Full year Results

 

21 March 2018

IGas Energy plc (AIM: IGAS)

Full year results for the year ended 31 December 2017

 

IGas Energy plc ("IGas" or "the Company" or "the Group"), one of the leading producers of hydrocarbons onshore in Britain, announces its full year results for the year ended 31 December 2017.

Results Summary

	Year ended 31 Dec 2017 £m	Year ended 31 Dec 2016 £m
Revenues	35.8	30.5
Adjusted EBITDA1	9.2	10.2
Profit/(loss) after tax	15.5	(32.9)
Net cash  from operating activities	6.7	12.4
Net debt2	6.2	99.7
Cash and cash equivalents	15.7	24.9

Operational Summary

·     Net production averaged 2,335 boepd for the year (2016: 2,355 boepd). Operating costs for the year were $28.2/boe (2016: $28.8/boe).  We currently anticipate net production of between 2,300 - 2,400 boepd in 2018 and operating expenditure of $32.5/boe (assuming an exchange rate of £1:$1.40)

·     2P conventional reserves replacement of over 100% (31 Dec 2017:  Net 2P reserves 13.64 MMboe³).

·     Site construction continues at both our sites in North Nottinghamshire, Springs Road and Tinker Lane. We are on track to spud the first well mid-2018.

·     In the North West, at Ellesmere Port, we were granted environmental permits and the Planning Officer's recommendation for the approval of our application. At the planning committee meeting on 25 January 2018, the committee voted to refuse the application. It is our intention to appeal this decision.

·     Also in the North West, at Ince Marshes, we continue to progress our planning application to drill a new well and hydraulically fracture at this existing site. Subject to surveys and monitoring we expect to submit the application mid-2018.

·     Our gas monetisation project at Albury in Surrey is progressing well.  We anticipate first gas from Albury in the second half of 2018, subject to planning consent.

·     The Stockbridge field project, which includes a number of secondary recovery techniques, is well underway. These activities will not only de-risk the existing production but add up to 30% of incremental production from the field.

Corporate and Financial Summary

·     Successful completion of capital restructuring and fundraising in April 2017.

·     Cash balances as at 31 December 2017 of £15.7 million and net debt of £6.2 million.

·     Carried work programme of up to $240 million as at 31 December 2017, at year end exchange rate of $1.35.

·     600,000 barrels hedged for 2018 using three-way zero cost collars with an average floor price protection of $47/bbl and an average call spread of $60/bbl - $75/bbl.

Notes

1.        Adjusted 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.

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

3.        Company estimates.

Commenting today Stephen Bowler, Chief Executive Officer, said:

"The expectation of ongoing free operating cash flow provides us with a solid platform and financial flexibility to execute our growth plans, as we move into a busy operational period for IGas.  We have sanctioned a number of projects, including Albury and Stockbridge, and would expect to see the benefits of these projects during the latter part of 2018.

Site construction continues at Springs Road and Tinker Lane and we look forward to progressing to drilling.  These wells will form the foundation of a wider development in the East Midlands with the mid-term focus moving to a pilot development in the Gainsborough Trough, leveraging our existing, long standing operations in the East Midlands.

In the North West we are progressing our application at Ince Marshes and advancing further applications.  It is our intention to appeal the decision of Cheshire West and Chester Council's Planning Committee of 25 January 2018 to refuse planning consent for our application to test the Pentre Chert formation at Ellesmere Port.

There is also a significant level of activity onshore UK, and over the next 12 months, the industry is expected to have a number of operators either drilling or flowing wells. As momentum builds across both our business and the industry as a whole, we look forward to the future with excitement as security of energy supply and diversification of the UK energy mix becomes ever more important."

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

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 35 years oil and gas exploration and production experience.

For further information please contact:

IGas Energy plc

Tel : +44 (0)20 7993 9899

Stephen Bowler, Chief Executive Officer

Julian Tedder, Chief Financial Officer

Ann-marie Wilkinson, Director of Corporate Affairs

 

Investec Bank plc (NOMAD and Joint Corporate Broker)

Tel: +44 (0)20 7597 5970

Sara Hale/Jeremy Ellis/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

I am pleased that the Company is now both financially stronger and at a very exciting point in its operational evolution.  2017 was a year of significant change at IGas. A major financial restructuring was successfully completed and as part of that process we attracted a new strategic investor in Kerogen Capital, who specialise in the oil and gas sector. Alongside the refinancing, we changed the composition of the Board, and implemented cost savings, particularly at head office, in order to be well positioned for the future.

The second half of the year brought a more stable and increasing oil price and momentum not only across the different facets of our business but across the wider UK onshore industry.  We are generating operating cash flow and production levels are stable at 2,300 boepd. We have a committed carried work programme of up to c.$240 million with our key partner INEOS, to develop our shale assets, and have commenced work on a number of projects within our conventional production assets that we were able to progress following the refinancing.

As we start another year, I find myself questioning how is the UK going to continue to meet the significant national demand for gas?  Gas heats 8 out of 10 homes, produces nearly half of our electricity and is used as a vital feedstock by British industry.  In December 2017, three separate events caused a European gas shortage and subsequent price spike, with Middle Eastern and Russian LNG suppliers assigning tankers to meet demand.

There may be plenty of gas that can be imported from around the world but that comes at a cost, not just a high financial one but imports have a higher carbon footprint and we cannot control employment and environmental policies and regulations in other jurisdictions.  If we develop our own home-grown supply we can maximise both the economic and environmental opportunities that come with it and have more security of supply.

Our businesses have been operating onshore in the UK for more than three decades and we are conscious of the significant responsibility we have not just to our shareholders and colleagues but to the communities in which we operate and the partners with whom we work. Much of our workforce live in and around the communities where we operate and understand what it means to be a responsible neighbour. Our focus on health, safety and the environment continues to be a key priority across the business.

