Unaudited Preliminary results

RNS Number : 3315D

Igas Energy PLC

26 April 2017

THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION.

26 April 2017

IGas Energy plc (AIM: IGAS)

Unaudited Preliminary results for the year ended 31 December 2016

IGas Energy plc ("IGas" or "the Company" or "the Group"), one of the leading producers of hydrocarbons onshore in Britain, announces its preliminary results for the year ended 31 December 2016.

Successful financial restructuring and fundraising with net debt reduced to c.$7 million

Planning permissions granted for three shale exploration wells all within carried work programme of up to $230 million

Results Summary

	Year ended 31 Dec 2016 £m	Nine months to 31 Dec 2015 £m
Revenues	30.5	25.1
Adjusted EBITDA¹	10.2	18.3
Loss after tax	(32.9)	(44.8)
Net cash from operating activities	12.4	1.0

Notes

1. EBITDA is considered by the Company to be a useful additional measure to help understand underlying performance. A reconciliation to loss before tax is included in the financial review.

Financial Summary

· Successful completion of balance sheet restructuring and fundraising in April 2017

o Kerogen 28% shareholder for $35m investment; further new equity raised (placing and open offer) of $21.9m

o Secured bonds debt for equity swap ($40m), cash buyback ($49.2m) and amended terms for remaining bonds ($30.1m)

o Unsecured bonds full debt for equity swap @ 62.5c into $17.1m of equity

o Net debt reduced from $122m at 31 December 2016 to c.$7m upon completion

Operational Summary

· Stable average 2016 net production of 2,355 boepd (2015: 2,570 boepd); forecast production for 2017 of c.2,500 boepd

· Continued focus on cash generation and costs; operating costs for 2016 of $28.8/boe (2015: $24.6/boe); forecast 2017 operating expenditure of c.$25/boe

· Significant value of conventional portfolio confirmed by D&M

o 2P post tax valuation of US$181m based on market consensus price curve (as at 31 October 2016)

· D&M has estimated that IGas has 2.5 trillion cubic feet (ca. 440 MMboe) of net risked shale gas resources

· Shale appraisal and development plan covered by up to $230 million carried work programme with INEOS and Total

o Two planning permissions granted for shale appraisal in North Nottinghamshire: Springs Road and Tinker Lane; both projects are carried

Outlook

· Bringing forward opportunities as part of the shale work programme:

o North West sites and applications planned in 2017

· Sanction of gas monetisation project in second half of 2017

Board Changes

As IGas enters the next stage of its growth a number of changes to the Board have been announced today:

· Chairman and Founder, Francis Gugen, and Non-executive director John Bryant to retire following the AGM in June 2017

· Mike McTighe, Deputy Chairman, to be appointed Non-executive Chairman following the AGM

· John Blaymires and Julian Tedder will resign from the PLC board following the AGM but will remain directors of the operating companies and continue to hold their executive roles

· Two Directors from Kerogen Capital, Philip Jackson and Tushar Kumar, appointed as Non-executives to the Board with immediate effect

Commenting today Stephen Bowler, Chief Executive Officer, said:

"Following the successful completion of our financial restructuring, IGas is positioned strongly for the future. We have a healthy balance sheet, supported by operating cashflow from our production assets, which will enable us to focus on delivering the significant potential of both our production and development assets and provide a solid foundation for the longer-term future of the Company.

We look forward to the next 12 months with confidence as both IGas and the wider industry start to drill and hydraulically fracture shale gas appraisal wells and collect important data for the future development of the UK shale industry."

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

The Company's Report and Accounts for the 12 months to 31 December 2016 will be made available to shareholders once approved and will be available to view and download on the Company's website at http://www.igasplc.com/investors/publications-and-reports, in accordance with AIM Rule 20.

John Blaymires, Chief Operating Officer of IGas Energy plc, and a qualified person as defined in the Guidance Note for Mining, Oil and Gas Companies, June 2009, of the London Stock Exchange, has reviewed and approved the technical information contained in this announcement. Mr. Blaymires has more than 30 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 4000

Sara Hale/Jeremy Ellis/George Price

Canaccord Genuity (Joint Corporate Broker)

Tel: +44 (0)20 7523 8000

Henry Fitzgerald-O'Connor

Vigo Communications

Tel: +44 (0)20 7830 9700

Patrick d'Ancona/Chris McMahon

Chairman's Statement

Over the course of the last two years, we have been de-leveraging the balance sheet through a combination of farm-outs and Bond buy-backs as well as through the amortisation of the Secured Bonds. However, despite the oil price improving considerably from lows in the first quarter of 2016 and the de-leveraging of the balance sheet, the Board has for some time considered that significant corrections to the Company's capital structure were necessary to achieve a structure that is sustainable in the current oil price environment, as well as enabling the business to capitalise on future value accretive opportunities.

Accordingly, much of the Board's activity over the year related to the restructuring of the Company's balance sheet, which I am pleased to report, successfully concluded in April 2017. We have now significantly reduced our debt and are cash generative at current oil prices. With up to $230 million of gross shale carry in place and having now secured planning applications, the Company is poised to capitalise on its potential.

I am pleased that the business continues to deliver operationally whilst retaining a sharp ongoing focus on managing its costs.

We are at a critical juncture in the UK for the future of our energy mix and supply. At the peak of North Sea production we were net exporters of gas but we now face future import dependency levels of up to 80% if we are unable to address our supply challenges. With the demise of coal production, UK sourced gas is increasingly important as part of the energy mix for security of supply whilst also providing environmental benefits compared to imported gas. The UK needs a secure supply of gas as a bridging fuel until renewable sources can provide sufficient stable energy for society's needs.

Performance

The teams have worked hard during the year to keep production steady and average production for the year was 2,355 boepd.

We have secured a number of planning consents for future conventional projects across the country as part of our strategy to replace underlying decline, grow production in the longer term and monetise our stranded gas assets.

In July 2016, DeGolyer & MacNaughton ("D&M"), a leading international reserves and resources auditor, completed an independent evaluation of both our conventional and shale interests. Their estimates show an increase in proven and probable reserves to 13.77 MMboe (as at 30 June 2016) and subsequently, based on these reserves, IGas valued the 2P reserves (post tax) at $181m based on market consensus price curve (as at 30 October 2016).

D&M have also estimated shale gas net risked prospective resources of 2.5Tcf, which in oil equivalent terms is c.440mmboe. The estimate takes into account a recovery factor, adjustments for productive areas and geological risk but, even heavily risked, this is still a significant number for IGas and to give it a context, equivalent to almost the entire UK gas consumption for a year.

We have also enjoyed success in moving our appraisal assets forward. We have been granted planning permission for two sites in North Nottinghamshire and in the North West we are in the process of site selection and pre-application preparations.

Health, Safety and the Environment

Health and safety is a priority across the Company and particularly in the current lower cost environment, we will not compromise on the integrity and safety of our people and operations. We continue to set ourselves challenging HSE targets to drive continuous improvement in all these areas. All of our production and drilling operations retain their ISO 14001 and 9001 certifications.

This year, we were proud to have received RoSPA's President's Award, which is awarded for ten consecutive years of Gold Awards for our health and safety performance. We are very proud of this great achievement and this award demonstrates our ongoing commitment to continuing to raise HSE standards.

As an operator of producing assets we are extremely conscious of our role in the communities in which we operate and that any activity is done safely and with as little impact to the environment as possible.

We have a long history of giving back to the communities in which we operate and one way we do this is through the awards made annually by our IGas Community Fund. The Community Fund exists to help make a positive difference to community and voluntary organisations and our goal is to continue making sustainable donations and to make commitments in terms of time, supporting and helping the community.

Board Changes

I have served as Chairman of the Company since I founded it in 2003. In that time IGas has grown to be one of the largest onshore oil and gas players in the UK, with one of the largest and most diverse shale acreage positions. Post the recent refinancing, the Company is poised to capitalise on its potential. Accordingly, I have decided that this is the right time to retire from the Board, which I will do at the AGM in June 2017. It has been a privilege to lead IGas through many milestones to become the Company it is today. I feel that I am leaving the Company in capable hands, with a very strong executive team.

