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Igas Energy PLC (IGAS)

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Wednesday 16 March, 2016

Igas Energy PLC

Preliminary Results

RNS Number : 2169S
Igas Energy PLC
16 March 2016
 

16 March 2016

IGas Energy plc (AIM: IGAS)

Preliminary results for the nine months ended 31 December 2015

IGas Energy plc ("IGas" or "the Company" or "the Group"), one of the leading producers of hydrocarbons onshore in Britain, announces its preliminary results for the nine months to 31 December 2015.

Results Summary

 

Nine months to 31 Dec 2015

£m

Year ended

31 March

2015

£m

Revenues

25.1

58.2

EBITDA1,2

18.3

21.6

Exploration and evaluation assets written off (net of tax)

(10.0)

(6.4)

Impairments of P,P&E assets and goodwill (net of tax)

(48.1)

(1.6)

(Loss)/profit after tax

(44.8)

5.2

Net cash  from operating activities

1.0

26.5

Net debt3

73.3

86.4

Cash and cash equivalents

28.6

19.0

Net assets

98.8

146.6

Notes

1.        EBITDA relates to earnings before finance costs (£7.8m)(2014/15: £12.5m), tax credit (£17.3m)(2014/15: £23.8m), depletion, depreciation and amortisation (£7.2m)(2014/15: £13.0m), impairment of oil and gas assets (£17.7m)(2014/15: £3.9m) and exploration and evaluation assets written off (£12.9m)(2014/15: £15.4m)

2.        EBITDA is considered by the Company to be a useful additional measure to help understand underlying performance

3.        Net debt is borrowings less cash and restricted cash

Highlights

·     Delivering against five year plan

Acquisition of 110km² of 3D seismic in North West completed in early November 2015. Processing and interpretation underway, due for completion in Q3 2016

Nottinghamshire County Council ("NCC") granted planning permission for Groundwater Monitoring Boreholes at the Springs Road site in January 2016; monitoring now installed 

Following the normal planning consultation period, NCC has requested further information from IGas for the Springs Road planning application. Further public consultation will follow.  Determination is expected in Q3 2016, subject to any additional requests for information

Planning application for the Tinker Lane site (PEDL 200) to be submitted to NCC in Q2 2016

·    Financials materially impacted by continued oil price decline with average realised price of $58.9/boe (2014/15: $94.0/boe); impairments in the period of £48.1m (net of tax) (2014/15: £1.6m); £8.9m (net of tax) relating to producing assets (2014/15: £1.6m)

·    Average net production in the period was 2,570 boepd (2014/15: 2,737 boepd); production for 2016 is expected to be between 2,500 - 2,700 boepd

·    Cost reduction exercise completed with operating costs for the period of $24.6/boe (2014/15: $34.6/boe); this includes a one-off rates rebate of £2.5m ($5.5/boe) due to a rating reassessment

·    2P reserves replacement of over 150% based on production of 0.71mmboe in the period: 2P net reserves as at 31 December 2015 were 13.33mmboe (IGas estimates)

·    390,000 barrels hedged in the 12 month period to December 2016 at an average floor price of approximately $62 per barrel. Mark to market value of hedges at 31 December 2015 was £6.6m

·    INEOS Upstream Limited ("INEOS") farm-out completed in May 2015 - £30m cash consideration and up to £138m carried work programme; Total carried gross work programme of up to $255m as at period end

·    Total of 17 blocks offered to IGas in 14th Onshore Licensing Round, increasing acreage position by 25%; awards expected in April 2016

Commenting today Stephen Bowler, Chief Executive Officer, said:

"In the period, we have continued to move the business forward significantly against a very difficult oil price environment, importantly reducing operating costs by 25% and strengthening our balance sheet through the farm-out to INEOS.

The progress we have made with the production assets has resulted in a 2P reserves replacement of over 150% in the period. This is largely due to a combination of reduced operating costs, better than anticipated field performance and our work on maximising economic recovery from existing assets.

We continue to make progress in line with our five year development plan for our shale assets, including the submission of planning applications in North Nottinghamshire and the interpretation and processing of the 3D seismic data in the North West.

The Round 14 Licences are expected to be issued by the OGA in April 2016, increasing our acreage by more than 25% to over 1m acres (gross) and the next step will be to undertake desktop analysis to refine our proposed work programmes.

In this protracted period of low oil prices, our focus remains on balance sheet strength and preserving cash whilst continuing to deliver value adding activity."

 

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

The Company's Report and Accounts for the nine months to 31 December 2015 will be posted to shareholders in due course and will be available to view and download on the Company's website at http://www.igasplc.com/investors/company-publications, in accordance with AIM Rule 20.

