Final Results

RNS Number : 3985H

Igas Energy PLC

06 April 2022

6 April 2022

IGas Energy plc (AIM: IGAS)

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

Full year results for the year ended 31 December 2021

Commenting today Stephen Bowler, Chief Executive Officer, said:

"I am very pleased with the way the business responded to the ongoing challenges of COVID-19 in 2021. Our production remains robust and we expect strong operating cash flow generation, in line with improved commodity prices.

We have made excellent progress on large scale geothermal, with specific provision now being made for drilling of geothermal wells in the Government's recently launched Green Heat Network Fund (GHNF). This now gives us a clearer line of sight to development as we firm up a number of rapidly emerging opportunities.

Our decision to follow an energy diversification strategy was the right one. However, what is clear, is that fossil fuels and gas in particular, will remain a significant part of the energy mix as we move towards and beyond net zero.

We welcome the Government's scientific review of shale gas by the British Geological Survey, expected before the end of June 2022, and the opportunity to demonstrate how shale gas can provide safe, secure and affordable energy for the UK. We believe that expediting shale gas development will help alleviate the recent supply issues and high prices, alongside reducing emissions through to the replacement of imported gas."

Results Summary

	Year ended 31 Dec 2021 £m	Year ended 31 Dec 2020 £m
Revenues	37.9	21.6
Adjusted EBITDA¹	5.9	4.0
Loss after tax	(6.0)	(42.1)
Operating cash flow before working capital adjustments	7.4	3.3
Net debt¹	12.2	12.2
Cash and cash equivalents	3.3	2.4

Notes

¹ Adjusted EBITDA and Net Debt (borrowings less cash and cash equivalents excluding capitalised fess) are used by the Group, alongside IFRS measures for both internal performance analysis and to help shareholders, lenders and other users of the annual report to better understand the Group's performance in the period in comparison to previous periods and to industry peers

Corporate and Financial Summary

· Successful redetermination under the Group's Reserve Based Lending facility (RBL) concluded in December 2021 confirming £19.3 (US$26.2) million of debt capacity and headroom of £7.1 million as at 31 December 2021.

· 231,000 bbls are currently hedged for 2022 using swaps at an average price of $74/bbl and 129,000 bbls using puts with an average guaranteed minimum price, net of premiums, of $46/bbl. 15,000 bbls hedged for Q1 23 using swaps at $95/bbl.

· Excluding hedging costs of £6.6 million, net cash generated from continuing operating activities for the year was £13.9 million (2020: £(1.0) million).

· Cash balances as at 31 December 2021 were £3.3 million with net debt unchanged from 2020 year-end at £12.2 million.

· The Group invested £4.8 million across its asset base during the year (2020: £8.4 million).

· In 2022, we are forecasting a total £7.4 million of capital expenditure including site improvements, near term incremental projects to generate c.70-100 boepd, as well as longer term development projects. In addition, we have £1.8 million of cash outflow in 2022 for projects executed towards the end of 2021.

· Ring fence tax losses at 31 December 2021 were £268 million.

Operational Summary

· Net production, in line with guidance, averaged 1,962 boepd for the year, with operations, maintenance and project activities all being directly and indirectly impacted by COVID-19. Excluding COVID impacts, production would have been c.2,100 boepd.

· Underlying operating costs for the year were c.$37/boe (at an average 2021 exchange rate of £1:$1.38).

· In 2022, we anticipate net production of c.2,000 boepd and operating costs of c.$38/boe (assuming an exchange rate of £1:$1.35), albeit subject to the ongoing challenges that COVID-19 still presents.

· Plan to progress two development opportunities in the East Midlands in 2022:

o One infill project with the potential to add c. 100 bbls/d and 0.35 mmstb 2P reserves in 2023 with an anticipated NPV10 of £3 million;

o A two-phased project to extend an existing field adding c.200 bbls/d and development of c. 1.0 mmstb 2P reserves with the subsequent phase having the potential to add an additional 500bbls/d and the addition of c.2mmstb 2P reserves.

· Shale:

o Whilst the effective moratorium remains in place, the Government has commissioned the British Geological Survey to advise on the latest scientific evidence around shale gas extraction.

o Domestic shale development can reduce higher carbon tax imports, reduce gas prices, improve our balance of payments and the country's tax revenues, and provide jobs.

o The Group holds a significant portfolio of shale licences, totalling 292,100 net acres with estimated Mean volumes of undiscovered GIIP of 93 TCF (net to IGas, independently assessed by D&M in 2016).

o Potential to deliver 5 production well pads, with each pad having up to 16 wells, which would supply 3 million homes with initial production within 12-18 months with the right Government support to rapidly accelerate the development of this strategic national resource .

· Deep geothermal:

o Made excellent progress with support from the UK Government - specific provision has been made for deep geothermal in the recently launched Green Heat Network Fund (GHNF);

o The GHNF Transition Scheme is a three year £288 million capital grant fund supporting the commercialisation and construction of new low and zero carbon heat networks including the drilling of deep geothermal wells and associated works;

o GHNF opened to applications in March 2022 and confirmed it will fund up to 50 percent of a project's total combined commercialisation and construction costs;

o Stoke-on-Trent will be the first project to apply to the fund and we are working with SSE to agree the Thermal Purchase Agreement by Q3 2022;

o Currently in discussions with six off takers, across six separate sites which equates to c.60-70 megawatts of installed heat generation; and

o Expect to announce the acquisition of our first site in the Manchester area in H1 2022.

· Collaborations announced with Cornish Lithium and CeraPhi Energy extending the geothermal portfolio

Reserves

· Reserves and resources updated in DeGolyer & MacNaughton (D&M) CPR of 31 December 2021

o 1P NPV10 of $139 million: 2P NPV10 of $190 million

o Reserves have, as anticipated, declined this year driven primarily by our 2021 production and higher operating cost assumptions.

IGas Group Net Reserves & Contingent Resources as at 31 December 2021 (MMboe)*

	1P	2P	2C
Reserves & Resources as at 31 December 2020	11.74	17.12	20.34
Production during the period	(0.71)	(0.71)	-
Additions & revisions during the period	(0.46)	(0.62)	-
Reserves & Resources as at 31 December 2021	10.57	15.79	20.34

* Oil price assumption of c. $67/bbl for 2022-2024 then escalated at an average rate of 2.5% thereafter

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 21 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/Virginia Bull/Jeremy Ellis

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

Henry Fitzgerald-O'Connor/James Asensio

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

Patrick d'Ancona/Finlay Thomson/Kendall Hill

Chairman's Statement

It is hard to believe that we have all lived through another 12 months of COVID-19 - a crisis unprecedented in living memory.

Against the backdrop of this crisis and its impact on commodity prices, market conditions and restrictions on movement of people and materials, IGas weathered the storm in 2021 with both motivation and determination. Operations, maintenance and project activities were all directly and indirectly impacted by COVID-19 which inevitably affected production. There has been a strong focus on health, safety and wellbeing across the business and further progress has been made in the Company's diversification strategy. Cash resources were also carefully managed, having taken a number of actions to conserve cash in the prior year.

As worldwide economic activity levels increased, there were fluctuations in commodity prices over the period. UK gas prices reached historic highs due to increasing worldwide demand, supply issues and competition for Liquified Natural Gas (LNG), reinforcing the need for the UK to maintain secure indigenous supplies of oil and gas as we transition to net zero by 2050.

Environmental, Social and Governance (ESG) issues remained a key priority during 2021. As a further commitment to corporate sustainability, we became a signatory to the United Nations Global Compact pledging to meet fundamental responsibilities in four areas: human rights, labour, environment and anti-corruption.

IGas recognises the need to respond to climate change and the critical role of the energy industry in addressing these environmental challenges. The Group's existing operational expertise as the UK's largest onshore operator gives us the opportunity to use our existing business platform to play an important role in the UK's transition to net zero.