I am delighted that Mike McTighe is to succeed me as Chairman. Mike joined the Board in August 2016 as Non-executive Deputy Chairman with a wealth of experience and wide industry and regulatory knowledge. Mike is currently Chairman of WYG Ltd, the project management and technical consultants, Openreach, Together Financial Services Ltd, Arran Isle Ltd and Gortmullan Holdings Ltd.

John Bryant will also be retiring from the Board at the AGM. John has served on the Board for the last nine years, since the Company was first listed on AIM. We have all benefitted greatly from his independent advice and significant contribution to the Company and we wish him the very best going forward.

In August 2016, Non-executive director, Robin Pinchbeck stepped down from the Board having served on the Board for over four years. I would like to thank Rob for his valuable contribution and commitment to the Board and the Company during his tenure and wish him well for the future.

We also welcome to the Board, following the successful fundraising, Philip Jackson and Tushar Kumar of Kerogen Capital as Non-executive Directors who join with immediate effect. Philip Jackson is appointed to the Remuneration Committee and Nomination Committee with immediate effect and will be appointed as Chairman of the Remuneration Committee with effect from the conclusion of the AGM. Tushar Kumar becomes a member of the Audit Committee with immediate effect.

Philip has over 30 years' experience in investments and corporate finance in energy and infrastructure projects. He started his career with the energy team at Ashurst LLP before moving to its client Trafalgar House plc, one of the UK's leading independent oil and gas companies at the time.

Tushar has 15 years' experience in investing, investment banking and equities, working with a range of oil and gas companies including upstream, downstream, majors and National Oil Companies across Europe, the Middle East and, Asia.

It has been agreed to reduce the size of the Board and therefore John Blaymires and Julian Tedder will resign from the PLC board with effect from the conclusion of the AGM. They will remain directors of the operating companies and continue to hold their executive roles, which will include regular attendance at Board meetings.

I would like to thank the board for all that they have done this year and the executive team who have worked resolutely to steer the business through a number of challenges. They deserve our thanks as do all our employees.

Outlook

As we look forward to 2017, we see a number of opportunities for the business. An improving oil price environment and the fall in sterling following the referendum, have boosted the economics for our production business as well as emphasising the importance of shale development in Britain. Technological advances in shale extraction, principally in the United States, bring further benefits for efficiencies and costs and we, as well as others in the industry, are set to be drilling this year as we start to roll out our shale development plan.

In the low oil price environment, the Board's priority has been to take considered and measured actions to reset business plans to meet near-term priorities. Cost and capital discipline remain key to ensuring we are well placed to deliver maximum value from our existing production whilst maintaining the capabilities needed to safely and successfully develop these reserves and our shale resources for the benefit of the UK; whilst always fully respecting the environment and the local communities within which we operate.

We remain grateful to all of our stakeholders for their ongoing support and now that we have successfully completed the restructuring process we can look forward to benefitting from a strong balance sheet, as well as a carried work programme of up to $230 million from our partners.

Chief Executive Officer's Statement

Against the challenging commodity price backdrop of the last 12 months, IGas has continued to work hard to deliver operationally and has made solid progress across many areas of the business.

Given the macro environment, the focus has been on operational efficiencies including further reductions to our cost base alongside improvements in an already strong safety performance.

In early April 2017, we completed a significant financial restructuring which was ongoing throughout much of the second half of 2016. We have been delighted to attract well known and experienced investors such as Kerogen Capital, alongside other new institutional investors and were pleased with the level of support received for the transaction from our existing bondholders and shareholders.

This restructuring has significantly improved our financial position and we are now generating positive operating cashflow at current oil prices and accordingly, are well positioned for the future.

Production Assets

Production for 2016 was 2,355 boepd, marginally below guidance of c.2,400 - 2,600 boepd, which was impacted by two key factors. Firstly, the Group reduced its capital expenditure budget in order to preserve cash and focus on projects that maximised economic benefits thereby delaying some planned production. In addition, the Group had unplanned downtime as a number of wells were worked over during the summer.

There remains significant potential in our existing producing fields. We have identified some infill drilling opportunities and have since applied for and secured planning permissions for infill drilling at Singleton. In addition, we received a field life extension at Stockbridge, both of these projects being in the Weald Basin.

We have also made good progress on our incremental projects during the year. Planning permissions were granted for our gas monetisation projects at Albury, Bletchingley, Lybster and Singleton and commercial discussions at Lybster are now at an advanced stage.

During the year, DeGolyer & MacNaughton ("D&M"), a leading international reserves and resources auditor, undertook a full Competent Persons Report ("CPR") across our assets. Their estimates confirmed a continuing high conventional reserves replacement driven principally by successful well operations, decreasing field decline rates and further lowering of operating costs.

The D&M evaluation also included an estimate of net contingent conventional resources of 21.8 MMboe for IGas properties. These resources include oil and gas resources within producing and undeveloped fields that can be readily developed with infill drilling and gas monetisation projects.

The oil price, although having recovered from its lows in early 2016, is still relatively low and we remain focussed on cash generation and capital discipline. Significant potential remains within our existing assets and should commodity prices improve we will accelerate our capital investment in projects that have short payback periods and attractive internal rates of return.

Appraisal Assets

We operate one of the largest acreage positions in the UK, of over 1 million acres (gross), with a total gross carried shale work programme of up to $230 million as at 31 December 2016.

We continue to move our shale development plan forward. In November 2016, following a recommendation from the Planning Officer, Nottinghamshire County Council's Planning and Licensing Committee granted planning consent for our application to develop a hydrocarbon wellsite and drill up to two exploratory wells in Misson Springs, North Nottinghamshire. In March 2017, we were granted planning permission for one exploratory well at our second site in North Nottinghamshire, at Tinker Lane. Both permissions are subject to the completion of Section 106 planning agreements which are both currently being agreed with the requisite authorities.

Results from these wells will improve our understanding of the shale gas potential in North Nottinghamshire and the wider Gainsborough Trough. Following the final 3D seismic interpretation and assessment in the North West, which confirms, alongside previous wells, the shale potential within the survey area, the data is being utilised to identify drilling locations and will allow us to firm up a development programme.

D&M also produced a separate independent evaluation of risked prospective shale gas resources in the IGas East Midlands and North West licence areas.

D&M has estimated an IGas gross mean gas initially in place ("GIIP") of 221 Tcf. D&M reports an IGas gross GIIP best estimate of 106 Tcf using PRMS guidelines.

After application of adjustments for productive areas and recovery factors based on D&M's worldwide experience with analogous shale gas basins, D&M has estimated unrisked IGas net shale gas prospective resources of 11 Tcf.

D&M has estimated that IGas has 2.5 Tcf (ca. 440 MMboe) of net risked shale gas resources after taking into account an estimated geological chance of success. Our new Round 14 blocks were included in this estimate.

In July 2016, IGas was formally awarded 17 blocks, across 9 PEDLS, in the UK's 14^th Onshore Oil and Gas Licensing round. The blocks, across three key basins, represent a total gross area of c. 257,000 acres; IGas' net interest is c. 115,000 acres.

Health, Safety and the Environment

The welfare of our employees, contractors, partners and communities neighbouring our operations is at the very top of our agenda and we constantly strive to improve this critical area of our business.

Lost Time Injuries ("LTIs") represent a direct measure of our safety procedures and the quality of training and have the potential to impact our reputation and ability to operate effectively. During the year we had zero LTIs.

Our endeavours were recognised this year through the President's Award from RoSPA. This special honour is presented to those organisations which have achieved more than 10 consecutive gold awards and I would like to thank the HSE team and the wider operation teams for their continuous demonstrable commitment to ensuring that health and safety is at the top of the agenda.

Everywhere we operate we are committed to safe and environmentally responsible activity. Throughout our operations robust measures are put in place and regulated to protect the environment.

IGas in the Community

The IGas Community fund is now in its eighth year and has awarded more than £850,000 to deserving community projects close to our operations. We support projects that make a difference to life in the mainly rural communities where we operate.

We are committed to having an open dialogue with the public. It is vital for the industry to understand specific communities' needs and to help people to understand the process and what it means for them.