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

 

For further information please contact:

IGas Energy plc Tel: +44 (0)20 7993 9899

Stephen Bowler, Chief Executive Officer

Julian Tedder, Chief Financial Officer

Ann-marie Wilkinson, Director of Corporate Affairs

Jefferies International Limited (NOMAD and Joint Corporate Broker)

Tel: +44 (0)20 7029 8000

Graham Hertrich/Jason Grossman/Simon Hardy

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

During the nine months to December 2015, we made significant progress with our high potential shale gas acreage, despite the very weak oil price environment affecting our near term conventional production.

Critically, in May 2015, we increased our carried shale work programme and strengthened the balance sheet by farming out part of our acreage to INEOS. Also, early in the period we were proactive in reviewing our cost base and, as a result, operating costs have reduced by over 25%.

After the farm-out to INEOS, we still operate one of the largest net acreage positions in the UK, with a very significant total gross carried shale work programme amounting to up to $255 million at the period end' which we operate on behalf of ourselves and our partners, Total, ENGIE E&P and INEOS. In the summer, we announced our five year development plan to evaluate and develop our shale gas resources to take them forward to commercial production. We have delivered against 2015's planned goals, with the completion of a significant 3D seismic programme in the North West, on time and on budget, and the submission of a planning application to drill two wells in North Nottinghamshire.

As regards our producing assets, we continue to devote the effort needed to maximise economic recovery. The progress we have made with the production assets has resulted in a 2P reserves replacement of over 150% in the period. This is largely due to a combination of reduced operating costs, better than anticipated field performance and our work on maximising economic recovery from existing assets.

We were very pleased with the results of the 14th Onshore Licensing Round, which has further increased our net acreage position by 25%, with the addition of 17 blocks. We are the largest UK shale player by gross acreage. We now have sufficient acreage across all of the UK's shale basins to be well placed to make a significant contribution to home grown gas production from shale, assuming successful commercialisation, and potentially to make a significant contribution to Britain's energy needs for the future.

During the period, the Government announced that the need to explore and test for shale gas is a "national priority" and set out to all Local Authorities a number of measures that have been implemented to ensure the planning system works effectively. 

The Government also committed to close all British coal fired power plants by 2025, making the UK the first country to set an end date for use of this fuel for electricity generation.  Coal currently makes up approximately 30% of UK electricity generation.  As recognised by the Intergovernmental Panel on Climate Change, gas has around half the emissions of coal, and so transitioning to gas is necessary in the medium-term to meet the UK's energy needs in the most environmentally responsible way. In the UK, gas and renewables can work together to replace coal and provide lower emissions. We currently rely on gas to meet a third of our energy needs and we will continue to depend on gas in the medium-term, especially given that eight out of ten homes use gas for heating.

I firmly believe that shale gas does not present a threat to renewables; it is in fact complementary.  In the US, we have seen wind and solar generation and shale gas production grow most quickly in those states that have fully embraced shale; so that together they have contributed to reducing emissions and reducing reliance on imports. 

The North Sea is now ever more challenged by reduced commodity prices; the UK has become a net gas importer, with the National Grid estimating that import dependency will reach 69% by 2018/2019.  The UK is increasingly dependent on imported gas to meet its needs. This means that we are ever more reliant on other countries to supply our energy needs, with imported energy also being at a greater cost to the environment - it takes a lot of energy to freeze gas, transport it on a ship and then re-gasify it at a British terminal.   Imported gas is costing around £11 million a day - money that is not generating jobs or tax revenues in Britain. 

As regards the leadership of the Company, in September 2015, we appointed Julian Tedder as Chief Financial Officer.  His wealth of experience in the sector, most recently at Tullow Oil where he was part of the team that grew the business from being an explorer to a significant international oil and gas company operating with multiple partners, complements IGas' existing leadership very well.   I would like to thank the executive team, my board colleagues and all our employees for everything that they have done and continue to do for the success of the Company. Finally, my thanks go to our shareholders and bondholders, for the support you have shown us during this turbulent period.

In this protracted period of low oil prices, our focus remains on balance sheet strength and preserving cash whilst continuing to deliver value adding activity.

 

 

Chief Executive Officer's Statement

We have made good progress across the business in the nine months to 31 December 2015 against a difficult oil price environment for our production business. Gas prices have also been impacted during the period, although less so than oil, with UK gas prices still more than double US prices.