Our Community Fund is now in its tenth year and we are proud of the work we have done to support local communities across our portfolio, investing almost £1 million in numerous projects that are both meaningful and sustainable to local residents.  We will continue making these important donations whilst endeavouring to engender trust within the communities in which we operate.

In June 2017, Francis Gugen who had been Chairman of the Company since it was founded, retired from the Board. I would like to thank Francis for his pivotal role in establishing IGas as one of the leading onshore oil and gas operators and we all wish him well for the future.  John Bryant, Senior Independent Non-executive Director, also retired from the Board in June 2017, having served on the Board for nine years.  I would like to thank John for his significant contribution to the Company.

Following the successful completion of the refinancing in April 2017, two directors from Kerogen Capital, Philip Jackson and Tushar Kumar joined the Board as Non-executive Directors. In addition, John Blaymires and Julian Tedder resigned from the PLC board but remain directors of the operating companies and continue to fulfil their executive roles.

In particular, I am grateful to the IGas leadership team for their energy and dedication in steering the business through a complicated restructuring and successful capital raise.

I want it to be recognised how hard our colleagues have worked during the past year and thank them for their commitment and resilience through challenging times and I would also like to thank our shareholders for their continued support.

Outlook

The last couple of years have been challenging both for IGas and the industry as a whole, but with the appropriate steps having been taken by the Company coupled with a more stable commodity price outlook, IGas is now well set for the next period of its growth.

While we remain focused on maintaining a solid operating performance, we have also allocated some capital to deploy in growth projects across our conventional assets and will be focused on delivering sanctioned projects.  Maintaining the strength of our conventional operating platform is a fundamental part of the Company's equity story, underpinning the significant opportunity our unconventional acreage presents.

Momentum is building across the business and across the industry as we start to drill and flow appraisal wells to assess commercial viability of these shale resources.  There is a significant level of activity onshore UK, and over the next year, the industry is expected to have over half a dozen operators either drilling or flowing wells, including a number from IGas.

We look forward to the future with excitement not only for IGas, but for the wider UK onshore industry, as security of energy supply and diversification of the UK energy mix becomes ever more important.

Chief Executive's Statement

We ended 2017 in a stronger financial position having carried out a successful capital restructuring earlier in the year against a backdrop of continued commodity price volatility.  Now, with capital available to deploy, we are taking further steps to improve operating and production efficiency that will underpin our conventional production through 2018 and beyond. 

The midpoint of the year saw the start of the current oil price run. A convergence of supply constraints and demand strength are factors contributing to continued oil price strength and creating foundations to sustain that relative strength in 2018. 

Over the past few years we have driven operating costs down to approximately US$28/boe. With oil prices now above US$60/bbl, we are reviewing further various initiatives to grow our production from our existing producing sites across the country.

The UK is heavily reliant on gas, being the second largest consumer of gas in the EU after Germany. Latest data available from 2016 shows 40% of UK primary energy was derived from natural gas, representing a 50% increase since 1990.   Currently c.50% of our gas is imported and that is set to rise to nearly 80% in the next 17 years.

We have the opportunity to be a potentially important contributor to changing the future dynamics of the UK's supply of gas, reducing our growing reliance on imports while meeting our national demand for gas, bringing direct local investment and also benefits to our wider environment and economy.

Strengthening the Balance Sheet

In April 2017, shareholders approved the terms of a fundamental capital restructuring of the Group concluding a long process that commenced in early 2016. This complex restructure involved new equity of $57 million being raised, a number of secured and unsecured bonds exchanged for equity, a number bought back and the remaining bond terms amended. This resulted in net debt being reduced from c.$120 million to under $10 million on completion. 

The transaction has significantly improved our financial position and we are generating operating cash for reinvestment back in the business at the current oil price of over $60/bbl. 

We have created a more robust and stable financial platform for the future development of the Group with senior management now focused on delivering operationally as well as strategically.

Operational Performance

Group production averaged 2,335 boepd for the year as our production crews worked hard getting wells back online that had required maintenance.

We continue to identify and evaluate opportunities across our conventional assets.  We see value creation in turning maturing field decline into production growth and whilst the past couple of years has seen little capital investment given the challenging oil price backdrop and focus on cash preservation, we are now spending more time looking at exploration and appraisal opportunities within these existing assets.

We have approved some incremental projects including the Albury and Gainsborough gas projects, pump enhancement and waterflood activity at Welton and plant and maintenance projects. We expect to see the benefits of these projects during the latter part of 2018.

We have also identified, and are looking to accelerate, a number of other projects with attractive returns.  Detailed technical and economic evaluations are progressing to advance these opportunities which will further underpin our conventional portfolio.

IGas is now approaching a period of increased operational activity across its acreage. Having received formal planning approval for three wells in North Nottinghamshire, site construction continues at our Tinker Lane and Springs Road sites.  We anticipate that we will spud the first well mid-2018.

In the North West, in July 2017, we submitted a planning application to test the Pentre Chert formation at our existing site at Ellesmere Port.  The planning officer made a recommendation for approval but the planning committee refused consent.  It is our intention to appeal this decision. At Ince Marshes, we continue to progress our planning application to drill a new well and hydraulically fracture at this existing site. Subject to surveys and monitoring we expect to make the application mid-2018.

Momentum in UK onshore activity

2018 will be a defining year for the onshore oil and gas industry. There is a significant level of activity onshore UK, and over the next 12 months, the industry is expected to have a number of operators either drilling or flowing wells. The industry has made the first payments under its community benefits scheme, prepared to begin drilling horizontally into shale rock for the first time in Lancashire and submitted a final stage application for high volume hydraulic fracturing in North Yorkshire.

