a bold step in realising that aspiration by acquiring a deep geothermal development business. We also took our first steps to allow us to advance hydrogen production opportunities through the partnership agreement we announced in October 2020, with BayoTech. This will enable us to monetise stranded gas reserves and increase the value of the gas we produce, whilst pioneering the use of small-scale steam methane reformation (SMR) equipment in the UK.

During the year, as part of our approach to responsible and sustainable development we undertook to align ourselves to a number of the United Nation's Sustainable Development Goals. We recognise the need to reduce greenhouse gas (GHG) emissions and strive to reduce them through new initiatives, including the installation of best available technology to all new projects to minimise their carbon intensity.

Operating Review

Production

Net production for the period averaged 1,907 boepd, in line with our revised forecast of 1,850 - 2,050 for the full year. We anticipate net production in 2021 of between 2,150 boepd and 2,350 boepd, assuming there are no further significant disruptions to our business from COVID-19.

In May 2020, when the oil price was trading at c.$25/bbl, we announced a temporary shut-in of a number of fields for the months of May and June. The impact of the shut-ins was a reduction in production by c.600 boepd for this period. This action had a positive impact on cash flow during these two months of c.£0.5 million. Those employees that were impacted by the shut-ins were furloughed in line with the Government scheme.

We have, since then, returned all but two fields back to production following improvements in the oil price. As the majority of our sites are 100% owned and operated by us, it gave us the flexibility to take shut-in decisions quickly and the ability to rapidly restore production, at some of our fields, once energy prices improved.

Given the fall in oil prices, we reviewed our capital expenditure programme for the year and reduced it broadly by half to focus on maintenance capex, abandonment and capital for projects already in execution which amounted to £6.0 million. IGas retains significant flexibility over its capital expenditure, and will ensure that as we move forward, expenditure commitments are appropriate in the macro environment.

It is our highest priority to continue to operate all of our assets in a safe and responsible manner, to ensure the safety of our workforce and communities in which we work and to minimise the potential risk to the environment. Throughout 2020, we worked closely with all our regulators to ensure we met the stringent guidelines in respect to COVID-19.

Reserves and Resources

In February 2021, IGas announced the publication of the Competent Persons Report (CPR) by DeGolyer & MacNaughton (D&M), a leading international reserves and resources auditor.

The report comprised an independent evaluation of IGas conventional oil and gas interests as of 31 December 2020. The full report can be found on the IGas website www.igasplc/investors/publications-and-reports

IGas Group Net Reserves & Contingent Resources as at 31^st Dec 2020 (MMboe)

	1P	2P	2C
Reserves & Resources as at 31^st Dec 2019	10.55	16.05	19.51
Production during the period	(0.68)	(0.68)	-
Revision of estimates	1.87	1.75	0.84
Reserves & Resources as at 31^st Dec 2020	11.74	17.12	20.35

The report confirms a continuing high reserves replacement of 2P reserves of approximately 250% reflecting the good performance of our production assets and progression of projects demonstrating the significant upside that remains in our conventional portfolio. Some 75% of the 2P is developed meaning it does not require any capital investment to produce.

IGas has a track record of significant reserves replacement with a three-year average of over 200%.

This independent report valued our conventional assets at c.$204 million on a 2P NPV10 basis: 1P NPV10 of $150 million (based on forward oil curve of 2021 $53/bbl; 2022 $56/bbl; 2023 $58/bbl; 2024 $59/bbl; 2025 $62/bbl).

Development

Conventional

In spite of the considerable challenges related to the COVID-19 pandemic, we commenced water injection at our Scampton North site on schedule and on budget in July 2020. As well as increasing oil production, the in-field pipeline and a new processing facility at the Scampton North C-Site will provide greater efficiency and environmental improvements by reducing venting, the need to truck water to the Welton Gathering Centre, as well as increasing the amount of gas available for power generation. The latest D&M CPR estimates this project will increase production from the Scampton field by 180 Mbbl (2P-Proved plus Probable reserves) and our mid-case economics for the project have an IRR of over 40% and a NPV of £2.5 million (which assumes a long-term oil price of $55/bbl).

Our second waterflood opportunity in the southern section of the Welton Field experienced delays predominantly with the supply chain and resource availability due to the pandemic, however, the project was brought online in January 2021, slightly behind our planned initial production of Q4 2020 and largely in line with budget. This is a material project in IGas's inventory, developing approximately 660 Mbbl of 2P reserves and adding over 100 bopd incremental production with a base case NPV10 of c.£7 million (assuming a long-term oil price of $55/bbl).

Both these projects are important advancements in developing the Company's 2P reserves.

Work on other projects, to appraise the potential that exists in our prospective resources such as the prospect at Godley Bridge in the South-east, will ramp-up again once there is more certainty in energy prices.

Gas from Shale

The effective moratorium on high volume hydraulic fracturing for shale-gas, that was introduced by the Government in November 2019, remains in place until new evidence is provided. IGas, along with its industry peers, continues to be committed to working closely with the OGA and other regulators to demonstrate that we can operate safely and in an environmentally responsible manner, and we remain confident of doing so by adopting a rigorous scientific approach.

It is worth noting that the Gainsborough Trough, where our world-class Springs Road gas asset is situated, is characterised by its structural simplicity and limited faulting. This has been confirmed by the recent reinterpretation of the 69 sq km reprocessed 3D seismic data around the Springs Road area which was originally acquired in 2014.

In November 2020, IGas submitted a Section 73 Planning Application to vary a condition of our existing Planning Permission in order to extend the operational period of the site for a further three years. The application was validated by Nottinghamshire County Council the same month.

Ellesmere Port Appeal

Our application to conduct a well test at our existing Ellesmere Port well, originally drilled in November 2014, was submitted on 21 July 2017. Following the Planning Committee's refusal against Officer recommendation in January 2018, a 12-day Planning Appeal was held between 15 January 2019 and 6 March 2019. The Secretary of State recovered the appeal on 27 June 2019. Some 21 months later and 44 months after the initial application, a decision is still awaited, despite the Written Ministerial Statement in May 2018 committing to a rapid turnaround in decisions.

Geothermal

Despite the challenges the pandemic has presented, we completed a significant transaction with the acquisition of the geothermal developer, GTE. This equity-funded deal was a major strategic milestone for the Company given our intention to play an important role in the UK's energy transition and is a logical step given the development and operational synergies with our onshore business.

There are many synergies between our existing skill sets. Essentially this is a very similar process in terms of geological interpretation, drilling, completion and facility design; we are just looking for a different resource, a permeable heat reservoir.

GTE's principal project is a 14MW deep geothermal project in the Etruria Valley, Stoke-on-Trent. The project is anticipated to supply zero carbon heat to the city of Stoke-on-Trent on a long-term 'take or pay' contract with Stoke-on-Trent City Council (SoTCC). It is anticipated that the heat will be supplied through the SoTCC owned and operated district heating network, which is undergoing installation. All the geophysical work on the project is complete and the necessary permitting in place. We await the grant of the renewed planning permission.

Like many other things however, COVID-19 has taken its toll on the project and this has meant that all construction of the heat network has paused and the TPA (thermal purchase agreement) has not been completed. However, in an effort to progress the project, we have entered into discussions with the council and Engie to deliver the project. This structure would take all financial risk away from the council and allow the project to proceed at a faster pace.

Discussions with Government regarding future financial support for renewable heat from geothermal beyond the closure of the Non-domestic Renewable Heat Incentive on 31 March 2021, are both ongoing and positive.

The Renewable Energy Association (REA) and ARUP supported by GTE and other industry players will launch a report in April 2021 into the economic opportunity of harnessing deep geothermal energy to solve the decarbonisation of heat in the UK. The report will highlight the significant geothermal resource that exists within the UK and show how other European countries with similar resources have been successful in exploiting their resources. A number of MP's have already indicated their support for developing an industry to harness geothermal.

We have identified a number of strategic geothermal development locations across the UK and are working at converting these into a development pipeline of projects. Areas include Newcastle, Crewe, and Southampton.

Hydrogen

In October 2020, IGas announced that it had entered into a partnership agreement with BayoTech, a manufacturer of modular SMR equipment.

BayoTech, whose high efficiency, low carbon technologies originated in Sandia National Laboratories, is a hydrogen generation technology company offering hydrogen production solutions through rentals, leases, sales and gas as a service to customers worldwide. Headquartered and produced in New Mexico, USA, BayoTech's on-site hydrogen generators are more efficient than legacy SMRs, leading to lower carbon emissions and low-cost hydrogen. In January 2021, BayoTech received an equity investment of up to $157 million from Newlight Partners LP, to accelerate its strategic growth.

