IGAS.L Regulatory News (IGAS)

THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION.

9 April 2020

IGas Energy plc (AIM: IGAS)

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

Full year results for the year ended 31 December 2019

IGas, one of the leading producers and explorers of hydrocarbons onshore in Britain, announces its full year results for the year ended 31 December 2019.

Results Summary

Notes

1 Includes £53.9 million of exploration costs relating to NW shale assets

Operational Summary

· Net production averaged 2,325 boepd for the year (2018: 2,258 boepd), within guidance, while operating costs for the year were c. $30/boe (at an average 2019 exchange rate of £1:$1.28) (2018: $31.9/boe). 

· Whilst we still anticipate net production of between 2,250 - 2,450 boepd and operating costs of c.$27.5/boe (assuming an exchange rate of £1:$1.20) in 2020, the challenging environment and material uncertainty that exists could have future impacts on the business.

· DeGolyer & MacNaughton (D&M) CPR as at 31 December 2019 - IGas net reserves and resources* (MMboe):

o Significant 2P reserves replacement ~277% (1P ~192%)

o 2P NPV10 of $183 million*

*based on forward oil curve of 2020 $61.78/bbl; 2021 $58.39/bbl; 2022 $56.97/bbl; 2023 $56.54/bbl; 2024 $57.67/bbl

· Scampton and Welton waterflood projects expected to be online in summer 2020.

· Significant exploration growth potential - identified prospectivity > 1.8bn bbls OIIP across the portfolio.

Corporate and Financial Summary

· $40 million Reserve Base Loan agreed in October 2019:

o Drawn down in November 2019 to repay secured bonds;

o Greater available capital to grow our conventional business; and

o Reduction of financing costs of c. $1 million on an annualised basis.

· £16.5 million of free operating cash flow generated in 2019 from the conventional business before administrative expenses, capital investment and finance costs.

· Cash balances as at 31 December 2019 of £8.2 million and net debt of £6.2 million.

· Underlying profit of £4.6 million (2018: £4.0 million). Loss after tax of £49.8 million (2018: loss £21.4 million) due to non-cash exploration write-offs of £53.9 million (2018: £29.1 million).

· As at 31 December 2019, the Group had hedged a total of 420,000 bbls for 2020, using a combination of puts (292,500 bbls at an average downside protected price of $51.4/bbl) and fixed price swaps (127,500 bbls at an average fixed price of $58.7/bbl).

· In light of the current recent weakness of sterling against the dollar, we hedged $9 million for 2020 at an average rate of $1.17:£1 and $3 million for 2021 at an average rate of $1.20:£1 in March 2020.

· In response to the current oil price environment, we have revised our capex for 2020 to c. £6 million; comprising c. £2 million on our production assets and c. £4 million on development assets.

· In response to the changing environment we are looking to maximise returns from our existing sites which could include electricity generation and storage.

· We are aligning our approach to sustainability with a number of the UN Sustainable Development Goals.

Commenting today Stephen Bowler, Chief Executive Officer, said:

"2019 saw production well within guidance and operating costs marginally better than forecast.

IGas benefits from having a diversified production base which generated £14 million in operating cash flow in 2019. Having refinanced our debt in October 2019, now with a tenure out to 2024, which alongside hedging for over 50% of our 2020 production at US$53/bbl, means we are as well placed as possible in this highly volatile marketplace.

I was delighted to report our significant reserves replacement, at over 250%, and a 1P reserves life index of over 10 years, underpinning both the longevity and potential upside in our portfolio.

We have limited committed capex in 2020, and given the oil price environment have trimmed our capital expenditure budget by £4 million to £6 million, with a focus on key capital projects. We have a good portfolio of projects and will flex our capital spending plans, if and when the oil price improves from its current depressed level.

The Coronavirus pandemic is a deeply concerning international public health emergency which everyone hopes to see contained quickly. Our primary focus is the health and safety of our employees and other stakeholders and we have acted promptly in that regard. Many of our sites are remotely manned and at this stage we are well equipped as a business to ensure we maintain business continuity. We continue to liaise and co-operate with all the relevant regulators.

Currently, the Group's operations continue to function as normal. However, we cannot rule out future impacts on the business given the material uncertainty that exists in the current environment."

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 19 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

Julian Tedder, Chief Financial 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/Tejas Padalkar 

BMO Capital Markets (Joint Corporate Broker) Tel: +44 (0)20 7653 4000

Tom Rider/Neil Elliot/Jeremy Low/Tom Hughes

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 

Chairman's Statement

We continued to deliver on our strategic priorities and generated strong operating cash flow in 2019, alongside further reducing our financing costs through a $40 million Reserve Based Lending Facility, which we secured in October 2019.

Nothwithstanding the uncertain political backdrop throughout the year and challenging operational conditions, we have delivered production well within guidance, made progress in advancing incremental production projects and made a potentially world-class gas discovery at our Springs Road well site.

In November 2019, the UK Government announced an effective moratorium on hydraulic fracturing in Britain, based on analysis of one well in Lancashire 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. We have been working, and will continue to work closely, with the relevant regulators to demonstrate that we can operate safely and environmentally responsibly. We have done this to date in our shale business, and across our existing c. 100 conventional wells that have been operating onshore UK for many decades.

As an onshore operator, we have, and must continue to have, a deep understanding of the potential environmental impacts and any mitigating actions we must take. Each site and basin can have substantially different geology. The OGA Report found that susceptibility to seismicity depends strongly on a location's specific geology with the mere presence of faulting or the parameters of the injection possibly of less importance.

Whilst we are cognisant that the consumption of fossil fuels has an impact on the environment, we maintain that the oil and gas industry is an essential component in delivering secure, efficient and cost-effective energy, as the world tries to balance its energy requirements, and is a key enabler in the transition to increased supply of renewable energy. Delivering a domestic source of affordable energy is key to a nation's security of supply, growth of its economy, heating homes and making a contribution to satisfying the growth of energy demand.

We are committed to supporting the British Government's target of reducing greenhouse gas emissions to net zero by 2050.

