IGAS.L Regulatory News (IGAS)

THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION.

28 March 2019

IGas Energy plc (AIM: IGAS)

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

Full year results for the year ended 31 December 2018

IGas, one of the leading producers and explorers of hydrocarbons onshore in Britain, announces its full year results for the year ended 31 December 2018.

Results Summary

Notes

1. Adjusted EBITDA and underlying profit are considered by the Company to be useful additional measures to help understand underlying performance. A reconciliation to loss before tax is included in the financial review.

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

3. 2019 production guidance revised whilst OPL transaction under review.

Operational Summary

· Net production averaged 2,258 boepd for the year (2017: 2,335 boepd). Operating costs for the year were $31.9/boe (2017: $28.2/boe). We currently anticipate net production of between 2,200 - 2,4003 boepd in 2019 and operating expenditure of $32.5/boe (assuming an exchange rate of £1:$1.30)

· North Nottinghamshire shale appraisal campaign yields highly encouraging initial results:

o At the Springs Road well, total depth ("TD") has been reached at 3,500 metres after encountering all three targets - Bowland Shale, Millstone Grit and Arundian shales

§ A hydrocarbon bearing shale sequence of over 250 metres was encountered, including the upper and lower Bowland Shale. Significant gas indications were observed throughout the shale section.

§ Cores and wireline logs will now undergo a suite of analysis the first results of which should be available Q2

o Preliminary tests on shale samples at Tinker Lane are encouraging for the potential gas resources in the Gainsborough Trough basin. The analysis of these samples is still subject to further testing and validation

o Drilling performance significantly ahead of expectations at both sites

· Competent Persons Report ("CPR") by DeGolyer & MacNaughton ("D&M"), a leading international reserves and resources auditors, published today:

o 2P reserves replacement of over 200% in 2018 (31 Dec 2018: 2P reserves of 14.6 MMboe)

o Addition of 2P reserves following third party studies during 2018 demonstrates significant potential upside in our portfolio

o 2P base case NPV10 of c.US$160m

· Successful completion of the Albury gas-to-grid project currently producing c.750 mscf/d (130 boe)

Corporate and Financial Summary

· Cash balances as at 31 December 2018 of £15.1 million and net debt of £6.4 million

· Net cash generated from operating activities for the year was £12.9 million (2017: £6.7 million), after oil hedge payments of £5.5 million

· Improved underlying profit of £4.0 million (2017: £1.3 million). Loss after tax of £21.4 million due to non-cash exploration write-offs, principally in relation to the Doe Green long-term test, of £29.1 million (2017: Profit after tax of £15.5 million due to tax credit of £19.1 million)

· Carried work programme of up to $220 million (£170 million) as at 31 December 2018

· 525,000 barrels hedged for 2019 with an average put price of US$58.5/bbl

Commenting today Stephen Bowler, Chief Executive Officer, said:

"As shown by the 200% reserves replacement in 2018 there is still significant upside in our conventional portfolio and we look forward to bringing projects to final investment decision over the coming months.

We are delighted with the initial results of our appraisal campaign in the Gainsborough Trough having recovered high quality hydrocarbon bearing cores at our Springs Road site.

We believe gas will be the transition fuel in Britain as we move to a cleaner energy future. As an industry we now have data that supports the potential of the rocks under our feet. We urgently need to ensure this abundant resource is brought out of the ground to deliver the significant benefits it offers to the country."

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 18 years oil and gas exploration and production experience.

For further information please contact:

IGas Energy plc

Tel: +44 (0)20 7993 9899

Stephen Bowler, CEO/Julian Tedder, CFO/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/Neil Coleman

Canaccord Genuity (Joint Corporate Broker)

Tel: +44 (0)20 7523 8000

Henry Fitzgerald-O'Connor

Vigo Communications

Tel: +44 (0)20 7830 0230

Patrick d'Ancona/Chris McMahon

Chairman's Statement

This has been a year of solid delivery from existing operations. We have completed a number of capital projects, as well as commencing our shale appraisal campaign in North Nottinghamshire.

The business has demonstrated its resilience and following the refinancing in 2017, is on a sound financial footing which is important in these volatile markets, particularly in relation to commodity prices and foreign currency.

Whilst the challenges of operating in a volatile commodity market and navigating the uncertain and lengthy UK planning regime are self-evident, there is material upside in the producing and development assets within the IGas portfolio and significant opportunities lie ahead. We will reinvest capital in our asset base to take advantage of these opportunities.

As a business, we take pride in our operations and strive for positive community engagement. Our Community Fund again distributed resources to support many local projects across our portfolio.

We maintain a company-wide focus on health, safety, and responsible operations. All of our production and drilling operations retained their ISO 14001 and 9001 certifications and we were awarded the ROSPA Presidents Award again, representing 12 years of commitment to Occupational Health and Safety.

As far as IGas is concerned we do not anticipate any direct post-Brexit issues for the business but believe our business becomes more important, if and when we are to leave the EU. The critical questions are, how will the UK continue to meet the national demand for gas and will we still be able to access our energy affordably?

Currently, gas meets 40% of the UK's primary energy requirements. Over 80% of British homes are heated by gas and two thirds of people use it for cooking. Today we import roughly 50% of that gas requirement, and by 2035 that figure is expected to rise to 75%. Imported gas costs us around £18 million a day. According to one National Grid scenario, Britain's import bill could hit £10 billion a year - creating no jobs and generating no tax revenue in this country, but granting these benefits instead to countries including Norway, Qatar and Russia.