As part of our commitment to open and transparent communications IGas undertakes extensive community engagement alongside our planning applications. This engagement consists of a number of different elements from community meetings and exhibitions to site visits, project websites, newsletters and social media campaigns.

Political and Regulatory Update

Following the vote in June 2016 to leave the EU, a new Government was formed in July 2016 under the leadership of a new Prime Minister, Theresa May. In her opening speech, the Prime Minister said that she wants an energy policy that emphasises the reliability of supply and lower costs for users. Since her appointment, the Prime Minister has created a new Department of Business, Energy and Industrial Strategy headed by Greg Clark, formerly Secretary of State for Communities and Local Government.

In July 2016, the Committee on Climate Change published a report which stated that "shale gas could make a useful contribution to UK energy supplies, including providing some energy security benefits." The report also confirmed that widespread shale gas production is compatible with the carbon budgets provided three tests are met. These tests are already met by existing UK regulations and policy.

On 8 August 2016, the Government launched a Shale Wealth Fund consultation to seek views on on the delivery method and priorities of the fund, including direct payments to communities. The consultation closed at the end of October 2016 and we await its recommendations.

In November 2016, UKOOG, the UK onshore oil and gas industry body, agreed a partnership with Community, the steel, iron and manufacturing industries trade union, to promote the importance of home-grown oil and gas and to protect British jobs.

This builds further links with key industry trade unions following the UKOOG and GMB joint charter on shale gas, focusing on safety, skills and supply chain development. A copy of the charter can be found at http://www.ukoog.org.uk/images/ukoog/pdfs/UKOOG-GMB_Charter_-_8_June_2015.pdf.

Role of Oil and Gas

Gas provides 84% of our homes with heat, 61% with the means to cook, up to 50% of our electricity and the employment of over half a million people in industries that turn natural gas into everyday products such as computers, mobile phones, cosmetics, medicines, fertilisers for our farmers and even solar panels.

The 2015 Paris Agreement re-emphasises the obligation on us to focus on minimising environmental impact. Governments agreed to reduce emissions and developing renewable sources of energy is vital to reducing greenhouse gas emissions. However, renewables cannot entirely satisfy demand themselves right now, and natural gas is needed to help clean energy sources grow.

Gas supports renewables in a number of ways. Gas provides back-up power for days when the wind does not blow and you can track this using Gridwatch http://www.gridwatch.templar.co.uk/ which gives live information on how we are generating our electricity. Gas and renewable energy sources also play different but complementary roles in the energy mix. Currently renewables generally provide electricity but today, 8 out of 10 homes in the UK are heated using gas and as we continue to decarbonise our electricity, it will be gas that will keep us warm. Finally, gas is used as a raw material to help build renewable energy hardware. Solar panels are a good example. Materials made from gas (and oil) protect and bind together the solar cells using items such as silicon rubber, plastic and polyesters.

People

As we move our business forwards it is important to review its effectiveness and efficiency and we have been carefully monitoring and reviewing the current organisational structure in light of the anticipated increase in our shale operational activity in 2017. We have streamlined ourselves not only to meet current challenges but to deliver effectively against our future corporate targets.

Looking back at the year it has certainly been a challenging one for us all but everyone has risen to the task in hand. When I go out into the business I have been struck by the commitment, enthusiasm and dedication of our people. I want to pay particular tribute to all of our employees and thank them for their efforts during 2016, and look forward to working with them in the next phase of our development.

Outlook

Following the completion of our restructuring, we now have a strong balance sheet which will enable us to focus on delivering the significant potential of our production and development assets and provide a solid foundation for the long-term future of the Company.

We are forecasting net production for 2017 to be c.2,500 boepd with capital expenditure of c.£4m in the year. We are focused on cash generation in our production business and anticipate operating costs of $25/boe for the year, which at these current oil price levels and our anticipated general and admin and financing costs means we will be cash generative.

We have now received two planning permissions in the East Midlands and we anticipate spudding these wells in the second half of 2017 to improve our understanding of the Gainsborough Trough. All wells are carried by our partners under our $230 million carried work programme. In the North West, having interpreted the 3D data, we are moving forward with site selection and pre-application preparations.

Our strategy remains clear and focused, as we look to maximise the potential of our existing assets and develop our shale gas business from appraisal to future production.

We look forward to the future with renewed confidence following the refinancing and are excited by the opportunities that increased momentum across the UK shale industry, including further well data, will present during 2017.

Operational Review

Production

2016 was a challenging year for the industry with low oil prices driving cost efficiencies across the sector to ensure competiveness was maintained. The impact on IGas' production business was no different and various actions were taken to ensure that the business remained sustainable in the prevailing circumstances. The main actions implemented entailed a thorough and comprehensive review of the Production business with the aim of reducing operating expenditure by some 15% and revisiting the proposed budgeted capital expenditure to preserve cash.

This review, which was part of the broader corporate cost reduction initiative, entailed a comprehensive assessment of existing processes, practice and costs and encouraged paradigm shifts in approach to achieve the target savings. Some of the key outputs from this exercise included changes in working and shift patterns to better utilise key skills and expertise; emphasis on integration and harmonisation of operations in the East Midlands and the Weald area, for example in maintenance, well services and outsourcing non-core services such as transportation. Unlike the North Sea, the opportunity to materially derive savings through the supply chain were not as tangible owing to the fact that the low levels of onshore related activity means the supply chain is historically already very cost conscious. Nevertheless, some more modest savings were achieved through this avenue.

In 2016, the overall operational expenditure was reduced by c.15% in sterling terms. This is a significant reduction in costs which has been achieved without impacting safety and is testimony to the hard work and commitment of our staff.

As part of the cost reduction exercise a thorough review of capital expenditure was also undertaken and as a consequence a number of projects were deferred to reduce capex and optimise value to the business. These projects offer economic solutions but were recognised as being discretionary and that they would be more attractive in a higher oil price scenario.

Production for the year averaged c.2,355 boepd against guidance of c.2,400 - 2,600 boepd. Production during the year was impacted by two key items, firstly the reduced capital expenditure had an effect and secondly, a number of wells were worked over during the summer.

Despite the backdrop of low oil prices, we were able to continue to advance the initiatives to sustain production and boost recovery through our technical work programmes and application of technology. Key successes included increased well performance through detailed modelling of lift performance and subsequent changes to well completions. The application of downhole gauges and Rod Pump Off Controllers (RPOC's) has provided the Engineering teams with live data against which they are able to evaluate and recommend beneficial changes to the well configurations. This has been a key contributor to lowering costs whilst maintaining production efficiency.

What has been very pleasing is that we have "instrumented" our fields, providing real time data, largely through the efforts of our "in house" team at a fraction of the cost that a similar exercise would have incurred from an industry recognised supplier. In effect we have built our own "digital oilfield" capability and continue to expand this concept with positive cost effective results.

Another key area we have continued to make good progress on is our water injection initiative. Building on the successful pilot conducted at Welton we are pursuing opportunities to expand this initiative both at Welton and in other fields. In parallel we have been trialling technology that can "clean up" produced water to drinking water standards. These trials have proven very successful and offer the opportunity to treat our produced water, removing solids and salts before it is re-injected back into the reservoir. This helps the injection efficiency and keeps costs down. This technology will also be invaluable in terms of re-circulating water used in the shale arena and in doing so help to reduce the overall consumption as well as reducing the number of truck movements required to transport the water.

Water injection has several advantages, it can increase production, extend field life and importantly boost recovery. Some of the incremental reserves referred to below is as a result of the commitment to expanding the water injection project.

Our producing assets portfolio consists largely of mature fields which have historically suffered from relatively high operating costs and low levels of production efficiency. Over the last two years we have embarked upon a number of measures to lower costs and improve production efficiency. We are now seeing these initiatives come to fruition in terms of reduced opex, sustained production levels, even in a reduced capex environment, and year on year increases in booked reserves.

Reserves and Resources

Independent Reserves and Resources Evaluations

On 17 October 2016 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 reports comprised an independent evaluation of IGas conventional oil and gas interests as of 31 July 2016, a report as of 31 July 2016 on the unconventional prospective resources and a report as of 30 June 2016 on reserves and revenue and contingent resources. The full reports can be found on the IGas website.