Cuadrilla has announced that early results from its vertical wells in Lancashire were very encouraging and they are confident that there is a very sizeable quantity of natural gas in the Bowland Shale.  The coming months should see important data in terms of flow rates that will help the industry better understand the geology in the key basins.

IGas in the Community

It is hugely important to us that the local communities where we operate benefit from our presenceboth economically and socially.

This means not only via investments from our own community fund,  which has distributed almost £1 million to communities in which we operate, but also providing jobs, working closely with the local supply chain and funding apprentices.

As many of our existing production sites will still operate for years to come and as new sites are brought into production we want to make sure that we make a positive difference to the local community.

People

2017 was another challenging year for the business, balancing the restructuring process with maintaining production and pursuing our shale development programme.

We continue to operate in an ever-changing and complicated industry where the challenges are numerous and the pace and pressure to deliver constant. What I appreciate is just how much each of our people cares, how dedicated they are to making this work and the personal sacrifices made to ensure the continued success of the business.

Outlook

The expectation of ongoing free operating cash flow provides us with a solid platform and financial flexibility to execute our growth plans.

Whilst we are optimistic about our plans and the opportunities before us, we are also cautious about the macro environment and will continue to maintain financial discipline across the business whilst bringing projects forward that have attractive returns at current oil prices.

There will be a number of wells drilled this year, some with hydraulic fracturing.  Once we have proven to our local communities that we can conduct this highly regulated and proven process in a safe and accountable way we hope that those undecided and unsure of the process will come to accept it for what it is, and has been for the last five decades: a standard oilfield operation that will help support the UK's energy independence, economy and environment.

 

Operational Review

Production

During 2017 the production division continued to deliver cost and production efficiencies through extending and embedding many of the initiatives that had been introduced in previous years.  Throughout the year we conducted a significant programme of well and facility maintenance which has resulted in the return to production of several shut-in wells. All of this activity resulted in average net production for the year of 2,335 boepd with operating costs of c.$28/bbl.

Our operations are based largely within mature fields with aged assets and as a consequence we believe that realising high production efficiency will be a fundamental component of achieving our operating cost goals going forward. As the fields have a long operating history and we have significant local operating knowledge we have been able to take advantage of both to conduct a systematic review of each of our wells in order to ascertain any performance or reliability issues. This exercise coupled with the live data that we now have from our downhole gauges and Rod Pump Off Controllers (part of our Digital OilField initiative) has meant that we are better able to execute predictive techniques with our wells.  For example, in order to avoid rod breaks or to ensure that following a rod break we have an enhanced repair program "on the shelf" to quickly return the well to production. This approach has delivered a 70% reduction in rod failures since its introduction and has created the capacity to allow our rodding rig to focus more on proactive activities and opportunities.

The deployment of our Digital Oil Field concept also continues as we see this being an enabler for real-time, swifter and better informed decision making, with increased employee engagement and productivity all combining to assist in driving down our future operating costs.

Early in the year a focus on developing near term projects and identifying optimisation opportunities continued, with key activities being progressed to ensure that we were well positioned to take them forward following the Company refinancing and an improved oil price environment.  Post the restructuring, several of our optimisation projects were sanctioned including the mobilisation of a coiled tubing unit for work on three separate wells, two of which have increased their production rates by over 100% and the third brought back online after being shut-in due to loss of productivity. These works combined with an intensive workover campaign that included deployment of wax mitigation technologies, pump optimisations and well conversions have effectively offset the annual decline with our production rates exiting the year almost 5% higher than at the start.

We approved the trial of beam pump gas compressors at two of our fields in order to reduce back pressure on several of our wells. These units are due for installation in mid-2018.  If successful they will improve the individual well productivity and provide additional gas for our power generation schemes as well as opening up the potential for further roll out across several other sites in the portfolio. Other innovations include the installation of a micro turbine package to trial the potential to utilise annulus gas for small scale local power generation whilst also taking back pressure off the well; this is also due for commissioning in mid-2018.

Progress also continues with our water injection initiatives in both the Weald and the East Midlands. We have recently approved a new scheme at our Welton field that, following the conversion of an existing well and the installation of injection facilities, envisages the return to production of two wells that are currently shut-in with the added benefit of de-risking the current production from the field.

Another project, at our Stockbridge field, is also underway where we have developed a package of works across five wells to debottleneck the water management constraints at the field whilst also returning existing wells to production. The program includes the side-track of a previously abandoned water injection well, the stimulation of a well with low productivity, two workovers and the reinstatement of a well shut-in for water management to be returned to production. These activities will not only de-risk the existing production but add up to 30% of incremental production from the field.

The monetisation of our stranded gas assets advanced throughout 2017; most notably at our Albury site. For several years the gas transmission business has been increasingly deregulated as it has had to adapt to enable the injection of small quantities of biomethane into the network. Typically this takes the form of CNG or low pressure gas; however, this has also created the opportunity for direct gas to grid solutions to be accepted for entry and following discussions with the local gas distribution network operator we have unlocked this as an alternative development solution to the originally planned CNG option. This new choice adds significant value to this development and has clear synergies for other stranded gas applications within our portfolio. 

Capital expenditure across these projects amounted to c.£4.0 million during the year. Going forward, we expect c.£5.0 million of incremental capital expenditure per annum will result in production of levels of c.2,500 boepd in the medium term. 

IGas net reserves and resources (MMboe)

We have had over 100% reserves replacement with 2P reserves standing at 13.64 MMboe as at 31 December 2017.

The Group's estimates of proved and proved plus probable reserves are taken from year-end internal estimates as of 31 December 2017. Proved 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. The probable reserves are estimated additional reserves determined to be more likely than not to be recoverable with some planned future capital investments.