The company's intent is to utilise this equipment to produce high quality hydrogen from its gas producing assets and from stranded gas assets.

IGas has initially identified two of its existing sites, in the South-east, where the gas resource can be reformed into hydrogen which will then be sold to local or national customers. We expect to advance these projects in 2021.

Outlook

Given the rapidly changing environment that the COVID-19 pandemic has created, it is still difficult to forecast with accuracy the full extent of the pandemic's impact on business. However, through all of this, the underlying operations of the company remained safe and steadfast, and projects continued to be brought online. None of this could have been achieved without the commitment and resilience of all our teams.

I am excited about the various energy transition opportunities that we have identified in our existing and new businesses. Our land portfolio is well suited to the development of renewable and hybrid flexible power generation and our assets have the potential for carbon storage close to emitters.

The British Geological Survey recently estimated that geothermal energy resources in the UK are sufficient to deliver about 100 years of heat supply for the entire UK. The publication of the UK Government's Ten Point Plan and Energy White Paper provides a strong platform for our geothermal business to contribute significantly towards the decarbonisation of large-scale heat.

We look forward to advancing these and other opportunities that will allow IGas to make material contributions to the Green Energy Revolution whilst continuing to maximise returns from our conventional portfolio given the clear need for oil and gas in a 2050 net zero environment.

Financial Review

During 2020, the average monthly price of Brent crude ranged between $16/bbl and $70/bbl. The lower average price of $42/bbl for the year versus $64/bbl for 2019 had a negative impact on our revenues. The average GBP/USD exchange rate for the year was broadly in line with the previous year at £1: $1.29 (2019: £1: $1.28).

For the year ended 31 December 2020 adjusted EBITDA was £4.0 million (2019: £13.8 million) whilst a loss was recognised from continuing activities after tax of £42.1 million (2019: loss £49.8 million). The main factors driving the movements between the years were as follows:

· Revenues decreased to £21.6 million (2019: £40.9 million) principally due to lower oil prices and a 17% decrease in oil sales volumes as a number of sites were shut-in for a period due to the impact of COVID-19. This was partially offset by a realised gain on oil price hedges of £4.6 million;

· Other costs of sales decreased to £17.5 million (2019: £20.5 million). Operating costs were £3.0 million lower than the prior year as the decision to temporarily shut in a number of sites led to lower production, transportation and maintenance costs;

· DD&A decreased to £6.0 million (2019: £9.1 million) due to lower production volumes and the impact of an increase in reserves on the depletion rate;

· Administrative expenses increased by £0.8 million to £5.3 million (2019: £4.5 million). Savings during the year following cost saving measures were offset by redundancy costs of £0.6 million, one-off acquisition costs related to GTE of £0.2 million and lower allocation to capital projects and lower recoveries from partners due to lower activity during the year;

· An impairment of £38.5 million (2019: nil) was recognised on oil and gas assets due to lower oil price forecasts. Exploration and evaluation assets of £0.1 million were written off during the year (2019: £53.9 million written off primarily relating to our shale assets in the North West following the effective moratorium on fracking in England);

· Net finance costs decreased to £2.2 million (2019: £3.4 million) due to lower borrowings combined with lower interest costs following the refinancing in October 2019 and gains on foreign exchange; and

· A tax credit of £2.0 million was recognised mainly due to adjustment to losses brought forward due to Ring Fence Expenditure Supplement claims (2019: £9.3 million recognised due to the recognition of a deferred tax asset relating to ring-fence tax losses).

Income statement

The Group recognised revenues of £21.6 million for the year (2019: £40.9 million). Group production for the year averaged 1,907 boepd (2019: 2,325 boepd). Revenues included £1.1 million (2019: £2.4 million) relating to the sale of third party oil, the bulk of which is processed through our gathering centre at Holybourne in the Weald Basin.

The average pre-hedge realised price for the year was $39.1/bbl (2019: $61.7/bbl) and post-hedge $48.4/bbl (2019: $60.1/bbl). A gain of £4.6 million was realised on hedges during the year due to a successful hedging programme. (2019: realised loss of £1.0 million). The average GBP/USD exchange rate for the year was £1: $1.29 (2019: £1: $1.28).

Cost of sales for the year were £23.5 million (2019: £29.6 million) including depreciation, depletion and amortisation (DD&A) of £6.0 million (2019: £9.1 million), and operating costs of £17.5 million (2019: £20.5 million). Operating costs were £3.0 million lower than the prior year due to decrease in production and transportation costs of $1.4 million and maintenance costs of $0.6 million. Operating costs include a cost of £1.0 million (2019: £2.2 million) relating to third party oil. The contribution received from processing this third party oil was £0.1 million (2019: £0.2 million).

Operating costs per barrel of oil equivalent (boe) were £25.8 ($33.3), excluding third party costs (2019: £23.6 ($30.1) per boe). Savings in absolute operating costs were offset by lower production volumes.

Adjusted EBITDA in the year was £4.0 million (2019: £13.8 million). The gross loss for the year was £1.9 million (2019: gross profit of £11.3 million).

Administrative costs increased by £0.8 million to £5.3 million (2019: £4.5 million). A cost saving programme reduced costs by c.£0.6 million net of redundancy costs of £0.6 million. However, net administrative costs increased due to lower allocation to capital projects and lower recoveries from partners due to lower activity during the year. The Group also incurred costs related to the acquisition of GTE of £0.2 million.

An impairment of £38.5 million was recognised on oil and gas assets during the period (2019: £nil) primarily as a result of lower oil price forecasts. The future cash flows were estimated using price assumptions for Brent of $50-55/bbl for the years 2021-2022 and $60/bbl thereafter. Management also performed sensitivity analysis on the key assumptions. See note 8 for further details.

Exploration and evaluation assets of £0.1 million were written-off during the year (2019: £53.9 million written off primarily relating to our shale assets in the North West following the effective moratorium on fracking in England).

Net finance costs were £2.2 million (2019: £3.4 million) primarily related to interest on borrowings of £1.3 million (2019: £1.9 million) and the unwinding of discount on provisions of £1.5 million (2019: £1.3 million), offset by a net foreign exchange gain of £1.5 million, principally on US dollar denominated debt and US dollar bank balances and a successful foreign exchange hedging programme (2019: gain £0.3 million). Interest on leases was £0.8 million (2019: £0.7 million).

The Group recognised a net gain on oil price derivatives of £3.5 million for the year (2019: loss £3.3 million) and a gain on foreign exchange hedges of £0.2 million (2019: gain £0.3 million).

A tax credit of £2.0 million was recognised mainly due to the adjustment to losses brought forward due to Ring Fence Expenditure Supplement claims (2019: a tax credit of £9.3 million mainly due to the recognition of a deferred tax asset relating to ring-fence tax losses).

Cash flow

Net cash generated from operating activities for the year was £3.6 million (2019: £12.0 million). The decrease was primarily due to lower revenue, net of realised hedge income, and working capital movements. The decrease was partially offset by cost savings.

The Group invested £8.5 million across its asset base during the year (2019: £6.4 million). £6.2 million was invested in our conventional assets primarily on the Scampton North and Welton waterflood projects and to optimise existing facilities and systems. £2.3 million, net of recoveries from our joint venture partners, was invested in progressing the Group's shale programme and on working up additional exploration opportunities on conventional assets.

The Group spent £1.3 million on its abandonment programme during the year (2019: £1.8 million).

The Group made a net drawdown of £0.9 million ($1.0 million) under its Reserve Based Lending facility (the RBL) and paid £0.9 million ($1.2 million) in loan interest (2019: £2.0 million ($2.6 million)).

To protect against the volatile oil price, the Group places commodity hedges for a period of up to 12 months. As at 31 December 2020, the Group had hedged a total of 369,600 bbls for 2021, using a combination of collars (166,800 bbls at an average downside protected price of $43.0/bbl) and fixed price swaps (202,800 bbls at an average fixed price of $44.7/bbl).

Cash and cash equivalents were £2.4 million at the end of the year (2019: £8.2 million).

Balance sheet

Net assets decreased by £39.8 million to £73.3 million at 31 December 2020 (2019: £113.1 million), mainly related to an impairment of oil and gas assets of £38.5 million (2019: nil).

The Group recognised an intangible development asset of £3.2 million on the acquisition of GT Energy UK Limited in September 2020.

The Group also recognised an increase in the net deferred tax asset of £2.0 million due to a decrease in accelerated capital allowances liability offset by a decrease in losses recognised (2019: increase in net deferred tax asset of £9.3 million).

Changes to the estimate of decommissioning costs following an internal review increased both assets and liabilities by £6.2 million (2019: increase of £7.7 million).