The D&M independent evaluation also included an estimate of 2C net contingent conventional resources of 21.8 MMboe for IGas properties based on 5.8 Mcf/boe. These resources include oil and gas resources within producing and undeveloped fields that can be readily developed with infill drilling and gas monetisation projects. Three gas monetisation projects now require only sales agreements and final investment decisions (FID) to be able to proceed, which will lead to future reserves additions and incremental production.

Prospective Shale Gas Resources

D&M also produced a separate independent evaluation of risked prospective shale gas resources in the IGas East Midlands and North West licence areas.

Using a deterministic method adopted by the British Geological Survey and including 14^th Round licences awarded in 2016, D&M estimated an IGas gross mean GIIP of 221 Tcf. D&M reported an IGas gross GIIP best estimate of 106 Tcf using PRMS guidelines. These estimates included uncertainty in the productive area.

After application of adjustments for productive areas and recovery factors based on D&M's worldwide experience with analogous shale gas basins, D&M estimated unrisked IGas net shale gas prospective resources of 11 Tcf.

Finally, D&M estimated that IGas has 2.5 Tcf (ca. 440 MMboe) of net risked shale gas resources after taking into account an estimated geological chance of success.

Net IGas Shale Gas Estimates	Units (TcF)	Comments
Gas in Place	102	Using BGS deterministic method
Unrisked Prospective Resource	11	Adjusted for productive area and recovery factor
Risked Mean Prospective Resource	2.5	Adjusted for geological chance of success

Assets

In addition to the 24 onshore fields IGas operates in the UK, predominantly centred in the East Midlands and the Weald Basin, we operate one of the largest net acreage positions in the UK, with a total gross carried shale work programme of up to $230 million as at 31 December 2016.

We continually monitor and manage our portfolio with a view to optimising the economic recovery of oil and gas. During 2016 there were some significant changes to the portfolio involving the relinquishment of acreage no longer deemed core to the business, reduction in equity in PEDLs 293 and 295 as a result of INEOS Upstream Limited ("INEOS") exercising an option to increase their holding, a farm-in into PEDL 278 and a successful outcome from the 14^th Round Licensing awards.

As part of our 14^th Round awards, in the East Midlands and Yorkshire, blocks SE31c/SE41e, SK59b/SK49, and SK89e/SK88b/SK87c were awarded to a joint venture comprising IGas, Total E&P UK Limited ("Total") and Egdon Resources plc ("Egdon"). IGas will be operator of the licences with a 35% interest, Total will have a 50% interest and Egdon a 15% interest. These licences are located in the Gainsborough Trough close to where the Company currently operates 80 sites, the majority of which have been in production for many years. IGas will conduct a shale work programme including 3D seismic surveys and three firm wells. Two further 100% blocks, TF18b and SK99a, were awarded to IGas in the East Midlands with a work programme consisting of two drill or drop wells targeting conventional prospects and 12km of 2D seismic.

In the North West, blocks SJ64/SJ65 and SJ75/SJ76 were awarded to a joint venture comprising IGas and ENGIE E&P UK Limited ("ENGIE"). In March 2017, INEOS completed its acquisition of ENGIE 's interests in certain UK onshore licences held jointly with IGas which included these blocks. IGas will be operator of the licences with a 65% interest and INEOS will have a 35% interest. A work programme consisting of 2D seismic and two drill or drop wells will help to establish the hydrocarbon potential of the shale in this area.

In the South East, IGas has been awarded blocks SU81c, SU81d, SU90a and TQ34d and will be the operator with a 100% interest. These blocks have conventional oil and gas potential and are located adjacent to the IGas Singleton and Bletchingley fields in the Weald Basin. A work programme consisting of 2D seismic acquisition will drive the decision on the two drill or drop wells.

The impact of these various changes to the portfolio is summarised below:

	Gross ('000 acres)	Net ('000 acres)
31 Dec 2015	1,052	769
31 Dec 2016	1,037	632

Development

Gas Monetisation

The planning application at Bletchingley for gas production and the application for compressed natural gas (CNG) at Albury have both now been approved. We continue to seek further cost savings in these projects where possible. Commercial discussions are underway and a formal FID will follow upon their conclusions.

At Lybster, in Scotland, we have been granted planning permission for the facilities upgrade and oil/gas and CNG production streams and discussions are ongoing in respect of the relevant off-take options.

In addition, an application for the installation of a CNG facility at the Singleton field in the Weald has been approved and options on commercial arrangements are being investigated.

Weald Basin

In addition to the planning consent for the CNG plant at Singleton, we also obtained planning consent for two further production wells at Singleton and extended the life of our site at Stockbridge.

East Midlands and Yorkshire

In November 2016, we received planning permission to drill two exploratory wells at a site at Springs Road in the parish of Misson, North Nottinghamshire. The planning application had been submitted in October 2015 and several rounds of information gathering and public consultation were undertaken before a decision was taken by Nottinghamshire County Council Planners.

As part of the planning obligations IGas agreed to sign a S106 legal agreement which covers issues including where HGV's will be routed, the continuation of a community liaison group and the creation of a bond for site restoration. Once these and the other conditions which were imposed have been agreed work can commence on the site. Meanwhile, our Ground Water Monitoring Boreholes are now operational and data is being collected and sent to the Environment Agency.

At our Tinker Lane site, which is also situated in North Nottinghamshire near Blyth, a planning application to drill a single well along with accompanying ground water monitoring boreholes was submitted in May 2016. In March 2017, following a recommendation by Planning Officers to grant consent, planning permission was granted, also subject to the completion of a S106 legal agreement.

Both of these developments will help us to understand the shale gas potential in the region and more widely. There is a pressing need to deliver lower carbon energy that is home grown, provides important energy security for the future alongside economic benefits to the local communities as well as the country as a whole. Depending on the results of these wells we may submit planning applications to carry out hydraulic fracturing in the future.

During the course of 2016 we have continued with an extensive community engagement programme in the area, with a dedicated Community Liaison representative living within the community and holding regular Community Liaison Group meetings and public events. We distributed two newsletters to over 5,000 people in the area and continue to engage with the community, businesses and other stakeholders who have an interest in these developments.

North West

Following the successful 3D North Dee seismic acquisition campaign in Q4 2015 the IGas and Joint Venture partnership geoscience teams have been evaluating the comprehensive data set to refine an initial subsurface target area for exploration and appraisal in the area. On the back of the geological work the IGas Lands & Planning team are in the process of securing surface location options to enable initial exploration and appraisal well applications to move forward.

International Assets

Further progress on divestment of International assets has been made during 2017. All Indonesian operations have been divested. Licences previously held in Germany and Australia have been relinquished or divested. The office in Brisbane has been closed and the lease has not been renewed. Operations in India have been completed and application made to relinquish the last remaining licence has been submitted. The deregistration of the companies in China and Vietnam have progressed and are expected to be finalised in December 2017.

Financial Review

A key objective for the Group for the year ended 31 December 2016 was to reach a consensual solution with its bondholders in relation to its forecast non-compliance with certain of its covenants during the year. After many months of discussions, agreement was ultimately reached with bondholders on a restructuring proposal which was formally approved by all stakeholders in April 2017. The restructure involved new equity of $55 million being raised net of expenses, $40 million of secured bonds being exchanged for equity at par, $49.2 million of secured bonds being bought by the Company at par, $27.4 million unsecured bonds being exchanged for equity at 62.5 cents and the remaining $30 million of secured bonds having their terms amended. This resulted in net debt being reduced from c.$122 million to under $10 million post completion of the transaction.

Results for the year

Oil price volatility and the fall in the value of sterling against the US dollar both had a significant impact on the results of the Group during the year. The price of Brent crude reached a low of $27/bbl in January 2016 and a high of $55/bbl in December 2016, with an average price of $44/bbl during the year. Sterling weakened against the US dollar following the result of the EU referendum and the exchange rate declined from £1:$1.50 at the beginning of the year to £1:$1.23 in December 2016, having a negative impact on our US dollar denominated debt.