As these are mature fields, their historical performances have reliable declines in producing-rate trends and the proved reserves have been estimated by the application of appropriate decline curves only to the limits of economic production. Probable undeveloped reserves were estimated for some incremental projects by using analogy type-well data of nearby wells completed in the same reservoirs. These incremental projects are based mainly on reinstatement of some offline wells to access shut-in and/or behind-pipe reserves by workovers, recompletions and sidetracks. 

There has been 2P reserves replacement of over 100% based on a cumulative production of 0.89 MMboe in the year. The reserves growth is due largely to a combination of planned future investments in non-producing and undeveloped reserves, and better reservoir management. The developed producing 2P reserves represent about 90% of the total 2P reserves.

Net Reserves and Resources (MMboe)

	1P	2P	2C
As at 31 Dec 20161	9.02	13.37	21.84
As at 31 Dec 20172	8.11	13.64	22.21

 

Notes

1.  D&M estimates as ta 30 June 2016 adjusted for six months production to 31 December 2016.

2.  IGas estimates, cumulative production in 2017 of 0.89 MMboe.

 

Development/Appraisal Assets

During 2017, good progress was made with developing our East Midlands and North West shale acreage. 

East Midlands

In the East Midlands we signed Section 106 legal agreements in May 2017 for the exploratory well sites at both Springs Road and Tinker Lane with Nottinghamshire County Council ("NCC"), in effect the legal agreement for the planning consent.  Construction commenced at both sites in late 2017 and is largely complete at Springs Road, with good progress being made at Tinker Lane. 

The wells will be drilled during 2018 and will form the foundation of a wider development in the East Midlands with the mid-term focus moving to a pilot development in the Gainsborough Trough, leveraging on our existing, long standing operations in the East Midlands. 

North West

In the North West, we submitted a planning application at our existing site at Ellesmere Port in July 2017. Evaluation of wire-line logs acquired across the various formations encountered during the drilling of the well in 2014 indicated hydrocarbons being present in the Pentre Chert Formation. 

The Pentre Chert Formation is a naturally fractured reservoir rock composed of interbedded layers of cherts and cherty mudstones, with subordinate thin layers of siltstones, limestones and sandstones.

The proposed project includes carrying out further tests on the Pentre Chert, including a Drill Stem Test ("DST"), to provide an initial analysis of the hydrocarbon composition and its flow characteristics within the formation. The initial information obtained during the DST will be used to determine whether commercially viable quantities of hydrocarbons exist and if successful we will then carry out an Extended Well Test to better understand the production performance and associated volumes. 

Environmental permits were issued by the Environment Agency in November 2017 and on 17 January 2018, the Planning Officer at Cheshire West and Chester Council made a recommendation for the approval of our application. At the planning committee meeting on 25 January 2018, the committee voted to refuse the application. It is our intention to appeal this decision.

Separately, a scoping report was submitted to Cheshire West and Chester Council in October 2017 which sought the Councils' views on a future application to drill a new well at our existing Ince Marshes well site. The proposed development would be for one new well, initially to be drilled vertically and then horizontally.  We also intend to hydraulically fracture and flow test the target formation, to assess the flow potential of the well.  A planning application will be made in the first half of 2018.

Further planning applications to drill, hydraulically fracture and flow test new wells will be made in 2018, with a view to utilising the 3D seismic data acquired in 2015 and accelerating development in this basin.

Financial Review

During the first half of the year the Company concluded a successful capital restructuring, significantly reducing debt and giving the company an improved capital structure which is sustainable in the current oil price environment.  The restructuring proposal was formally approved by all stakeholders in April 2017 and resulted in the issue of new equity for $57 million, secured bonds of $40 million 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 60 cents in the dollar and the remaining $30 million of secured bonds having their terms amended. On completion, net debt was reduced from c.$120 million (£100 million) to under $10 million (£7 million).

 

Results for the year

 

Oil prices remained volatile during the year driven by concerns over high inventories and over supply. In the second half, OPEC extended its production cuts and rig counts in the US remained at relatively low levels, against the backdrop of increasing global growth, providing support for oil prices. The price of Brent crude averaged $54.2/bbl (2016: $44/bbl) for the year, which had a positive impact on our revenues. Sterling strengthened against the US dollar and the exchange rate increased from £1:$1.26 at the beginning of the year to £1:$1.35 in December 2017, having a negative impact on our US dollar revenue but a positive impact on US dollar denominated debt.

For the year ended 31 December 2017 adjusted EBITDA¹ was £9.2 million (2016: £10.2 million) whilst a profit was recognised from continuing activities after tax of £15.9 million (2016: loss £31.8 million). The main factors driving the movements between the years were as follows:

·     Revenues increased to £35.8 million (2016: £30.5 million) principally due to higher oil prices. This was moderated slightly by a stronger average sterling to US dollar exchange rate and slightly lower oil volumes for the year;

·     Other costs of sales increased to £21.4 million (2016: £20.9 million) mainly due to additional workovers and higher inspection and re-permitting costs;

·     Administrative expenses decreased by £5.0 million to £6.4 million (2016: £11.4 million). Legal and professional costs were £2.6 million lower in 2017 as 2016 included costs relating to the proposed refinancing whereas similar costs in 2017 were offset against the gain on restructuring once completed. Share-based payment charges were £1.5 million lower in 2017 as prior year schemes became fully vested by the end of 2016. A cost reduction exercise also contributed to the reduction in administrative expenses;

·     Redundancy costs were £0.2 million (2016: £0.6 million) as the redundancy programme was completed primarily in 2016;

·     The £0.1 million exploration write-off related to costs on relinquished licences (2016: £4.5 million);

·     Other income decreased to £0.2 million (2016: £0.7 million); and

·     A tax credit of £19.1 million was recognised mainly due to the recognition of a deferred tax asset relating to ring-fence tax losses (2016: a tax credit of £13.0 million 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).