Dependency on imports leaves the UK dangerously exposed to shortages and price spikes when there are infrastructure failures or tight international supplies. On 1 March 2018, National Grid issued its first "gas supply deficit" warning for eight years. A number of large businesses agreed with their suppliers to use less gas, and within-day prices rose to as high as 350 pence per therm - over six times the normal price. This inevitably hits our industrial competitiveness, pushes up costs for our gas-dependent manufacturing industries, and creates risks for business and increased prices for consumers.

As the Netherlands becomes a net gas importer, Norwegian gas will be in high demand and as competition for Norwegian supplies increases, a rising proportion of the UK's gas is likely to come from countries with environmental and human rights standards far lower than our own. Large amounts of energy are required to freeze gas and transport it by ship as LNG, resulting in production and processing emissions being as much as twice those compared with home-grown shale gas production.

People

We are committed to ensuring that our teams and talent are diverse as we know the benefits that diverse thinking, perspectives and experiences can bring to our business.

It has been another busy year across the business and I would like to thank all employees for their ongoing commitment and hard work.

On behalf of the Board, I would like to extend my sincere thanks to John Blaymires, our Chief Operating Officer, who will retire from the business on conclusion of the Springs Road vertical well. John has been an integral part of the IGas story for the last eight years. The Company has benefited greatly from his dedication and commitment, wise counsel and wealth of industry experience. We wish him well in all his future endeavours.

Outlook

We have laid down a solid foundation for our business and we will continue to ensure that our cost base reflects the external economic situation.

We are focused on balancing our investment in our assets with maintaining a sound financial footing in volatile market conditions. Our ongoing work programme across our shale acreage, principally funded by our partners, will give us important data in understanding further the increasingly vital resource beneath our feet.

Chief Executive's Statement

2018 was a year of delivery, completing a number of projects as well as taking further steps to improve our operating and production efficiencies. We are generating free cash flow and took proactive steps to invest into our producing and development assets.

The increase in the oil price helped to boost cash flows from our producing assets, enabling us to invest in a number of sanctioned projects and advance our development "hopper" by accelerating third party field development studies preparing for execution in 2019 and beyond.

Operational Performance

Group production averaged 2,258 boepd for the year. Production for the first five months of the year was ahead of budget but was impacted by the shut-in of a water injection well at our Stockbridge field in August 2018. The injection well was brought back online and we are considering additional options for increasing water disposal capacity to uplift production. We successfully completed the Albury gas-to-grid project with full production start-up and gas export to the grid at the end of November 2018. We continue to progress the Welton water injection project building upon the success of the pilot results.

In 2018, we have undertaken a systematic review of our production portfolio, including identifying optimisation opportunities to enhance production and reserves. To aid this exercise we have carried out a series of field studies. These scoping studies have highlighted a number of opportunities with the most promising projects requiring a more detailed engineering evaluation and assessment before they are FID ready. We will continue to advance these over the next 12 months.

Following these studies, we commissioned an independent CPR by D&M of our reserves and resources. There has been a significant 2P reserves replacement of over 200% in 2018 based on cumulative production of 0.82 MMboe in the year.

We began our shale appraisal campaign of the Gainsborough Trough basin in North Nottinghamshire, in the fourth quarter of 2018. It is an integrated exploration and appraisal programme to better define the basin consisting of the margin sited well at Tinker Lane and a basin centred well at Springs Road.

We spudded the Tinker Lane well on 27 November 2018 and reached TD on 17 December 2018, significantly ahead of schedule. Whilst we did not encounter the Bowland Shale, the preliminary tests on shale samples from within the Millstone Grit Group are encouraging for the potential gas resources in the Gainsborough Trough basin. The analysis of these samples is still subject to further testing and validation. The results of this well will help calibrate our geological models of the region and importantly has demonstrated further improvements in drilling performance, which will be an important component of commerciality.

The well has now been plugged and abandoned and preparations are being made to fully restore the site.

We mobilised the equipment to Springs Road in early January 2019 and spudded the well on 22 January 2019. In mid-February, we encountered shales on prognosis, at c.2,200 metres depth and drilled through a hydrocarbon bearing shale sequence of over 250 metres, including the upper and lower Bowland Shale. TD has been reached at 3,500 metres after encountering all three targets - Bowland Shale, Millstone Grit and Arundian shales. Significant gas indications were observed throughout the shale section and additionally within the Millstone Grit sequence and the Arundian shale. The cores and wireline logs will now undergo a suite of analysis, the first results of which should be available in the second quarter of 2019.

In the North West, we were refused planning permission in January 2018 for a simple drill stem test, at our existing Ellesmere Port site, by Cheshire West and Chester Council ("CWaCC") contrary to their planning officer's recommendations and despite receiving no objections from any statutory or non-statutory technical consultees.

We made an application to appeal the decision, which was accepted, and a public inquiry took place over a period of 12 days in January, February and March 2019. Following further written submissions from all parties, the Planning Inspector will opine on the representations of the various parties and determine if the planning application should be allowed or refused.