At 31 December 2020, right of use assets capitalised was £7.7 million (2019: £7.7 million) and lease liabilities increased to £7.5 million (2019: £7.2 million).

At 31 December 2020, the Group has a combined carried gross work programme of up to $218 million (£160 million) (2019: $214 million (£161million)) from its partner, INEOS Upstream Limited. In 2020, £0.4 million (2019: £7.3 million) gross costs were carried, principally in relation to activities at Springs Road, which have not been included in the additions to intangible exploration and evaluation assets during the year.

Borrowings increased from £13.1 million to £13.7 million due to net drawdowns of £0.9 million, offset by a revaluation gain of £0.6 million and amortisation of capitalised fees of £0.3 million.

Net debt at the year-end, being the nominal value of borrowings less cash and cash equivalents, was £12.2 million (2019: £6.2 million).

	31 December 2020	31 December 2019
	£m	£m
Debt (nominal value excluding capitalised expenses)	(14.6)	(14.4)
Cash and cash equivalents	2.4	8.2
Net Debt	(12.2)	(6.2)

Principal risks and uncertainties

The Group constantly monitors the Group's risk exposures and reports to the Audit Committee and the Board on a regular basis. The Audit Committee receives and reviews these reports and focuses on ensuring that the effective systems of internal financial and non-financial controls including the management of risk are maintained. The results of this work are reported to the Board which in turn performs its own review and assessment.

The principal risks for the Group can be summarised as:

· Strategy fails to meet shareholder expectations;

· Planning, environmental, licensing and other permitting risks associated with its operations and, in particular, with drilling and production operations;

· Climate change risks that causes changes to laws, regulations, policies, obligations and social attitudes relating to the transition to a lower carbon economy which could have a cost impact or reduced demand for hydrocarbons for the Group and could impact our strategy;

· Cyber security risk that gives exposure to a serious cyber-attack which could affect the confidentiality of data, the availability of critical business information and cause disruption to our operations;

· No guarantee can be given that oil or gas can be produced in the anticipated quantities from any or all of the Group's assets or that oil or gas can be delivered economically;

· Development of shale gas resources not successful;

· Loss of key staff;

· Market price risk through variations in the wholesale price of oil in the context of the production from oil fields it owns and operates;

· Market price risk through variations in the wholesale price of gas and electricity in the context of its future unconventional production volumes;

· Exchange rate risk through both its major source of revenue and its major borrowings being priced in US$ while most of the Group's operating and G&A costs are denominated in UK pounds sterling;

· Liquidity risk through its operations;

· Capital risk resulting from its capital structure, including operating within the covenants of its RBL facility;

· Political risk such as change in Government or the effect of local or national referendum; and

· Pandemic that impacts the ability to operate the business effectively.

Going Concern

The Group continues to closely monitor and manage its liquidity risks. Cash flow forecasts for the Group are regularly produced based on, inter alia, the Group's production and expenditure forecasts, management's best estimate of future oil prices, management's best estimate of foreign exchange rates and the Group's available loan facility under the RBL. Sensitivities are run to reflect different scenarios including, but not limited to, possible further reductions in commodity prices, strengthening of sterling and reductions in forecast oil and gas production rates.

The ability of the Group to operate as a going concern is dependent upon the continued availability of future cash flows and the availability of the monies drawn under its RBL, which is re-determined semi-annually based on various parameters (including oil price and level of reserves) and is also dependent on the Group not breaching its RBL covenants. Whilst we have better financial flexibility and a reduced overall cost of debt under the RBL and have successfully completed the 2020 year-end re-determination, we have re-evaluated our priorities in the short-term to ensure we weather both any oil price weakness and other impacts of COVID-19, including potential disruption to the Group's operational activities which could impact earnings, cash flows and financial condition of the Group.

Management has also considered the impact of the COVID-19 global crisis on the Group's operations. We continue to monitor the situation closely and act within Government guidelines and have a number of contingency plans in place should our operations be significantly affected by the coronavirus. Many of our sites are remotely manned and at this stage we are well equipped as a business to ensure we maintain business continuity. Our production comes from a large number of wells in a variety of locations and we have flexibility in our off-take arrangements. We continue to liaise and co-operate with all the relevant regulators.

The Group's base case cash flow forecast was run with average oil prices of $61/bbl for 2021 and $58/bbl in 2022, with a foreign exchange rate of $1.40/£1 during the period. Our modelling included the benefits of the Group's commodity hedging policy with 369,600 bbls hedged at an average minimum price of $44/bbl. Our forecasts show that the Group will have sufficient financial headroom to meet its financial covenants based on the existing RBL facility. Given the uncertainties described above, the level of Group revenues and availability of facilities under the RBL are inherently uncertain. As such, management has also prepared a downside forecast with average oil prices at $63/bbl in the second quarter of 2021 and have then modelled in a sudden crash in price to $43/bbl in July 2021 with prices remaining at that level for a year before increasing to $45/bbl in July 2022. Our downside case also included an average reduction in production of 5% over the period and a strengthening of sterling against the US dollar with rates moving to $1.45 by October 2021 and remaining at this level for 2022. To manage the impact of the downside scenario modelled, management would take mitigating actions, including further commodity hedging, delaying capital expenditure and additional reductions in costs in order to remain within the Group's debt liquidity covenants. All such mitigating actions are within management's control. In the downside case, management would also consider additional cash generating opportunities for the Group. While management acknowledges that these may not be completely in our control, we have assumed that cash flow from some of these opportunities would be available in 2022. In this downside scenario, our forecast shows that the Group will have sufficient financial headroom to meet its financial covenants for the 12 months from the date of approval of the financial statements. However, should oil price or demand (and therefore revenue) fall below our downside scenario oil price forecast, the Group may not have sufficient funds available for 12 months from the date of approval of these financial statements.

As a result, at the date of approval of the financial statements, there continues to be a material uncertainty in respect of the potential impact of COVID-19 on the Group's operational activities and future commodity prices. These material uncertainties may cast significant doubt upon the Group's ability to continue as a going concern. Notwithstanding these material uncertainties, the Directors have a reasonable expectation that the Group has adequate resources to continue in existence for the foreseeable future and have concluded it is appropriate to adopt the going concern basis of accounting in the preparation of the financial statements. The financial statements do not include the adjustments that would result if the Group was unable to continue as a going concern.

Stephen Bowler

Chief Executive Officer

Adjusted EBITDA and underlying operating (loss)/profit

Adjusted EBITDA and underlying operating (loss)/profit are considered by the Company to be useful additional measures to help understand underlying performance.

Adjusted EBITDA
	2020	2019
	£m	£m
Loss before tax	(44.1)	(59.1)
Net finance costs	2.2	3.4
Loss on refinancing	-	0.7
Changes in fair value of contingent consideration	0.2	-
Depletion, depreciation & amortisation	6.3	9.2
Impairments/write offs	38.6	58.7
EBITDA	3.2	12.9
Lease rentals capitalised under IFRS 16	(1.8)	(2.0)
Share-based payment charge	1.0	0.8
Unrealised loss on hedges	0.8	2.1
Redundancy costs	0.6	-
Acquisition costs	0.2	-
Adjusted EBITDA	4.0	13.8

Underlying operating (loss)/profit
	2020	2019
	£m	£m
Operating loss	(42.1)	(55.0)
Operating lease rentals capitalised under IFRS 16	(1.8)	(2.0)
Share-based payment charge	1.0	0.8
Impairments/write-offs	38.6	58.7
Unrealised loss on hedges	0.8	2.1
Redundancy costs	0.6	-
Acquisition costs	0.2	-
Underlying operating (loss)/profit	(2.7)	4.6

Realised Price Per Barrel
	2020	2019
	$	$
Realised price per barrel	48.4	60.1
G&A per BOE	10.3	7.0
Other operating cost (underlying)	24.3	22.2
Well services	5.4	4.5
Transportation and storage	3.6	3.4

	2020 £m	2019 £m
Revenues	21.6	40.9
Adjusted EBITDA	4.0	13.8
Underlying operating (loss)/profit	(2.7)	4.6
Loss after tax	(42.1)	(49.8)
Net cash from operating activities	3.6	12.0
Net debt¹	(12.2)	(6.2)
Cash and cash equivalents	2.4	8.2
Net assets	73.3	113.1

Note 1 Net debt is borrowings less cash and cash equivalents excluding capitalised fees