Board

I have served on the Board of the Company since December 2012 and as Interim Non-executive Chairman since October 2019, and as announced at the start of the year, have decided to step down from the Board at the conclusion of the 2022 annual general meeting (AGM). Over the last 10 years, IGas has grown to be one of the largest onshore oil and gas players in the UK and is now embarking on the next chapter of its journey, as it positions itself at the heart of the UK energy transition.

I am delighted that Chris Hopkinson is to succeed me as Chairman. We welcomed Chris to the Board in January this year, as a Non-executive Director, and I know that he will be an effective leader for the Company. He has been very engaged in the business ahead of him taking up his role as Chair.

In February 2022, we also welcomed Kate Coppinger to the IGas Board who brings with her Board-level expertise, drawing on over 20 years advising energy companies.

We are delighted that we have been able to strengthen the diversity of the Board, which has been a key objective of the nomination committee. These appointments now bring us in line with the best practice as recommended by the QCA Code.

Hans Årstad, Non-executive Director, resigned from the Board at the May 2021 AGM. On behalf of the Board, I thank him for his contribution.

People

The strength of a business is built on the hard work and dedication of all its people and this year has highlighted the resilience of all our colleagues and their ability to work together in times of crisis. I would like to thank them for their outstanding work during an extremely demanding year.

Outlook

I sincerely hope that the worst of the pandemic is now behind us however, we are in unchartered geopolitical territory, with the unfolding atrocities in Ukraine. Our thoughts are with everyone whose lives have been affected by Russia's actions.

Clearly this will have far reaching impacts on society and on global commodity prices and need for energy independence.

In light of current, and likely to continue, high gas prices we must focus the debate on energy where gas contributes around 40% of the UK's energy requirements not solely on electricity. Over 80% of our homes are heated by gas and industry is reliant on it; this cannot in the short to medium term be replaced by wind or solar and under any of the Climate Change Committee's scenarios the UK needs gas beyond 2050.

Developing UK shale gas resources can reduce gas prices, reduce the country's carbon footprint by replacing imports, improve our balance of payments and the country's tax revenues, and lead to job creation in areas where they are most needed, as part of the Government's levelling up agenda.

Comparing UK spot gas prices with US spot gas prices at a fraction of the cost, demonstrates how a domestic gas supply can decouple gas prices from expensive LNG prices.

As a business, we remain firmly focused on cost and capital discipline whilst building our business for the future. We will continue to invest prudently in our existing cash-generative assets, to create future shareholder value and move ahead purposefully with our low-carbon energy businesses.

Chief Executive's Statement

Introduction

The impact of COVID-19 presented our business with major challenges this year in sustaining operations through restrictions and self-isolation. Supply chains too were impacted, bringing some additional delays and fluctuations to operational priorities.

As a result, our collective focus has been on keeping our employees, contractors, and other stakeholders safe by continuing to work from home where possible, maintaining social distancing measures and continuing to take all precautions to ensure risks were minimised. I would like to thank all of our employees for their dedication and focus throughout this pandemic.

Despite these challenging headwinds the business has, since the start of 2021, benefitted from a much-improved economic environment, most notably oil and gas prices which recovered from the very low levels experienced at the start of the previous year.

We have continued to pursue our strategy of maximising our UK onshore production whilst exposing shareholders to value creating opportunities in the energy transition space, principally through deep geothermal heat and hydrogen.

Operating Review

Production

Net production for the period averaged 1,962 boepd (2020: 1,907), with operations, maintenance and project activities all being directly and indirectly impacted by COVID-19. The COVID-19 pandemic presented a unique set of challenges for our production business. They comprised both direct and indirect consequences of managing the effects of the virus, some of which had an immediate impact and others that were extended over longer periods andwe had to prioritise essential (especially safety and environmentally critical) activities throughout the year.

We identified three key drivers to COVID-19 related production deferral; Internal Resourcing and External Resourcing and the External Supply Chain. Our analysis of the production impact during the period has shown fluctuations on a month-by-month basis. The average impact for the year was c.130 boepd. Excluding that impact, production for the year would have been 2,100 boepd.

Whilst we started 2022 with the challenge of a high number of operational staff isolating due to COVID-19, we anticipate net production in 2022 of c.2,000 boepd, assuming there are no further significant disruptions to our business.

We continue to focus our technical and operational expertise on offsetting the underlying natural decline in our fields through the execution of incremental production opportunities that demonstrate commercial benefit via our delivery assurance processes. Artificial lift optimisation remains a key continuous improvement objective in terms of cost management and production enhancement, with routine dynamic optimisation activities and specific intervention works sanctioned. This has included the introduction of innovative scale management technology, artificial lift type conversions, rod string improvements, rod pump deepening plus the expansion of the beam-gas compressor systems across more fields. In addition, we have continued to invest in our facilities to drive operational improvements such as replacing older power generation systems with newer, more efficient versions and the continued expansion and modernisation of our instrumentation systems.

As part of our decommissioning programme we completed the abandonment of Welton A31 and the zonal abandonment of Welton A4 during the period. In addition, in conjunction with the Net Zero Technology Centre, IGas is exploring alternative zonal abandonment technology that could significantly reduce abandonment costs for the UK oil and gas industry as a whole. Trials are expected to commence in 2022. In addition, we have initiated a well repurpose trial with CeraPhi Energy, a geothermal company specialising in oil and gas well repurposing which, if successful, may lead to future reuse of suspended wells.

It has been another challenging year in particular for those working on site but operating our assets in a safe, secure and environmentally responsible manner is fundamental to our business. We continue to work closely with all our regulators to ensure we at least meet, if not exceed our responsibilities.

Reserves and resources

CPR

In February 2022, IGas announced the publication of the full and final results 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 2021. The full report can be found on the IGas website www.igasplc/investors/publications-and-reports

IGas Group Net Reserves & Contingent Resources as at 31December 2021 (MMboe)

	1P	2P	2C
Reserves & Resources as at 31 December 2020	11.74	17.12	20.34
Production during the period	(0.71)	(0.71)	-
Revision of estimates	(0.46)	(0.62)	-
Reserves & Resources as at 31 December 2021	10.57	15.79	20.34

The audited 2P reserves have, as anticipated, declined this year driven primarily by our 2021 production and higher operating cost assumptions.

The report values our conventional assets at c. $190 million on a 2P NPV10 basis (based on a forward oil curve of c. $67/bbl for 2022-2024 and then escalated at an average rate of 2.5% thereafter).

Development

Conventional

The Welton (C-1) waterflood project was brought online in Q2 2021 and completed on budget with good results as anticipated, with capacity to inject c.400 bbls/d of water which is expected to increase field recovery by approximately 660 Mbbls and ramping up to over 100 bopd incremental production which will start to be realised in 2022. During 2021, Scampton North was on the lower end of expectation encountering higher than anticipated injection pressure, injecting c. 70 bbls/d of water. In March 2022, we completed a clean-out of the wellbore that has resolved the higher injection pressure issues. The injection well is now back online with initial positive results indicating a P50 outcome for the project which will increase the ultimate field recovery. These projects not only add incremental value but also improve our environmental impact by reducing emissions and reducing vehicle movements in water handling.

In the first quarter of 2022, work was completed to convert an existing, suspended well in the Stockbridge field to a water disposal well; this will allow for the resumption of c. 50 bbls/d of suspended production to be brought back on line. The project will also provide more operational flexibility in handling produced water in the Stockbridge area.