In the twelve months ended 31 December 2016 adjusted EBITDA was £10.2 million (Nine months ended 31 December 2015: £18.3 million) whilst a loss was recognised from continuing activities after tax of £31.8 million (Nine months ended 31 December 2015: loss £47.2 million). The main factors driving the movements between the twelve months ended 31 December 2016 and the nine months ended 31 December 2015 were as follows:

· Revenues increased to £30.5 million (Nine months ended 31 December 2015: £25.1 million) principally due to higher sales volumes in the longer accounting period. Lower average daily production and a lower US dollar price per barrel were partially offset by a strengthening US dollar;

· Other costs of sales increased to £20.9 million (Nine months ended 31 December 2015: £14.4 million) mainly due to higher sales volumes over the full year;

· Administrative expenses increased to £11.4 million (Nine months ended 31 December 2015: £6.0 million) due to the inclusion of £3.0 million (Nine months ended 31 December 2015: £nil) of legal and professional costs relating to refinancing, higher non-cash share based payment charges of £2.6 million (Nine months ended 31 December 2015: £0.5 million) and lower capitalisation of costs due to lower capital activity in the year. Restructuring costs were £0.6 million (Nine months ended 31 December 2015: £2.1 million) as the cost reduction programme was completed primarily in 2015;

· Impairment charges of £nil on property, plant and equipment (Nine months ended 31 December 2015: £8.9 million net of tax) and impairment charges of £nil on goodwill (Nine months ended 31 December 2015: £39.2 million) due to higher reserves, higher estimated future oil prices and a favourable USD/GBP exchange rate;

· An exploration write off of £4.5million (Nine months ended 31 December 2015: £12.9 million);

· A profit on disposal of oil and gas assets of £nil (Nine months ended 31 December 2015: £4.0 million on the INEOS farm-out);

· Other income decreased to £0.7 million (Nine months ended 31 December 2015: £5.1 million); and

· A tax credit of £13.0 million mainly due to the reversal of temporary timing differences and a reduction in the supplementary corporation tax rate from 20% to 10% from 1 January 2016 (Nine months ended 31 December 2015: £17.3 million credit due to timing difference reversals caused by the impairment of assets).

Income statement

The Group recognised revenues of £30.5 million in the year (Nine months ended 31 December 2015: £25.1 million). Group production in the year was an average of 2,355 boepd (Nine months ended 31 December 2015: 2,570 boepd). Revenues for the year included £3.3 million (Nine months ended 31 December 2015: £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 $44.1/bbl (Nine months ended 31 December 2015: $51.3/bbl) and post hedge $58.1/bbl (Nine months ended 31 December 2015: $58.9/bbl). The realised gain on hedges was £8.5 million (Nine months ended 31 December 2015: £3.3 million) reflecting the movement in oil prices. The average GBP/USD exchange rate for the year was £1: $1.37 (Nine months ended 31 December 2015: £1: $1.53) which positively impacted revenues.

Cost of sales for the year were £27.2 million (Nine months ended 31 December 2015: £21.5 million) including depreciation, depletion and amortisation (DD&A) of £6.3 million (Nine months ended 31 December 2015: £7.1 million), and operating costs of £20.9 million (Nine months ended 31 December 2015: £14.4 million). Operating costs include a cost of £2.7 million (Nine months ended 31 December 2015: £2.2 million) in relation third party oil. The contribution received from processing this third party oil was £0.6 million (Nine months ended 31 December 2015: £0.2 million).

Operating costs per barrel of oil equivalent (boe) were £21.1 ($28.8), excluding third party costs (Nine months ended 31 December 2015: £16.1 ($24.6) per boe). Operating costs per boe were higher in 2016 due to the impact of lower volumes on fixed costs, higher transportation costs and a credit in 2015 of £3.6/boe ($5.5/boe) related to a refund for land rates.

Adjusted EBITDA in the year was £10.2 million (Nine months ended 31 December 2015: £18.3 million). Gross profit for the year was £3.3 million (Nine months ended 31 December 2015: £3.6 million). Administrative costs increased by £5.4 million to £11.4 million (Nine months ended 31 December 2015: £6.0 million) principally due to the longer accounting period, additional legal and professional costs relating to refinancing of £3.0 million (Nine months ended 31 December 2015: £nil), increase in non-cash share based payment charges to £2.6 million (Nine months ended 31 December 2015: £0.5 million) and lower capitalisation of costs due to lower capital activity in the year, partially offset by higher restructuring costs in 2015.

No impairment charge was recognised in the year principally as a result of higher reserves, higher estimated future oil prices and a favourable USD/GBP exchange rate (Nine months ended 31 December 2015: £48.1 million net of tax - £8.9 million relating to producing assets and £39.2 million relating to goodwill).

Exploration costs written off were £4.5 million (Nine months ended 31 December 2015: £12.9 million) relating to relinquishment of licences during the year.

Other income of £0.7 million included £0.4 million (Nine months ended 31 December 2015: £4.9 million) relating to a fair value adjustment on the contingent deferred consideration in relation to an amount payable to a joint venture partner.

Net finance costs were £28.8 million for the year (Nine months ended 31 December 2015: £7.8 million), which primarily related to interest on borrowings of £11.9 million (Nine months ended 31 December 2015: £8.7 million), a net foreign exchange loss of £14.8 million principally on the US$ denominated debt (Nine months ended 31 December 2015: gain £0.1 million) and a realised loss on the sale of bonds of £1.5 million (Nine months ended 31 December 2015: £0.9 million gain on bonds repurchased)

The Group made a loss on oil price derivatives of £3.5 million for the year (Nine months ended 31 December 2015: gain £8.6 million).

Cash flow

Net cash generated from operating activities for the year was £12.4 million (Nine months ended 31 December 2015: £1.0 million). The Group invested £8.8 million across its asset base during the year (Nine months ended 31 December 2015: £9.4 million), of which £6.5 million was invested in the conventional assets in order to maintain current levels of production and £2.3 million in unconventional assets in furtherance of our shale exploration programme.

The Company repaid £4.9 million ($7.1 million) of principal on borrowings to bondholders in the period in accordance with the terms of the bonds (Nine months ended 31 December 2015: £6.1 million ($8.2 million)), which represents a repayment of 5% of the original principal amount of the secured bonds. The Company also resold bonds with a face value of $8.0 million for $6.5 million in November 2016 (Nine months ended 31 December 2015: repurchased bonds with a face value of $7.0 million for $5.3 million).

The Company paid £11.6 million ($15.5 million) in interest (Nine months ended 31 December 2015: £5.9 million ($9.0 million)). Cash and cash equivalents were £24.9 million at the end of the year (31 December 2015: £28.6 million).

Balance sheet

Net assets were £70.5 million at 31 December 2016 (31 December 2015: £98.8 million) with the decrease in net assets principally resulting from the loss arising during the year.

Trade and other receivables decreased by £8.0 million mainly due to a reduction in receivables from JV partners following lower activity and a receivable in respect of a rates refund included in 2015.

Borrowings increased from £102.9 million to £124.6 million mainly as a result of the negative impact of the strengthening of the US dollar on US dollar denominated debt and the sale of $8.0 million secured bonds during the year.

At 31 December 2016, the Group's derivative instruments had a net negative fair value of £0.9 million (31 December 2015: net positive fair value of £6.6 million).

Net debt, being borrowings less cash, at the period end amounted to £99.7 million (31 December 2015: £73.3 million).

At the Annual General Meeting of the Company held on 25th May 2016, a special resolution was passed approving a reduction of the Company's capital by way of the cancellation of the whole of the amount standing to the credit of the Company's share premium account and the capital redemption reserve thus eliminating the current deficit position and creating distributable reserves. Following the approval of the High Court and the subsequent registration of the Court order with the Registrar of Companies the Capital Reduction has now become effective.