CONSOLIDATED INCOME STATEMENT

FOR THE YEAR ENDED 31 DECEMBER 2020

	Note	Year ended 31 December 2020 £000	Year ended 31 December 2019 £000
Revenue	2	21,578	40,901
Cost of sales:
Depletion, depreciation and amortisation		(5,974)	(9,058)
Other costs of sales		(17,553)	(20,542)
		(23,527)	(29,600)
Gross (loss)/profit		(1,949)	11,301

Administrative expenses		(5,331)	(4,533)
Exploration and evaluation assets written-off	7	(67)	(53,928)
Oil and gas assets impairment	8	(38,535)	-
Goodwill impairment		-	(4,801)
Gain/(loss) on oil price derivatives		3,520	(3,348)
Gain on foreign exchange contracts		229	265
Operating loss		(42,133)	(55,044)

Finance income	3	1,472	460
Finance costs	3	(3,648)	(3,861)
Loss on extinguishment of debt	10	-	(692)
Changes in fair value of contingent consideration	11	(180)	-
Other income		415	-
Loss from continuing activities before tax		(44,074)	(59,137)
Income tax credit	4	1,985	9,307
Loss after tax from continuing operations attributable to shareholders' equity		(42,089)	(49,830)
Loss after taxation from discontinued operations after tax from discontinued operations	12	(11,060)	(396)
Net loss for the year attributable to shareholders' equity		(53,149)	(50,226)
Loss attributable to equity shareholders from continuing operations:
Basic loss per share	5	(34.35p)	(40.93p)
Diluted loss per share	5	(34.35p)	(40.93p)
Loss attributable to equity shareholders including discontinued operations:
Basic loss per share	5	(43.37p)	(41.26p)
Diluted loss per share	5	(43.37p)	(41.26p)

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

FOR THE YEAR ENDED 31 DECEMBER 2020

		Year ended 31 December 2020 £000	Year ended 31 December 2019 £000
Loss for the year		(53,149)	(50,226)
Other comprehensive loss for the year:
Currency translation adjustments recycled to the income statement	12	10,781	(63)
Currency translation adjustments		(19)	68
Total other comprehensive loss for the year		10,762	5
Total comprehensive loss for the year		(42,387)	(50,221)

CONSOLIDATED BALANCE SHEET

AS AT 31 DECEMBER 2020

	Note	31 December 2020 £000	31 December 2019 £000
ASSETS
Non-current assets
Intangible assets	7	46,711	41,455
Property, plant and equipment	8	72,439	104,532
Right-of-use assets		7,658	7,668
Restricted cash	9	410	410
Deferred tax asset	4	31,945	29,961
		159,163	184,026
Current assets
Inventories		1,023	1,193
Trade and other receivables		4,095	5,986
Cash and cash equivalents	9	2,438	8,194
Derivative financial instruments		314	127
		7,870	15,500
Total assets		167,033	199,526
LIABILITIES
Current liabilities
Trade and other payables		(5,247)	(9,288)
Derivative financial instruments		(1,271)	(266)
Lease liabilities		(694)	(988)
Provisions	11	(293)	-
		(7,505)	(10,542)
Non-current liabilities
Borrowings	10	(13,695)	(13,071)
Other payables		(1,160)	(1,529)
Lease liabilities		(6,820)	(6,173)
Provisions	11	(64,550)	(55,101)
		(86,225)	(75,874)
Total liabilities		(93,730)	(86,416)
Net assets		73,303	113,110
EQUITY
Capital and reserves
Called up share capital		30,333	30,333
Share premium account		102,906	102,680
Foreign currency translation reserve		3,473	(7,289)
Other reserves		35,117	32,781
Accumulated deficit		(98,526)	(45,395)
Total equity		73,303	113,110

These financial statements were approved and authorised for issue by the Board on 7 April 2021 and are signed on its behalf by:

Stephen Bowler Frances Ward

Chief Executive Officer Finance Director

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

FOR THE YEAR ENDED 31 DECEMBER 2020

	Called up share capital 000	Share premium account £000	Foreign currency translation reserve* 000	Other reserves** £000	Accumulated surplus/(deficit) 000	Total equity 000
At 1 January 2019	30,333	102,501	(7,294)	31,310	4,831	161,681
Loss for the year	-	-	-	-	(50,226)	(50,226)
Share options issued under the employee share plan	-	-	-	1,599	-	1,599
Issue of shares	-	179	-	-	-	179
Forfeiture of options under the employee share plan	-	-	-	(128)	-	(128)
Currency translation adjustments	-	-	5	-	-	5
At 31 December 2019	30,333	102,680	(7,289)	32,781	(45,395)	113,110
Loss for the year	-	-	-	-	(53,149)	(53,149)
Share options issued under the employee share plan	-	-	-	2,366	-	2,366
Issue of shares	-	226	-	(30)	-	196
Disposal of shares held in EBT	-	-	-	-	18	18
Currency translation adjustments	-	-	10,762	-	-	10,762
At 31 December 2020	30,333	102,906	3,473	35,117	(98,526)	73,303

* The foreign currency translation reserve represents exchange gains and losses arising on translation of foreign currency subsidiaries net assets and results, and on translation of those subsidiaries intercompany balances which form part of the net investment of the Group.

** Other reserves include: 1) EIP/MRP/LTIP/VCP/EDRP reserves which represent the cost of share options issued under the long term incentive plans; 2) share investment plan reserve which represents the cost of the partnership and matching shares; 3) treasury shares reserve which represents the cost of shares in IGas Energy plc purchased in the market and held by the IGas Employee Benefit Trust (EBT) to satisfy awards held under the Group incentive plans; and 4) capital contribution reserve which arose following the acquisition of IGas Exploration UK Limited.

CONSOLIDATED CASH FLOW STATEMENT

FOR THE YEAR ENDED 31 DECEMBER 2020

	Notes	Year ended 31 December 2020 £000	Year ended 31 December 2019 £000
Cash flows from operating activities:
Loss from continuing activities before tax for the year		(44,074)	(59,137)
Net loss on extinguishment of debt re-financing	10	-	692
Depletion, depreciation and amortisation*		6,303	9,449
Abandonment costs/other provisions utilised		(1,348)	(1,760)
Share based payment charge		1,025	801
Exploration and evaluation assets written-off	7	67	53,928
Oil and gas assets impairment	8	38,535	-
Goodwill impairment		-	4,801
Unrealised loss on oil price derivatives		1,048	2,380
Unrealised gain on foreign exchange contracts		(229)	(265)
Changes in fair value of contingent consideration	11	180
Other income		(415)	-
Finance income	3	(1,472)	(460)
Finance costs	3	3,648	3,861
Other non-cash adjustments		(10)	(14)
Operating cash flow before working capital movements		3,258	14,276
Decrease/(increase) in trade and other receivables and other financial assets		1,514	(602)
Decrease in trade and other payables		(1,187)	(1,733)
Decrease/(increase) in inventories		170	(44)
Cash from continuing operating activities		3,755	11,897
(Increase)/decrease in discontinued operating activities		(156)	105
Taxation paid - continuing operating activities		-	-
Net cash from operating activities		3,599	12,002
Cash flows from investing activities:
Purchase of intangible exploration and evaluation assets		(2,314)	(2,716)
Purchase of property, plant and equipment		(6,152)	(3,668)
Purchase of intangible development assets		(67)	-
Cash acquired on acquisition of subsidiary	6	77	-
Proceeds from disposal of assets		-	1
Other income received		4	14
Interest received		11	129
Cash used in continuing investing activities		(8,441)	(6,240)
Net cash used in investing activities		(8,441)	(6,240)

Cash flows from financing activities:
Cash proceeds from issue of ordinary share capital		56	69
Proceeds from disposal of shares held in EBT net of costs		4	-
Drawdown on Reserves-Based Lending Facility	9	5,544	19,319
Repayment on Reserves-Based Lending Facility	9	(4,645)	(4,639)
Fees paid related to debt re-financing	9	-	(1,059)
Repayment of bonds	9	-	(21,355)
Repayment of principal portion of lease liability		(973)	(2,010)
Repayment of interest on lease liabilities		(795)	(677)
Interest paid	9	(940)	(2,021)
Net cash used in financing activities		(1,749)	(12,373)
Net decrease in cash and cash equivalents in the year		(6,591)	(6,611)
Net foreign exchange difference		835	(307)
Cash and cash equivalents at the beginning of the year		8,194	15,112
Cash and cash equivalents at the end of the year	9	2,438	8,194

* Depletion, depreciation and amortisation includes £1.3 million (2019: £1.5 million) relating to right-of-use assets

CONSOLIDATED FINANCIAL STATEMENTS - NOTES

FOR THE YEAR ENDED 31 DECEMBER 2020

1 Accounting policies

(a) Basis of preparation of financial statements and corporate information

Whilst the financial information in this preliminary announcement has been prepared in accordance with international accounting standards in conformity with the requirements of the Companies Act 2006 ("the "Standards"), this announcement does not contain sufficient information to comply with the Standards. The Group will publish full financial statements that comply with the Standards in May 2021.