We are currently progressing two development opportunities in the East Midlands. The first is an infill drilling project which has the potential to add c. 100 bbls/d and 0.35 mmstb 2P reserves in 2023 with an anticipated NPV10 of £3 million. The second, is a larger appraisal/development project to extend one of our existing fields. This opportunity will be progressed in a phased approach, with a planning application to be submitted in 2022. If phase I is successful, this will be followed by further development drilling in subsequent years. The first phase of the project is targeting an additional c.200 bbls/d and development of c.1.0 mmstb 2P reserves with the subsequent development having the potential to add an additional 500bbls/d and the addition of c.2mmstb 2P reserves.

Shale

The Group holds a significant portfolio of shale licences, totalling 292,100 net acres with estimated Mean volumes of undiscovered GIIP of 93 TCF (net to IGas, independently assessed by D&M in 2016).

We know that the shales contain significant amounts of natural gas. In 2019, we drilled a shale well at Springs Road, just outside Misson, North Nottinghamshire, with our partners including Ineos, and had the cores (rock samples) analysed by Weatherford in the US. Through this analysis they estimate gas in place is 630 BCF/square mile. If applied to all our East Midland's acreage that would imply over 250 TCF of gas in place. Even at a conservative 10% recovery factor, 27 TCF of gas would satisfy the UK's requirements for nine years, from our acreage alone.

We welcome the Government's scientific review of shale gas, announced on 5 April 2022, to be undertaken by the British Geological Survey, which is expected before the end of June 2022.

If the UK Government were to lift the moratorium and allow activity to proceed through permitted development we have the potential to deliver 5 production well pads, with each pad having up to 16 wells, which would supply 3 million homes with initial production within 12-18 months. Total production is estimated at c.750 BCF from these 5 production pads.

However, activity is currently paused with all licences being held on a care and maintenance basis due to the effective moratorium on hydraulic fracturing for shale gas imposed by the UK Government in November 2019.

Deep Geothermal

The opportunity to decarbonise large-scale heat using deep geothermal energy in the UK is a significant one. We have made excellent progress in moving this forward with the UK Government, and specific provision has been made for deep geothermal in the recently launched Green Heat Network Fund (GHNF).

The GHNF Transition Scheme is a three year £288 million capital grant fund that will support the commercialisation and construction of new low and zero carbon heat networks including the drilling of deep geothermal wells and associated works. The GHNF opened to applications in March 2022 and confirmed that it will fund up to 50 percent of a project's total combined commercialisation and construction costs. As a developer of deep geothermal we are eligible to apply directly to the fund and will put forward a number of projects, the first of which will be the Stoke-on-Trent project.

We have continued to have positive discussions with the UK Government regarding future, longer-term financial support for the deep geothermal industry. We have had several meetings with senior ministers including the Secretary of State and a working group with the Department for Business, Energy and Industrial Strategy (BEIS) has been established to look at a financial model for the long-term support of deep geothermal heat.

In April 2021, a new industry report on the economic and environmental importance of UK deep geothermal resources by the ARUP Group and the Association for Renewable Energy and Clean Technology (REA) was published. The Report estimates that, with immediate government support, the UK could deliver 360 geothermal projects by 2050. This would include an estimated 12 projects being operational by 2025 with 1,300 jobs created and c.£100 million of investment flowing into the UK economy.

In June 2021, we received planning approval for the Stoke-on-Trent project from both Stoke-on-Trent City Council and Newcastle-under-Lyme. In September, we signed a Memorandum of Understanding (MoU) with SSE Heat Networks Limited (SSE) for the roll-out of the Stoke geothermal district heating project. The MoU grants exclusivity to each of SSE and GT Energy with regard to the project for a period of 12 months with certain milestones including executing a thermal purchase agreement in relation to the geothermal plant. SSE in turn have agreed a MoU with Stoke-on-Trent City council to work together to deliver a heat network across the city.

We are working with SSE towards agreeing the TPA for the offtake of geothermal heat in Q3 this year and subject to securing grant funding from the GHNF, this will enable the project to progress towards financial close in Q4 2022.

SSE is leading the way in developing the low-carbon assets and infrastructure required for the UK to reach its target of net zero emissions by 2050 and has set out their plans for a £1.2 billion investment in low carbon energy infrastructure over the next five years, to which geothermal is core in realising.

Following the confirmation of Government support through the GHNF we are currently reviewing additional sites for deep geothermal at strategic locations across England and we would expect to announce the acquisition of our first site in the Manchester area in H1 2022.

We are currently in discussions with six off-takers, across six separate sites which equates to c.60-70 MW of installed heat generation.

Closed-loop Geothermal

In September 2021, we announced a Heads of Terms (HoT) with CeraPhi Energy, developers and owners of a proprietary closed-loop geothermal technology. The intent is to jointly develop geothermal energy projects utilising specific oil and gas wells in IGas's asset portfolio and CeraPhi's technology.

A programme has been agreed with an initial single well to be repurposed at Nettleham, to the northeast of Lincoln. Following the repurposing, a period of testing will be undertaken.

This pathfinder project will be used to demonstrate the commercial potential for geothermal energy production from repurposing existing oil and gas assets for direct heat for agriculture, residential heating and cooling, and the development of hybrid energy systems generating both heat and power.

Hydrogen

Significant work has been undertaken in order to understand the potential for low carbon energy production from our existing asset base.

Last year we identified two sites in Surrey - Albury which has existing gas production and Bletchingley where we have been seeking a way to monetise the existing gas - as being suitable for the production of hydrogen utilising modular SMR technology.

At Albury, we submitted a planning application in July 2021 to generate 1000kg/day of hydrogen.

The Bletchingley application was submitted in late August 2021. This is a bigger project involving two SMR units with initial generation of 2000kg/day and a potential of up to 6000kg/day depending on reserves. Due to COVID-19 related backlogs we are now expecting both these applications to go to Surrey County Council's Planning Committee for determination in H1 2022.

The projects are being developed in phases, the first phase being to establish the principle of hydrogen production at the sites. The second, to produce blue hydrogen, is now being accelerated following positive feedback from key regulators and interest from local communities. However, we await clarification from the UK Government as to thresholds for carbon intensity for low carbon hydrogen following a consultation that closed in October 2021 before committing to a technological solution for blue hydrogen.

Discussions with potential off-takers for both projects are ongoing.

Carbon Capture and Storage (CCS)

Whilst the UK Continental Shelf offers significant future potential for CCS we believe that smaller, onshore carbon sequestration presents an opportunity to help better understand the development work required for the larger scale offshore facilities. Furthermore, a study by BEIS indicated that CO₂ transport to ports or points of sequestration is a major issue and many industrial facilities located centrally in the UK are under threat of becoming "stranded assets".

Our work at this stage is at a high level and extends to engagement with academia, industry, government and regulators.

We have joined an academic - industry consortium called Net Zero RISE. Its aim is to repurpose existing onshore oil and gas infrastructure as research sites for carbon sequestration, hydrogen storage and closed-loop geothermal technologies. The consortia brings together Newcastle, Oxford and Durham Universities with industry partners, including IGas, and has been established to support the UK's energy transition to net zero by reusing onshore infrastructure that is available now.

IGas has also been invited by the NSTA to take on a core role in the Bacton Energy Hub Project's Regulatory Special Interest Group (SIG) led by Hydrogen East. The UK onshore regulatory regime is complex and comprehensive and we have a strong track record of responsible and safe development and ongoing compliance. IGas brings extensive experience of developing complex energy projects to the Bacton project

The Bacton Energy Hub is envisaged to play a major role in the UK's energy future through the production of hydrogen from natural gas (with associated capture and storage of carbon dioxide) and from electrolysis powered by renewable and nuclear energy.

IGas will also be contributors to the Infrastructure SIG, led by Xodus and the Hydrogen Supply SIG, led by Summit Exploration and Production.

Lithium extraction from Geothermal Brines

In February 2022, IGas agreed a HoT with Cornish Lithium, a company that has secured extensive land and mineral rights in the south west of England. IGas and Cornish Lithium intend to jointly develop geothermal energy projects in areas where it is believed there are significant lithium resources. The projects will supply renewable heat to end users whilst lithium is extracted from the brines. IGas will bring its experience of well design, drilling and operations to the projects.