Income statement

The Group recognised revenues of £35.8 million in the year (2016: £30.5 million). Group production in the year averaged 2,335 boepd (2016: 2,355 boepd). Revenues for the year included £3.0 million (31 December 2016: £3.3 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 $51.0/bbl (2016: $44.1/bbl) and post hedge $51.3/bbl (2016: $58.1/bbl). £0.2 million was realised on hedges during the year with average Brent oil prices generally trading within the monthly hedged collars (2016: realised gains of £8.5 million).  The average GBP/USD exchange rate for the year was £1: $1.29 (2016: £1: $1.37) which negatively impacted revenue for the year.

Cost of sales for the year were £29.3 million (2016: £27.2 million) including depreciation, depletion and amortisation (DD&A) of £7.8 million (2016: £6.3 million), and operating costs of £21.4 million (2016: £20.9 million).  Operating costs include a cost of £2.8 million (2016: £2.7 million) relating to third party oil.  The contribution received from processing this third party oil was £0.2 million (2016: £0.6 million). 

Operating costs per barrel of oil equivalent (boe) were £21.9 ($28.2), excluding third party costs (2016: £21.1 ($28.8) per boe). Operating costs per boe were higher in 2017 due to additional workovers and higher inspection and re-permitting costs.

Adjusted EBITDA in the year was £9.2 million (2016: £10.2 million).  Gross profit for the year was £6.5 million (2016: £3.3 million).  Administrative costs decreased by £5.0 million to £6.4 million (2016: £11.4 million) principally due to lower legal and professional costs, lower share-based payment charges due to options relating to prior year schemes becoming fully vested and a general cost reduction exercise.

Exploration costs written off of £0.1 million related to costs on relinquished licences (2016: £4.5 million relating to relinquishment of licences during the year).

Other income was £0.2 million (2016: £0.7 million which included a £0.4 million adjustment on the contingent deferred consideration in relation to an amount payable to a joint venture partner).

Net finance costs were £6.2 million (2016: £28.8 million), which primarily related to interest on borrowings of £5.4 million (2016: £11.9 million) and, a net foreign exchange gain of £0.2 million, principally on US$ denominated debt and bank balances (2016: loss £14.8 million). 2016 also included a £1.5 million loss on the sale of bonds. The Group realised a net gain on restructuring of £4.9 million (2016: nil).

The Group made a loss on oil price derivatives of £2.1 million for the year due to the increase in underlying prices (2016: loss £3.5 million).

Cash flow

Net cash generated from operating activities for the year was £6.7 million (2016: £12.4 million). The decrease was primarily due to higher revenue and a decrease in administrative expenses offset by lower realised hedges and the timing of payments. The Group invested £6.3 million across its asset base during the year (2016: £8.8 million), of which £3.7 million was invested in the conventional assets, where investments continue to maintain our production at current levels, and £2.6 million in unconventional assets in relation to our shale development programme.

IGas carried out a capital restructuring during the year 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 also repaid £3.6 million ($4.6 million) of principal on borrowings to bondholders during the year in accordance with the terms of the bonds and purchased bonds with a face value of £1.8 million ($2.2million) (2016: repaid £4.9 million ($7.1 million), and sold bonds with a face value of $8.0 million for $6.0 million). Future annual interest costs have decreased to approximately $2.3 million following the capital restructuring.

IGas paid £5.9 million ($7.3 million) in interest (2016: £11.6 million ($15.5 million)).

Cash and cash equivalents were £15.7 million at the end of the year (2016: £24.9 million).

Balance sheet

Net assets were £181.6 million at 31 December 2017 (2016: £70.5 million) with the increase of £111.1 million arising primarily from the results of the capital restructuring and an income tax credit.

Borrowings decreased from £124.6 million to £21.2 million following the successful capital restructuring during the year.

At 31 December 2017, the Group's derivative instruments had a net negative fair value of £2.8million due to an increase in the underlying Brent forward curve (2016: net negative fair value of £0.9 million).

Net debt at the year end, being the nominal value of borrowings less cash and cash equivalents, was £6.2 million (2016: £99.7 million).

	31 December 2017	31 December 2016
	£m	£m
Debt (nominal value excluding capitalised expenses)	(21.9)	(124.6)
Cash and cash equivalents	15.7	25.0
Net Debt	(6.2)	(99.7)

 

Shareholders' equity increased by £111.1 million to £181.6 million primarily as a result of the gain after tax and the capital restructuring.

 

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 2017	Year to 31 December 2016
	£ million	£ million
Loss before tax	(3.3)	(44.8)
Net finance costs	6.2	28.8
Depletion, depreciation & amortisation	7.9	6.5
Share based payment charges	1.1	2.6
Redundancy costs	0.2	0.6
Impairments/write offs	0.1	4.5
Gain on capital restructuring	(4.9)	-
Unrealised loss on hedges	1.9	12.0
Adjusted EBITDA	9.2	10.2

 

Underlying Operating Profit

	Year to 31 December 2017	Year to 31 December 2016
	£ million	£ million
Operating loss	(2.0)	(16.0)
Share based payment charges	1.1	2.6
Restructuring costs	0.2	0.6
Impairments/write offs	0.1	4.5
Unrealised loss on hedges	1.9	12.0
Underlying operating profit	1.3	3.7

 

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 was improved significantly by the capital restructuring which was completed in April 2017. The Group continues to closely monitor and manage its liquidity risks. 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 (based on current forward curves, adjusted for the Group's hedging programme) and the Group's borrowings. Sensitivities are run to reflect different scenarios including, but not limited to, possible further reductions in commodity prices below the current forward curve, reductions in forecast oil and gas production rates and changes in the US$ to GB£ exchange rates.