No further activity in the PEDL licences that fall within the CWaCC Planning Committee will be undertaken until the outcome of the Ellesmere Port appeal is known.

UK Onshore Shale Development

On 24 July 2018, Cuadrilla received final hydraulic fracture consent from BEIS for its first horizontal shale gas exploration well at its Preston New Road site in Lancashire. 

They commenced their hydraulic fracture programme on 13 October 2018 and announced first gas on 2 November 2018. They have repeatedly seen natural gas flowing back to surface along with the water injected during the fracturing process and this flow of gas was earlier than expected. Whilst there have been undoubted challenges and restrictions in operating within what is acknowledged to be a very conservative micro-seismic traffic red light threshold (set at just 0.5 on the Richter Scale), this early gas flow is a hugely encouraging signal of the potential locked up in this natural gas resource. 

Following two successful appeals, INEOS has permission for two exploration wells in Derbyshire and South Yorkshire, as part of their appraisal programme.

IGas in the Community

We have a responsibility to work in partnership with the communities in which we operate and we aspire to be a good neighbour by respecting the people and communities we impact and being sensitive to their needs.

To be successful, we need to work with communities and build respectful, long-term relationships. By doing so we better understand local concerns and how we can work together to minimise disruption to peoples' lives, and where we make mistakes; learning from these will help us to constantly improve our engagement approach.

The IGas Community Fund is now in its eleventh year and continues to help make a positive difference to community and voluntary organisations. 

People

In February 2019, we announced that John Blaymires, Chief Operating Officer, will retire from the Company on the completion of the Springs Road vertical well. 

John has been a core member of the senior team at IGas for the last eight years and has helped to build the operational capacity we have today. We are all grateful for his valued contribution in that time and wish him well in his retirement. John's day-to-day responsibilities have been taken on by Ross Glover, Development Director, Chris Beard, Production Director and Ross Pearson, Technical Director who all joined the Executive Committee in February 2019. They bring highly complementary skills to the Executive as we move towards a very exciting period for the business in 2019 and beyond.

Outlook

2018 was undeniably a significant year for shale exploration in the UK with the commencement of hydraulic fracturing at Preston New Road in Lancashire alongside the commencement of our appraisal programme in the Gainsborough Trough. We believe that, safely and responsibly produced, shale gas can be an important future resource for the UK. With over 80% of UK households using gas for heating, c.40% of electricity generation and industry using it to make vital products, it is not a case of whether we need to use gas but where we should source it from. 

We strive to employ and develop a strong and motivated workforce, develop local supply chains and work closely with our local communities to ensure they share in the benefits our industry can deliver. 

We are highly encouraged by the initial results of our exploration programme in the Gainsborough Trough basin and look forward to completing the interpretation of the complete data suite from the wells at both Tinker Lane and Springs Road. This will help refine our work programme in the East Midlands for the rest of the year. 

Across our existing assets in the East Midlands and the Weald Basin, we are advancing projects and taking them through FEED studies.

Whilst challenges in some areas of onshore planning remain, we are confident in our ability to progress the development of our assets. Significant opportunity exists within our portfolio but in order to carefully manage our cash, we will be prudent in bringing forward projects that have attractive returns at current commodity prices.

Operational Review

Production

Average net production for the year was 2,258 boepd following the execution of the conventional capital expenditure programme; production gains were achieved through well optimisation and increased production efficiency across multiple fields. These production levels were attained despite the impact of reduced water disposal capacity at the Stockbridge field that prevented the reinstatement of a further c.100 boepd. As ever, all of the teams have worked hard across the portfolio.

The aim of the Stockbridge production recovery programme was to debottleneck the water management constraints at the field to create additional production capacity, whilst also returning existing wells to production. On the whole, the five well project program was executed in line with budget and schedule, with successful results arising from the intervention work on four wells and the effective drilling of the STK19 side-track well. However, the sidetrack failed to provide the additional water injection capacity we had anticipated which meant the full benefit of the project could not be realised and c.100 boepd remains shut-in. Measures are being pursued to unlock this additional potential and alleviate the water handling constraints.

Our advancement of the Welton water injection scheme continued during 2018 with the completion of an additional injection well plus enhanced injection capacity. Early indications, such as well performance and pressure response, are in line with prognosis leading to the approval of the next stage of the development early in 2019. A number of studies have been conducted to look at the broader issue of water management in the East Midland fields and how production and recovery could be optimised whilst lowering opex costs across the portfolio. Similar capacity constraints regarding water disposal as to those existing in the Weald also exist in the East Midlands and we have embarked upon an investment programme to address this to ensure that oil production and ultimately recovery are improved.

At Albury, the power generation element of the development was accelerated allowing electricity export to commence in July 2018, four months ahead of schedule. At the end of November 2018, in line with the project schedule the 'Gas-to-Grid' scheme came online following the completion of the gas treatment, network entry and network pipeline enabling full capacity export to occur. The site now has a combined export capability of over 170 boepd.

During the year we continued to invest in our core assets which included routine maintenance and integrity activities on our facilities and pipelines, site facility upgrades and further extension of the digital oilfield programme.

Over the last 12 months, we have undertaken a systematic review of our production portfolio, both fields and the associated infrastructure, in order to ascertain any performance or capacity issues and how these might be mitigated. We have also focused on identifying optimisation opportunities to enhance production and reserves and reduce operating expenditure. A series of field studies have highlighted a number of opportunities, the most promising of which are being advanced through detailed engineering evaluation and assessment before they are fully FID ready.