Solar

Another example of how we can leverage the Group's existing operational expertise and use our existing business platform to play an important role in the UK's transition to net zero was through the signing of a HoT with Iona Capital in October 2021. IGas and Iona, an investor with a long track record of successfully investing in UK renewable energy projects, will jointly develop utility scale solar farms in the UK, initially leveraging the strong landowner relationships the Company has through its long history of onshore oil and gas operations.

The first, of what is expected to be several similar scale projects, will be situated in southern England and will be 25-40MW in size. IGas will contribute its planning and infrastructure expertise, whilst Iona will provide non-recourse project finance. During the development phase, costs will be shared and throughout the project lifecycle, IGas and Iona will each own 50% of the project.

Outlook

The road ahead is an exciting one, but not without its challenges. The world still needs oil and gas for many decades to come but we must also consider our environmental footprint, particularly the greenhouse gases from our operations, and minimise those as much as possible. To meet this objective, we will deploy our technological skills to reduce our carbon footprint where we can, working with regulators and other stakeholders to deliver reduced emissions.

We have committed to an energy transition pathway and our operational expertise as the UK's largest onshore operator gives us the opportunity to use our existing business platform to play an important role in the UK's transition to net zero. Our sub-surface expertise for example, is relevant to both drilling for geothermal resources, and assessing the potential for carbon capture and storage.

Operationally, in the short-term, we will continue to focus on safe and responsible production of oil and gas bringing forward projects to final investment decision (FID) within our existing conventional portfolio that have good internal rates of return and short payback periods.

As we generate free cash flow we must be selective in our capital allocation to ensure the continued longevity of the cash generative production assets but also to help fund new initiatives and assets to repurpose in a readily accessible onshore environment.

Financial Review

Oil prices have recovered significantly since the start of 2021 hitting highs of c.$86/bbl in 2021, as the global economic recovery led to oil demand increasing faster than supply. Natural gas prices in Europe and the UK have also been very strong in 2021 with prices rising to over 400p/therm in the UK, a record due to supply constraints in a number of key producing regions and low oil inventories across Europe. The average GBP/USD exchange rate for the year was at £1:$1.38 (2020: £1: $1.29).

Production for the year averaged 1,962 boepd (2020: 1,907 boepd). The combination of improved pricing and production resulted in increased revenues of £37.9 million for the year (2020: £21.6 million) which was partially offset by the strengthening of sterling and a realised loss on hedging of £6.6 million (2020: realised gain of £4.6 million). Operating costs increased to £19.1 million (2020: £17.6 million) mainly due to higher electricity generation costs resulting in higher electricity sales volumes and revenues, higher production costs related to higher volumes, the restarting of higher cost fields which were shut in in 2020 and higher staff costs. These increases were partially offset by lower rates and transportation costs. DD&A decreased to £4.8 million (2020: £6.0 million) mainly due to the lower carrying value of assets in 2021 following the impairment to oil and gas properties in 2020. Underlying operating costs per boe, including costs relating to leases capitalised under IFRS 16, were £27.1 ($37.4) per boe for the year (2020: £25.8 ($33.3) per boe).

No impairment charge was recognised on the oil and gas properties for the year (2020: impairment of £38.5 million).

Adjusted EBITDA was £5.9 million (2020: £4.0 million) and underlying operating profit was £2.0 million (2020: underlying operating loss of £1.4 million), with the increases resulting primarily from improved revenues.

The Group's net debt was £12.2 million at 31 December 2021 (31 December 2020: £12.2 million) with higher operating cashflows being used to finance capital expenditure and Reserves Based Lending Facility (RBL) interest payments. The Group's RBL is subject to a semi-annual redetermination which was completed in November 2021 confirming an available facility limit of £19.3 million ($26.2 million).

Income statement

The Group recognised revenues of £37.9 million for the year (2020: £21.6 million). Group production for the year averaged 1,962 boepd (2020: 1,907 boepd). Revenues included £1.1 million (2020: £1.1 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 $68.5/bbl (2020: $39.1/bbl) and post-hedge $54.3/bbl (2020: $48.4/bbl). A loss of £6.6 million was realised on hedges due to the improvement in oil prices during the year. (2020: realised gain of £4.6 million). The average GBP/USD exchange rate for the year was £1: $1.38 (2020: £1: $1.29).

Cost of sales for the year were £23.9 million (2020: £23.5 million) including depreciation, depletion and amortisation (DD&A) of £4.8 million (2020: £6.0 million), and operating costs of £19.1 million (2020: £17.5 million). Operating costs were £1.6 million higher than the prior year due to higher costs from increased electricity generation and higher staff costs partially offset by lower rates and transportation costs. Operating costs include a cost of £1.0 million (2020: £1.0 million) relating to third party oil. The contribution received from processing this third party oil was £0.1 million (2020: £0.1 million).

Operating costs per barrel of oil equivalent (boe) increased to £27.1 ($37.4), excluding third party costs (2020: £25.8 ($33.3) per boe) as a result of the higher operating costs in the year.

Adjusted EBITDA in the year was £5.9 million (2020: £4.0 million). The gross profit for the year was £14.0 million (2020: gross loss of £1.9 million).

Administrative costs increased by £0.5 million to £5.8 million (2020: £5.3 million). The increase was due to higher staff costs, higher legal and professional costs relating to corporate activities and the dissolution of international subsidiaries and a lower allocation to capital projects during the year. This was partially offset by lower share-based payment and office rental costs.

No impairment charge was recognised on the oil and gas properties for the year.

Exploration and evaluation assets of £10.5 million were written off during the year (2020: £0.1 million) mainly related to the PEDL 200 licence,in which the basin edge defining Tinker Lane well was drilled in 2018. PEDL 200 and EXL 288 were relinquished during the period. This allows the Group to focus on its core Gainsborough Trough shale acreage.

Net finance costs were £3.9 million (2020: £2.2 million) primarily related to interest and amortisation of finance fees on borrowings of £1.1 million (2020: £1.3 million), the unwinding of discount on provisions of £1.9 million (2020: £1.5 million) and a foreign exchange loss of £0.2 million (2020: gain of £1.5 million). Interest on leases was £0.7 million (2020: £0.8 million).

The increase in oil prices during the year generated a net loss on oil price derivatives of £6.7 million (2020: gain £3.5 million).

A tax credit of £6.2 million was recognised mainly due to the increase in recognition of deferred tax asset relating to ring-fence tax losses as a result of a significantly improved oil price environment (2020: a tax credit of £2.0 million mainly due to the adjustment to losses brought forward due to Ring Fence Expenditure Supplement claims).

Cash flow

Net cash generated from operating activities for the year was £7.1 million (2020: £3.6 million). The increase was primarily due to higher revenue partially offset by a realised hedge cost and increased operating and administrative expenses.

The Group invested £4.8 million across its asset base during the year (2020: £8.4 million). £3.9 million was invested in our conventional assets primarily on production enhancement and operational improvements such as replacing older power generation systems with newer, more efficient models as well as the continued expansion and modernisation of instrumentation across our sites. £0.7 million was spent on working up additional exploration opportunities on conventional assets as well as 'care and maintenance' costs relating to shale licences.

The Group spent £0.4 million on its abandonment programme during the year mainly related to wells in the Welton field (2020: £1.3 million).

A net drawdown of £0.7 million ($1.0 million) (2020: £0.9 million ($1.0 million)) was made under our RBL and we paid £0.8 million ($1.0 million) in loan interest (2020: £0.9 million ($1.2 million)).