As previously announced, we implemented a cost saving programme early in the period, and the effects are demonstrated in these results, with operating costs of approximately $24.6/boe (12 months ended 31 March 2015: $34.6/boe), excluding reorganisation costs of £2.1 million which were incurred in the period to 31 December 2015. We remain focused on our operating cost per barrel in this oil price environment, being on both absolute costs and maintaining our production volumes. Given the actions we have already taken, further significant reductions in operating costs per barrel will be more challenging.

As at 31 December 2015, the Company had cash of £28.6 million and net debt of £73.3 million.  IGas continues to employ a rolling hedging programme in order to plan and protect its cash flows.  At the period end, the Company had 390,000 barrels hedged in the 12 month period to December 2016 at an average floor price of approximately $62 per barrel. The mark to market value of hedges at 31 December 2015 was £6.6m.  The Company will continue to add to its hedge position as market conditions allow.

The impact of the prolonged oil price decline, with an average realised price of $58.9/boe (12 months ended 31 March 2015: $94/boe), and the considerably lower forward oil price curve has resulted in impairment charges of £48.1 million (net of tax) in the nine months ended 31 December 2015, of which £8.9m (net of tax) relates to producing assets.

Following receipt of all the necessary consents and approvals from the Department of Energy and Climate Change ("DECC") the INEOS farm-out deal completed on 7 May 2015 with a consideration of £30 million cash and a gross carried work programme of up to £138 million.

Production Assets

Average net production in the nine months to 31 December 2015 was 2,570 boepd (12 months ended 31 March 2015: 2,737 boepd).

In terms of maintaining and growing production we have been focused on activities such as sidetracks, workovers, water injection and gas monetisation projects as well as further progress on our digital oilfield initiative.  We continue to monitor and evaluate our water injection pilots and to consider methods to increase injection rates and improve reservoir management to enhance production and recovery. These initiatives have contributed to reserves replacement of over 150% based on production of 0.71mmboe in the period.

In the current oil price environment expenditure will be focused on maintaining and increasing production from existing sites, thereby reducing operating cost per barrel and improving pay back periods and returns on capital employed.

We will continue to move forward other projects to final investment decision, so that when the commodity prices and the corporate economic hurdles are met, we can advance these projects.

Appraisal Assets

The industry is working towards a goal of establishing commercial production of shale gas by the end of the decade. The Company continues to make progress against its five year shale development plan and further details are outlined in the operational review.  In the period we completed the acquisition of 110km2 of 3D seismic in the North West, without incident, on time and on budget.  This data is currently being processed and interpreted and is likely to be completed in the third quarter of 2016.

The planning application for two exploration wells at the Springs Road site was validated by the local council on 30 October 2015.There followed a period of consultation both with the public and a number of statutory consultees and since the period end the council has written to IGas to seek further information on a range of matters.  Once we have submitted that information, a further consultation period will take place before determination of the application which we expect in the third quarter 2016, subject to any further request for additional information. Also, since the period end, we have been granted permission to drill Groundwater Monitoring Boreholes at Springs Road and these have now been installed.

We are in the process of identifying a number of sites for further shale appraisal drilling and hydraulic fracturing of wells to determine flow rates and assess commerciality.

14th Onshore Licensing Round

IGas has been offered a total of 17 blocks across three basins representing a total additional gross area of c. 270,000 acres; IGas' net interest is c. 163,000 acres. These new licences will be formally awarded in April 2016 and further increase our oil and gas operations onshore in Britain whilst extending our acreage position in the strategically important shale basins.  We are also particularly pleased to be strengthening the relationships with our existing partners Total, ENGIE E&P and Egdon.

Following the formal award of these blocks, IGas will have a total of c. 876,000 net acres under licence.  The work programmes associated with the blocks will be phased and are subject to finalisation with the OGA. Under these work programmes, IGas has a minimum committed spend in the first two years of approximately £3 million net to IGas, focused on geological studies and seismic assessments. This will be followed by exploration drilling, targeting the prospective hydrocarbon bearing formations. 

Political and Regulatory Update

In August 2015, IGas welcomed the announcement by Government that gives greater clarity on the timetable for determining planning decisions for onshore oil and gas exploration and underlines Government's commitment to get shale gas exploration underway in the UK.

Following this, in November 2015, the Secretary of State for Communities and Local Government announced that he would decide the Cuadrilla Lancashire appeals after the Planning Inspector has conducted the Public Inquiry and produced a report and recommendations. The Public Inquiry is nearing conclusion.

In the Autumn Statement, the Chancellor announced that 10% of tax revenues from shale gas developments, up to a maximum of £10 million per site, will be put into a Shale Wealth Fund which could deliver up to £1 billion of investment in local communities hosting shale gas developments over the next 25 years. This provides a considerable opportunity in addition to the 1% of production revenues that shale gas companies have already committed to put back into local communities if shale gas exploration proves successful.