The Company issued 4,082,114 ordinary shares at a nominal value of 10p each. 1,767,220 shares were issued in connection with the disposal of the Company's interest in Sangatta West CBM Inc under a Share Transfer Agreement with Ephindo International CBM Holding Inc. thereby disposing of the Group's remaining interest in Indonesia. The balance of shares were issued in connection with the IGas Energy Share Incentive Plan. (Nine months ended 31 December 2015: 1,899,102 shares issued)

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

Adjusted EBITDA

	Year to 31 December 2016	Nine months to 31 December 2015
	£ million	£ million
Loss before tax	(44.8)	(64.5)
Net finance costs	28.8	7.8
Depletion, depreciation & amortisation	6.5	7.2
Share based payment charges	2.6	0.5
Restructuring costs and one-off costs relating to Ineos farm-out	0.6	2.7
Impairments/write offs	4.5	69.8
Unrealised loss/(gain) on hedges	12.0	(5.3)
Adjusted EBITDA	10.2	18.3

Underlying Operating Profit

	Year to 31 December 2016	Nine months to 31 December 2015
	£ million	£ million
Operating loss	(16.0)	(56.6)
Share based payment charges	2.6	0.5
Restructuring costs and one off costs relating to Ineos farm-out	0.6	2.7
Impairments/write offs	4.5	69.8
Loss/(gain) on oil price derivatives	12.0	(5.3)
Underlying operating profit	3.7	11.1

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 strength of the Group's balance sheet has been improved significantly by the capital restructuring completed in April 2017. Based on the Group's strategic plans and working capital forecasts, the Directors have a reasonable expectation that the Group has adequate resources to continue in existence for the foreseeable future. Thus the Directors continue to adopt the going concern basis in the preparation of the financial statements.

Outlook

Following the completion of the capital restructuring in April 2017 we have a strong balance sheet that will allow us to fully pursue our strategy of achieving long term value creation for all our stakeholders.

Stephen Bowler Julian Tedder

Chief Executive Officer Chief Financial Officer

25 April 2017 25 April 2017

Consolidated Income Statement

For the year ended 31 December 2016

	Notes	Year ended 31 December 2016 £000	Nine months ended 31 December 2015 £000
Revenue	2	30,471	25,123
Cost of sales:
Depletion, depreciation and amortisation		(6,323)	(7,105)
Other costs of sales		(20,857)	(14,416)
		(27,180)	(21,521)
Gross profit		3,291	3,602
Administrative expenses		(11,406)	(5,973)
Restructuring costs		(557)	(2,117)
Impairment of goodwill	8	-	(39,227)
Exploration and evaluation assets written off	9	(4,485)	(12,900)
Impairment of property, plant and equipment	10	-	(17,720)
Profit on disposal of oil and gas assets	3	-	3,998
(Loss)/gain on oil price derivatives		(3,496)	8,618
Other income	4	660	5,070
Operating loss		(15,993)	(56,649)
Finance income	5	277	1,302
Finance costs	5	(29,057)	(9,127)
Loss from continuing activities before tax		(44,773)	(64,474)
Income tax credit	6	13,006	17,257
Loss after tax from continuing operations attributable to equity shareholders of the Group		(31,767)	(47,217)
(Loss)/gain after tax from discontinued operations		(1,144)	2,395
Net loss attributable to equity shareholders of the Group		(32,911)	(44,822)
Loss attributable to equity shareholders:
Basic loss per share (pence/share)	7	(10.99p)	(15.15p)
Diluted loss per share (pence/share)	7	(10.99p)	(15.15p)

Consolidated Statement of Comprehensive Income

For the year ended 31 December 2016

	Year ended 31 December 2016 £000	Nine months ended 31 December 2015 £000
Loss for the year/period	(32,911)	(44,822)
Other comprehensive income/(loss) for the year/period
Currency translation adjustments recycled to the income statement	105	1,229
Currency translation adjustments	(1,231)	(5,058)
Total comprehensive loss for the year/period	(34,037)	(48,651)

Consolidated Balance Sheet

For the year ended 31 December 2016

	Notes	31 December 2016 £000	31 December 2015 £000
ASSETS
Non-current assets
Intangible exploration and evaluation assets	9	112,448	113,394
Property, plant and equipment	10	97,709	82,911
Goodwill	8	4,801	4,801
		214,958	201,106
Current assets
Inventories		1,270	1,208
Trade and other receivables		7,015	14,809
Cash and cash equivalents		24,946	28,614
Other financial assets - restricted cash		-	1,007
Derivative financial instruments		-	6,654
Assets classified as held for sale		-	1,837
		33,231	54,129
Total assets		248,189	255,235
LIABILITIES
Current liabilities
Trade and other payables		(8,170)	(9,218)
Current tax liabilities		(1,318)	(2,004)
Borrowings	11	(6,084)	(4,819)
Other liabilities		(11)	(147)
Derivative financial instruments		(876)	-
Liabilities associated with assets classified as held for sale		-	(1,837)
		(16,459)	(18,025)
Non-current liabilities
Borrowings	11	(118,495)	(98,060)
Deferred tax liabilities		(1,779)	(14,636)
Provisions	12	(40,924)	(25,323)
Contingent deferred consideration		-	(420)
		(161,198)	(138,439)
Total liabilities		(177,657)	(156,464)
Net assets		70,532	98,771
EQUITY
Capital and reserves
Called up share capital		30,282	29,882
Share premium account		32	121,623
Capital redemption reserve		-	64,882
Foreign currency translation reserve		(7,990)	(6,864)
Other reserves		28,757	23,544
Surplus/(Accumulated deficit)		19,451	(134,296)
Total equity		70,532	98,771

Consolidated Statement of Changes in Equity

For the year ended 31 December 2016

	Called up share capital £000	Share premium account £000	Capital redemption reserve £000	Foreign currency translation reserve* £000	Other reserves** £000	Accumulated surplus/(deficit) £000	Total equity £000
At 1 April 2015	26,446	117,463	41,239	(3,035)	1,264	(36,757)	146,620
Adjustment	3,246	3,892	23,643	-	22,222	(53,003)	-
Adjusted balance at 1 April 2015***	29,692	121,355	64,882	(3,035)	23,486	(89,760)	146,620
Loss for the period	-	-	-	-	-	(44,822)	(44,822)
Employee share plans	-	-	-	-	1,344	-	1,344
Forfeiture of LTIPs under the employee share plan	-	-	-	-	(1,000)	-	(1,000)
Lapse of LTIPs under the employee share plan	-	-	-	-	(286)	286	-
Issue of shares	190	268	-	-	-	-	458
Currency translation adjustments	-	-	-	(3,829)	-	-	(3,829)
Adjusted balance at 31 December 2015 and 1 January 2016	29,882	121,623	64,882	(6,864)	23,544	(134,296)	98,771


Loss for the period	-	-	-	-	-	(32,911)	(32,911)
Capital reduction	-	(121,776)	(64,882)	-	-	186,658	-
Employee share plans	-	-	-	-	5,344	-	5,344
Forfeiture of LTIPs under the employee share plan	-	-	-	-	(131)	-	(131)
Issue of shares	400	185	-	-	-	-	585
Currency translation adjustments	-	-	-	(1,126)	-	-	(1,126)
At 31 December 2016	30,282	32	-	(7,990)	28,757	19,451	70,532

* 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.

*** Reclassification of the Group's share capital, share premium, capital redemption reserve and other reserves to align with those of the parent company. This adjusts the classification adopted on the reverse acquisition in December 2007.