The Committee on Climate Change (CCC) in its May 2019 report, clearly forecast a very significant UK gas demand out to 2050 and beyond - approximately 70% of 2019 gas demand still existing in 2050 in a net zero scenario. Under the CCC's recommended pathway to net zero CO2, this gas would be used as both a feedstock for making hydrogen and a backup supply for generating electricity, and they have recommended that we use domestically produced gas. Without new supplies of gas it is expected that we will be importing over 80% of our gas requirements by 2050.

Engaging with communities local to our sites, and earning and maintaining our social licence to operate is imperative to our success as a business. We endeavour to build respectful, long-term relationships and earn the trust of those who host our activities.

Trust can only be earned, and kept, if people see that we share their concerns and hopes for the future. They can only see that if we are transparent about what we do and why we do it. Transparency goes beyond publishing financial results; it is about being as open as we can be with all our stakeholders.

The more transparent we are about our activities, the better equipped our investors, communities and wider society are to decide whether we merit their trust.

Across the Company we strive to achieve the highest standards of health, safety and environmental protection. All of our production and drilling operations retained their ISO 14001 and 9001 certifications and we were awarded the ROSPA Presidents Award again, representing 13 years of commitment to Occupational Health and Safety.

Board changes

In May 2019, Hans Årstad was appointed as a Non-executive Director, exercising the right of KKR to take a seat on the Board through their 14.7% investment in IGas. We welcome Hans to the Board.

In October 2019, our Chairman, Mike McTighe stepped down for personal reasons. We thank Mike for his considerable contribution to the Company and valued leadership over the last three years.

People

All the teams around the business have worked incredibly hard during 2019. Production teams in keeping the volumes on track, finance and legal teams in securing the new reserves based lending facility, our drilling and operational teams for the Springs Road well which was drilled significantly ahead of schedule and budget, and lands, planning and project teams for securing permissions and advancing projects through to the execution phase. Thanks to all the support teams around the business; it is you supporting all these activities that enable us to achieve success.

Outlook

The Coronavirus pandemic is a deeply concerning international public health emergency which everyone hopes to see contained quickly. Our primary focus is the health and safety of our employees and other stakeholders and we have acted promptly in that regard.

We continue to monitor the situation closely and act within Government guidelines and to that end we have worked up a number of contingency plans should our operations be significantly affected by the coronavirus.

In February 2020, the oil price began to be affected by the global spread of COVID-19 and the resultant reduction in oil demand. This situation has since been compounded by the failure of OPEC to reach an agreement on constraining supply and the position of Saudi Arabia to increase output. 

Whilst we have better financial flexibility and a reduced overall cost of debt, we have re-evaluated our priorities in the short-term to ensure we weather the current oil price disruption. However, if oil prices remain low for a prolonged period of time we cannot rule out future impacts on the business given the material uncertainty that currently exists.

In the longer term, we will continue to drive to maximise our existing assets, many of which still have significant potential, whilst developing new assets to deliver future shareholder value, as we ensure IGas is an important part of the onshore UK energy transition.

Chief Executive's Statement

Introduction

I am pleased to report a solid set of results for 2019, which reflect a good operational performance across the business and continued progress delivering our strategy of optimising our existing assets and seeking to provide future energy solutions through our world-class shale gas discovery at Springs Road in the Gainsborough Trough.

In October 2019, we signed a $40 million Reserve Base Lending facility with BMO Capital Markets. The facility reduces our overall cost of debt and provides the financial flexibility for continued investment into our conventional portfolio to grow our production over the coming years.

Over recent weeks we have witnessed an unprecedented global situation in the form of COVID-19 combined with depressed oil prices.

Currently, the Group's operations continue to function as normal. Of our 148 employees those that are able to work from home have been doing so, in a phased way, since early March 2020. We have approximately 65% of staff who are in operational roles and have been identified as key workers by the Government. Many of these are "lone" workers who had already been 'identified, trained and equipped' pre-COVID-19 so the pandemic does not require a significant change to existing procedures or protocols.

In respect of IGas's operational sites, our facilities are designed with operational control provisions that ensure safe and compliant operation within the normal operational envelope and automated shutdown functionality should there be an unexpected excursion outside of these routine conditions. In addition to these local control and shutdown systems IGas has the ability to monitor the site operations from remote locations utilising its digital systems which allow efficient intervention by operational and maintenance staff to be coordinated alongside the standard monitoring visits that are conducted by our staff.

However, the inbuilt control systems are able to make any site and well safe without the need for human intervention and we continue to liaise with all our regulators.

Whilst we are reliant on transporting oil to UK refineries, we have significant capacity for managing our production inventory. All key contractors in terms of transport and refineries are also classified as key workers.

Operating Review

Production

Production for the year was 2,325 boepd which was in the upper end of the production target range of 2,200 - 2,400 boepd.

Production in our East Midlands assets benefited from the success of waterflood and optimisation activities conducted in 2018, alongside 2019 projects being brought online ahead of schedule and wells performing in the upper range of expectation. These efforts resulted in not only the complete offset of the annual decline rate but an uplift of overall production for the year compared to that delivered in 2018. These results were also mirrored in our southern operations, where following the successful completion of our routine maintenance and integrity programs, and the implementation of a series of optimisation works we were also able to finish 2019 at a higher production rate than that delivered in 2018. Our Gas to Wire and Gas to Grid facility at Albury continued to improve during 2019 and by the close of the year we were capable of achieving a peak maximum daily production rate of c. 200 boepd from the combined export streams.

Reserves and Resources

In February 2020, 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 2019. The full report can be found on the IGas website www.igasplc/investors/publications-and-reports

IGas Group Net Reserves & Contingent Resources as at 31st Dec 2019 (MMboe)

The report confirms a continuing high reserves replacement of 2P reserves of approximately 277% (1P ~192%) reflecting the good performance of our production assets and progression of projects demonstrating the significant upside that remains in our conventional portfolio. 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. $180 million on a 2P NPV10 basis, an increase of $20 million compared to 2018 (based on forward oil curve of 2020 $61.78/bbl; 2021 $58.39/bbl; 2022 $56.97/bbl; 2023 $56.54/bbl; 2024 $57.67/bbl).