The financial information for the year ended 31 December 2020 does not constitute statutory financial statements as defined in sections 435 (1) and (2) of the Companies Act 2006. Statutory financial statements for the year ended 31 December 2019 have been delivered to the Registrar of Companies and those for 2020 will be delivered following the Company's annual general meeting. The auditor has reported on these financial statements; their reports were unqualified, though they drew attention to a material uncertainty related to going concern in 2020. These reports did not contain a statement under section 498 (2) or (3) of the Companies Act 2006.

The accounting policies applied are consistent with those adopted and disclosed in the Group's financial statements for the year ended 31 December 2019. There have been a number of amendments to accounting standards and new interpretations issued by the International Accounting Standards Board which were applicable from 1 January 2020. These did not have a material impact on the accounting policies, methods of computation or presentation applied by the Group.

There are also a number of amendments to accounting standards and new interpretations issued by the International Accounting Standards Board which will be applicable from 1 January 2021 onwards. These are not expected to have a material impact on the accounting policies, methods of computation or presentation applied by the Group and have not been adopted early.

Further details on new International Financial Reporting Standards adopted and yet to be adopted will be disclosed in the 2020 Annual Report and Financial Statements.

IGas Energy plc is a public limited company incorporated and registered in England and Wales and is listed on the Alternative Investment Market ("AIM"). The Group's principal area of activity is exploring for, appraising, developing and producing oil and gas resources in Great Britain.

The financial information is presented in UK pounds sterling and all values are rounded to the nearest thousand (£000) except when otherwise indicated.

(b) Going concern

2 Revenue

The Group derives revenue solely within the United Kingdom from the transfer of goods and services to external customers which is recognised at a point in time when the performance obligation has been satisfied by the transfer of goods. The Group's major product lines are:

	Year ended 31 December 2020 £000	Year ended 31 December 2019 £000
Oil sales	20,546	39,248
Electricity sales	438	966
Gas sales	594	687
	21,578	40,901

Revenues of approximately £11.9 million and £8.7 million were derived from the Group's two largest customers (2019: £18.8 million and £20.5 million) and are attributed to the oil sales.

As at 31 December 2020, there are no contract assets or contract liabilities outstanding (2019: nil).

3 Finance income/(costs)

	Year ended 31 December 2020 £000	Year ended 31 December 2019 £000
Finance income:
Interest on short-term deposits	11	127
Foreign exchange gains	1,461	333
Finance income	1,472	460

Finance expense:
Interest on borrowings	(940)	(1,651)
Amortisation of finance fees on borrowings	(387)	(223)
Unwinding of discount on decommissioning provision (note 11)	(1,466)	(1,310)
Unwinding of discount on contingent consideration (note 11)	(60)	-
Finance charge on lease liability for assets in use	(795)	(677)
Finance expense	(3,648)	(3,861)

4 Income tax credit

(i) Tax credit on loss from continuing ordinary activities

	Year ended 31 December 2020 £000	Year ended 31 December 2019 £000
Current tax:
Charge on loss for the year	-	-
Charge in relation to prior years	-	-
Total current tax charge	-	-
Deferred tax:
Charge/(credit) relating to the origination or reversal of temporary differences	1,409	(3,461)
Credit due to tax rate changes	(99)	-
Credit in relation to prior years	(3,295)	(5,846)
Total deferred tax credit	(1,985)	(9,307)
Tax credit on loss on ordinary activities	(1,985)	(9,307)

ii) Factors affecting the tax charge

The majority of the Group's profits are generated by "ring-fence" businesses which attract UK corporation tax and supplementary charge at a combined average rate of 40% (2019: 40%).

A reconciliation of the UK statutory corporation tax rate applied to the Group's loss before tax to the Group's total tax credit is as follows:

	Year ended 31 December 2020 £000	Year ended 31 December 2019 £000
Loss from continuing ordinary activities before tax	(44,074)	(59,137)
Expected tax credit based on loss from continuing ordinary activities multiplied by an average combined rate of corporation tax and supplementary charge in the UK of 40% (2019: 40%)	(17,630) (17,776)	(23,655)
Deferred tax credit in respect of the prior year	(3,295)	(5,846)
Tax effect of expenses not allowable for tax purposes	(740)	9,850
Tax effect of differences in amounts not allowable for supplementary charge purposes*	6	(121)
Impact of profits or losses taxed or relieved at different rates	461	292
Net increase in unrecognised losses carried forward	7,781	10,197
Net increase in unrecognised temporary taxable differences	11,533	-
Tax rate change	(99)	-
Other	(2)	(24)
Tax credit on loss on ordinary activities	(1,985)	(9,307)

* Amounts not allowable for supplementary charge purposes relate to net financing costs disallowed for supplementary charge offset by investment allowance which is deductible against profits subject to supplementary charge.

iii) Deferred tax

The movement on the deferred tax asset in the year is shown below:

	Year ended 31 December 2020 £000	Year ended 31 December 2019 £000
Asset at 1 January	29,961	20,656
Tax credit relating to prior year	3,295	5,846
Tax (charge)/credit during the year	(1,409)	3,461
Tax charge arising due to the changes in tax rates	99	-
Other	(1)	(2)
Asset at 31 December	31,945	29,961

The following is an analysis of the deferred tax asset by category of temporary difference:

	31 December 2020 £000	31 December 2019 £000
Accelerated capital allowances	(7,791)	(13,993)
Tax losses carried forward	26,633	29,735
Investment allowance unutilised	1,542	1,297
Decommissioning provision	7,390	9,628
Unrealised gains or losses on derivative contracts	2,126	1,799
Share based payments	2,090	1,675
Right-of-use asset and liability	(45)	(180)
Deferred tax asset	31,945	29,961

iv) Tax losses

Deferred tax assets have been recognised in respect of tax losses and other temporary differences where the Directors believe it is probable that these assets will be recovered based on a five-year profit forecast. Such tax losses include £130 million (2019: £94.4 million) of ring-fence corporation tax losses.

The Group has further tax losses and other similar attributes carried forward of approximately £215.4million (2019: £234.8 million) for which no deferred tax asset is recognised due to insufficient certainty regarding the availability of appropriate future taxable profits. The unrecognised losses may affect future tax charges should certain subsidiaries in the Group generate taxable trading profits in future periods.

5 Earnings per share (EPS)

Continuing

Basic EPS amounts are based on the loss for the year after taxation from continuing operations attributable to ordinary equity holders of the parent of £42.1 million (2019: a loss after taxation from continuing operations attributable to shareholders' equity of £49.8 million) and the weighted average number of ordinary shares outstanding during the year of 122.5 million (2019: 121.7 million).

Diluted EPS amounts are based on the loss for the year after taxation from continuing operations attributable to the ordinary equity holders of the parent and the weighted average number of shares outstanding during the year plus the weighted average number of ordinary shares that would be issued on the conversion of all the potentially dilutive ordinary shares into ordinary shares, except where these are anti-dilutive.

As at 31 December 2020, there are £10.9 million potentially dilutive employee share options (31 December 2019: 6.3 million potentially dilutive share options) which are not included in the calculation of diluted earnings per share as their conversion to ordinary shares would have decreased the loss per share.

The following reflects the income and share data used in the basic and diluted earnings per share from continuing operations:

	Year ended 31 December 2020	Year ended 31 December 2019
Basic loss per share - ordinary shares of 0.002 pence each	(34.35p)	(40.93p)
Diluted loss per share - ordinary shares of 0.002 pence each	(34.35p)	(40.93p)
Loss for the year attributable to equity holders of the parent from continuing operations - £000	(42,089)	(49,830)
Weighted average number of ordinary shares in the year- basic EPS	122,537,605	121,729,407
Weighted average number of ordinary shares in the year- diluted EPS	122,537,605	121,729,407

Discontinued

The following reflects the income and share data used in the basic and diluted earnings per share including discontinued operations:

	Year ended 31 December 2020	Year ended 31 December 2019
Basic loss per share - ordinary shares of 0.002 pence each	(43.37p)	(41.26p)
Diluted loss per share - ordinary shares of 0.002 pence each	(43.37p)	(41.26p)
Loss for the year attributable to equity holders of the parent - £000	(53,149)	(50,226)
Weighted average number of ordinary shares in the year- basic EPS	122,537,605	121,729,407
Weighted average number of ordinary shares in the year- diluted EPS	122,537,605	121,729,407

6 Acquisitions

Acquisition of GT Energy UK Limited

IGas entered into a sale and purchase agreement ("SPA") to acquire GT Energy UK Limited ("GT Energy"), a developer of deep geothermal heat projects onshore UK on 16 September 2020. GT Energy's principal project is a 14MW deep geothermal project in the Etruria Valley, Stoke-on-Trent. The project is anticipated to supply zero carbon heat to the city of Stoke-on-Trent on a long-term 'take or pay' contract ("TPA") with Stoke-on-Trent City Council ("SoTCC"). It is anticipated that the heat will be supplied through the SoTCC owned and operated district heating network, which is undergoing installation.