We will continue to advance these over the next 6-12 months to ensure we have a robust suite of attractive investment opportunities underpinning the business. The success of the Albury development has corroborated our views on some of the other stranded gas opportunities within our portfolio and we are now putting increased focus into their advancement in 2019 and beyond.

In May 2018, we announced the potential sale of certain non-core assets to Onshore Petroleum Limited ("OPL"). We believe the OGA will not give their consent to the proposed transaction and are therefore in the process of exploring alternative options with OPL and the OGA as to the structure and form of a transaction.

IGas Net Reserves and Resources

IGas's reserves and resources were determined through an independent reserve assessment conducted by D&M, a leading international reserves and resources auditor as part of a full CPR.

Net Reserves and Resources (MMboe)

Notes

1. IGas reported reserve and resource estimates published in 2017 Annual report

2. D&M estimates as of 31 December 2018 from the CPR, production in 2018 of 0.82 MMboe

3. 2C decrease due largely to successful capital projects in 2018 moving the resources into reserves

Proved (1P) and probable (2P) developed reserves are estimated reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years under existing economic and operating conditions. As these are mature fields, their historical performances have reliable declines in producing-rate trends and the developed reserves have been estimated by the application of appropriate decline curve analysis with a cut-off defined as the limits of economic production. The developed, producing 2P reserves account for over 90% of the total 2P reserves.

Probable (2P) undeveloped reserves were estimated for a number of incremental projects by using analogy type-well data of nearby wells completed in the same reservoirs. These incremental projects are actively being matured and have been determined to be more likely than not to be economically recoverable with some planned further capital investment.

There has been significant 2P reserves replacement ratio of over 200% in 2018 based on a cumulative production of 0.82 MMboe in 2018. The reserves growth is due largely to a continued focus on optimising reservoir management, a combination of planned future investments in non-producing and undeveloped reserves and movement of contingent resources to reserves through actual and planned capital investment.

The D&M independent evaluation also included an estimate of 2C net contingent conventional resources of 19.2 MMboe for IGas properties, using a conversion factor of 5.8 Mcf/boe for gas resources. These resources include conventional oil and gas resources within producing and undeveloped fields that can be readily developed once the particular contingencies are removed, should they be commercial or otherwise. The decrease in resources from during the year is largely due to relinquishment of a non-producing asset and maturing capital projects that were advanced in 2018 moving the relevant resources into the reserve category.

The prospective resource associated with shale exploration/appraisal is not included in this assessment.

Development/Appraisal Assets

During 2018 good progress was made in developing our shale acreage.

In the East Midlands, we continued with the exploration of the Gainsborough Trough area. 

Construction of the Tinker Lane site and drilling of the stratigraphic well was completed in 2018. The purpose of the well was to delineate the edge of the shale in the Gainsborough Trough basin and fulfil a licence obligation. Whilst the target Bowland Shale was not present in the well, the indications of hydrocarbons encountered within the Millstone Grit Group of shales are encouraging for the potential gas resources throughout the Gainsborough Trough basin. The well has helped to better calibrate the seismic interpretation and define the margin of the basin. The well has now been plugged and abandoned and plans are being drawn up to fully restore the site to its former condition. It is anticipated that this will be carried out in mid-2019. 

Site construction and the drilling of the well was carried out successfully, under stringent environmental and planning conditions. The site hosted multiple visits by the various industry regulators at different stages of the operation. Throughout the operation there were no material breaches of any of the conditions. The site has been subject to significant environmental monitoring over the past two years, with data on noise, ground water and ground gas being regularly collected and analysed. The analysis of this data demonstrates that the site has had no significant environmental impact during its existence and no environmental effects will remain once the site has been restored.

Site construction at our Springs Road site was completed in 2018. Drilling of the first of two wells at the site commenced in 2019. The purpose of the first well is to core and log various intervals in the centre of the Gainsborough Trough basin. As with Tinker Lane, the site is subject to stringent environmental and planning conditions. Site construction was carried out with no material breaches of any of the conditions.

As with Tinker Lane, the Springs Road drilling performance has been very encouraging with improved rates of penetration leading to better than anticipated drilling performance and lower costs. The learnings from these initial wells will be incorporated into subsequent activity and demonstrate that such efficiencies will result in reduced time and cost of future wells with all the attendant benefits.

At Springs Road we encountered a hydrocarbon bearing shale sequence of over 250 metres, including the upper and lower Bowland Shale. Significant gas indications were observed throughout the shale section and additionally within sands in the Millstone Grit sequence. A video showing some recovered core from the well effervescing gas when immersed in water can be viewed here: https://youtu.be/dnZDrTLWiyQ .

We have now reached TD for the well, having successfully encountered the tertiary target, the Arundian shales where gas indications were also observed. Wireline logs and cores have now been acquired across all targets. Petrophysical and core analysis is currently being conducted, which will give us further insight into the resource potential and shale characterisation that will be utilised for future appraisal and development of the wider East Midlands area.

The rate of drilling at both Tinker Lane and Springs Road (down to the primary target) were quicker than anticipated, with corresponding cost savings. This is highly encouraging for future cost efficiencies.