In December 2015, MPs voted to allow fracking for shale gas 1,200m below national parks and other protected sites.  The new regulations permit drilling from outside the protected areas. The amending Order to allow for groundwater monitoring boreholes to be granted under Permitted Development Rights bringing the onshore oil and gas industry in line with water companies and other industries which drill dozens of boreholes each year is likely to come into force later this year.

The fourth and final report of Lord Smith's Task Force on Shale Gas was published in December and recommended fracking should get underway to establish how much shale gas there is in the UK. The report calls on the government and local communities to allow initial exploratory wells and concluded that it had found that, with the right regulations in place, fracking could take place safely.

International Assets Disposal Programme

Further progress has been made on the rationalisation of non-core international assets with the disposal and relinquishment of licences in Australia and the majority of the Indonesian interests, which both completed in the fourth quarter of 2015. 

Health and Safety

Health and safety is of vital importance throughout the business in providing the highest level of protection to our employees, contractors, visitors, neighbours and the environment. Whilst we are keeping a tight control on costs there has been no compromise on the integrity and safety of our operations as demonstrated by zero lost time incidents in the period.

2015 was our ninth consecutive year of receiving a Gold ROSPA Award, validating our commitment to the prevention of accidents in the work place by having robust policies and procedures, risk assessments, accident incident investigation and lessons learned. 

IGas in the Community

We continue to embrace the need to communicate effectively with local communities. Two years ago the industry launched its own community engagement charter which specifies that developers need to engage as early as possible, well before any planning applications are submitted. 

Over the course of the last nine months we have been working hard in the communities where we operate, engaging in a host of community events and initiatives.

We have distributed over 37,000 leaflets and letters across our acreage, held 4 community exhibitions, presented at parish council meetings, engaged with local MPs, spoken at roundtable events and visited a number of projects that have benefitted from our community fund.

In October 2015 we announced the launch of the 2016 round of our IGas Energy Community Fund. Further information about the fund and its recipients can be found on the website at www.igascommunityfund.co.uk.

People

I would like to thank each and every one of our employees for their hard work and commitment in what has been an extremely challenging environment. 

In a difficult operating environment it is even more important to recognise and reward our employee's contribution. Although the Company did not make cash bonuses in respect of 2015, the Board approved a new Management Retention Plan in November 2015, resulting in the award of options over IGas Energy plc ordinary shares to all permanent employees.  Subject to remaining in employment, these awards vest in December 2016 with a further 12 month retention period before they may be sold.

Outlook

In the production business, we will continue to seek to mitigate the underlying decline and for the year ended 31 December 2016 we expect production to be in the range of 2,500 - 2,700 boepd. We have reduced our capital expenditure in light of the current oil price environment and 2016 capital expenditure is expected to be less than $10 million. 

The Round 14 Licences are expected to be issued by the OGA in April 2016, increasing our acreage by more than 25% to over 1m acres (gross) and the next step will be to undertake desktop analysis to refine our proposed work programmes. There is significant opportunity across our shale asset portfolio and we are making progress against our five year plan including the submission of planning applications in North Nottinghamshire and the interpretation and processing of the 3D seismic acquisition in the North West. At the same time we are pursuing sites across the acreage and starting preparation work on scoping reports.

2016 is likely to be another challenging year for the industry. With commodity prices still remaining at low levels, our focus remains on retaining balance sheet strength and preserving cash.  Whilst the steps we have taken to manage costs and improve the strength of the balance sheet have helped the business in this environment, we must remain focused on cost effective, value adding activity both on the production and appraisal assets.

 

 

Operational Review

Production Performance

Average net production in the 9 months to 31 December 2015 was 2,570 boepd (12 months ended 31 March 2015: 2,737 boepd).  Production delivery was initially very strong, benefitting from the determined focus on production optimisation and the reduction of unplanned deferred production.

However, production in the latter part of the period was impacted by a deferral in workover activity to allow an extended maintenance programme on a key workover rig to be conducted.  This unit has now been returned to service and the level of workover activity has now resumed with the aim of restoring production back to projected levels.

Maximising Economic Recovery from Existing Assets

We continue to offset the underlying natural decline in our fields through focused technical and operational expertise.  Opportunities for incremental production are technically and commercially evaluated to meet the relevant screening criteria aimed at maximising the economic recovery from the existing assets.  

Detailed subsurface studies are utilised in conjunction with field operating experience to select appropriate production enhancement candidates taking into account relevant constraints. 