 

The Group's 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. The Directors, therefore, have a reasonable expectation that the Group has adequate resources to continue in existence for the foreseeable future and they continue to adopt the going concern basis of accounting 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 Chief Executive Officer 20 March 2018

Julian Tedder Chief Financial Officer 20 March 2018

 

Consolidated Income Statement

For the year ended 31 December 2017

 

 

	Notes	Year ended 31 December 2017 £000	Year ended 31 December 2016 £000
Revenue	2	35,793	30,471
Cost of sales:
Depletion, depreciation and amortisation		(7,832)	(6,323)
Other costs of sales		(21,435)	(20,857)
		(29,267)	(27,180)
Gross profit		6,526	3,291
Administrative expenses		(6,441)	(11,406)
Redundancy costs		(212)	(557)
Exploration and evaluation assets written off	8	(70)	(4,485)
Loss on oil price derivatives		(2,050)	(3,496)
Other income	3	214	660
Operating loss		(2,033)	(15,993)
Finance income	4	277	277
Finance costs	4	(6,428)	(29,057)
Gain on restructuring		4,935	-
Loss from continuing activities before tax		(3,249)	(44,773)
Income tax credit	5	19,105	13,006
Profit/(loss) after tax from continuing operations attributable to equity shareholders of the Group		15,856	(31,767)
Loss after tax from discontinued operations		(375)	(1,144)
Net profit/(loss) attributable to equity shareholders of the Group		15,481	(32,911)
Profit/(loss) attributable to equity shareholders:
Basic loss per share (pence/share)	6	12.76p	(219.74p)
Diluted loss per share (pence/share)	6	12.46p	(219.74p)

                                      

Consolidated Statement of Comprehensive Income

For the year ended 31 December 2017

	Year ended 31 December 2017 £000	Year ended 31 December 2016 £000
Profit/(loss) for the year	15,481	(32,911)
Other comprehensive income/(loss) for the year
Currency translation adjustments recycled to the income statement	-	105
Currency translation adjustments	931	(1,231)
Total comprehensive income/(loss) for the year	16,412	(34,037)

 

Consolidated Balance Sheet

As at 31 December 2017

	Notes	31 December  2017 £000	31 December  2016 £000
ASSETS
Non-current assets
Goodwill	7	4,801	4,801
Intangible exploration and evaluation assets	8	115,130	112,448
Property, plant and equipment	9	93,158	97,709
Restricted cash		303	-
Deferred tax asset		16,900	-
		230,292	214,958
Current assets
Inventories		1,322	1,270
Trade and other receivables		7,459	7,015
Cash and cash equivalents		15,727	24,946
Restricted cash		126	-
		24,634	33,231
Total assets		254,926	248,189
LIABILITIES
Current liabilities
Trade and other payables		(6,558)	(8,170)
Current tax liabilities		(358)	(1,318)
Borrowings	11	(1,687)	(6,084)
Other liabilities		-	(11)
Derivative financial instruments		(2,749)	(876)
		(11,352)	(16,459)
Non-current liabilities
Borrowings	11	(19,553)	(118,495)
Other creditors		(303)	-
Deferred tax provision		-	(1,779)
Other provisions	12	(42,117)	(40,924)
		(61,973)	(161,198)
Total liabilities		(73,325)	(177,657)
Net assets		181,601	70,532
EQUITY
Capital and reserves
Called up share capital		30,333	30,282
Share premium account		102,342	32
Foreign currency translation reserve		(7,059)	(7,990)
Other reserves		29,994	28,757
Accumulated surplus		25,991	19,451
Total equity		181,601	70,532

 

 

Consolidated Statement of Changes in Equity

For the year ended 31 December 2017

	Called up share capital        £000	Share premium account    £000	Capital redemption  reserve     £000	Foreign currency translation  reserve*  £000	Other reserves**    £000	Accumulated (deficit)/surplus  £000	Total equity  £000
At 1 January 2016	29,882	121,623	64,882	(6,864)	23,544	(134,296)	98,771
Loss for the year	-	-	-	-	-	(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
Profit for the year	-	-	-	-	-	15,481	15,481
Employee share plans	-	-	-	-	1,333	-	1,333
Forfeiture of LTIPs under the employee share plan	-	-	-	-	(85)	56	(29)
Lapse of LTIPs under the employee share plan	-	-	-	-	(11)	11	-
Issue of shares and conversion of debt	51	93,302	-	-	-	-	93,353
Reserves transfer on equitisation of unsecured bonds ***	-	9,008	-	-	-	(9,008)	-
Currency translation adjustments	-	-	-	931	-	-	931
At 31 December 2017	30,333	102,342	-	(7,059)	29,994	25,991	181,601

*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 equitised 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 2017

	Notes	Year ended  31 December 2017 £000	Year ended 31 December 2016 £000
Cash flows from operating activities:
Loss before tax		(3,249)	(44,773)
Write off deferred consideration		-	(420)
Net gain on capital restructuring		(4,935)	-
Depletion, depreciation and amortisation	9	7,968	6,474
Decommissioning costs incurred		-	(418)
Other provisions utilised		(39)	-
Share based payment charge		1,056	3,499
Exploration and evaluation assets written off	8	70	4,485
Unrealised loss on oil price derivatives		1,872	11,969
Finance income	4	(277)	(277)
Finance costs	4	6,428	29,057
Other non-cash adjustments		24	(13)
Operating cash flow before working capital movements		8,918	9,583
Decrease in trade and other receivables and other financial assets		40	3,366
(Decrease)/increase in trade and other payables, net of accruals related to investing activities		(2,084)	698
Increase in inventories		(52)	(176)
Cash generated from continuing operating activities		6,822	13,471
Cash generated from/(used in) discontinued operating activities		422	(489)
Taxation paid - continuing operating activities		(571)	(559)
Net cash generated from operating activities		6,673	12,423
Cash flows from investing activities:
Purchase of intangible exploration and evaluation assets		(2,591)	(2,304)
Purchase of property, plant and equipment		(3,679)	(6,509)
Disposal of subsidiary		-	(171)
Disposal of oil and gas assets		14	22
Interest received		27	34
Cash used in continuing investing activities		(6,229)	(8,928)
Cash used in discontinued investing activities		-	(177)
Net cash used in investing activities		(6,229)	(9,105)
Cash flows from financing activities:
Cash proceeds from issue of ordinary share capital		77	136
Cash proceeds from the issue of shares in capital restructuring		46,789	-
Cash paid in settlement of secured bonds		(39,337)	-
Fees paid relating to capital restructure		(4,311)	-
Repayment and repurchase of borrowings	10	(5,423)	(4,916)
Sale of bonds		-	4,914
Interest paid	10	(5,917)	(11,570)
Net cash used in financing activities		(8,122)	(11,436)
Net decrease in cash and cash equivalents in the year		(7,678)	(8,118)
Net foreign exchange difference		(1,541)	4,450
Cash and cash equivalents at the beginning of the year		24,946	28,614
Cash and cash equivalents at the end of the year	10	15,727	24,946