The Tinker Lane and Springs Road results will form the foundation of a pilot development in the East Midlands which looks to leverage the advantage our existing infrastructure and unique UK onshore operational capability offers. The first phase of our development indicates significant potential within the region to expand our existing operations around a pilot shale development that could see sustained production over the long-term. Based on average gas consumption rates, this would supply the needs of hundreds of thousands of UK homes for many years. The development would yield significant benefit for the local economy in the way of highly skilled, highly paid jobs.

Our commitment to the local area would ensure the associated environmental impacts are minimised to the lowest possible level by way of investment in supporting infrastructure with innovative solutions. The UK's long established, world class regulatory framework and our commitment to sustainable development ensures this exciting opportunity will bring a renewed focus and prosperity to many areas in the UK.

In the North West, we appealed against the decision by Cheshire West and Chester Council to refuse our planning application to carry out tests on the Pentre Chert Formation in our existing well at Ellesmere Port. The appeal was heard by way of a planning inquiry which began in January 2019. The Planning Inspector's decision to allow or to refuse the appeal is expected in the second quarter of 2019. 

The shale operations have the benefit of an extensive injunction that protects three sites, Springs Road, Tinker Lane and Ellesmere Port and access along the public highway to both Springs Road and Tinker Lane. The injunction was obtained in the second half of 2018 and has resulted in significantly fewer obstructive actions.

Following the refinancing in 2017, 2018 has been a year in which the foundations for future growth, in both the production and shale business, has been established. All the teams are clearly committed to advancing our activities safely, environmentally responsibly and cost effectively.

Financial Review

Oil prices remained volatile in 2018 with the price of Brent crude increasing from c.$66/bbl at the beginning of the year to a high of $86/bbl in October 2018 before falling to a low of $50/bbl in December 2018. Average oil price for 2018 was $71/bbl (2017: $54/bbl) which had a positive impact on our revenues. The average GBP/USD exchange rate for the year was £1: $1.34 (2017: £1: $1.29) which negatively impacted revenue for the year.

For the year ended 31 December 2018 adjusted EBITDA was £10.8 million (2017: £9.2 million) whilst a loss was recognised from continuing activities after tax of £21.4 million (2017: profit £15.9 million). The main factors driving the movements between the years were as follows:

· Revenues increased to £42.9 million (2017: £35.8 million) principally due to higher oil prices, partially offset by a 4% decrease in volumes and a stronger average sterling to US dollar exchange rate;

· Other costs of sales increased to £21.9 million (2017: £21.4 million) mainly due to higher production and transportation costs partially offset by lower water handling costs and third party purchases. The higher costs also include operating costs for the Albury gas field which commenced production in November 2018;

· Administrative expenses decreased by £0.9 million to £5.5 million (2017: £6.4 million). Costs were lower in 2018 than in 2017 principally due to a higher capitalisation of costs from increased capital activity and a greater recovery of costs from our joint venture partners;

· The £29.1 million exploration expense includes the write off of costs relating to PEDL 145 (Doe Green) where a long-term test has concluded that there is not the potential for a commercial development, an Albury well not being used in the current development and various licence relinquishments (2017: £0.1 million related to relinquished licences); and

· A tax credit of £3.7 million was recognised mainly due to the recognition of a deferred tax asset relating to ring-fence tax losses (2017: a tax credit of £19.1 million mainly due to the recognition of a deferred tax asset relating to ring-fence tax losses).

Income statement

The Group recognised revenues of £42.9 million for the year (2017: £35.8 million). Group production for the year averaged 2,258 boepd (2017: 2,335 boepd). Revenues included £2.4 million (2017: £3.0 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 $67.0/bbl (2017: $51.0/bbl) and post-hedge $57.4/bbl (2017: $51.3/bbl). A £5.5 million loss was realised on hedges during the year (2017: realised loss of £0.2 million). The average GBP/USD exchange rate for the year was £1: $1.34 (2017: £1: $1.29) which negatively impacted revenue for the year.

Cost of sales for the year were £28.8 million (2017: £29.3 million) including depreciation, depletion and amortisation (DD&A) of £6.8 million (2017: £7.8 million), and operating costs of £21.9 million (2017: £21.4 million). Operating costs include a cost of £2.3 million (2017: £2.8 million) relating to third party oil. The contribution received from processing this third party oil was £0.2 million (2017: £0.2 million). 

Operating costs per barrel of oil equivalent (boe) were £23.6 ($31.9), excluding third party costs (2017: £21.9 ($28.2) per boe). Operating costs per boe were higher in 2018 due to higher production and transportation costs and lower volumes.

Adjusted EBITDA in the year was £10.8 million (2017: £9.2 million). Gross profit for the year was £14.2 million (2017: £6.5 million). Administrative costs decreased by £0.9 million to £5.5 million (2017: £6.4 million) principally due to a higher capitalisation of costs from increased capital activity and a greater recovery of costs from our joint venture partners.

Exploration costs written off of £29.1 million exploration expense includes the write off of costs relating to PEDL 145 (Doe Green) where a long-term test has concluded that there is not the potential for a commercial development, an Albury well not being used in the current development and various licence relinquishments (2017: £0.1 million);

Other costs/income were £nil (2017: £0.2 million income).