To protect against the volatile oil price and in accordance with the requirements of our RBL facility, the Group places commodity hedges for a period of up to 12 months. As at 31 December 2021, the Group had hedged a total of 336,000 bbls for 2022, using a combination of puts (114,000 bbls at an average downside protected price, net of premium, of $44.5/bbl) and fixed price swaps (216,000 bbls at an average fixed price of $67.9/bbl). In addition, we have hedged 15,000 bbls for Q1 23 using swaps at $95/bbl.

Cash and cash equivalents were £3.3 million at the end of the year (2020: £2.4 million).

Balance sheet

Net assets decreased by £4.7 million to £68.6 million at 31 December 2021 (2020: £73.3 million), mainly due to the impairment of exploration and evaluation assets of £10.5 million, offset by an increase in the net deferred tax asset of £6.2 million.

Changes to the estimate of decommissioning costs following an internal review increased both assets and liabilities by £3.3 million (2020: increase of £6.2 million).

At 31 December 2021, right-of-use assets were £7.0 million (2020: £7.7 million) and related lease liabilities were £7.2 million (2020: £7.5 million).

At 31 December 2021, the Group has a combined carried gross work programme of up to $216.4 million (£159.7 million) (2020: $218.0 million (£160.0 million)) from its partner, INEOS Upstream Limited.

Borrowings increased from £13.7 million to £14.8 million during the year due to net drawdowns of £0.7 million and a revaluation loss of £0.2 million and amortisation of capitalised fees of £0.2 million. Net debt at the year-end was £12.2 million (2020: £12.2 million).

	31 December 2021	31 December 2020
	£m	£m
Debt (nominal value excluding capitalised expenses)	(15.5)	(14.6)
Cash and cash equivalents	3.3	2.4
Net Debt	(12.2)	(12.2)

2022 Capital Expenditure

In 2022, we are forecasting a total £7.4 million of capital expenditure. This includes site improvements, near term incremental projects to generate c.70-100 boepd, as well as longer term development projects which have the potential to unlock a total of 2.5 million barrels of 2C resource and generate up to 8MW of power. In addition, we have £1.8 million of cash outflow in 2022 for projects executed towards the end of 2021.

We expect a cash outflow of c.£1.8 million for our abandonment programme in 2022, of which £0.4million relates to work carried out in 2021.

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 and ensures that appropriate mitigations are in place.

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 Group's operating cash flows have improved in 2021 as a result of improving commodity prices and we have successfully completed the 2021 year-end redetermination. However, 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 redetermined 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. We also assumed that our existing RBL facility is amortised in line with its terms but is not refinanced or extended resulting a reduction in the facility to $12 million from 1 July 2023. To mitigate these risks, the Group benefits from its hedging policy with 231,000 bbls currently hedged for Q2-Q4 2022 using swaps at an average price of $74/bbl and 129,000 bbls using puts with an average price, net of premiums, of $46/bbl. In addition, we have hedged 15,000 bbls for Q1 23 using swaps at $95/bbl.

Management has considered the impact of supply chain constraints on the Group's operations. We have seen some impact on production during 2021 due to supply chain constraints and the need for members of our staff to self-isolate and have developed a number of contingency plans to mitigate this. Many of our sites are remotely manned and we are well equipped as a business to ensure we maintain business continuity recognising that our production comes from a large number of wells in a variety of locations and we have flexibility in our off-take arrangements.

Crude oil prices rose during 2021 and into 2022 as increasing COVID-19 vaccination rates, loosening pandemic-related restrictions, and a growing economy resulted in global petroleum demand rising faster than petroleum supply. The Ukraine war and sanctions imposed on Russia have caused disruption to international trade and dislocations in energy markets, tightening oil and gas markets significantly and causing prices to rise further while increasing price volatility.

The Group's base case cash flow forecast was run with average oil prices of $96/bbl for 2022 falling to an average of $85/bbl in 2023 based on the forward curve. A foreign exchange rate of $1.35/£1 was used. Our forecasts show that the Group will have sufficient financial headroom to meet its financial covenants based on the existing RBL facility for the 12 months from the date of approval of the financial statements. Management has also prepared a downside case with average oil prices at $90/bbl for H1 2022; $76/bbl for H2 2022 and $68/bbl for 2023 and an average exchange rate of $1.37/£1.00 for 2022 and $1.42/£1.00 for 2023. Our downside case also included an average reduction in production of 5% over the period. Management expects to execute further hedging during the course of the year, which will provide further protection in the downside case. Management would also take mitigating actions including delaying capital expenditure and additional reductions in costs in order to remain within the Group's debt liquidity covenants should such actions be necessary if prices were to decrease further. All such mitigating actions are within management's control. We have not assumed any extensions or refinancing to the RBL. 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.

Based on the analysis above, 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.

Stephen Bowler

Chief Executive Officer

Adjusted EBITDA and underlying operating (loss)/profit are used by the Group, alongside IFRS measures for both internal performance analysis and to help shareholders, lenders and other users of the annual report to better understand the Group's performance in the period in comparison to previous periods and to industry peers.

Adjusted EBITDA
	2021	2020
	£m	£m
Loss before tax	(12.3)	(44.1)
Net finance costs	3.9	2.2
Changes in fair value of contingent consideration	(0.6)	0.2
Depletion, depreciation & amortisation	4.9	6.3
Impairments	10.5	38.6
EBITDA	6.4	3.2
Lease rentals capitalised under IFRS 16	(1.5)	(1.8)
Share-based payment charge	0.9	1.0
Unrealised loss on hedges	0.1	0.8
Redundancy costs	-	0.6
Acquisition costs	-	0.2
Adjusted EBITDA	5.9	4.0

Underlying operating profit/(loss)
	2021	2020
	£m	£m
Operating loss	(9.0)	(42.1)
Lease rentals capitalised under IFRS 16	(1.5)	(1.8)
Depreciation charge of right-of-use assets	1.0	1.3
Share-based payment charge	0.9	1.0
Impairments	10.5	38.6
Unrealised loss on hedges	0.1	0.8
Redundancy costs	-	0.6
Acquisition costs	-	0.2
Underlying operating profit/(loss)	2.0	(1.4)

Realised Price Per Barrel
	2021	2020
	$	$
Realised price per barrel	54.3	48.4
G&A per BOE	11.4	10.3
Other operating cost (underlying)	29.0	24.3
Well services	5.3	5.4
Transportation and storage	3.1	3.6

Underlying operating profit/(loss)
	2021	2020
	£m	£m
Revenues	37.9	21.6
Adjusted EBITDA	5.9	4.0
Underlying operating profit/(loss)	2.0	(1.4)
Loss after tax	(6.0)	(42.1)
Net cash from operating activities	7.1	3.6
Net debt¹	12.2	12.2
Cash and cash equivalents	3.3	2.4
Net assets	68.6	73.3

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

CONSOLIDATED INCOME STATEMENT

FOR THE YEAR ENDED 31 DECEMBER 2021

	Note	Year ended 31 December 2021 £000	Year ended 31 December 2020 £000
Revenue	2	37,916	21,578
Cost of sales:
Depletion, depreciation and amortisation		(4,794)	(5,974)
Other costs of sales		(19,105)	(17,553)
		(23,899)	(23,527)
Gross profit/(loss)		14,017	(1,949)

Administrative expenses		(5,827)	(5,331)
Exploration and evaluation assets written-off	6	(10,463)	(67)
Oil and gas assets impairment	7	-	(38,535)
(Loss)/gain on derivative financial instruments		(6,715)	3,520
Gain on foreign exchange contracts		-	229
Operating loss		(8,988)	(42,133)