Under the terms of the SPA, IGas made an initial payment of £0.5 million (the "Initial Purchase Price") to the Sellers satisfied in 2,222,223 IGas ordinary shares on completion by the transfer of 1,844,637 shares held by IGas (not as treasury shares, as defined under the AIM Rules) and allotment and issue of 377,586 shares based on an agreed share price of £0.225 per share. The Initial Purchase Price was subject to an immaterial post-completion adjustment following the preparation of completion accounts, and an adjustment will be made against any additional consideration payable upon satisfaction of future milestone events ("Milestone Consideration") in accordance with the SPA.

The maximum consideration payable to the Sellers under the SPA is £12.0 million and the ordinary shares of IGas which may be issued under the SPA shall not exceed twenty-nine point nine per cent (≤29.9%) of the fully diluted issued ordinary share capital of IGas. In addition to the Initial Purchase Price, the Company may be required to pay the Milestone Consideration - see below. GT Energy has entered into a term sheet with Gravis Capital Management Limited ("Gravis") which provides indicative and non-binding terms, on behalf of Funds managed by Gravis, to fund a significant proportion of the c. £20 million project through a limited-recourse debt facility. Such provision of finance is conditional on, inter alia, signature of the TPA by SoTCC and GT Energy, agreement and execution of the financing documentation, the completion of Gravis' due diligence and internal Gravis and third-party approvals. GT Energy is currently engaged in advanced negotiations with SoTCC in respect of the TPA.

The Company may be required to pay Milestone Consideration upon:

(i) financial close, within five years of the date of the SPA (the "First Milestone Longstop"), of a funding facility in respect of GT Energy's principal project (described above) on terms reasonably acceptable to the Company (the "First Milestone");

(ii) subject to completion of the First Milestone first delivery of heat to the district heat network under the TP

(iii) subject to completion of the First Milestone, six months following (ii),

(iv) subject to completion of the First Milestone the first anniversary of (ii);

(v) the first of either (being the "Business Development Milestone"):

· GT Energy securing a further geothermal project in the UK by successfully completing certain key targets relevant thereto (as set out in the SPA), within the earlier of (a) the fifth anniversary of the date of the SPA, and (b) the second anniversary of an announcement by the UK Government of a new RHI Scheme, or in the reasonable opinion of the Company, equivalent scheme; or

· One Thousand British Pounds (GBP £1,000) per full kW electrical generating capacity installed, capped at £1 million (for 1000kW or more) subject to and measured on the date upon which, inter alia, validation of a planning application to allow electricity generation at the primary project location, and installation and successful commissioning of an electricity generation plant which utilises excess heat from the primary project, together with the ability to utilise such electricity to supply the Project's electricity requirements, and / or connect to a private wire or the national grid as the case may be.

The Milestone Consideration will be satisfied by the allotment of ordinary shares in IGas, as is derived by, for each Seller, dividing their proportion of the relevant Milestone Consideration by: (a) in respect of ordinary shares in IGas to be allotted in respect of the First Milestone: either (i) if the First Milestone is satisfied within thirty (30) months of the date of the SPA, the volume weighted average price of IGas' ordinary shares as derived from the AIM section of the London Stock Exchange Daily Official List ("VWAP"), on the one hundred and eighty (180) dealing days preceding the date of the SPA ("First VWAP"), or (ii) if the First Milestone is satisfied in the period falling on or after thirty (30) months from the date of the SPA and before the First Milestone Longstop, the VWAP on the thirty (30) dealing days preceding the date of the satisfaction of the First Milestone ("Second VWAP"); (b) in respect of ordinary shares in IGas to be allotted in respect of any other milestone (other than the Business Development Milestone), either the First VWAP or Second VWAP as was applicable, or would have been applicable to (as the case may be), to any ordinary shares in IGas to be allotted under the First Milestone; and (c) in respect of ordinary shares in IGas in respect of the Business Development Milestone, the VWAP on the ninety (90) dealing days preceding the date of satisfaction of the relevant Business Development Milestone, with, in each case, the resulting number being rounded down to the nearest whole share and subject to, inter alia, admission to trading on AIM of the relevant shares.

Details of the consideration (Initial Purchase Price and Milestone Consideration) and net assets acquired are as follows:


	£000
Amount settled in cash	-
Fair value of Initial Purchase Price	500
Fair value of the Milestone Consideration	2,784
Fair value of the consideration transferred	3,284
Recognised amounts of identifiable assets and liabilities at fair value
Property, plant and equipment Intangible Assets- Development costs Trade and trade receivables Cash and cash equivalents Trade and other payables	1 3,223 18 77 (35)
Net identifiable assets and liabilities	3,284

The fair value of the consideration relating to the Initial Purchase Price (£0.5 million) is based on 2,222,223 shares issued at an agreed share price of 22.5p under the SPA.

The £2.8 million fair value of the Milestone Consideration (contingent consideration liability) recognised on the acquisition date has been calculated by determining the probability weighted value of the Milestone payments and the fair value of IGas shares issued to satisfy these payments. The calculation is based on an internal assessment of the probability of the milestones being achieved and of the inputs to the economic model which determines the level of the consideration for each milestone in accordance with the SPA. The probability weighted Milestone payments were discounted using a WACC of 8.3%. The resulting consideration amount was divided by the First VWAP (28.09p) to calculate the estimated number of shares to be issued as management have assumed that the First Milestone would be satisfied within 30 months of the date of the SPA. The estimated number of shares to be issued was then multiplied at a share price of 12.6p, being the IGas share price as at acquisition date (which is reflective of the estimated fair value of IGas shares), resulting in the estimated fair value of the Milestone Consideration of £2.8 million. The estimated fair value of the Milestone Consideration will be reviewed at each year end and any changes recognised in the income statement.

Acquisition related costs amounting to £0.2 million have been recognised as an expense in the consolidated income statement, as part of administrative expenses.

7 Intangible assets

	2020			2019
	Exploration and evaluation assets £'000	Development costs £'000	Total £'000	Exploration and evaluation assets £'000	Development costs £'000	Total £'000
At 1 January	41,455	-	41,455	89,282	-	89,282
Acquisitions (note 6)	-	3,223	3,223	-	-	-
Additions	2,090	67	2,157	3,984	-	3,984
Transfers from held for sale	-	-	-	342	-	342
Changes in decommissioning*	(57)	-	(57)	1,775	-	1,775
Amounts written-off	(67)	-	(67)	(53,928)	-	(53,928)
At 31 December	43,421	3,290	46,711	41,455	-	41,455

*The decommissioning asset decreased in line with the decommissioning liability following a review of the estimate at 31 December 2020 (note 11).

Exploration and evaluation assets

In November 2019, the UK Government announced an effective moratorium on fracking in Britain, based on analysis of one well in the North West by the Oil and Gas Authority ("OGA"), until new scientific evidence is provided in respect of the impacts of seismicity during the process of hydraulic fracturing. Management has been working and will continue to work closely with the relevant regulators to demonstrate that the Group can operate safely and environmentally responsibly. During the year, we also continued the interpretation of the Springs Rd well results and re-interpreted the 3D seismic data acquired in the Springs Road area in 2014.

Exploration and evaluation costs written off were £0.1 million (31 December 2019: £53.9 million). Following an impairment review in 2019, the Group impaired in full those assets outside our core area where the Group does not have plans in the near-term to continue exploration or development activities. The impairment comprised £51.8 million related to licences in the North West, primarily PEDL145 (Doe Green), PEDL 193, PEDL147 and PEDL 189 where the previously capitalised assets have been written off in full; and £0.8 million related to PEDL 146, EXL 288 and 56-1 in the East Midlands where relinquishment of the licences are planned in 2020/2021. The balance relates to exploration costs on a number of other licences outside our core area. Management continually review the Group's acreage positions and will seek to relinquish non-core licences or impair licences where the carrying value cannot be supported.