Net finance costs were £3.9 million (2017: £6.2 million) primarily related to interest on borrowings of £1.9 million (2017: £5.4 million) which was lower following the capital restructure in April 2017, and a net foreign exchange loss of £0.8 million, principally on US$ denominated debt and bank balances (2017: gain £0.2 million). The Group realised a net gain on restructuring of £4.9 million in 2017.

The Group made a loss on oil price derivatives of £0.7 million for the year due to the increase in underlying prices (2017: loss £2.1 million) and a loss on foreign exchange hedges of £0.2 million (2017: £nil).

Cash flow

Net cash generated from operating activities for the year was £12.9 million (2017: £6.7 million). The increase was primarily due to higher revenue and a decrease in administrative expenses offset by higher counter party payments in respect of realised hedges.

The Group invested £10.6 million across its asset base during the year (2017: £6.3 million). £8.1 million was invested in our conventional assets including the successful completion of the Albury gas-to-grid project, the Welton water injection project including the completion of an additional water injection well, a sidetrack at our Stockbridge site and investments at other sites in order to upgrade our site facilities, extend our digital oilfield programme and maintain our production at current levels. We invested £2.5 million in unconventional assets in relation to our shale development programme including the Ellesmere Port appeal. Expenditure on our Tinker Lane well was funded by a carry from our joint venture partner and did not result in a net cash outflow by IGas in 2018.

IGas repaid £1.7 million ($2.3 million) of principal on borrowings to bondholders during the year in accordance with the terms of the bonds. (2017: repaid £3.6 million ($4.6 million) and purchased bonds with a face value of £1.8 million ($2.2 million). In 2017, IGas also carried out a capital restructuring resulting in a cash inflow of £46.8 million from the issue of shares and cash outflows of £39.3 million and £4.3 million, respectively, from the repayment of secured bonds and payment of fees).

IGas paid £1.8 million ($2.3 million) in interest (2017: £5.9 million ($7.3 million)).

To protect against the volatile oil price the Group places commodity hedges for a period of up to twelve months. The Group currently has 525,000 barrels hedged for 2019 with an average put price of $58.5/bbl with an average premium cost of $2.50/bbl.

Cash and cash equivalents were £15.1 million at the end of the year (2017: £15.7 million).

Balance sheet

Net assets were £161.7 million at 31 December 2018 (2017: £181.6 million) with the decrease of £19.9 million arising primarily from the loss for the year.

Intangible exploration and evaluation assets decreased by £25.8 million primarily as a result of amounts written off of £29.1 million, offset by additions during the year of £3.6 million.

At 31 December 2018, the Group has a combined carried gross work programme of up to $220 million (£170 million) (2017: $240 million (£179 million)) from its partner, INEOS Upstream Limited. In 2018 £9.2 million (2017: £3.0 million) gross costs were carried, principally in relation to activities at Tinker Lane and Springs Road, which have not been included in the additions to intangible exploration and evaluation assets during the year.

Borrowings decreased from £21.2 million to £21.0 million with repayments being offset by an increase due to the impact of a higher USD/GBP foreign exchange rate.

At 31 December 2018, the Group's derivative instruments had a net positive fair value of £2.2 million due to a decrease in the underlying Brent forward curve (2017: net negative fair value of £2.8 million).

Other provisions decreased by £4.2 million to £37.9 million. The overall decrease of £4.2 million in the decommissioning provision was principally due to a transfer to liabilities held for sale of £9.9 million offset by an increase of £4.7 million due to a reassessment of future decommissioning liabilities following an independent study.

Net debt at the year end, being the nominal value of borrowings less cash and cash equivalents, was £6.4 million (2017: £6.2 million).

Disposal of Non-core Fields

In May 2018, we announced the potential sale of certain non-core assets to Onshore Petroleum Limited ("OPL"). We believe the OGA will not give their consent to the proposed transaction and are therefore in the process of exploring alternative options with OPL and the OGA as to the structure and form of a transaction.

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;

· 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 existing bond agreements; and

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

Going Concern

The Group continues to closely monitor and manage its liquidity risks including the continued use of both oil and interest rate derivatives. Cash 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 borrowings. 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 base case working capital forecasts show that the Group will have sufficient financial headroom for the 12 months from the date of approval of the financial statements. To manage the impact of the most extreme downside scenarios modelled, management would have to take action, including delaying capital expenditure in order to remain within the company's banking facilities. All such mitigating actions are within management's control.

Therefore, after making appropriate enquiries and considering the risks described above, the Directors have a reasonable expectation that the Group has adequate resources to continue in existence for the foreseeable future. Thus they continue to adopt the going concern basis of accounting in the preparation of the financial statements.

Stephen Bowler Julian Tedder

Chief Executive Officer Chief Financial Officer

27 March 2019 27 March 2019

CONSOLIDATED INCOME STATEMENT

FOR THE YEAR ENDED 31 DECEMBER 2018

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

FOR THE YEAR ENDED 31 DECEMBER 2018

CONSOLIDATED BALANCE SHEET

AS AT 31 DECEMBER 2018

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

FOR THE YEAR ENDED 31 DECEMBER 2018

* 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.

