Igas Energy PLC Full year Results (3632I)

Share Name	Share Symbol	Market	Type	Share ISIN	Share Description
Igas Energy Plc	LSE:IGAS	London	Ordinary Share	GB00BZ042C28	ORD 0.002P

	Price Change	% Change	Share Price	Bid Price	Offer Price	High Price	Low Price	Open Price	Shares Traded	Last Trade
	0.00	0.00%	14.89	14.80	14.98				0.00	01:00:00

Industry Sector	Turnover	Profit	EPS - Basic	PE Ratio	Market Cap
	0	0		N/A	0

Igas Energy (LSE:IGAS)
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TIDMIGAS

RNS Number : 3632I

Igas Energy PLC

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     Year 
                                      ended    ended 
                                      31 Dec   31 Dec 
                                       2017     2016 
                                       GBPm     GBPm 
-----------------------------------  -------  ------- 
Revenues                              35.8     30.5 
-----------------------------------  -------  ------- 
Adjusted EBITDA(1)                     9.2     10.2 
-----------------------------------  -------  ------- 
Profit/(loss) after tax               15.5    (32.9) 
-----------------------------------  -------  ------- 
Net cash from operating activities     6.7     12.4 
-----------------------------------  -------  ------- 
Net debt(2)                            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 GBP1:$1.40)

-- 2P conventional reserves replacement of over 100% (31 Dec 2017: Net 2P reserves 13.64 MMboe(3) ).

-- 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 GBP15.7 million and net debt of GBP6.2 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 GBP1 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 GBP1 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.GBP4.0 million during the year. Going forward, we expect c.GBP5.0 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 
    2016(1)      9.02   13.37   21.84 
--------------  -----  ------  ------ 
 As at 31 Dec 
    2017(2)      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 (GBP100 million) to under $10 million (GBP7 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 GBP1:$1.26 at the beginning of the year to GBP1:$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 EBITDA(1) was GBP9.2 million (2016: GBP10.2 million) whilst a profit was recognised from continuing activities after tax of GBP15.9 million (2016: loss GBP31.8 million). The main factors driving the movements between the years were as follows:

-- Revenues increased to GBP35.8 million (2016: GBP30.5 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 GBP21.4 million (2016: GBP20.9 million) mainly due to additional workovers and higher inspection and re-permitting costs;

-- Administrative expenses decreased by GBP5.0 million to GBP6.4 million (2016: GBP11.4 million). Legal and professional costs were GBP2.6 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 GBP1.5 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 GBP0.2 million (2016: GBP0.6 million) as the redundancy programme was completed primarily in 2016;

-- The GBP0.1 million exploration write-off related to costs on relinquished licences (2016: GBP4.5 million);

   --     Other income decreased to GBP0.2 million (2016: GBP0.7 million); and

-- A tax credit of GBP19.1 million was recognised mainly due to the recognition of a deferred tax asset relating to ring-fence tax losses (2016: a tax credit of GBP13.0 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 GBP35.8 million in the year (2016: GBP30.5 million). Group production in the year averaged 2,335 boepd (2016: 2,355 boepd). Revenues for the year included GBP3.0 million (31 December 2016: GBP3.3 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). GBP0.2 million was realised on hedges during the year with average Brent oil prices generally trading within the monthly hedged collars (2016: realised gains of GBP8.5 million). The average GBP/USD exchange rate for the year was GBP1: $1.29 (2016: GBP1: $1.37) which negatively impacted revenue for the year.

Cost of sales for the year were GBP29.3 million (2016: GBP27.2 million) including depreciation, depletion and amortisation (DD&A) of GBP7.8 million (2016: GBP6.3 million), and operating costs of GBP21.4 million (2016: GBP20.9 million). Operating costs include a cost of GBP2.8 million (2016: GBP2.7 million) relating to third party oil. The contribution received from processing this third party oil was GBP0.2 million (2016: GBP0.6 million).

Operating costs per barrel of oil equivalent (boe) were GBP21.9 ($28.2), excluding third party costs (2016: GBP21.1 ($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 GBP9.2 million (2016: GBP10.2 million). Gross profit for the year was GBP6.5 million (2016: GBP3.3 million). Administrative costs decreased by GBP5.0 million to GBP6.4 million (2016: GBP11.4 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 GBP0.1 million related to costs on relinquished licences (2016: GBP4.5 million relating to relinquishment of licences during the year).

Other income was GBP0.2 million (2016: GBP0.7 million which included a GBP0.4 million adjustment on the contingent deferred consideration in relation to an amount payable to a joint venture partner).

Net finance costs were GBP6.2 million (2016: GBP28.8 million), which primarily related to interest on borrowings of GBP5.4 million (2016: GBP11.9 million) and, a net foreign exchange gain of GBP0.2 million, principally on US$ denominated debt and bank balances (2016: loss GBP14.8 million). 2016 also included a GBP1.5 million loss on the sale of bonds. The Group realised a net gain on restructuring of GBP4.9 million (2016: nil).

The Group made a loss on oil price derivatives of GBP2.1 million for the year due to the increase in underlying prices (2016: loss GBP3.5 million).

Cash flow

Net cash generated from operating activities for the year was GBP6.7 million (2016: GBP12.4 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 GBP6.3 million across its asset base during the year (2016: GBP8.8 million), of which GBP3.7 million was invested in the conventional assets, where investments continue to maintain our production at current levels, and GBP2.6 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 GBP46.8 million from the issue of shares and cash outflows of GBP39.3 million and GBP4.3 million, respectively, from the repayment of secured bonds and payment of fees. IGas also repaid GBP3.6 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 GBP1.8 million ($2.2million) (2016: repaid GBP4.9 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 GBP5.9 million ($7.3 million) in interest (2016: GBP11.6 million ($15.5 million)).

Cash and cash equivalents were GBP15.7 million at the end of the year (2016: GBP24.9 million).

Balance sheet

Net assets were GBP181.6 million at 31 December 2017 (2016: GBP70.5 million) with the increase of GBP111.1 million arising primarily from the results of the capital restructuring and an income tax credit.

Borrowings decreased from GBP124.6 million to GBP21.2 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 GBP2.8million due to an increase in the underlying Brent forward curve (2016: net negative fair value of GBP0.9 million).

Net debt at the year end, being the nominal value of borrowings less cash and cash equivalents, was GBP6.2 million (2016: GBP99.7 million).

 
                           31 December   31 December 
                                  2017          2016 
------------------------  ------------  ------------ 
                                  GBPm          GBPm 
------------------------  ------------  ------------ 
 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 GBP111.1 million to GBP181.6 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        Year to 
                                            December    31 December 
                                                2017           2016 
                                                 GBP 
                                             million    GBP 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        Year to 
                                 December    31 December 
                                     2017           2016 
                                      GBP 
                                  million    GBP 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 GBGBP 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     Julian Tedder 
  Chief Executive    Chief Financial Officer 
  Officer            20 March 2018 
  20 March 2018

Consolidated Income Statement