One area where we have seen significant progress has been artificial lift optimisation, resulting in incremental production and reduced operating costs.  This positive outcome has been heavily influenced by the installation of Rod Pump-Off Controllers (RPOC's), part of the Group investment in the "Digital Oilfield" technology.  This initiative is beginning to bear fruit and is being adopted more widely across the assets. The adoption of cost effective technology to unlock value in our assets remains a key part of our overall strategy. 

Another initiative, under the "Digital Oilfield" project has been the implementation of "real time" field monitoring and reporting.  We have been able to build "in house" much of the necessary architecture and the results not only allow more effective field management but deliver significant cost savings.  This capability is also being developed with a view to planning future field instrumentation and remote management, something that will be particularly beneficial for shale development.

The potential to enhance production and reserves through the application of secondary recovery methods, e.g. water injection, is another initiative that is being pursued.  Two "pilot schemes" have been implemented in our East Midland fields.   Preliminary results are encouraging and whilst we continue to monitor and evaluate our water injection pilots, based on these early results, we are looking at measures to increase injection rates aiming to further enhance production and recovery.  Depending on the success of these trials we will look to further expand the initial pilot schemes as well as looking at adopting a similar approach in other candidate fields.

To maximise the benefits of secondary recovery by water injection it is advantageous to ensure the produced water is treated before it is re-injected into the producing reservoir.  We instigated a number of trials on a water treatment plant at our Welton facility to "field prove" the technology.  The results from these trials look very encouraging for a wider field application.

A detailed and extensive study of the Stockbridge Field in the Weald Basin has been completed resulting in an updated Field Development Plan (FDP).  This is one of several such studies that are being conducted on the major fields in the portfolio.  The Stockbridge FDP has identified some infill drilling opportunities that offer the possibility of incremental production and reserves. 

Three sidetracks, from existing, low productivity wells, were successfully drilled by the period end; on time, on budget and without incident.  All three wells, each drilled horizontally through the main carbonate reservoirs, encountered the formations and hydrocarbons as prognosed.  At the period end the wells were being completed and preliminary production testing was being initiated.  Current production across the three wells is c. 100 boepd, which is below expectations, but an extended production period will be necessary to ascertain long-term, stable rates.

Gas monetisation of the Albury, Bletchingley and Lybster fields continues to be progressed.  Project plans have been developed and market quotes for the activities obtained for both Albury and Bletchingley.  

Albury, which had been granted planning consent for a mini Liquefied Natural Gas (LNG) development, has been revisited and a new application submitted to develop the field for a mini Compressed Natural Gas (CNG) development.  CNG represents a simpler and cheaper solution.  The Bletchingley Field gas offtake assumes the gas will be exported via the local grid network.  Both planning applications have been submitted, validated and we await determination.  However, final project sanction will depend on being able to negotiate suitable commercial terms with the offtakers, in today's more difficult market. 

At Lybster, in Scotland, we are redeveloping the existing facilities whilst we continue discussions with a number of entities to evaluate the off-take options for the associated gas.  In the interim, the well remains shut-in while the various site upgrades are completed.  Consideration will be given to recommencing oil production during 2016 but the duration of the flow period will be determined by the gas off-take discussions.

During the course of the period an extensive cost saving programme was undertaken.  This has resulted in a significant reduction in operating expenditure from $34.6/boe (12 months ended 31 March 2015) to $24.6/boe (including a one-off rates rebate equivalent to $5.5/boe).  The focus continues on maintaining production at broadly historical levels whilst managing absolute costs but ensuring safety is not compromised.

As part of the cost saving programme, a new production division organisational structure was implemented as of the 1st October 2015 which introduced a rationalised, but standardised approach to the delivery of safe, compliant and efficient production operations. The new structure emphasises accountability and responsibility for delivery whilst encouraging optimisation and knowledge exchange across the business.  Underpinning these changes is a clear focus on the business priorities, which is essential in the current climate.

Reserves Update

Despite reduced commodity price assumptions, potentially affecting the commercial lives of the fields, we have seen 2P reserves replacement of over 150% based on a cumulative production of 0.71mmboe in the period. This is largely due to a combination of reduced operating costs, better than anticipated field performance combined with the various initiatives outlined above.

IGas Net Reserves (mmboe)*

 

1P

2P

As at 31 March 2015

6.29

12.63

As at 31 Dec 2015

8.31

13.33

*IGas estimates, cumulative production 0.71mmboe

 

 

Shale Gas - Delivery against the Five Year Development Plan

Recent activity, outlined below, commences our work on the five year development plan to advance the evaluation and development of our shale gas resources through to commercial production. 