Development - Conventional

We continue to mature our production portfolio opportunities and achieved final approvals for our Scampton North Waterflood project during the first half of 2019. This c. £2.0 million project to install water injection capability and convert a suspended well into a water injector has advanced significantly during the year, with the project remaining on schedule and budget ready to deliver initial production in the summer of 2020. This secondary recovery project (waterflood) is forecast to double the current output of the field to over 200 bopd and increase the ultimate recovery from the field. The D&M CPR estimated 180 Mbbl of incremental 2P (Proved plus Probable Undeveloped) 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).

Following the success of the first phase of the Welton waterflood project, the technical team recommended an additional opportunity in the southern section of the Welton Field in the Tupton & Deep Hard Rock Reservoirs. The project involves converting a suspended production well (WC01) to a water injector to improve reservoir sweep and increase field recovery by c. 660 Mbbl (2P reserves) with a peak incremental production rate of c. 100 bopd.

The Company's estimated base-case project economics have an IRR of over 100% and a NPV10 of c.£7.0 million (which assumes a long term oil price of $55/bbl). Positive well integrity and injectivity tests allowed full sanction of the project in the third quarter of 2019, with engineering activities, regulatory approvals and long lead items all being progressed in line with the project schedule, with full completion planned by the summer of 2020.

This is part of the wider Welton Full Field Development and as well as increasing production, will aid in de-risking further injection projects into other areas of the field and provide critical infrastructure to assist with water disposal and support future rationalisation work across the Welton sites.

We have continued to mature other projects across the portfolio as we seek to maximise returns on our existing operations and infrastructure and will flex our capital spending plans, if and when the oil price improves from its current depressed level.

For example, Bletchingley is a Gas Monetisation, gas-to wire project which recently received planning approval. The project involves the installation of up to 6MW of electrical generation capability at the Bletchingley Central site fuelled by gas from the Bletchingley 2 well, which is currently suspended. However, in light of the current oil price, we have reduced our expenditure in progressing projects such as this significantly and will not take this project further forward until energy prices improve.

As part of our ongoing active portfolio management, we relinquished two non-core PEDLs in the East Midlands, PEDL 137 and PEDL 337.

Development - Shale

We mobilised a drill rig and ancillary equipment to our Springs Road site in North Nottinghamshire in early January 2019 and spudded the well on 22 January 2019. In mid-February 2019, we encountered shales on prognosis, at c. 2,200 metres depth and drilled through a significant hydrocarbon bearing shale sequence, including the Upper and Lower Gainsborough Shale.

The well sought to assess three target zones: the Gainsborough Shale; the Millstone Grit and the Arundian Shale. All three targets were encountered, with c.400 m of Gainsborough Shale, the primary target, with key shale attributes such as Total Organic Content, kerogen type, and clay content akin to world class shale plays observed in North America. 

IGas acquired 147 metres of core within the Gainsborough Shale, the first extensive core sample from this basin, which has subsequently been analysed by Stratum Reservoir (formerly Weatherford Labs) in their laboratories in both the UK and the USA. The results from the core analysis confirm that a nationally significant hydrocarbon resource is present in the Gainsborough Trough.

The key characteristics of the Gainsborough Shale in the SR-01 well compare favourably to commercial shale operations observed in North America such as the Eagle Ford, Barnett and the Marcellus. The core results indicate a mature, organic rich source rock with good porosity confirming favourable gas resource density, and, additionally, the low clay content in large sections of the Gainsborough shale is an encouraging indication of the suitability for effective hydraulic fracture stimulation.

The analysis we have undertaken will help delineate the resource potential and help refine the subsequent appraisal programme. Working with our joint venture partners, IGas will now consider the attributes of the data set alongside reprocessed 3D seismic for the area. This will allow us to commence planning for both a future potential appraisal programme and a pilot development within the Gainsborough Trough, a geologically well understood and quiescent basin.

As well as obtaining extremely positive geological results, the two well drilling programme was highly successful operationally. Both wells were drilled significantly under budget, principally due to faster than expected drilling and coring rates. The Springs Road well, the deepest penetration into the Gainsborough Trough to date, was 25% under budget, despite obtaining 50% more core than planned. Through our local sourcing programme, our direct East Midlands spend through the two well drilling programme was in excess of £10 million, supporting local, skilled jobs. Throughout operations we were compliant with all stringent planning permissions and environmental permits for both sites and have been commended on the high standard of our operations by regulators and the local community. Whilst protest did occur during the drilling of the well at Springs Road, the level of protest was negligible and generally took the form of monitoring as opposed to obstruction.

The well that was drilled at Tinker Lane, which delineated the southern extent of the Gainsborough Trough, was plugged and abandoned earlier in the year and the site was fully restored to farmland and handed back to the landowner in September 2019, ahead of schedule.

In the North West, the Ellesmere Port appeal was recovered by the Secretary of State (SoS) at the end of June 2019 in order to determine a decision. The Planning Inspectorate then set a deadline for the report and recommendation by the inquiry inspector of 23 January 2020. The recommendation was sent to the SoS in early January 2020 and a decision was expected around 8 April 2020. We have been informed that, similar to other decisions, this has now been delayed until further notice.

In November 2019, the UK government announced an effective moratorium on the process of hydraulic fracturing in England based on a report by the Oil and Gas Authority (OGA) which found that it is not currently possible to accurately predict the probability or magnitude of earthquakes linked to fracking operations. The Report found that susceptibility to seismicity depends strongly on a location's specific geology with the mere presence of faulting or the parameters of the injection possibly of less importance. Each site and basin can have substantially different geology.

The company operates multiple licences across the East Midlands and in the North West. In the East Midlands along with the OGA, we are seeking to simplify and focus the various work programmes so that more rapid and directed appraisal and then development of the shale resource can take place. As such all licences are now on 2014 model clauses and have linked work plans.