*** The transfer on equitisation of unsecured bonds has arisen due to the unsecured bonds being issued at 60% of par and represents the difference between the nominal value of the shares issued and the book value of the debt exchanged

CONSOLIDATED CASH FLOW STATEMENT

FOR THE YEAR ENDED 31 DECEMBER 2018

CONSOLIDATED FINANCIAL STATEMENTS - NOTES

FOR THE YEAR ENDED 31 DECEMBER 2018

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 March 2019.

The financial information for the year ended 31 December 2018 does not constitute statutory accounts as defined in sections 435 (1) and (2) of the Companies Act 2006. Statutory accounts for the year ended 31 December 2017 have been delivered to the Registrar of Companies and those for 2018 will be delivered following the Company's annual general meeting. The auditor has reported on these accounts; their reports were unqualified, did not include a reference to any matters to which the auditor drew attention by way of emphasis of matter and 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 2017. 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 2018, however these have not had 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 2019 onwards. These are not expected to have a material impact on the accounting policies, methods of computation or presentation applied by the Group, except for IFRS 16 Leases.

Further details on new International Financial Reporting Standards adopted and yet to be adopted will be disclosed in the 2018 Annual Report and Accounts.

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 including the continued use of both oil and interest rate derivatives. Cash 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 borrowings. 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 base case working capital forecasts show that the Group will have sufficient financial headroom for the 12 months from the date of approval of the financial statements. To manage the impact of the most extreme downside scenarios modelled, management would have to take action, including delaying capital expenditure in order to remain within the company's banking facilities. All such mitigating actions are within management's control.

 Therefore, after making appropriate enquiries and considering the risks described above, the Directors have a reasonable expectation that the Group has adequate resources to continue in existence for the foreseeable future. Thus they continue to adopt the going concern basis of accounting in the preparation of the financial statements. 

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 £21.6 million and £20.4 million were derived from the Group's two largest customers (2017: £19.3 million and £15.9 million).

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 liability in the year is shown below:

The following is an analysis of the deferred tax asset/(liability) 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 £114.0 million (2017: £107.5 million) of ring-fence corporation tax losses.

The Group has further tax losses and other similar attributes carried forward of approximately £203 million (2017: £195 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)

Basic EPS amounts are based on the loss for the year after taxation attributable to ordinary equity holders of the parent of £21.3 million (2017: a profit of £15.5 million) and the weighted average number of ordinary shares outstanding during the year of 121.5 million (2017: 121.4 million).

Diluted EPS amounts are based on the profit 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.

There were 4.6 million potentially dilutive employee share options which are not included in the calculation of diluted earnings per share because they are anti-dilutive as their conversion to ordinary shares would decrease the loss per share. In the prior year, there were no potentially dilutive employee share options.

The following reflects the income and share data used in the basic and diluted earnings per share computations:

6 Goodwill

The carrying value of goodwill relates 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 2018 and assessed it for impairment by estimating the fair value of risked contingent resources using an estimated market valuation of resources. The fair value is a level 3 fair value measurement. No impairment was required for the year (2017: £nil).

7 Intangible exploration and evaluation assets

Under the terms of the secured bond agreement, the secured bondholders have a fixed and floating charge over these assets.

Exploration costs written off were £29.1 million (31 December 2017: £0.1 million). An impairment of £20.7 million in 2018 relates to the Doe Green production facility in the North West (PEDL 145) where a long-term test determined that there is no potential for a commercial development; £3.2 million relating to a well that is not being used in the current Albury development and £5.2 million relating to the relinquishment of licences during the year. The impairment in 2017 relates entirely to the relinquishment of 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. Further analysis by location of asset is as follows:

North West: The group has £48.7 million of capitalised exploration expenditure which includes PEDL's 145,147, 184, 189 and 190. Work is still ongoing to assess the viability for shale exploration and development across the North West licences though we await the outcome of the ongoing Ellesmere Port planning appeal before commencing further operations. Further details are included in the operational review above.

East Midlands: The group has £36.9 million of capitalised exploration expenditure which includes PEDL's 12, 139, 140 and 200. The Tinker Lane well (PEDL 200) was completed in Q4 2018. We are currently drilling a well at our Springs Road site (PEDL 140).

South: The group has £3.7 million of capitalised exploration expenditure in relation to Singleton.

As at 31 December 2018, the Group has a combined carried gross work programme of up to £170 million (2017: $240 million (£178 million)) from its partner, INEOS Upstream Limited ("INEOS"). In 2018 £9.2 million (2017: £3.0 million) gross costs were carried principally in relation to activities at Tinker Lane and Springs Road, which have not been reflected in the additions to intangible exploration and evaluation assets.

8 Property, plant and equipment

* Charge for the year includes £99 thousand charge categorised as administration expenses in the profit and loss (2017: £125 thousand) and £nil thousand (2017: £11 thousand) relating to capitalised equipment used for exploration and evaluation.

*\* The decommissioning asset increased in line with the decommissioning liability following a review of the estimate and assumptions at 31 December 2018.

Under the terms of the secured bond agreement, the secured bondholders have a fixed and floating charge over these assets.