Consolidated Cash Flow Statement

For the year ended 31 December 2016

	Notes	Year ended 31 December 2016 £000	Nine months ended 31 December 2015 £000
Cash flows from operating activities:
Loss before tax for the year/period		(44,773)	(64,474)
Adjustment for non-operating gain relating to farm-out		-	(3,998)
Adjustment for gain relating to deferred consideration	4	(420)	(4,947)
Depletion, depreciation and amortisation	10	6,474	7,233
Decommissioning costs incurred		(418)	(6)
Share based payment charge		3,499	600
Impairment of goodwill		-	39,227
Exploration and evaluation assets written off	9	4,485	12,900
Impairment of property, plant and equipment		-	17,720
Unrealised loss/(gain) on oil price derivatives		11,969	(5,281)
Finance income	5	(277)	(1,302)
Finance costs	5	29,057	9,127
Other non-cash adjustments		(13)	(326)
Operating cash flow before working capital movements		9,583	6,473
Decrease/(increase) in trade and other receivables and other financial assets		3,366	(5,568)
Increase in trade and other payables, net of accruals related to investing activities		698	130
Increase in inventories		(176)	(248)

Cash generated from continuing operating activities		13,471	787
Cash (used in)/generated from discontinued operating activities		(489)	175
Taxation paid - continued		(559)	-
Net cash generated from operating activities		12,423	962
Cash flows from investing activities:
Purchase of intangible exploration and evaluation assets		(2,304)	(2,963)
Purchase of property, plant and equipment		(6,509)	(6,396)
Disposal of subsidiary		(171)	-
Disposal of exploration and evaluation assets		-	30,000
Disposal of oil and gas assets		22	181
Interest received		34	107
Cash (used in)/generated from continuing investing activities		(8,928)	20,929
Cash used in discontinued investing activities		(177)	(52)
Net cash (used in)/generated from investing activities		(9,105)	20,877

Cash flows from financing activities:
Cash proceeds from issue of ordinary share capital		136	125
Interest paid		(11,570)	(5,925)
Bond renegotiation costs		-	(940)
Repayment of borrowings	11	(4,916)	(6,147)
Cash proceeds from sale of bonds		4,914	-
Cash used in continuing financing activities		(11,436)	(12,887)
Net cash used in financing activities		(11,436)	(12,887)
Net (decrease)/increase in cash and cash equivalents in the year/period		(8,118)	8,952
Net foreign exchange difference		4,450	637
Cash and cash equivalents at the beginning of the year/period		28,614	19,025
Cash and cash equivalents at the end of the year/period		24,946	28,614

Consolidated Financial Statements - Notes

For the year ended 31 December 2016

1 Accounting policies

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

The financial information set out above does not constitute the Group's statutory accounts for the year ended 31 December 2016, but is derived from the Group's full financial accounts, which are in the process of being audited. The Group's full financial accounts will be prepared under International Financial Reporting Standards as adopted by the European Union. The condensed consolidated financial information has been prepared under the historical cost convention basis, as modified by the revaluation of financial assets and financial liabilities (including derivative instruments) at fair value through profit and loss.

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 strength of the Group's and Company's balance sheet has been improved significantly by the capital restructuring as disclosed in note 13 to the financial statements. Based on their strategic plans and working capital forecasts, the Directors have a reasonable expectation that the Group and the Company have adequate resources to continue in existence for the foreseeable future. Thus they continue to adopt the going concern basis in the preparation of the financial statements.

2 Revenue and segment information

IFRS 8 requires operating segments to be identified on the basis of internal reports about components of the Group that are regularly reviewed by the Chief Operating Decision Maker ("CODM") to make decisions about resources to be allocated to the segments and assess their performance, and for which financial information is available. In the case of the Group, the CODM are the Chief Executive Officer and the Board of Directors and all information reported to the CODM is based on the consolidated results of the Group representing core (UK) and non-core (Rest of the World) operating segments. Therefore the Group has two operating and reportable segments as reflected in the Group's consolidated financial statements.

All revenue, which represents turnover, arises solely within the United Kingdom and relates to external parties. Revenues of approximately £16.0 million and £10.3 million were derived from the Group's two largest customers (nine months ended 31 December 2015: £11.8 million and £10.1 million).

The majority of the Group's non-current assets are in the United Kingdom.

	UK £000	Rest of the World £000	Year ended 31 December 2016 Group £000

Oil sales to external customers	30,009	-	30,009
Electricity sales to external customers	462	-	462
	30,471	-	30,471

	(15,926)	(67)	(15,993)
Segment operating loss

Interest expense (note 5)	(11,930)	-	(11,930)
Interest income (note 5)	63	-	63
Other finance costs - net (note 5)	(16,913)	-	(16,913)
Loss before tax and discontinued operations	(44,706)	(67)	(44,773)

Other segment information
Capital expenditure - exploration and evaluation (note 9)	3,616	-	3,616
Capital expenditure - property, plant and equipment (note 10)	5,964	-	5,964
Depletion, depreciation and amortisation (note 10)	6,494	-	6,494

	UK £000	Rest of the World £000	Nine months ended 31 December 2015 Group £000

Oil sales to external customers	24,753	-	24,753
Electricity sales to external customers	370	-	370
	25,123	-	25,123


Segment operating loss	(56,408)	(241)	(56,649)

Interest expense (note 5)	(8,731)	-	(8,731)
Interest income (note 5)	105	-	105
Other finance income - net (note 5)	801	-	801
Loss before tax and discontinued operations	(64,223)	(241)	(64,474)

Other segment information
Capital expenditure - exploration and evaluation (note 9)	2,931	-	2,931
Capital expenditure - property, plant and equipment (note 10)	7,573	-	7,573
Depletion, depreciation and amortisation (note 10)	7,249	-	7,249

3 Profit on disposal of oil and gas assets

The profit on disposal of oil and gas assets for the period ended 31 December 2015 arose as a result of the farm-out agreement with INEOS Upstream Limited ("INEOS") which completed in May 2015. Under the agreement, INEOS acquired a 50% interest in IGas' UK Onshore PEDLs 147, 184, 189 and 190 and a 60% interest in IGas' UK Onshore PEDLs 145, 193 and EXL 273, (the "Bowland Licences") in the North West of England. In addition, INEOS acquired IGas' entire working interest in the acreage held under PEDL 133 in Scotland. In the East Midlands, INEOS also acquired a 20% interest in in PEDLs 012 and 200. INEOS assumed operatorship of PEDLs 145 and 193 and EXL 273. IGas retained operatorship of all other Bowland Licences. INEOS made a cash payment to IGas of £30.0 million on completion of the deal, resulting in a gain of £4.0 million, and will provide a fully funded future work programme of up to £138.0 million gross, of which IGas' share is expected to amount to approximately £56.0 million.

4 Other income

Other income includes £0.4 million (nine months ended 31 December 2015: £4.9 million) relating to the release of contingent deferred consideration.

5 Finance income and costs

	Year ended 31 December 2016 £000	Nine months ended 31 December 2015 £000
Finance income:
Interest on short-term deposits	63	105
Foreign exchange gains	-	51
Other interest	78	1
Gain on Bond buyback (note 11)	-	943
Gain on fair value of warrants	136	202
Finance income recognised in income statement	277	1,302

Finance expense:
Loss on sale of bonds (note 11)	1,540	-
Interest on borrowings	11,930	8,731
Foreign exchange loss	14,841	-
Unwinding of discount on provisions (note 12)	746	396
Finance expense recognised in income statement	29,057	9,127

6 Taxation

i) Tax charge on loss from continuing ordinary activities

	Year ended 31 December 2016 £000	Nine months ended 31 December 2015 £000
UK corporation tax:
Current tax on income for the year	-	1,253
Credit in relation to prior year	(149)	(335)
Total current tax charge	(149)	918
Deferred tax:
Current year credit relating to the origination or reversal of temporary differences	(6,009)	(16,418)
Current year credit relating to the movement due to the tax rate changes	(6,270)	-
Credit in relation to prior year	(578)	(1,757)
Total deferred tax credit	(12,857)	(18,175)
Tax credit on profit on ordinary activities	(13,006)	(17,257)

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%. This has decreased from 50% following the reduction in the supplementary charge rate from 20% to 10% with effect from 1 January 2016.

7 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 £32.9m (nine months ended 31 December 2015: £44.8m) and the weighted average number of ordinary shares outstanding during the period of 299.5 million (31 December 2015: 295.9 million).

Diluted EPS amounts are based on the loss after taxation attributable to the ordinary equity holders of the parent and the weighted average number of shares outstanding during the period 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.

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

	Year ended 31 December 2016	Nine months ended 31 December 2015
Basic EPS - ordinary shares of 10p each (pence)	(10.99p)	(15.15p)
Diluted EPS - ordinary shares of 10p each (pence)	(10.99p)	(15.15p)
Loss for the year/period attributable to equity holders of the parent - £000	(32,912)	(44,822)
Weighted average number of ordinary shares in the year/period - basic EPS	299,542,623	295,947,728
Weighted average number of ordinary shares in the year/period - diluted EPS	299,542,623	295,947,728

There are 32,727,361 potentially dilutive warrants and options over the ordinary shares at 31 December 2016 (31 December 2015: 23,305,230), which are not included in the calculation of diluted earnings per share because they were anti-dilutive as their conversion to ordinary shares would decrease the loss per share.