The OGA has granted three-year extensions to the initial terms on the following 14th round, Company operated licences: PEDL 189, PEDL 235, PEDL 257, PEDL 273, PEDL 278, PEDL 305, PEDL 316 and PEDL 326.

Moving resources to reserves

Significant exploration potential exists in our prospective resources.

In early July 2019, we announced plans for a proposed new site in the Weald basin on PEDL 235, which IGas owns and operates 100%. The intention is to drill up to two wells to explore and evaluate the resource potential of both the Portland Sandstones and the Kimmeridge Micrites.

The Portland Sandstone has an existing gas discovery (IGas 2C resources includes c. 2.1 MMBoe http://www.igasplc.com/media/40892/dm-2019-ye-cpr-2020.pdf and technical studies conducted by the IGas team have concluded that there is significant upside potential for the Portland reservoir to be considerably larger with 5-10 MMboe of recoverable gas. Additionally, the underlying Kimmeridge Micrite formations, has the potential for a large additional resource.

Work has temporarily ceased on this project but when energy prices improve we will seek to submit a planning application given the significant returns available. As part of the planning process, IGas would undertake community consultation to take account of feedback from local residents before submitting the full planning application.

Diversifying our energy portfolio

IGas has a wide land portfolio across the East Midlands and the Weald basin where our well sites, gathering centres and pipelines are located. As a part of broadening the Company's approach to energy production, not least in light of its intentions to play an important role in the UK's energy transition, work has commenced on assessing various sites for their suitability for electricity generation and storage as well as bio-methane production. Given the current energy price environment we do not see these projects coming to fruition in the short term.

Outlook

Given the fall in oil prices, we have reviewed our capital expenditure programme for the year and reduced it principally to maintenance capex, abandonment and capital for projects already in execution. We will continue to review our priorities to ensure we weather any prolonged depressed oil price scenario. There remains, however, material uncertainty of the potential impact of Covid-19 on the Group's operational activities, future commodity prices and the outcome of the May 2020 redetermination of the RBL.

The greater than 250% 2P reserves replacement demonstrates the significant upside in our conventional portfolio and we continue to identify and progress projects with short-term growth potential and good returns even in this oil price environment.

The UK currently imports in excess of 50% of its energy requirements. As we transition to becoming independent from the EU and focus on our climate change ambitions, there is a growing need to develop domestic energy sources, including oil and gas, which have both economic and environmental advantages compared to imports.

Whilst there is a clear need for oil and gas in a 2050 net zero environment, we have also begun to look at ways of maximising returns from our sites and high grading for potential opportunities for electricity generation, storage and bio-methane production, as we seek to ensure IGas positions itself as a flexible deliverer of a variety of energy sources to the UK.

I am proud of our response, as a business, to the COVID-19 pandemic and want to thank all our colleagues for their professionalism and "can do" attitude in such difficult times. We continue to monitor and respond to the situation as it develops and believe that we will come out of this a stronger and more cohesive Company than ever before.

Financial Review

Results for the year

Oil prices remained volatile in 2019 with the average monthly price of Brent crude ranging between $59/bbl and $71/bbl. The lower average price of $64/bbl for the year versus $71/bbl for 2018 had a negative impact on our revenues. The average GBP/USD exchange rate for the year was £1: $1.28 (2018: £1: $1.34) which positively impacted revenue for the year.

For the year ended 31 December 2019 adjusted EBITDA was £13.8 million (2018: £10.8 million) whilst a loss was recognised from continuing activities after tax of £49.8 million (2018: loss £21.4 million). The main factors driving the movements between the years were as follows:

· Revenues decreased to £40.9 million (2018: £42.9 million) principally due to lower oil prices and a 3% decrease in oil sales volumes. The decrease was partially offset by a weaker average sterling to US dollar exchange rate and increased gas sales from our Albury field which commenced production in November 2018;

· Other costs of sales decreased to £20.5 million (2018: £21.9 million). Operating costs were £1.4 million lower than the prior year due to the capitalisation of operating lease costs of £1.7 million on adoption of IFRS 16 and a refund for rent and rates. The decrease was partially offset by an increase in regulatory, production and workover costs;

· Administrative expenses decreased by £1.0 million to £4.5 million (2018: £5.5 million). A continued focus on costs resulted in lower staff, external consultants and premises costs;

· The £53.9 million exploration expense relates primarily to our shale assets in the North West. In November 2019, the UK Government announced an effective moratorium on the process of hydraulic fracturing in England. We will now work with industry partners and government and should the moratorium be lifted we would focus on our core area of the Gainsborough Trough in the short to medium term. (2018: £29.1 million related to PEDL 145 Doe Green, an Albury well and various relinquished licences);

· Goodwill of £4.8 million relating to the acquisition of Dart shale assets has been written off due to the moratorium announced by the government in November 2019; and

· A tax credit of £9.3 million was recognised mainly due to the recognition of a deferred tax asset relating to ring-fence tax losses (2018: a tax credit of £3.7 million mainly due to the recognition of a deferred tax asset relating to ring-fence tax losses).

New Debt Facility Signed

IGas signed a $40 million senior secured Reserve-Based Lending Facility (RBL) with BMO Capital Markets (BMO) in October 2019.

In addition to the committed $40 million RBL, a further $20 million accordion facility is available on an uncommitted basis, subject to new bank commitments. The RBL has a five-year term, an interest rate of LIBOR plus 4.0% and matures in September 2024. 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. The Company also exercised its call option and issued a redemption notice with respect to all outstanding bonds (Secured Bonds) pursuant to the 10 per cent. IGas Energy PLC Senior Secured Callable Bond Issue 2013/2018 - ISIN NO 001 0673791. The Secured Bonds were redeemed at par value (100%) plus accrued interest on the redeemed amount up until, but not including, the settlement date of the call option on 19 November 2019. The proceeds from the new RBL were used to repay the Secured Bonds and will be used to fund development opportunities in the conventional portfolio and for general corporate purposes.