North West

We have successfully completed a significant 3D seismic acquisition programme in the North West covering an area of 110km².  We are now in receipt of some of the preliminary results and the processing and interpretation phase has commenced. This is likely to complete in the third quarter of 2016.

As we move into the appraisal stage, we are in the process of identifying a number of sites for further appraisal drilling and hydraulic fracturing of the wells to determine flow rates and assess commerciality. The results from the 3-D survey will determine our future exploration and appraisal work programme in the area.

East Midlands and Yorkshire

In October 2015, we submitted a planning application at our Springs Road site, in North Nottinghamshire. The proposal is to drill two exploratory wells in order to evaluate the geology in the local area and begin assessing its potential for shale gas recovery. The site is located in PEDL 140, where we operate on behalf of Total, Egdon and eCorp Oil & Gas UK Ltd.

The planning application supported by an Environmental Statement, for two exploration wells at the Springs Road site was validated by Nottinghamshire County Council ("NCC") on 30 October 2015.   There followed a period of consultation both with the public and a number of statutory consultees.  Planning law prescribes circumstances where consultation must take place between a local planning authority and certain organisations referred to as statutory consultees, prior to a decision being made on an application. The organisations in question are under a duty to respond to the local planning authority within a set deadline and must provide a substantive response to the application in question.   

More than 2,000 responses were received during public consultation on the application, and the Council has recently written to IGas to seek further information on a range of matters including site selection and sequential testing, surface water run-off, ecology, traffic and transportation, and landscape and visual impact.  This is a usual part of the planning process for major developments, particularly those subject to an environmental impact assessment.  Once we have submitted the additional information, a further period of public consultation will take place before NCC determines the application.  IGas has agreed with NCC that such a decision must be made before the end of July 2016, subject to further requests for information.   

As part of the Springs Road site programme, IGas lodged a planning application to seek consent to drill a series of groundwater monitoring boreholes adjacent to the Springs Road site.  These boreholes allow groundwater to be monitored before, during and after any IGas operations on the Springs Road site.  This application was granted in January 2016 and the boreholes were successfully drilled and completed in February 2016. Data gathered from these boreholes will provide further information relating to the current local surface and groundwater quality and will allow for a full understanding of conditions before, during and after our operations.

The drilling of the two exploration wells at Springs Road will be an important step in helping us to understand the shale gas potential in North Nottinghamshire and more widely in the East Midlands and Yorkshire.  A successful exploration well would, in all likelihood, lead to a subsequent planning application to flow test a well which would involve hydraulic fracturing.

IGas embarked on a community engagement process that began in early 2014, including the formation of a Community Liaison Group (CLG), providing community representatives with a forum to meet with members of the IGas project team, discuss the proposals and make recommendations.  There have also been three public information events to give residents the opportunity to find out more about activity at the proposed site.

Further information can be found at www.igas-engage.co.uk and www.springsroad.co.uk.

In the adjoining licence block, PEDL 200, we have identified a new site, Tinker Lane, and have submitted an initial scoping request to NCC to drill a single vertical exploration well to obtain key geological data, including logs and cores. 

We continue to work with local businesses and energy intensive industries to build a supply chain capable of supporting the shale industry.  We are also actively identifying opportunities across our acreage where we can utilise infrastructure and resources to ensure, where possible, we minimise our surface footprint and local impacts.  These are fundamental considerations for any site selection.

International Assets

Following the acquisition of Dart Energy in 2014, the Group has been through a process of disposing of non-core assets acquired as part of this transaction.

The Group divested by way of relinquishment, asset sale or corporate disposal all of its operational interests in Australia.

Following the closure of the Singapore office in March 2015, one employee remains to assist with the ongoing operations and divestment of non-core assets.

An office presence is maintained in China where the formal process of deregistering the legal entities registered there continues.

In India, IGas remains as Operator of the Assam Block AS-CBM-2008/IV and retains a 10% working interest. The outstanding work programme is scheduled to complete on time in early 2016. The exploration phase has been completed with two test production wells to drill and flow-test. It is likely that the licence will be relinquished once the minimum work programme has been completed as required by the Regulator.

A Share Purchase Agreement for Dart Energy (Indonesia) Holdings Pte. Ltd. was executed in May 2015 and completed in November 2015. Bank guarantees totalling US$2.6m have been received to date.  IGas retains a working interest in the non-operated Sangatta West PSC. 

Health, Safety and Environmental Protection

IGas is committed to conducting its operations in a safe, secure and environmentally responsible manner. Maintaining the highest standards of safety and environmental protection is something we take seriously, and is the top priority at each and every one of our operational sites. 