8 Goodwill

	31 December 2016 £000	31 December 2015 £000
Opening balance	4,801	44,028
Impairment	-	(39,227)
	4,801	4,801

Goodwill is monitored by conventional and unconventional CGUs for internal management purposes. The carrying value of goodwill relates to unconventional assets acquired as part of the Dart acquisition in 2014. Goodwill related to the conventional assets was impaired in full in the year ended 31 December 2015.

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 2016 and assessed it for impairment by estimating the fair value of risked contingent resources using an estimated market valuation of resources based on a recent transaction. The fair value is a level 3 fair value measurement. No impairment was required for the year (31 December 2015: £39.2 million). Full details of the 2015 goodwill impairment are disclosed in the Group's 2015 Annual Report which is available at www.igasplc.com. There was no tax effect of the impairment of goodwill for the year ended 31 December 2015.

9 Intangible exploration and evaluation assets

	Year ended 31 December 2016 £'000	Nine months ended 31 December 2015 £'000
At 1 January/April	113,394	151,615
Additions	3,616	2,931
Farm-out	-	(28,252)
Changes in decommissioning^**	(77)	-
Amounts written off*	(4,485)	(12,900)
At 31 December	112,448	113,394

* 2016 - write off of unconventional exploration and evaluation assets of £4.5 million due to relinquishment of licences considered to be uncommercial.

2015 - write off of unconventional exploration and evaluation assets of £7.0 million due to relinquishment of licences considered to be uncommercial; impairment of UK-conventional exploration and evaluation assets of £5.9 million.

**The decommissioning asset increased in line with the decommissioning liability following a review of the estimate and assumptions at 31 December 2016 (note 12).

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

The Group's exploration and evaluation assets were reviewed for indicators of impairment as at 31 December 2016. No indicators of impairment were identified. As at 31 December 2015, the impairment of UK-conventional assets was £5.9 million pre-tax (£2.9 million post-tax). Full details of the assumptions used in the 2015 review of impairment are disclosed in the Group's 2015 Annual Report which is available at www.igasplc.com.

10 Property, plant and equipment

	Year ended 31 December 2016			Nine months ended 31 December 2015
	Oil and gas assets £'000	Other fixed assets £'000	Total £'000	Oil and gas assets £'000	Other fixed assets £'000	Total £'000
Cost
At 1 January/April	147,434	3,731	151,165	144,230	4,318	148,548
Additions	5,622	342	5,964	7,480	93	7,573
Disposals	(77)	(306)	(383)	(383)	(555)	(938)
Changes in decommissioning^**	15,350	-	15,350	(3,893)	-	(3,893)
Write off	-	-	-	-	(118)	(118)
Foreign exchange	-	-	-	-	(7)	(7)
At 31 December	168,329	3,767	172,096	147,434	3,731	151,165
Depreciation and Impairment
At 1 January/April	66,815	1,439	68,254	42,524	1,710	44,234
Charge for the year/period	6,156	338	6,494^*	6,956	293	7,249*
Disposals	(77)	(284)	(361)	(383)	(440)	(823)
Impairment	-	-	-	17,720	-	17,720
Write off	-	-	-	-	(118)	(118)
Foreign exchange	-	-	-	(2)	(6)	(8)
At 31 December	72,894	1,493	74,387	66,815	1,439	68,254
NBV at 31 December	95,435	2,274	97,709	80,619	2,292	82,911

* Charge for the year includes £20 thousand (nine months ended 31 December 2015: £15 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 2016 (note 12).

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, the Group's oil and gas properties were reviewed for impairment as at 31 December 2016. 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 $55/bbl for 2017, $60/bbl for 2018, $65/bbl for 2019, $70/bbl for 2020 and $75/bbl thereafter, and a USD/GBP foreign exchange rate of $1.25/£1.00. Cash flows were discounted using a pre-tax discount rate of 14%. No impairment was required in the year to 31 December 2016 (nine months ended 31 December 2015: impairment charge of £17.7 million pre-tax (£8.8 million post-tax)).

Sensitivity of changes in assumptions

As discussed above the principal assumptions are recoverable future production and resources and estimated Brent prices. Neither a 10% reduction in production, an average $10/bbl reduction in Brent prices nor a 10% decline in the value of sterling against the US dollar would result in an impairment.

11 Borrowings

	31 December 2016			31 December 2015
	Within 1 year £000	Greater than 1 year £000	Total £000	Within 1 year £000	Greater than 1 year £000	Total £000
Bonds - secured*	6,084	96,700	102,784	4,819	80,125	84,944
Bonds - unsecured*	-	21,795	21,795	-	17,935	17,935
Total	6,084	118,495	124,579	4,819	98,060	102,879

*No additional transaction costs relating to debt were incurred during the year (31 December 2015: costs of £1.0 million which have been netted against the liability).

In 2013, the Company and Norsk Tillitsmann ("Bond Trustee") entered into a Bond Agreement for the Company to issue up to US$165.0 million secured bonds and up to US$30.0 million unsecured bonds (issued at 96% of par). The bonds were subsequently listed on Oslo Bors and the Alternative bond market in Oslo. During the period to 31 December 2015 the Company amended the terms of the Bond Agreement. The primary changes were in relation to the covenants and the maintenance of financial ratios including the establishment of the DSRA.

Both secured and unsecured bonds carry a coupon of 10% per annum (where interest is payable semi-annually in arrears). The secured bonds are amortised semi-annually at 2.5% of the initial loan amount. Final maturity on the secured bonds is on 22 March 2018 and on the unsecured bonds is 11 December 2018.

During the year to 31 December 2016, the Company sold a total of 8,000,000 secured bonds resulting in an aggregate loss of £1.5 million (nine months ended 31 December 2015: repurchased 5,414,747 secured bonds resulting in a gain of £0.5m).

No unsecured bonds were sold or repurchased during the year to 31 December 2016. During the nine months to 31 December 2015, the Company repurchased a total of 1,600,000 unsecured bonds resulting in an aggregate gain of £0.4 million.

The liability has increased compared to 31 December 2015 reflecting the impact of the decline in the value of sterling against the US dollar.

See note 13 for details of changes to the liability since the year end.

12 Provisions for liabilities and charges

	31 December 2016			31 December 2015
	Decommissioning £000	Other £000	Total £000	Decommissioning £000	Other £000	Total £000
At the beginning of the year/period	25,284	39	25,323	28,787	39	28,826
Utilisation of provision	(418)	-	(418)	(6)	-	(6)
Unwinding of discount (note 5)	746	-	746	396	-	396
Reassessment of decommissioning provision/liabilities	15,273	-	15,273	(3,893)	-	(3,893)
At the end of the year/period	40,885	39	40,924	25,284	39	25,323

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 2 and 29 years from the year end (31 December 2015: 2 to 32 years). These provisions are based on the Groups' internal estimate as at 31 December 2016. 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.

The risk free rate range of 0.58% to 3.80% is used in the calculation of the provision as at 31 December 2016 (31 December 2015: Risk free rate range of 0.68% to 3.58%).

13 Subsequent events

SIP scheme

On 30 January 2017, the Company issued 484,956 Ordinary 10p shares in relation to the Group's SIP scheme.

Capital restructure

During the year, the Company disclosed that it expected to be non-compliant with its leverage covenants under its secured bond agreement at 31 December 2016 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;

· 403,069,644 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; and

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

14 Preliminary results announced

The Annual Report and Accounts 2016 will be made available to shareholders once approved and will be available on the Company's website - www.igasplc.com

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

MMboe Millions of barrels of oil equivalent

MMscfd Millions of standard cubic feet per day

PEDL United Kingdom petroleum exploration and development licence.

PL Production licence

Tcf Trillions of standard cubic feet of gas

UK United Kingdom

This information is provided by RNS

The company news service from the London Stock Exchange

END

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