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 2018. 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 and South was prepared on a value-in-use basis and using discounted future cash flows based on 2P reserve profiles. The impairment assessment for Scotland was prepared on a fair value less costs of disposal basis. The future cash flows were estimated using price assumption for Brent of $60/bbl for the years 2019-2022 and $75/bbl thereafter, and a USD/GBP foreign exchange rate of $1.30/£1.00. Cash flows were discounted using a pre-tax discount rate of 11%. No impairment was required in the year (2017: £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. A 10% reduction in production or brent prices would result in an impairment of £9.0 million for the North CGU and £1.9 million for the South CGU. A decline in the value of sterling against the US dollar from $1.30/£1.00 to $1.50/£1.00 would result in an impairment of £14.5 million for the North CGU, £7.9 million for the South CGU and £0.3 million for Scotland CGU. None of the CGUs would be impacted by a 10% change in discount rates.

9 Cash and cash equivalents

Restricted cash

The cash and cash equivalents does not include restricted cash.

The current and non-current restricted cash for 2018 and the non-current restricted cash for 2017 represent restoration deposits paid to Nottinghamshire County Council which serve as collateral for the restoration of the sites at the end of their life. The current restricted cash balance for 2017 relates to margin payments in respect of oil hedge contracts.

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

10 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 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. The restructuring also resulted in changes to the covenants and the removal of the need for a Debt Service Requirement Account (DSRA). The secured bonds now have two covenants: a liquidity requirement of $7.5 million and a leverage ratio, tested every six months, that requires net debt versus adjusted EBITDA to be less than 3.5 times.

Further details of the restructuring transaction are provided in note 12.

11 Other provisions

* £4,596,000 per note 8, the remainder being in long term creditors.

Decommissioning provision

Provision has been made for the discounted future cost of restoring fields to a condition acceptable to the relevant authorities. The abandonment of the fields is expected to happen at various times between 1 to 26 years from the year end (2017: 1 to 31 years). These provisions are based on the Groups' internal estimate as at 31 December 2018. Assumptions based on the current economic environment have been made, which management believes are a reasonable basis upon which to estimate the future liability. The estimates are reviewed regularly to take into account 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 0.98% to 3.04% is used in the calculation of the provision as at 31 December 2018 (2017: Risk free rate range of 0.98% to 3.05%).

12 Capital restructure

During the year ended 31 December 2016, the Company disclosed that it expected to be non-compliant with its leverage covenants under its secured bond agreement and that it also expected to breach its daily liquidity covenant in late March 2017. The Company therefore engaged in discussions with its bondholders, a strategic investor and other potential investors and stakeholders with regard to possible restructuring options in order to provide a remedy to the expected breach and achieve a capital structure that would be sustainable in the current oil price environment. In March 2017, the Company announced final terms of the restructuring and fundraising package which were subsequently approved at the meetings of the Company's secured and unsecured bondholders and at the general meeting of shareholders on 3 April 2017. In addition, the shareholders approved the subdivision of each of the 303,305,534 ordinary shares of 10p each of the Company into one new ordinary share of 0.0001p each and one deferred share of 9.9999p each.

On 4 April 2017, the Company announced that all new ordinary shares issued in accordance with the terms of the fundraising were admitted to trading and, as a result, the restructuring of the Company's secured bonds and unsecured bonds and the fundraising had become effective in accordance with their respective terms. The principal terms are set out below:

· 679,282,165 new ordinary shares were issued to Unconventional Energy Limited, an affiliate of Kerogen Capital, pursuant to a subscription agreement (including 40,030,273 new ordinary shares at nominal value pursuant to a top-up mechanism) raising £28.77 million and giving Unconventional Energy Limited an interest of 28% in the Company.

· 400,069,644 new ordinary shares were issued pursuant to a placing, open offer and ancillary subscription raising £18.04 million.

· 528,175,031 new ordinary shares were issued to holders of secured bonds who accepted voluntary equity exchange of secured bonds extinguishing $28.92 million (£23.78 million) in face value of the secured bonds.

· 202,398,542 new ordinary shares were issued to holders of secured bonds pursuant to a conditional secured debt for equity swap extinguishing a further $11.08 million (£9.11 million) in face value of the secured bonds.

· c.$49.2 million (£40.4million) in face value of secured bonds were cancelled in consideration for c.$49.2 million (£40.4 million) cash pursuant to a voluntary cash offer.

· 312,776,818 new ordinary shares were issued to holders of unsecured bonds on the conversion of all unsecured bonds into equity extinguishing $27.4 million (£22.5 million) in face value, being all of, the unsecured bonds not held by the Company.

· The Company cancelled $13.09 million (£10.7 million) in face value of the secured bonds and unsecured bonds held by the Company, being all of the unsecured bonds and secured bonds held by the Company.

· The renegotiated terms and conditions and covenants for the remaining secured bonds (total aggregate face value of c.$30.08 million) came into effect upon admission.

· The new ordinary shares were issued at a price of 4.5p per share.

A gain of £4.9 million (net of fees of £2.5 million) arising from the restructure was recognised for the year ended 31 December 2017.

13 Subsequent events

On 24 January 2019 the Group issued 45,598 Ordinary £0.00002 shares in relation to the Company's SIP scheme. The shares were issued at £0.80 resulting in share premium of £36,477.

On 11 March 2019, the Company announced a significant advancement in UK share prospectively with over 250 metres of hydrocarbon bearing shales encountered, including the upper and lower Bowland Shale, in the Springs Road 1 well.

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

LNG Liquefied Natural Gas

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

PEDL United Kingdom petroleum exploration and development licence.

PL Production licence

Tcf Trillions of standard cubic feet of gas

UK United Kingdom