Income statement

The Group recognised revenues of £40.9 million for the year (2018: £42.9 million). Group production for the year averaged 2,325 boepd (2018: 2,258 boepd). Revenues included £2.4 million (2018: £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 $61.7/bbl (2018: $67.0/bbl) and post-hedge $60.1/bbl (2018: $57.4/bbl). A loss of £1 million was realised on hedges during the year primarily relating to the premium cost of puts (2018: realised loss of £5.5 million). The average GBP/USD exchange rate for the year was £1: $1.28 (2018: £1: $1.34) which positively impacted revenue for the year.

Cost of sales for the year were £29.6 million (2018: £28.8 million) including depreciation, depletion and amortisation (DD&A) of £9.1 million (2018: £6.8 million), and operating costs of £20.5 million (2018: £21.9 million). Operating costs were £1.4 million lower than the prior year due to a decrease relating to the re-classification of operating leases under IFRS 16 of £1.7 million and a refund for rent and rates, partially offset by an increase in regulatory, production and workover costs. Operating costs include a cost of £2.2 million (2018: £2.3 million) relating to third party oil. The contribution received from processing this third party oil was £0.2 million (2018: £0.2 million). 

Operating costs per barrel of oil equivalent (boe) were £23.6 ($30.1), excluding third party costs (2018: £23.6 ($31.9) per boe). The reduction was due to lower absolute operating costs and higher production volumes.

Adjusted EBITDA in the year was £13.8 million (2018: £10.8 million). Gross profit for the year was £11.3 million (2018: £14.2 million). Administrative costs decreased by £1.0 million to £4.5 million (2018: £5.5 million) principally due to a reduction in staff, external consultants and premises costs.

Exploration costs written off of £53.9 million relates to our shale assets in the North West as we plan to focus on our core area of the Gainsborough Trough in the short to medium term (2018: £29.1 million).

Net finance costs were £3.4 million (2018: £3.9 million) primarily related to interest on borrowings of £1.9 million (2018: £1.9 million) and the unwinding of discount on provisions of £1.3 million (2018: £1.1 million), finance charges relating to right-of-use assets £0.7 million (2018: £nil), offset by a net foreign exchange gain of £0.3 million, principally on US$ denominated debt and bank balances (2018: loss £0.9 million). A loss of £0.7 million was incurred relating to the refinancing of debt including the write-off of costs relating to the bond which had previously been capitalised.

The Group made a loss on oil price derivatives of £3.3 million for the year due to the premiums on options placed in 2019 and an increase in underlying prices impacting hedges placed in 2018 (2018: loss £0.7 million) and a gain on foreign exchange hedges of £0.3 million (2018: loss £0.2 million).

A tax credit of £9.3 million was recognised mainly due to the recognition of a deferred tax asset relating to an increase in the recoverability of ring-fence tax losses (2018: a tax credit of £3.7 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 £12.0 million (2018: £12.9 million). The decrease was primarily due to lower revenue and an increase in working capital, offset by a decrease in administrative expenses and lower payments to counterparties in respect of realised hedges.

The Group invested £6.4 million across its asset base during the year (2018: £10.6 million). £3.7 million was invested in our conventional assets including the Scampton North Waterflood project, the Welton water injection project and the installation of gas pump compressors on additional sites, resulting in additional production during the year. We continued to invest in new projects to increase production across our existing sites. We invested £2.7 million in unconventional assets in relation to our shale development programme including the Group's net share of the cost of drilling a vertical well at Tinker Lane and costs to progress the Ellesmere Port planning appeal.

The Group also continued its abandonment programme and spent £1.8 million on abandoning five wells during the year.

Following a successful refinancing, IGas repaid £21.4 million ($27.6 million) of principal on its Norwegian bond borrowings to bondholders during the year. (2018: repaid £1.7 million ($2.3 million)). The Group made a net drawdown of £14.7 million ($19.0 million) on its new reserves-based loan facility. IGas paid £2.0 million ($2.6 million) in interest (2018: £1.8 million ($2.3 million)).

To protect against the volatile oil price, the Group places commodity hedges for a period of up to twelve months. As at 31 December 2019, the Group had hedged a total of 420,000 bbls for 2020, using a combination of puts (292,500 bbls at an average downside protected price of $51.4/bbl) and fixed price swaps (127,500 bbls at an average fixed price of $58.7/bbl).

Cash and cash equivalents were £8.2 million at the end of the year (2018: £15.1 million).

Balance sheet

Net assets decreased by £48.6 million to £113.1 million at 31 December 2019 (2018: £161.7 million), mainly related to an impairment of intangible exploration and evaluation assets and goodwill of £58.7 million, offset by an income tax credit of £9.3 million.

Changes to the estimate of decommissioning costs following an internal review increased both assets and liabilities by £7.7 million.

The Group adopted IFRS 16 Leases (effective 1 January 2019) resulting in the capitalisation of leasing costs of £7.7 million and the recognition of a lease liability of £7.2 million as at 31 December 2019.

At 31 December 2019, the Group has a combined carried gross work programme of up to $214 million (£161 million) (2018: $220 million (£170 million)) from its partner, INEOS Upstream Limited. In 2019, £7.3m (2018: £9.2 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.

At 31 December 2019, the Group's oil derivative instruments had a net negative fair value of £0.2 million (2018: net positive fair value of £2.2 million).

Borrowings decreased from £21.0 million to £13.1 million following the refinancing carried out during the year as, under the new financing arrangements, there is no requirement to maintain a minimum cash balance and repayments can be made in the short-term using excess cash.

Net debt at the year end, being the nominal value of borrowings less cash and cash equivalents, was £6.2 million (2018: £6.4 million).

Disposal of Non-core Fields

As announced in July 2019, we were unable to agree a transaction with Onshore Petroleum Limited and consequently all non-core assets will now remain with IGas.

Adjusted EBITDA

Adjusted EBITDA and underlying Operating Profit are considered by the Company to be a useful additional measure to help understand underlying performance.