 

Consolidated Financial Statements - Notes

For the year ended 31 December 2017

 

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 April 2018.

 

The financial information for the year ended 31 December 2017 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 2016 have been delivered to the Registrar of Companies and those for 2017 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 2016. 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 2017, however these have not had a material impact on the accounting policies, methods of computation or presentation applied by the Group. 

 

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. 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

 

All revenue, which represents turnover, arises solely within the United Kingdom and relates to external parties.

 

	Year ended 31 December 2017 £000	Year ended 31 December 2016 £000
Oil sales	35,289	30,009
Electricity sales	504	462
	35,793	30,471

 

Revenues of approximately £19.3 million and £15.9 million were derived from the Group's two largest customers (2016: £17.6 million and £12.4 million).

 

3 Other income

Other income includes £0.2 million relating to rental income (2016: £0.2 million relating to rental income and £0.4 million relating to the release of contingent deferred consideration).

 

4 Finance income and costs 

	Year ended 31 December 2017 £000	Year  ended 31 December 2016 £000
Finance income:
Interest on short-term deposits	26	63
Foreign exchange gains	239	-
Other interest	1	78
Gain on fair value of warrants	11	136
Finance income	277	277
Finance expense:
Loss on sale of bonds	-	1,540
Interest on borrowings	5,358	11,930
Foreign exchange loss	-	14,841
Unwinding of discount on provisions	1,070	746
Finance expense	6,428	29,057

 

5 Income tax credit

 

i) Tax credit on loss from continuing ordinary activities

	Year ended 31 December 2017 £000	Year ended 31 December 2016 £000
Current tax:
Charge on loss for the year	-	-
Credit in relation to prior years	(426)	(149)
Total current tax credit	(426)	(149)
Deferred tax:
Credit relating to the origination or reversal of temporary differences	(21,180)	(6,009)
Credit relating to the movement due to the tax rate changes	-	(6,270)
Charge/(credit) in relation to prior years	2,501	(578)
Total deferred tax credit	(18,679)	(12,857)
Tax credit on loss on ordinary activities	(19,105)	(13,006)

 

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:

 

	Year ended 31 December 2017 £000	Year ended 31 December 2016 £000
Loss from continuing ordinary activities before tax	(3,249)	(44,773)
Expected tax credit based on profit or loss from continuing ordinary activities multiplied by an average combined rate of corporation tax and supplementary charge in the UK of 40% (2016: 40%)	(1,300)	(17,909)
Deferred tax charge/(credit) in respect of the prior year	2,501	(578)
Current tax credit related to prior year	(426)	(149)
Tax effect of expenses not allowable for tax purposes / (income not taxable)	616	2,926
Tax effect of differences in amounts not allowable for supplementary charge purposes*	1,467	945
Impact of profits or losses taxed or relieved at different rates	(1,699)	3,093
Loss carried back	-	975
Net (decrease)/increase in unrecognised losses carried forward	(20,347)	3,961
Tax rate change	-	(6,270)
Other	83	-
Tax credit on loss on ordinary activities	(19,105)	(13,006)

 

* 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:

	Year ended 31 December 2017 £000	Year ended 31 December 2016 £000
Liability at 1 January	(1,779)	(14,636)
Tax (charge)/credit relating to prior year	(2,501)	578
Tax credit during the year	21,180	6,009
Tax credit arising due to the changes in tax rates	-	6,270
Asset/(liability) at 31 December	16,900	(1,779)

 

 

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

	31 December 2017 £000	31 December 2016 £000
Accelerated capital allowances	(33,897)	(34,206)
Tax losses carried forward	41,553	22,522
Investment allowance unutilised	485	313
Decommissioning provision	4,628	6,348
Unrealised gains or losses on derivative contracts	2,843	2,126
Share based payments	1,288	1,118
Deferred tax asset/(liability)	16,900	(1,779)

 

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 £107.5 million (2016: £67.4 million) of ring-fence corporation tax losses.

 

The Group has further tax losses and other similar attributes carried forward of approximately £195 million (2016: £210 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.

 

6 Earnings per share (EPS)

 

Basic EPS amounts are based on the profit for the year after taxation attributable to ordinary equity holders of the parent of £15.5 million (2016: £32.9 million) and the weighted average number of ordinary shares outstanding during the year of 121.3 million (2016: 299.5 million).

 

Diluted EPS amounts are based on the profit 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.

 

For the year ended 31 December 2016, there were 1.6 million (restated based on the subdivision) potentially dilutive employee share options, LTIPs and warrants, 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.