Finance income	3	2	1,472
Finance costs	3	(3,850)	(3,648)
Changes in fair value of contingent consideration	10	570	(180)
Other income		-	415
Loss from continuing activities before tax		(12,266)	(44,074)
Income tax credit	4	6,230	1,985
Loss after tax from continuing operations attributable to shareholders' equity		(6,036)	(42,089)
Loss after taxation from discontinued operations after tax from discontinued operations		(203)	(11,060)
Net loss for the year attributable to shareholders' equity		(6,239)	(53,149)
Loss attributable to equity shareholders from continuing operations:
Basic loss per share	5	(4.82p)	(34.35p)
Diluted loss per share	5	(4.82p)	(34.35p)
Loss attributable to equity shareholders including discontinued operations:
Basic loss per share	5	(4.98p)	(43.37p)
Diluted loss per share	5	(4.98p)	(43.37p)

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

FOR THE YEAR ENDED 31 DECEMBER 2021

	Note	Year ended 31 December 2021 £000	Year ended 31 December 2020 £000
Loss for the year		(6,239)	(53,149)
Other comprehensive income/(loss) for the year:
Currency translation adjustments recycled to the income statement		326	10,781
Currency translation adjustments		-	(19)
Total other comprehensive income for the year		326	10,762
Total comprehensive loss for the year		(5,913)	(42,387)

CONSOLIDATED BALANCE SHEET

AS AT 31 DECEMBER 2021

	Note	31 December 2021 £000	31 December 2020 £000
ASSETS
Non-current assets
Intangible assets	6	38,322	46,711
Property, plant and equipment	7	74,583	72,439
Right-of-use assets		7,017	7,658
Restricted cash	8	410	410
Deferred tax asset	4	38,176	31,945
		158,508	159,163
Current assets
Inventories		1,092	1,023
Trade and other receivables		5,509	4,095
Cash and cash equivalents	8	3,289	2,438
Derivative financial instruments		-	314
		9,890	7,870
Total assets		168,398	167,033
LIABILITIES
Current liabilities
Trade and other payables		(6,863)	(5,247)
Derivative financial instruments		(1,410)	(1,271)
Lease liabilities		(815)	(694)
Provisions	10	(2,419)	(293)
		(11,507)	(7,505)
Non-current liabilities
Borrowings	10	(14,836)	(13,695)
Other payables		(770)	(1,160)
Lease liabilities		(6,362)	(6,820)
Provisions	10	(66,307)	(64,550)
		(88,275)	(86,225)
Total liabilities		(99,782)	(93,730)
Net assets		68,616	73,303
EQUITY
Capital and reserves
Called up share capital		30,333	30,333
Share premium account		102,992	102,906
Foreign currency translation reserve		3,799	3,473
Other reserves		36,257	35,117
Accumulated deficit		(104,765)	(98,526)
Total equity		68,616	73,303

These financial statements were approved and authorised for issue by the Board on 6 April 2022 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 2021

	Called up share capital 000	Share premium account £000	Foreign currency translation reserve* 000	Other reserves** 000	Accumulated deficit 000	Total equity 000
At 1 January 2020	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
Loss for the year	-	-	-	-	(6,239)	(6,239)
Share options issued under the employee share plan	-	-	-	1,140	-	1,140
Issue of shares	-	86	-	-	-	86
Currency translation adjustments	-	-	326	-	-	326
At 31 December 2021	30,333	102,992	3,799	36,257	(104,765)	68,616

* The foreign currency translation reserve represents exchange gains and losses on translation of previously held foreign currency subsidiaries' net assets and results, and on translation of those subsidiaries' intercompany balances, which formed part of the net investment of the Group. During the year ended 31 December 2021, we commenced the liquidation process for the remaining of these foreign currency subsidiaries' and control over these entities has been transferred to the administrators .

** 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 previously held by the IGas Employee Benefit Trust (EBT) to satisfy awards held under the Group incentive plans; 4) capital contribution reserve which arose following the acquisition of IGas Exploration UK Limited; and 5) merger reserve which arose on the reverse acquisition of Island Gas Limited.

CONSOLIDATED CASH FLOW STATEMENT

FOR THE YEAR ENDED 31 DECEMBER 2021

	Note	Year ended 31 December 2021 £000	Year ended 31 December 2020 £000
Cash flows from operating activities:
Loss from continuing activities before tax for the year		(12,266)	(44,074)
Depletion, depreciation and amortisation*		4,903	6,303
Abandonment costs/other provisions utilised		(356)	(1,348)
Share-based payment charge		878	1,025
Exploration and evaluation assets written-off	6	10,463	67
Oil and gas assets impairment	7	-	38,535
Change in unrealised loss on oil price derivatives		138	1,048
Change in unrealised loss/(gain) on foreign exchange contracts		315	(229)
Changes in fair value of contingent consideration	10	(570)	180
Other income		-	(415)
Finance income	3	(2)	(1,472)
Finance costs	3	3,850	3,648
Other non-cash adjustments		9	(10)
Operating cash flow before working capital movements		7,362	3,258
(Increase)/decrease in trade and other receivables and other financial assets		(1,637)	1,514
Increase/(decrease) in trade and other payables		1,699	(1,187)
(Increase)/decrease in inventories		(69)	170
Cash from continuing operating activities		7,355	3,755
Cash used in discontinued operating activities		(221)	(156)
Taxation paid - continuing operating activities		-	-
Net cash from operating activities		7,134	3,599
Cash flows from investing activities:
Purchase of intangible exploration and evaluation assets		(734)	(2,314)
Purchase of property, plant and equipment		(3,905)	(6,152)
Purchase of intangible development assets		(167)	(67)
Cash acquired on acquisition of subsidiary		-	77
Other income received		-	4
Interest received		2	11
Net cash used in investing activities		(4,804)	(8,441)

Cash flows from financing activities:
Cash proceeds from issue of ordinary share capital		40	56
Proceeds from disposal of shares held in EBT net of costs		-	4
Drawdown on Reserves Based Lending facility	8	1,432	5,544
Repayment on Reserves Based Lending facility	8	(756)	(4,645)
Repayment of principal portion of lease liability		(747)	(973)
Repayment of interest on lease liabilities		(684)	(795)
Interest paid	8	(812)	(940)
Net cash used in financing activities		(1,527)	(1,749)
Net increase/(decrease) in cash and cash equivalents in the year		803	(6,591)
Net foreign exchange difference		48	835
Cash and cash equivalents at the beginning of the year		2,438	8,194
Cash and cash equivalents at the end of the year	8	3,289	2,438

* Depletion, depreciation and amortisation includes £1.1 million (2020: £1.3 million) relating to right-of-use assets.

CONSOLIDATED FINANCIAL STATEMENTS - NOTES

FOR THE YEAR ENDED 31 DECEMBER 2021

1 Accounting policies

(a) Basis of preparation of financial statements

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 2022.

The financial information for the year ended 31 December 2021 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 2020 have been delivered to the Registrar of Companies and those for 2021 will be delivered following the Company's annual general meeting. The auditor has reported on the 2021 financial statements and their report was unqualified. The report 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 2020. 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 2021. 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 2022 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 2021 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 2021 £000	Year ended 31 December 2020 £000
Oil sales	33,254	20,546
Electricity sales	2,048	438
Gas sales	2,614	594
	37,916	21,578

Revenues of approximately £17.4 million and £15.9 million were derived from the Group's two largest customers (2020: £11.9 million and £8.7 million) and are attributed to the oil sales.

As at 31 December 2021, there are no contract assets or contract liabilities outstanding (2020: nil).