Throughout the business there is a strong and visible commitment to HSE management and promoting a positive culture within the Company and that focus resulted in achieving zero Lost-Time Incidents for the period.   

We have again maintained our ISO 9001 and 14001 accreditation with no major non-conformances identified.  We remain committed to maintaining these international standards in 2016.

Minimising our impact on the environment

At IGas, we work to minimise our impact on the environment and during the period we volunteered as entrant to the Energy Saving Opportunity Scheme (ESOS) to reduce energy usage across our operations. The ESOS has been established by the Department of Energy and Climate Change (DECC) in response to the requirement to implement Article 8 of the Energy Efficiency Directive.

We are in the process of replacing approximately half of our combustion engine vehicle fleet with electric vehicles in the East Midlands. This will reduce vehicle exhaust emissions and noise in the local communities in which we operate. The electricity will be supplied from our own generating capacity.

The business continues to review its environmental performance in reducing its emissions to the environment and has been awarded funds from Innovate UK to trial methods to capture low volumes of methane for beneficial use.  Waste heat will also be recovered and used to aid oil water separation in the onsite oil tanks which will reduce transport costs and movements.

Regulation

IGas continues to cooperate and collaborate with industry and regulators to further progress the development, updating and implementation of best available techniques for both conventional and unconventional operations, transferring best practice and lessons learned where applicable. There have been many developments during 2015 which have given much needed clarity to IGas and industry including issues relating to technical underground trespass and the issuing of regulatory position statements around such matters as flaring, hydraulic fracture programmes and site safety assessments.

 

 

Financial Review

Good progress was made in the nine months ended 31 December 2015 in strengthening the Group's balance sheet. The farm-out to INEOS in May 2015 for £30m in cash and up to a £138m carried gross work programme has improved the Group's cash position and the amendment of the bond terms in August 2015 provided the Group with more financial flexibility. As at the period end, the Group has a carried gross work programme of up to $255 million on its shale assets which will enhance the Group's ability to deliver on its strategy.

However, the last nine months has seen a further decline in the oil price and this has materially impacted the financial results. In the nine months ended 31 December 2015 adjusted EBITDA1 was £18.3m (12 months ended 31 March 2015: £21.6m) whilst a loss was recognised from continuing activities after tax of £44.8m (12 months ended 31 March 2015: profit £5.2m). The main factors explaining the movements between the nine months ended 31 December 2015 and the 12 months ended 31 March 2015 were as follows:

·     Reduced revenues of £25.1m (12 months ended 31 March 2015: £58.2m) principally due to reduced oil prices;

·     Restructuring costs of £2.1m (12 months ended 31 March 2015: £nil) following completion of a cost reduction programme;

·     Impairment charges of £48.1m (net of tax) (12 months ended 31 March 2015: £1.6m); comprising producing assets (£8.9m net of tax) and goodwill (£39.2m net of tax) due to the reduced oil price;

·     An exploration write off of £10.0m (net of tax) (12 months ended 31 March 2015: £6.4m);

·     A profit on disposal of £4.0m (12 months ended 31 March 2015: £nil) on the INEOS farm-out; and

·     A tax credit of £17.3m (12 months ended 31 March 2015: £23.8m credit) due mainly to timing difference reversals caused by the impairments.

We remain focused on maintaining flexibility for the business in the current oil price environment.

Income statement

The Group recognised revenues of £25.1m in the nine months (12 months ended 31 March 2015: £58.2m). Group production in the nine months was an average of 2,570 boepd (12 months ended 31 March 2015: 2,737 boepd). Revenues for the nine months included £2.4m (12 months ended 31 December 2015: £7.7m) 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 realised price for the nine months per barrel pre hedge was $51.3 (12 months ended 31 March 2015: $84.1) and post hedge $58.9 (12 months ended 31 March 2015: $94.0).  The average exchange rate for the nine months was £1: $1.53 (12 months ended 31 March 2015: £1: $1.63) which positively impacted revenues.

Cost of sales for the nine months were £21.5m (12 months ended 31 March 2015: £42.7m) including depreciation, depletion and amortisation (D,D&A) of £7.1m (12 months ended 31 March 2015: £12.8m), and operating costs of £14.4m (12 months ended 31 March 2015: £29.9m).  Operating costs include a £2.2m charge (12 months ended 31 March 2015: £7.2m) in relation to processing third party oil, a decrease of £5.0m from the comparative period due to the decreased number of barrels purchased from third parties and processed by us and the significant fall in the oil price.  The contribution received from processing this third party oil was £0.2m (12 months ended 31 March 2015: £0.5m). 