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 forecasts for the Group are regularly produced based on, inter alia, management's best estimate of:

· The Group's production and expenditure forecasts;

· Future oil prices;

· The level of available facilities under the group's RBL; and

· Foreign exchange rates.

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.

In the first quarter of 2020, the oil price has been affected by the global spread of COVID-19 and the resultant reduction in oil demand. This situation has since been compounded by the failure of OPEC to reach an agreement on constraining supply and the decision of several countries to increase output. At the date of this report, there remains significant uncertainty over the impact of COVID-19 on future global demand for oil and therefore the price of oil.

The ability of the Group to operate as a going concern is dependent upon the future oil prices and foreign exchange rates as they impact the continued generation of future cash flows and the loan facility available 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. To mitigate these risks, the Group benefits from its hedging policy with 420,000 bbls hedged at an average minimum price of $53.6/bbl for 2020. The Group also has $12 million of foreign exchange hedges in place at rates between $1.17-$1.20:£1 for the period to 30 June 2021. Furthermore, the Group's net reserves position has increased by 1.5 mmboe during 2019 which will partially offset any impact of lower prices in its RBL facility at the next redetermination in May 2020.

Management has 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 COVID-19. 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 (all of which are on land and in the UK) and we have flexibility in our off-take arrangements, as we transport oil via road. In this regard, we continue to liaise and co-operate with all the relevant regulators.

The Group's base case going concern model was run with average oil prices of $32/bbl for April to December 2020 rising to $45/bbl from January 2021 and a foreign exchange rate of $1.20:£1 during the period. Our forecasts show that the Group will have sufficient financial headroom to meet its financial covenants based on the existing RBL facility, as well as an estimate, based on management's knowledge and past experience, of the outcome of the next half-yearly redetermination due in May 2020, and the following redetermination date in December 2020, albeit the level of the facility available to us is dependent on the facility provider, BMO, and is beyond our control.

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 the following assumptions:

· Oil prices at $20/bbl in the second quarter of 2020 rising to $30/bbl in the fourth quarter of 2020 and $43-$45/bbl in 2021. As this assumption is lower than external current forward curves, management considers this is a reasonable downside scenario that reflects further potential reductions in price caused by the failure of OPEC to reach an agreement on constraining supply and lower demand from reduced industrial activity caused by COVID-19. This downside is partially mitigated by the commodity hedges the Group has in place. However, oil price is outside the Company's control and this could be lower should there be further market disruption either from COVID-19, or OPEC disagreements;

· No change to the level of available RBL loan facility during the forecast period as this reflects longer term oil price assumptions that have been considered in conjunction with recent discussions with the RBL facility provider;

· A reduction in production of 10% to reflect a disruption risk to operational and production related activities from the COVID-19 crisis. As the Group is providing a government designated essential service and due to the large number of operational wells, the impact of COVID-19 on production has to date been very limited and has been assumed to remain so as management does not currently foresee wells needing to be shut down due to the impact of COVID-19. Management therefore considers this assumption represents a reasonable downside in this uncertain time based on management's experience of previous unplanned shut downs;

· Exchange rates of $1.20:£1 for 2020 and $1.25:£1 for 2021 to reflect a downside caused by the weakening of the dollar later in the period. This downside is partially mitigated by the currency hedges the Group has in place; and

· Includes the impact of action management could take to reduce cash outflow, including delaying capital expenditure and additional reductions in costs in order to remain within the Company's debt liquidity covenants based on the Group's expected RBL redeterminations in May 2020 and December 2020. All such mitigating actions are within management's control and could be actioned within the required time frame.

In this downside scenario, our forecast shows that the Group will have sufficient liquidity and 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 further, the Company 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 is material uncertainty over future commodity prices, the outcome of the May 2020 redetermination of the RBL and the potential impact of COVID-19 on the Group's operational activities. 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 Julian Tedder

Chief Executive Officer Chief Financial Officer

8 April 2020 8 April 2020

CONSOLIDATED INCOME STATEMENT

FOR THE YEAR ENDED 31 DECEMBER 2019

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

FOR THE YEAR ENDED 31 DECEMBER 2019

CONSOLIDATED BALANCE SHEET

AS AT 31 DECEMBER 2019

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

FOR THE YEAR ENDED 31 DECEMBER 2019

* 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 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 2019

CONSOLIDATED FINANCIAL STATEMENTS - NOTES

FOR THE YEAR ENDED 31 DECEMBER 2019

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 Financial Reporting Standards (IFRS) and International Financial Reporting Interpretation Committee (IFRIC) interpretations adopted for use by the European Union, with those parts of the Companies Act 2006 applicable to companies reporting under IFRS and with the requirements of the United Kingdom Listing Authority (UKLA) Listing Rules, this announcement does not contain sufficient information to comply with IFRS. The Group will publish full financial statements that comply with IFRS in May 2020.

The financial information for the year ended 31 December 2019 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 2018 have been delivered to the Registrar of Companies and those for 2019 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 2019. 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 2018. 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 2019. These did not have a material impact on the accounting policies, methods of computation or presentation applied by the Group, except for IFRS 16 Leases. The Group had to change its accounting policies as a result of adopting IFRS 16. The Group elected to adopt the new rules under the modified retrospective approach but recognised the cumulative effect of initially applying the new standard on 1 January 2019.

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 2020 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 2019 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

The Group continues to closely monitor and manage its liquidity risks. Cash forecasts for the Group are regularly produced based on, inter alia, management's best estimate of:

· The Group's production and expenditure forecasts;

· Future oil prices;

· The level of available facilities under the group's RBL; and

· Foreign exchange rates.

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.

In the first quarter of 2020, the oil price has been affected by the global spread of COVID-19 and the resultant reduction in oil demand. This situation has since been compounded by the failure of OPEC to reach an agreement on constraining supply and the decision of several countries to increase output. At the date of this report, there remains significant uncertainty over the impact of COVID-19 on future global demand for oil and therefore the price of oil.