3 Finance income/(costs)	Year ended 31 December 2021 £000	Year ended 31 December 2020 £000
Finance income:
Interest on short-term deposits	2	11
Foreign exchange gains	-	1,461
Finance income	2	1,472

Finance expense:
Interest on borrowings	(812)	(940)
Amortisation of finance fees on borrowings	(267)	(387)
Foreign exchange losses	(151)	-
Unwinding of discount on decommissioning provision	(1,659)	(1,466)
Unwinding of discount on contingent consideration	(277)	(60)
Finance charge on lease liability for assets in use	(684)	(795)
Finance expense	(3,850)	(3,648)

4 Income tax credit

(i) Tax credit on loss from continuing ordinary activities	Year ended 31 December 2021 £000	Year ended 31 December 2020 £000
Current tax:
Charge on loss for the year	-	-
Total current tax charge	-	-
Deferred tax:
(Credit)/charge relating to the origination or reversal of temporary differences	(6,360)	1,409
Credit due to tax rate changes	(393)	(99)
Debit/(credit) in relation to prior years	523	(3,295)
Total deferred tax credit	(6,230)	(1,985)
Tax credit on loss on ordinary activities	(6,230)	(1,985)

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 charges at a combined average rate of 40% (2020: 40%).

A reconciliation of the UK statutory corporation tax rate (applicable to oil and gas companies) applied to the Group's loss before tax to the Group's total tax credit is as follows:

	Year ended 31 December 2021 £000	Year ended 31 December 2020 £000
Loss from continuing ordinary activities before tax	(12,266)	(44,074)
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% (2020: 40%)	(4,906)	(17,630)
Deferred tax debit/(credit) in respect of the prior year	523	(3,295)
Tax effect of expenses not allowable for tax purposes	2,085	(740)
Tax effect of differences in amounts not allowable for supplementary charge purposes*	24	6
Impact of profits or losses taxed or relieved at different rates	(2)	461
Net increase/(decrease) in unrecognised losses carried forward	(6,911)	7,781
Net increase in unrecognised temporary taxable differences	3,422	11,533
Tax rate change	(393)	(99)
Other	(72)	(2)
Tax credit on loss on ordinary activities	(6,230)	(1,985)

* 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:

	2021 £000	2020 £000
Asset at 1 January	31,945	29,961
Tax (charge)/credit relating to prior year	(523)	3,295
Tax credit/(charge) during the year	6,360	(1,409)
Tax charge arising due to the changes in tax rates	393	99
Other	1	(1)
Asset at 31 December	38,176	31,945

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

	31 December 2021 £000	31 December 2020 £000
Accelerated capital allowances	(9,041)	(7,791)
Tax losses carried forward	34,809	26,633
Investment allowance unutilised	1,837	1,542
Decommissioning provision	8,263	7,390
Unrealised gains or losses on derivative contracts	2,083	2,126
Share-based payments	162	2,090
Right-of-use asset and liability	63	(45)
Deferred tax asset	38,176	31,945

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 £174.2 million (2020: £130.0 million) of ring-fence corporation tax losses.

The Group has further tax losses and other similar attributes carried forward of approximately £184.1 million (2020: £215.4 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 financial years.

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 £6.0 million (2020: a loss after taxation from continuing operations attributable to shareholders' equity of £42.1 million) and the weighted average number of ordinary shares outstanding during the year of 125.3 million (2020: 122.5 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 2021, there are 11.7 million potentially dilutive employee share options (31 December 2020: 10.9 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 2021	Year ended 31 December 2020
Basic loss per share - ordinary shares of 0.002 pence each	(4.82p)	(34.35p)
Diluted loss per share - ordinary shares of 0.002 pence each	(4.82p)	(34.35p)
Loss for the year attributable to equity holders of the parent from continuing operations - £000	(6,036)	(42,089)
Weighted average number of ordinary shares in the year- basic EPS	125,269,135	122,537,605
Weighted average number of ordinary shares in the year- diluted EPS	125,269,135	122,537,605

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 2021	Year ended 31 December 2020
Basic loss per share - ordinary shares of 0.002 pence each	(4.98p)	(43.37p)
Diluted loss per share - ordinary shares of 0.002 pence each	(4.98p)	(43.37p)
Loss for the year attributable to equity holders of the parent - £000	(6,239)	(53,149)
Weighted average number of ordinary shares in the year- basic EPS	125,269,135	122,537,605
Weighted average number of ordinary shares in the year- diluted EPS	125,269,135	122,537,605

6 Intangible assets

	2021			2020
	Exploration and evaluation assets £'000	Development costs £'000	Total £'000	Exploration and evaluation assets £'000	Development costs £'000	Total £'000
At 1 January	43,421	3,290	46,711	41,455	-	41,455
Acquisitions	-	-	-	-	3,223	3,223
Additions	888	188	1,076	2,090	67	2,157
Changes in decommissioning*	998	-	998	(57)	-	(57)
Impairment	(10,463)	-	(10,463)	(67)	-	(67)
At 31 December	34,844	3,478	38,322	43,421	3,290	46,711

*The decommissioning asset increased in line with the decommissioning liability following a review of the estimate at 31 December 2021 (note 10).

Exploration and evaluation assets

Exploration costs impaired in the financial year to 31 December 2021 were £10.5 million (2020: £0.1 million) of which £10.0 million related to the PEDL 200 (Tinker Lane) licence and £0.5 million impairment of capitalised decommissioning assets relating to previously written off licences. PEDL 200, the licence in which the basin edge defining well Tinker Lane was drilled, and EXL 288 have been relinquished during the financial year. This allows the Group to focus on its core Gainsborough Trough shale acreage, defined as those licences in which a significant thickness of the Gainsborough shale is, or is predicted, to be present.

Further analysis by location of assets is as follows:

North West: The Group has £6.4 million (2020: £6.1 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 appeal has been recovered by the Secretary of State and we are awaiting the outcome. As the outcome is still undetermined, it is appropriate to keep the carrying value of the asset capitalised.

East Midlands: The Group has £23.2 million (2020: £32.8 million) of capitalised exploration expenditure relating to our core area in the Gainsborough Trough which includes PEDL's 12, 139, 140, 169 and 210. The Gainsborough Trough is an area with significant shale potential. Following the moratorium on fracking, we continue to work with the NSTA, 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 industry representatives and the work is ongoing. During the discussions, industry representatives reiterated their belief that lifting the moratorium would give the UK greater energy security by reducing the likelihood of supply concerns and reducing the carbon footprint of UK energy and, given increasing energy prices and the longer term demand for gas, that the government should consider shale a nationally strategic resource for development. As the industry discussions regarding the moratorium are still ongoing, the Directors believe that it is appropriate to continue to capitalise this asset.

Conventional assets: The Group has £5.2 million (2020: £4.5 million) of capitalised exploration expenditure which relates to our conventional assets including PEDL 235 and PL 240.

At 31 December 2021, the Group has a combined carried gross work programme of up to $216 million (£160 million) (2020: $218.0 million (£160.0 million)) from its partner, INEOS Upstream Limited. In 2021, 0.3m (2020: £0.4 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.

Development costs

The development costs relate to assets acquired as part of the GT Energy acquisition in 2020. 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 2021 and assessed it for impairment. The development of the Stoke-on-Trent project has taken longer than anticipated principally due to COVID-19 related delays. During 2021, we received planning approval for the Stoke-on-Trent project from both Stoke-on-Trent City Council and Newcastle-under-Lyme. In September, we signed a Memorandum of Understanding (MoU) with SSE Heat Networks Limited (SSE) for the roll-out of the Stoke geothermal district heating project. The MoU grants exclusivity to each of SSE and GTE with regard to the project for a period of 12 months with certain milestones including executing a heat offtake agreement in relation to the geothermal plant. SSE in turn have agreed a MoU with Stoke-on-Trent City Council to work together to deliver a heat network across the city. We are also in dialogue with the Government regarding grant funding to support the project.

Although the development of the project has been delayed, this does not materially impact the overall economics and, therefore, no impairment of development costs has been recognised for the year (2020: £nil). The principal assumptions are the unit price and discount rate. A 10% reduction in price would result in a decline of the recoverable amount by £3.8m. An increase in the discount rate assumed of 1% (from 8.3% to 9.3%) would result in a decline of the recoverable amount by £5.1m. There would be no impairment in either case.