Further analysis by location of assets is as follows:

North West: The Group has £6.1 million (2019: £5.9 million) of capitalised exploration expenditure relating to Ellesmere Port where IGas has lodged an appeal against the decision made by Cheshire West and Chester Council's Planning and Licensing Committee to refuse planning consent for routine tests on a rock formation encountered in the Ellesmere Port-1 well. The Secretary of State has recovered the appeal and we are awaiting the outcome. As the outcome is still undetermined and the North West acreage continues to be an area of focus for the Group, it is appropriate to keep the carrying value of the asset capitalised.

East Midlands: The Group has £32.8 million (2019: £31.6 million) of capitalised exploration expenditure relating to our core area in the Gainsborough Trough which includes PEDL's 12, 139, 140, 169, 200 and 210. The Gainsborough Trough is an area with significant shale potential. Following the moratorium on fracking, we continue to work with the OGA, BEIS and No 10 Policy Unit to demonstrate that we can develop shale in this area in a safe manner. Our discussions have focused on the new science that would be brought forward on a sector wide and site-specific basis that would allow the moratorium to be lifted. We are doing this in conjunction with our joint venture partners and the work is ongoing at present.

Conventional assets: The Group has £4.5 million (2019: £4.0 million) of capitalised exploration expenditure on conventional assets which includes PEDL 235 and PL 240. The Group spent £0.6 million during the year progressing exploration opportunities on conventional assets.

At 31 December 2020, the Group has a combined carried gross work programme of up to $218.0 million (£160.0 million) (2019: $214.0 million (£161.0 million)) from its partner, INEOS Upstream Limited. In 2020, 0.4m (2019: £7.3 million) gross costs were carried, principally in relation to activities at and Springs Road, which have not been included in the additions to intangible exploration and evaluation assets during the year.

Development costs

Development costs relate to assets acquired as part of the GT Energy UK Limited acquisition as explained in note 6. The costs relate to the design and development of deep geothermal heat projects in the United Kingdom, with the principal project being at Etruria Valley, Stoke-on-Trent.

The Group reviewed the carrying value of development costs as at 31 December 2020 and assessed it for impairment. No impairment was required for the year (2019: £nil).

8 Property, plant and equipment

	2020			2019
	Oil and gas assets £'000	Other property, plant and equipment £'000	Total £'000	Oil and gas assets £'000	Other property, plant and equipment £'000	Total £'000
Cost
At 1 January	197,875	3,660	201,535	154,649	2,871	157,520
Additions	5,212	1	5,213	5,491	10	5,501
Disposals	(117)	(710)	(827)	(118)	-	(118)
Changes in decommissioning*	6,255	-	6,255	5,908	-	5,908
Transfers from assets held for sale	-	-	-	31,945	779	32,724
At 31 December	209,225	2,951	212,176	197,875	3,660	201,535
Accumulated Depreciation and Impairment
At 1 January	94,940	2,063	97,003	65,002	1,115	66,117
Charge for the year	4,875	151	5,026	7,688	258	7,946
Disposals	(117)	(710)	(827)	(117)	-	(117)
Impairment	38,535	-	38,535	-	-	-
Transfers from assets held for sale	-	-	-	22,367	690	23,057
At 31 December	138,233	1,504	139,737	94,940	2,063	97,003
NBV at 31 December	70,992	1,447	72,439	102,935	1,597	104,532

*The decommissioning asset increased in line with the decommissioning liability following a review of the estimate at 31 December 2020 (note 11).

Expenditure during the year related to the Welton and Scampton North waterflood projects and continued investment in our assets to increase or maintain production rates.

Impairment of oil and gas properties

The COVID-19 pandemic developed rapidly in 2020, with a significant number of cases worldwide. Measures taken by various governments to contain the virus affected global economic activity and resulted in a significant reduction in demand for oil and, therefore, in oil prices. The decline in oil prices in first half of 2020 and the uncertainty surrounding the pandemic triggered an impairment review of oil and gas properties as at 30 June 2020. Although the oil price improved towards the end of the year, management identified impairment triggers due to the significant uncertainty as to how COVID-19 and its aftermath would impact economies, oil demand and oil price over the near and mid-term. Therefore, management carried out a further review of oil and gas properties for impairment as at 31 December 2020 which resulted in an additional impairment of £3.9 million. The impairment review performed at 31 December 2019 did not result in any impairment.

Cash generating units (CGUs) for impairment purposes are the group of fields whereby technical, economic and/or contractual features create underlying interdependence in cash flows. The Group has identified the three main producing CGUs as: North, South, and Scotland. The impairment assessment for the North, South and Scotland was prepared on a fair value less costs of disposal basis using discounted future cash flows based on 2P reserve profiles. The future cash flows were estimated using the following key assumptions:

	31 December 2020	30 June 2020	31 December 2019
Oil Price (Brent)	$50-$55/bbl for the years 2021-2022 and $60/bbl thereafter	$45-55/bbl for the years 2020-2022 and $60/bbl thereafter	$60/bbl for the years 2020-2024 and $70/bbl thereafter
USD/GBP foreign exchange rate	$1.37:£1.00 for 2021 and $1.35:£1 thereafter	$1.32:£1.00	$1.35:£1.00
Post-tax discount rate	8.3%	8.3%	8.5%

Outcome of impairment reviews

The reduction in oil price in 2020 resulted in an impairment charge of £21.9 million in the North CGU, £11.9 million in the South CGU and £0.9 million in the Scotland CGU giving a total impairment charge of £34.6 million for the period to 30 June 2020. At 31 December 2020, although oil prices had improved, an additional £3.9 million impairment charge was recognised on the North CGU at 31 December 2020 primarily due to the weakening of the US Dollar compared to British Pound Sterling in the second half of 2020 offset by an increase in 2P reserves based on the latest Competent Persons Report ("CPR"). This resulted in a total impairment of £38.5 million in the year (2019: £nil).

Sensitivity of changes in assumptions

As discussed above, the principal assumptions are recoverable future production and resources, estimated Brent prices and the USD/GBP foreign exchange rate. The additional impairment that would result from changes to the key assumptions are shown below for the North CGU. There is no additional impairment in any of these scenarios in the South CGU and Scotland CGU:

CGU	10% reduction in price	10% reduction in production	USD/GBP foreign exchange rate @1.4	Discount rate @ 9.3%
	£'million	£'million	£'million	£'million
North	(9.6)	(9.8)	(3.2)	(2.3)

The sensitivity analysis above does not take into account any mitigating actions available to management should these changes occur.

In addition, management considered the impact of climate change on the value of the Group's conventional assets. Assessing the impact is difficult and very subjective. However, management have assumed that this might result in lower oil prices or increased costs in the medium term and have therefore calculated a sensitivity based on a reduced price of £50/bbl from 2030 onwards and a cessation of production after 2050. This would result in an additional impairment of £4.1 million for the North CGU, nil for the South CGU and nil for the Scotland CGU (2019: £7.9 million for the North CGU, £1.3 million for the South CGU and £0.1 million for the Scotland CGU).

Transfers from assets held for sale

In May 2018, the Group announced the potential sale of certain non-core assets to Onshore Petroleum Limited (OPL) subject to OGA consent. The OGA did not give their consent to the proposed transaction and the Group has not agreed an alternative transaction with OPL. Assets and liabilities which were recognised as held for sale in 2018 have therefore been re-classified back to their respective balance sheet categories during the prior year.

9 Cash and cash equivalents

	31 December 2020 £000	31 December 2019 £000
Cash at bank and in hand	2,438	8,194

31 December

2020

£000

31 December

2019

£000

Cash at bank and in hand

2,438

8,194

The cash and cash equivalents do not include restricted cash.

Restricted cash

	31 December 2020 £000	31 December 2019 £000
Non-current	410	410

31 December

2020

£000

31 December

2019

£000

Non-current

410

The restricted cash represents restoration deposits paid to Nottinghamshire County Council which serve as collateral for the restoration of drilling sites at the end of their life. The restoration deposits are subject to regulatory and other restrictions and are therefore not available for general use of the Group.