The ability of the Group to operate as a going concern is dependent upon the future oil prices and foreign exchange rates as they impact the continued generation of future cash flows and the loan facility available 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. To mitigate these risks, the Group benefits from its hedging policy with 420,000 bbls hedged at an average minimum price of $53.6/bbl for 2020. The Group also has $12 million of foreign exchange hedges in place at rates between $1.17-$1.20:£1 for the period to 30 June 2021. Furthermore, the Group's net reserves position has increased by 1.5 mmboe during 2019 which will partially offset any impact of lower prices in its RBL facility at the next redetermination in May 2020.

Management has 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 COVID-19. 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 (all of which are on land and in the UK) and we have flexibility in our off-take arrangements, as we transport oil via road. In this regard, we continue to liaise and co-operate with all the relevant regulators.

The Group's base case going concern model was run with average oil prices of $32/bbl for April to December 2020 rising to $45/bbl from January 2021 and a foreign exchange rate of $1.20:£1 during the period. Our forecasts show that the Group will have sufficient financial headroom to meet its financial covenants based on the existing RBL facility, as well as an estimate, based on management's knowledge and past experience, of the outcome of the next half-yearly redetermination due in May 2020, and the following redetermination date in December 2020, albeit the level of the facility available to us is dependent on the facility provider, BMO, and is beyond our control.

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 the following assumptions:

· Oil prices at $20/bbl in the second quarter of 2020 rising to $30/bbl in the fourth quarter of 2020 and $43-$45/bbl in 2021. As this assumption is lower than external current forward curves, management considers this is a reasonable downside scenario that reflects further potential reductions in price caused by the failure of OPEC to reach an agreement on constraining supply and lower demand from reduced industrial activity caused by COVID-19. This downside is partially mitigated by the commodity hedges the Group has in place. However, oil price is outside the Company's control and this could be lower should there be further market disruption either from COVID-19, or OPEC disagreements;

· No change to the level of available RBL loan facility during the forecast period as this reflects longer term oil price assumptions that have been considered in conjunction with recent discussions with the RBL facility provider;

· A reduction in production of 10% to reflect a disruption risk to operational and production related activities from the COVID-19 crisis. As the Group is providing a government designated essential service and due to the large number of operational wells, the impact of COVID-19 on production has to date been very limited and has been assumed to remain so as management does not currently foresee wells needing to be shut down due to the impact of COVID-19. Management therefore considers this assumption represents a reasonable downside in this uncertain time based on management's experience of previous unplanned shut downs;

· Exchange rates of $1.20:£1 for 2020 and $1.25:£1 for 2021 to reflect a downside caused by the weakening of the dollar later in the period. This downside is partially mitigated by the currency hedges the Group has in place; and

· Includes the impact of action management could take to reduce cash outflow, including delaying capital expenditure and additional reductions in costs in order to remain within the Company's debt liquidity covenants based on the Group's expected RBL redeterminations in May 2020 and December 2020. All such mitigating actions are within management's control and could be actioned within the required time frame.

In this downside scenario, our forecast shows that the Group will have sufficient liquidity and 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 further, the Company 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 is material uncertainty over future commodity prices, the outcome of the May 2020 redetermination of the RBL and the potential impact of COVID-19 on the Group's operational activities. 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.

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. The Group's major product lines are:

Revenues of approximately £18.8 million and £20.5 million were derived from the Group's two largest customers (2018: £21.6 million and £20.4 million) and are attributed to the oil sales.

3 Finance income and costs 

4 Income tax credit

(i) Tax credit on loss from continuing ordinary activities

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%. 

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:

* 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:

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

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. Such tax losses include £94.4 million (2018: £114.3 million) of ring-fence corporation tax losses.

The Group has further tax losses and other similar attributes carried forward of approximately £234.8 million (2018: £203.0 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 attributable to ordinary equity holders of the parent of £49.8 million (2018: a loss of £21.4 million) and the weighted average number of ordinary shares outstanding during the year of 121.7 million (2018: 121.5 million).

Diluted EPS amounts are based on the loss for the year after taxation 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 2019, there are 6.3 million potentially dilutive employee share options (31 December 2018: 4.6 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:

Discontinued

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

6 Goodwill

The carrying value of goodwill related to unconventional assets acquired as part of the Dart acquisition in 2014. The Group tests goodwill for impairment annually or more frequently if there are indications that goodwill might be impaired. The Group reviewed the valuation of goodwill as at 31 December 2019 and assessed it for impairment. Following a moratorium on fracking announced by the UK Government in late 2019, management assessed that the carrying value of goodwill was not recoverable and impaired the brought forward balance of £4.8 million in full for the year (2018: £nil).

7 Intangible exploration and evaluation assets

\* The decommissioning asset increased in line with the decommissioning liability following a review of the estimate at 31 December 2019.

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 have been working and will continue to work closely with the relevant regulators to demonstrate that the Group can operate safely and environmentally responsibly. However, following an impairment review, 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. Exploration costs written off were £53.9 million (31 December 2018: £29.1 million), of which £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. The balance relates to exploration costs on a number of other licences outside our core area. (2018 impairment comprised: £20.7 million related to the Doe Green production facility in the North West (PEDL 145) where a long-term test determined that there was no potential for a commercial development; £3.2 million related to a well not being used in the Albury development and £5.2 million related to relinquished licences). As part of our ongoing active portfolio management, we are continually reviewing our acreage positions and will continue to seek to relinquish non-core licences or impair licences where the carrying value cannot be supported.

An analysis by location of the remaining exploration and evaluation assets is as follows:

North West: The group has £5.9 million (2018: £48.7 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 the decision is expected in mid-2020. As the outcome is still undetermined it is appropriate to keep the carrying value of the asset capitalised.

East Midlands: The group has £31.6 million (2018: £36.9 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 and we have a work programme in place. Following the moratorium on fracking, we will work with the UK Government to demonstrate that we can develop shale in this area in a safe manner.

Weald: The group has £4.0 million (2018: £3.5 million) of capitalised exploration expenditure which includes PEDL235.

At 31 December 2019, the Group has a combined carried gross work programme of up to $214 million (£161 million) (2018: $220 million (£170 million)) from its partner, INEOS Upstream Limited. In 2019 £7.3m (2018: £9.2 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.