7 Property, plant and equipment

	2021			2020
	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	209,225	2,951	212,176	197,875	3,660	201,535
Additions	3,700	-	3,700	5,212	1	5,213
Disposals/write-offs	-	(521)	(521)	(117)	(710)	(827)
Changes in decommissioning*	2,297	-	2,297	6,255	-	6,255
At 31 December	215,222	2,430	217,652	209,225	2,951	212,176
Accumulated Depreciation and Impairment
At 1 January	138,233	1,504	139,737	94,940	2,063	97,003
Charge for the year	3,801	52	3,853	4,875	151	5,026
Disposals/write-offs	-	(521)	(521)	(117)	(710)	(827)
Impairment	-	-	-	38,535	-	38,535
At 31 December	142,034	1,035	143,069	138,233	1,504	139,737
NBV at 31 December	73,188	1,395	74,583	70,992	1,447	72,439

*The decommissioning asset increased in line with the decommissioning liability following a review of the estimate at 31 December 2021 (note 10).

Expenditure during the year related to the Welton and Scampton North waterflood projects and continued investment in our assets to drive operational improvements.

Impairment of oil and gas assets

Year ended 31 December 2021

The Group reviewed the carrying value of oil and gas assets as at 31 December 2021 and assessed it for impairment indicators. The impact of the downward revision of the reserves estimate is offset by an improving economic outlook and a significantly improved oil price environment. On this basis, management concluded that there were no impairment indicators as at 31 December 2021. However, as at 31 December 2021, continued uncertainty exists regarding the future impact of the COVID-19 pandemic including the emergence of new variants which may have a negative impact on economic activity and therefore on the demand for oil. As a result, management concluded that there were no impairment reversal indicators as at 31 December 2021 and that a reversal of prior years' impairments was not appropriate.

Year ended 31 December 2020

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 the first half of 2020 and the uncertainty surrounding the pandemic triggered an impairment review of oil and gas assets 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 assets for impairment as at 31 December 2020, which resulted in an additional impairment of £3.9 million.

Cash generating units (CGUs) for impairment purposes are the group of sites whereby technical, economic and/or contractual features create underlying interdependence in cash flows. The Group 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
Oil Price (Brent)	$50-$55/bbl for the years 2021-2022 and $60/bbl thereafter
USD/GBP foreign exchange rate	$1.37:£1.00 for 2021 and $1.35:£1 thereafter
Post-tax discount rate	8.3%

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. This was primarily due to an increase in the decommissioning provision (note 19) and 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.

8 Cash and cash equivalents

	31 December 2021 £000	31 December 2020 £000
Cash at bank and in hand	3,289	2,438

31 December

2021

£000

31 December

2020

£000

Cash at bank and in hand

3,289

2,438

The cash and cash equivalents do not include restricted cash.

Restricted cash

	31 December 2021 £000	31 December 2020 £000
Non-current	410	410

31 December

2021

£000

31 December

2020

£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 2021 £000	31 December 2020 £000
Cash and cash equivalents	3,289	2,438
Borrowings - including capitalised fees	(14,836)	(13,695)
Net debt	(11,547)	(11,257)
Capitalised fees	(669)	(937)
Net debt excluding capitalised fees	(12,216)	(12,194)

	2021			2020
	Cash and cash equivalents	Borrowings	Total	Cash and cash equivalents	Borrowings	Total
	£000	£000	£000	£000	£000	£000
At 1 January	2,438	(13,695)	(11,257)	8,194	(13,071)	(4,877)
Interest paid on borrowings	(812)	-	(812)	(940)	-	(940)
Drawdown of RBL	1,432	(1,432)	-	5,544	(5,544)	-
Repayment of RBL	(756)	756	-	(4,645)	4,645	-
Foreign exchange adjustments	48	(198)	(150)	835	610	1,445
Other cash flows	939	-	939	(6,550)	-	(6,550)
Other non-cash movements	-	(267)	(267)	-	(335)	(335)
At 31 December	3,289	(14,836)	(11,547)	2,438	(13,695)	(11,257)

9 Borrowings

	31 December 2021 £000	31 December 2020 £000
Reserve-Based Lending Facility (RBL) - secured (non-current)	(14,836)	(13,695)

31 December

2021

£000

31 December

2020

£000

Reserve-Based Lending Facility (RBL) - secured (non-current)

(14,836)

(13,695)

The carrying amounts of each of the Group's financial liabilities included within borrowings are considered to be a reasonable approximation of their fair value.

Reserves-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 USD LIBOR plus 4.0%, matures in September 2024 and is secured on IGas Energy plc's assets. The Group is continuing preparation for transition to incorporate alternative risk-free rates and is monitoring the market and discussing the potential changes with its counterparties in order to effectively transition from USD LIBOR to alternative risk-free rates. Management does not expect any material impact on its financial position and performance resulting from this transition.

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 2021, the Group had successfully completed the November 2021 redetermination which confirmed an available facility limit of $26.2 million (2020: $31.7million).

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 ("EBITDAX" as defined in the RBL agreement) for the previous 12 months shall be less than or equal to 3.5:1. The Group complied with its covenants for the financial year ended 31 December 2021.

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).

10 Provisions

	2021			2020
	Decommissioning provisions £'000	Contingent consideration £'000	Total £'000	Decommissioning provisions £'000	Contingent consideration £'000	Total £'000
At 1 January	(61,819)	(3,024)	(64,843)	(55,101)	-	(55,101)
Acquisitions	-	-	-	-	(2,784)	(2,784)
Utilisation of provision	778	-	778	946	-	946
Unwinding of discount	(1,659)	(277)	(1,936)	(1,466)	(60)	(1,526)
Reassessment of decommissioning provision	(3,295)	-	(3,295)	(6,198)	-	(6,198)
Changes in fair value of contingent consideration	-	570	570	-	(180)	(180)
At 31 December	(65,995)	(2,731)	(68,726)	(61,819)	(3,024)	(64,843)

	2021			2020
	Decommissioning provisions £'000	Contingent consideration £'000	Total £'000	Decommissioning provisions £'000	Contingent consideration £'000	Total £'000
Current	(2,139)	(280)	(2,419)	-	(293)	(293)
Non-current	(63,856)	(2,451)	(66,307)	(61,819)	(2,731)	(64,550)
At 31 December	(65,995)	(2,731)	(68,726)	(61,819)	(3,024)	(64,843)

Decommissioning provision

The Group spent £0.8 million on decommissioning activities during the year (2020: 0.9 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 40 years from year end (2020: 1 to 37 years). The provisions are based on the Group's internal estimate as at 31 December 2021. 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 based on a planned programme of abandonments but also include a provision to be spent in 2022-2025 on preparing for the abandonment campaign, abandoning wells and restoring sites which for regulatory, integrity or other reasons fall outside the planned campaign. The wells to be decommissioned in 2022 and 2023 are in line with management's discussions with the regulator. 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 1.2% to 3.0% is used in the calculation of the provision as at 31 December 2021 (2020: Risk free rate range of 1.20% to 3.00%).

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 £4.0 million.

Management also performed sensitivity analysis to assess the impact of changes to the undiscounted future cost of abandoning wells and restoring sites on the Group's decommissioning provision balance. A 10% increase in the undiscounted future cost would result in an increase in the decommissioning provision by £6.6m million.

Contingent consideration

The carrying value of contingent consideration relates to the GT Energy acquisition in 2020. The change in fair value is primarily related to the movement in fair value of IGas plc shares from the previous year end, 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 a 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 (2020: £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 (2020: £0.2 million).

12 Subsequent events

On 26 January 2022, the Group issued 144,232 Ordinary £0.00002 shares in relation to the Group's SIP scheme. The shares were issued at £0.1455 resulting in share premium of £20,983.

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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