Net debt reconciliation

					31 December 2020 £000		31 December 2019 £000
Cash and cash equivalents					2,438		8,194
Borrowings - including capitalised fees					(13,695)		(13,071)
Net debt					(11,257)		(4,877)
Capitalised fees					(937)		(1,272)
Net debt excluding capitalised fees					(12,194)		(6,149)

	2020			2019
	Cash and cash equivalents	Borrowings	Total	Cash and cash equivalents		Borrowings		Total
	£000	£000	£000	£000		£000		£000
At 1 January	8,194	(13,071)	(4,877)	15,112		(20,980)		(5,868)
Repayment of bond	-	-	-	(21,355)		21,355		-
Interest paid on borrowings	(940)	-	(940)	(2,021)		-		(2,021)
Drawdown of RBL (note 10)	5,544	(5,544)	-	19,319		(19,319)		-
Capitalised fees	-	-	-	(1,059)		1,308		249
Repayment of RBL (note 10)	(4,645)	4,645	-	(4,639)		4,639		-
Foreign exchange adjustments	(836)	610	(226)	(307)		645		338
Other cash flows	(4,879)	-	(4,879)	3,144		-		3,144
Other non-cash movements	-	(335)	(335)	-		(719)		(719)
At 31 December	2,438	(13,695)	(11,257)	8,194		(13,071)		(4,877)

10 Borrowings

	31 December 2020	31 December 2019
Reserve Based Lending Facility (RBL) - secured	-	(13,695)	(13,695)	-	(13,071)	(13,071)

31 December 2020

31 December 2019

Current

£000

Non-current

£000

Total

£000

Current

£000

Non-current

£000

Total

£000

Reserve Based Lending Facility (RBL) - secured

(13,695)

(13,071)

Reserve Based Lending facility

On 3 October 2019, the Company announced that it had signed a $40.0 million RBL Facility with BMO Capital Markets (BMO). In addition to the committed $40.0 million RBL, a further $20.0 million is available on an uncommitted basis, and can be used for any future acquisitions or new conventional developments. The RBL has a five-year term, an interest rate of LIBOR plus 4.0%, matures in September 2024 and is secured on the Company's assets. The RBL is subject to a semi-annual redetermination in May and November when the loan availability will be recalculated taking into account forecast commodity prices, remaining field reserves (assessed by an independent reserves auditor annually) and the latest forecast of operating and capital costs. As at 31 December 2020, the Group had successfully completed the November 2020 redetermination which confirmed an available facility limit of $31.7 million.

Under the terms of the RBL, the Group is subject to a financial covenant whereby, as at 30 June and 31 December each year, the ratio of Net Debt at the period end to Earnings before Interest, Tax, Depreciation, Amortisation and Exceptional items (the "EBITDAX" as defined in the RBL agreement) for the previous 12 months shall be less than or equal to 3.5:1.

A loss of £0.7 million arising from debt re-financing was recognised for the year ended 31 December 2019.

Collateral against borrowing

A Security Agreement was executed between BMO and IGas Energy plc and some of its subsidiaries, namely; Island Gas Limited, Island Gas Operations Limited, Star Energy Weald Basin Limited, Star Energy Group Limited, Star Energy Limited, Island Gas (Singleton) Limited, Dart Energy (East England) Limited, Dart Energy (West England) Limited, IGas Energy Development Limited, IGas Energy Enterprise Limited, Dart Energy (Europe) Limited and IGas Energy Production Limited.

Under the terms of this Agreement, BMO have a floating charge over all of the assets of these legal entities, other than property, assets, rights and revenue detailed in a fixed charge. The fixed charge encompasses the Real Property (freehold and/or leasehold property), the specific petroleum licences, all pipelines, plant, machinery, vehicles, fixtures, fittings, computers, office and other equipment, all related property rights, all bank accounts, shares and assigned agreements and rights including related property rights (hedging agreements, all assigned intergroup receivables and each required insurance and the insurance proceeds).

11 Provisions

	2020			2019
	Decommissioning provisions £'000	Contingent consideration £'000	Total £'000	Decommissioning provisions £'000	Contingent consideration £'000	Total £'000
At 1 January	(55,101)	-	(55,101)	(37,946)	-	(37,946)
Acquisitions (note 6)	-	(2,784)	(2,784)	-	-	-
Utilisation of provision	946	-	946	1,760	-	1,760
Unwinding of discount (note 3)	(1,466)	(60)	(1,526)	(1,310)	-	(1,310)
Reassessment of decommissioning provision (note 7 and note 8)	(6,198)	-	(6,198)	(7,683)	-	(7,683)
Changes in fair value of contingent consideration	-	(180)	(180)	-	-	-
Transfer from liabilities held for sale	-	-	-	(9,922)	-	(9,922)
At 31 December	(61,819)	(3,024)	(64,843)	(55,101)	-	(55,101)

Decommissioning provision

The Group spent £0.9 million on decommissioning activities during the year (2019: 1.8 million).

Provision has been made for the discounted future cost of abandoning wells and restoring sites to a condition acceptable to the relevant authorities. This is expected to take place between 1 to 37 years from year-end (2019: 1 to 35 years). The provisions are based on the Group's internal estimate as at 31 December 2020. Assumptions are based on the current experience from decommissioning wells which management believes is a reasonable basis upon which to estimate the future liability. The estimates are reviewed regularly to take account of any material changes to the assumptions. Actual decommissioning costs will ultimately depend upon future costs for decommissioning which will reflect market conditions and regulations at that time. Furthermore, the timing of decommissioning is uncertain and is likely to depend on when the fields cease to produce at economically viable rates. This, in turn, will depend on factors such as future oil and gas prices, which are inherently uncertain.

A risk free rate range of 1.20 % to 3.00 % is used in the calculation of the provision as at 31 December 2020 (2019: Risk free rate range of 1.27% to 3.03%).

Sensitivity of changes in assumptions

Management performed sensitivity analysis to assess the impact of changes to the risk free rate on the Group's decommissioning provision balance. A 0.5% decrease in the risk free rate assumption would result in an increase in the decommissioning provision by £3.9 million.

Contingent consideration

The carrying value of contingent consideration relates to GT Energy acquisition as explained in note 6. The change in fair value is primarily related to the increase in fair value of IGas plc shares between acquisition date and year ended 31 December 2020 as the consideration is payable in shares.

Sensitivity of changes in assumptions

The principal assumptions in calculating the fair value of contingent consideration is the probability assigned to Milestone payments and the share price at valuation date. Management performed sensitivity analysis to assess the impact of changes to the key assumptions. An increase in the probability of the scenario which would result in the maximum pay out by 5% would result in an increase in the contingent consideration provision by £0.3 million. An increase in the share price at valuation date by 10% would result in an increase in the contingent consideration provision by £0.2 million.

12 Discontinued operations

The divestment of assets acquired as part of the Dart Acquisition, namely the Rest of the World segment, was completed in 2016. The Group still has a presence in a small number of Australian and Singaporean registered operations and continues its plans to exit all legal jurisdictions in the near future. During the year ended 31 December 2020, a number of these overseas dormant subsidiaries have been struck off or liquidated. The total loss after tax in respect of discontinued operations was £11.1 million primarily due to the recycling of the currency translation reserve on liquidation/strike off (2019: loss after tax from discontinued operations of £0.4 million, primarily relating to administration costs). Tax on discontinued operations during the year was nil (2019: £nil).

Effect of liquidation/strike off on the financial statements:

	31 December 2020 £000
Other receivables	2
Cash and cash equivalents	(9)
Other payables	56
Net assets and liabilities disposed	49
Disposal consideration	-

Translation reserve re-classification to income statement on liquidation/strike off	(10,781)
Loss on liquidation/strike off charged to the income statement	(10,732)

13 Subsequent events

On 27 January 2021, the Group issued 338,277 Ordinary £0.00002 shares in relation to the Group's SIP scheme. The shares were issued at £0.0925 resulting in share premium of £31,291.

On 4 February 2021, the Parent company of the Group, IGas plc, changed its registered address from 7 Down Street, London W1J 7AJ to the Welton Gathering Centre, Barfield Lane Off Wragby Road, Sudbrooke, Lincoln, England, LN2 2QX.

Glossary

£ The lawful currency of the United Kingdom

$ The lawful currency of the United States of America

1P Low estimate of commercially recoverable reserves

2P Best estimate of commercially recoverable reserves

3P High estimate of commercially recoverable reserves

1C Low estimate or low case of Contingent Recoverable Resource quantity

2C Best estimate or mid case of Contingent Recoverable Resource quantity

3C High estimate or high case of Contingent Recoverable Resource quantity

AIM AIM market of the London Stock Exchange

boepd Barrels of oil equivalent per day

bopd Barrels of oil per day

CCC Committee on Climate Change

GIIP Gas initially in place

Mbbl Thousands of barrels

MMboe Millions of barrels of oil equivalent

MMscfd Millions of standard cubic feet per day

NBP National balancing point - a virtual trading location for the sale and purchase and exchange of UK natural gas

OIIP Oil initially in place

PEDL United Kingdom petroleum exploration and development licence.

PL Production licence

SoS Secretary of State

RoSPA Royal Society for the Prevention of Accidents

Tcf Trillions of standard cubic feet of gas

UK United Kingdom

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