8 Property, plant and equipment

* Charge for the year includes £48 thousand categorised as administration expenses in the profit and loss (2018: £99 thousand).

*\* The decommissioning asset increased in line with the decommissioning liability following a review of the estimate at 31 December 2019.

Impairment of oil and gas properties

Due to the continuing volatility in oil and gas prices and foreign exchange rates, the Group's oil and gas properties were reviewed for impairment as at 31 December 2019. 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 price assumption for Brent of $60/bbl for the years 2020-2024 and $70/bbl (2018: $75/bbl) thereafter, and a USD/GBP foreign exchange rate of $1.35:£1.00 (2018: $1.30/£1.00). Cash flows were discounted using a pre-tax discount rate of 8.5% (2018: 11%). No impairment was required in the year (2018: £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.

Impairments that would result from changes to the key assumptions are shown below:

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 impairment of £7.9 for the North CGU, £1.3 for the South CGU and £0.1 for the Scotland CGU.

9 Right-of-use assets and lease liabilities

The Group adopted IFRS 16 Leases, which sets out the principles for the recognition, measurement, presentation and disclosure of leases, for periods commencing after 1 January 2019. On adoption of IFRS 16, the Group recognised lease liabilities in relation to leases which were previously classified as operating leases under the provisions of IAS 17 Leases.

The Group's leasing activities and how these are accounted for

The Group leases property, land, cars and other equipment. Rental contracts are typically made for fixed periods of between 3 and 30 years but may have extension options. Lease terms are negotiated on an individual basis and contain a wide range of terms and conditions. Leased assets may not be used as security for borrowing purposes.

Until 31 December 2018, leases of property, land, cars and other equipment were classified as operating leases. From 1 January 2019, leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the Group.

(a) Adjustments recognised on adoption of IFRS 16

In accordance with the transition provisions in IFRS 16, the modified retrospective approach has been adopted with the cumulative effect of initially applying the new standard recognised on 1 January 2019. Comparatives for the 2018 financial year have not be restated. The financial impact of transition to IFRS 16 for the year ended 31 December 2019 has been summarised within this note. In applying IFRS 16 for the first time, the Group has used the practical expedient permitted by the standard, relying on previous assessments on whether leases are onerous as an alternative to performing an impairment review - there were no onerous contracts as at 1 January 2019. The Group has elected to use the recognition exemptions for lease contracts that, at the commencement date, have a lease term of 12 months or less and do not contain a purchase option, and lease contracts for which the underlying asset is of low value ('low-value assets'). The Group recognises lease expenses for these contracts on a straight-line basis as permitted by IFRS 16. Lease liabilities related to operated Joint Ventures are disclosed gross.

(b) Amounts recognised in the balance sheet

The Group has identified lease portfolios for property, land, cars and other equipment as follows:

Additions to the right-of-use assets during the 2019 financial year were £1.4 million and depreciation £1.5 million

Sensitivity 

Management performed sensitivity analysis to assess the impact of changes to the incremental borrowing rate on the Group's lease liability and right-of-use asset balances. A 3% increase in the IBR would result in an increase in right-of-use asset of £1.1 million and lease liability by £1.1 million.

(c) Amounts recognised in the income statement

The income statement includes the following amounts relating to leases:

During the year ended 31 December 2019, the Group had a total cash outflow of £2.7 million on qualifying leases.

The financial effect of revising lease terms to reflect the effect of exercising extension and termination options was an increase in recognised lease liabilities and right-of-use assets of £1.4 million.

10 Cash and cash equivalents

The cash and cash equivalents does not include restricted cash.

Restricted cash

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 by the other entities within the group.

Net debt reconciliation

11 Borrowings

In 2013, the Company and Norsk Tillitsmann ("Bond Trustee") entered into a Bond Agreement for the Company to issue up to $165.0 million secured bonds and up to $30.0 million unsecured bonds (issued at 96% of par). These bonds were subsequently listed on Oslo Bors and the Alternative bond market in Oslo. Both secured and unsecured bonds carried a coupon of 10% per annum (where interest was payable semi-annually in arrears). The secured bonds were amortised semi-annually at 2.5% of the initial loan amount. Final maturity on the secured notes was on 22 March 2018 and on the unsecured notes was 11 December 2018.

In April 2017, the Company restructured its debt resulting in the equitisation of the unsecured bonds and a repayment/equitisation of a portion of the secured bonds. The restructuring reduced the total aggregate face value of the secured bonds to $30.4 million. The interest rate was reduced to 8%, the repayment term was extended to 30 June 2021, and the amortisation rate was increased to 5% of the initial loan amount from 23 March 2018.

On 19 November 2019, the Group repaid its secured bonds at par value (100%) plus accrued interest through the drawdown of $25 million from the RBL with BMO Capital Markets.

Reserve Based Lending Bank Facility Loan (RBL)

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.

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 EBITDAX 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).

12 Provisions

The Group spent £1.8 million on decommissioning during the year.

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 36 years from year-end (2018: 1 to 26 years). The provisions are based on the Groups' internal estimate as at 31 December 2019. 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 1.27% to 3.03% is used in the calculation of the provision as at 31 December 2019 (2018: Risk free rate range of 0.98% to 3.04%).

13 Subsequent events

On 24 January 2020, the Group issued 66,076 Ordinary £0.00002 shares in relation to the Group's SIP scheme. The shares were issued at £0.47 resulting in share premium of £31,054.

The global pandemic of Covid-19 in early 2020 has caused worldwide economic disruption. The Group considers this to be a non-adjusting post balance sheet event as of 31 December 2019. As described in our going concern assessment there is material uncertainty of the potential impact of Covid-19 on the Group's operational activities, future commodity prices and the outcome of the May 2020 redetermination of the RBL.

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

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 licenceSoS Secretary of State

RoSPA Royal Society for the Prevention of Accidents

Tcf Trillions of standard cubic feet of gas

UK United Kingdom