 

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

	Year ended 31 December 2017	Year ended 31 December 2016
Basic EPS - ordinary shares of 0.002 pence each	12.76p	(219.74)p
Diluted EPS - ordinary shares of 0.002 pence each	12.46p	(219.74)p
Profit/(loss) for the year attributable to equity holders of the parent - £000	15,481	(32,911)
Weighted average number of ordinary shares in the year- basic EPS	121,357,572	14,977,131
Weighted average number of ordinary shares in the year- diluted EPS	124,298,195	14,977,131

 

7 Goodwill

	31 December 2017 £000	31 December 2016 £000
At 1 January and 31 December	4,801	4,801

 

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 2017 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 (2016: £nil).

 

8 Intangible exploration and evaluation assets

	31 December  2017 £'000	31 December 2016  £'000
At 1 January	112,448	113,394
Additions	2,752	3,616
Changes in decommissioning	-	(77)
Amounts written off*	(70)	(4,485)
At 31 December	115,130	112,448

* Write off of unconventional exploration and evaluation assets due to relinquishment of licences considered to be uncommercial.

 

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 2017 and at 31 December 2016. No indicators of impairment were identified at either year-end.

 

9 Property, plant and equipment

		31 December 2017					31 December 2016
		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		168,329	3,767	172,096			147,434	3,731	151,165
Additions		3,380	58	3,438			5,622	342	5,964
Disposals		(14)	(23)	(37)			(77)	(306)	(383)
Changes in decommissioning**		-	-	-			15,350	-	15,350
Transfers		193	(193)	-			-	-	-
Write off		-	(6)	(6)			-	-	-
At 31 December		171,888	3,603	175,491			168,329	3,767	172,096
Depreciation and Impairment
At 1 January		72,894	1,494	74,388			66,815	1,439	68,254
Charge for the year*		7,669	299	7,968			6,156	338	6,494*
Disposals		-	(23)	(23)			(77)	(284)	(361)
Transfers		193	(193)	-			-	-	-
At 31 December		80,756	1,577	82,333			72,894	1,493	74,387
NBV at 31 December		91,132	2,026	93,158			95,435	2,274	97,709

*   Charge for the year includes £125 thousand charge categorised as administration expenses in the profit and loss (2016: £151 thousand) and £11 thousand (2016: £20 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.

                                                                     

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 2017. 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 $67/bbl for 2018, $64/bbl for 2019, $61/bbl for 2020, $60/bbl for 2021 and $75/bbl thereafter, and a USD/GBP foreign exchange rate of $1.43/£1.00.  Cash flows were discounted using a pre-tax discount rate of 11%. No impairment was required in the year (2016: £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.  Neither a 10% reduction in production a 10% reduction in Brent prices nor a 10% decline in the value of sterling against the US dollar would result in an impairment in the South or Scotland CGUs. For the North CGU, a 10% reduction in either production or price would result in an impairment of £11.7 million and a 10% reduction in the USD/GBP exchange rate would result in an impairment of £4.0 million.

 

10 Cash and cash equivalents and other financial assets

	31 December 2017 £000	31 December 2016 £000
Cash at bank and in hand	15,727	24,946

The carrying value of the Group's cash and cash equivalents as stated above is considered to be a reasonable approximation of their fair value.  Cash and cash equivalents included £9.1 million at 31 December 2016 which was held in the Debt Service Retention Account ("DSRA"). This was designated, at the Company's discretion, for the buy-back or repayment of bonds.  In April 2017, the Company restructured its debt which resulted in the removal of the requirement for a DSRA.

 

Restricted cash

	31 December 2017 £000	31 December 2016 £000
Current	126	-
Non-current	303	-

The non-current restricted cash represents 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 relates to margin payments in respect of oil hedge contracts.

 

Net debt reconciliation

 

	31 December 2017 £000
Cash and cash equivalents	15,727
Borrowings	(21,240)
Net debt	(5,513)
Borrowings - capitalised fees	(686)
Net debt excluding capitalised fees	(6,199)

 

	Cash and cash equivalents £000	Borrowings £000	Total £000
At 1 January 2017	24,946	(124,579)	(99,633)
Capital restructuring	3,140	90,025	93,165
Repayment and repurchase of borrowings	(5,423)	5,423	-
Interest paid	(5,917)	5,917	-
Foreign exchange adjustments	(1,541)	2,369	828
Other cash flows	522	-	522
Other non-cash movements	-	(395)	(395)
At 31 December 2017	15,727	(21,240)	(5,513)

 

11 Borrowings

	31 December 2017			31 December 2016
	Current £000	Non-current £000	Total £000	Current £000	Non-current £000	Total £000
Bonds - secured	1,687	19,553	21,240	6,084	96,700	102,784
Bonds - unsecured	-	-	-	-	21,795	21,795
Total	1,687	19,553	21,240	6,084	118,495	124,579

 

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 13.

 

12 Other provisions

	31 December 2017			31 December 2016
	Decommissioning £000	Other £000	Total £000	Decommissioning £000	Other £000	Total £000
At 1 January	40,885	39	40,924	25,284	39	25,323
Utilisation of provision	-	(39)	(39)	(418)	-	(418)
Unwinding of discount	1,070	-	1,070	746	-	746
Reassessment of decommissioning provision/liabilities	162	-	162	15,273	-	15,273
At 31 December	42,117	-	42,117	40,885	39	40,924

 

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 31 years from the year end (2016: 2 to 29 years). These provisions are based on the Groups' internal estimate as at 31 December 2017. 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 0.98% to 3.05% is used in the calculation of the provision as at 31 December 2017 (2016: Risk free rate range of 0.58% to 3.80%).

 

13 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 has been recognised for the year.

 

14 Subsequent events

 

On 24 January 2018 the Group issued 69,195 Ordinary £0.00002 shares in relation to the Company's SIP scheme. The shares were issued at £0.69 resulting in share premium of £47,570.

 

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

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