Operating costs per barrel of oil equivalent were £16.1 ($24.6), excluding the third party costs (12 months ended 31 March 2015: £21.5 ($34.6) per barrel). The reduction in the operating cost is due to the completion of the cost reduction exercise and includes a £2.5m ($5.5/boe) refund for land rates following discussions with the Valuation Office Agency.

Adjusted EBITDA1 in the nine months was £18.3m (12 months ended 31 March 2015: £21.6m).  Gross profit of £3.6m was recognised in the nine months (12 months ended 31 March 2015: £15.4m).  Administrative costs decreased by £3.4m to £6.0m (12 months ended 31 March 2015: £9.4m) principally due to the cost reduction exercise.

Net back per boe (on an Income Statement basis)2 was $21.4 (£14.0), (12 months ended 31 March 2015: $45.5 (£28.0)) and on a pre G&A basis was $34.3 (£22.4) (12 months ended 31 March 2015: $59.0 (£36.3)).

The Group recognised an impairment charge of £48.1m (net of tax) (12 months ended 31 March 2015: £1.6m) relating to producing assets (£8.9m net of tax) and goodwill (£39.2m), principally as a result of the reduction in commodity forward curves at the year end. Exploration costs written off were £10.0m (net of tax) (12 months ended 31 March 2015: £6.4m).

Other income of £5.0m (12 months ended 31 March 2015: £0.3m) has been recognised in the period relating to a fair value adjustment on the contingent deferred consideration in relation to amounts payable to a joint venture partner.

Net finance costs were £7.8m in the nine months (12 months ended 31 March 2015: £12.5m), which primarily relate to interest on borrowings of £8.7m (12 months ended 31 March 2015: £12.6m), a gain on fair value of warrants of £0.2m (12 months ended 31 March 2015: gain of £5.4m), a net foreign exchange gain of £0.1m (12 months ended 31 March 2015: loss of £6.3m) and a realised gain on the bonds repurchased of £0.9m (12 months ended 31 March 2015: £1.4m).

The Group made a gain in the nine months on oil price derivatives of £8.6m (12 months ended 31 March 2015: £7.0m).

Portfolio management

During the nine months, the Group completed the farm-out to INEOS, who acquired an interest in certain licences in the North West and East Midlands and the Group's participating interest in the acreage held under PEDL 133 in Scotland. The consideration for IGas' participating interests comprised £30m cash which was received on completion and a funded forward work programme of up to £138m gross, of which IGas' share to be funded fully by INEOS is expected to amount to approximately £65m. The Group recognised a profit of £4.0m on this transaction.

Cash flow

Net cash generated from operating activities in the nine months amounted to £1.0m (12 months ended 31 March 2015: £26.5m). The Group invested £9.4m across its asset base in the nine months (12 months ended 31 March 2015: £16.8m), of which £6.4m was invested in the conventional assets, principally related to the three Stockbridge sidetracks completed in the period, where we continue to invest to maintain our production at current levels.

IGas repaid £6.1m ($8.2m) of principal on borrowings to bondholders in the period in accordance with the terms of the bonds (12 months ended 31 March 2015: £5.2m ($8.3m)), which represents a repayment of 2.5% of the original principal amount of the secured bonds. In the nine months ended 31 December 2015, the Company repurchased bonds with a face value of $7.0m for $5.3m (12 months ended 31 March 2015: face value of $15.7m for $13.2m).

IGas paid £5.9m ($9.0m) in interest (12 months ended 31 March 2015: £11.5m ($18.5m)). Cash and cash equivalents were £28.6m at the period end (31 March 2015: £19.0m).

____________
1Adjusted EBITDA relates to earnings before gains/(losses) on oil price derivatives, net finance costs, tax, depletion, depreciation and amortisation, impairments, acquisition costs, restructuring costs and IFRS 2 charges 

2 Net back per boe on an Income Statement basis is realised oil price, less operating costs and G&A

 

Balance sheet

Net assets at 31 December 2015 amounted to £98.8m (31 March 2015: £146.6m) with the decrease in net assets principally resulting from the loss during the nine months ended 31 December 2015 from continuing activities which was due to impairments to assets and goodwill caused by the reduction in commodity prices.

The Group hedges its oil production through the use of a mixture of puts, swaps and zero cost collars, therefore minimising the cost of the hedge instruments. At 31 December 2015, the Group's derivative instruments had a net positive fair value of £6.6m (31 March 2015: £1.4m)

Net debt, being borrowings less cash, at the period end amounted to £73.3m (31 March 2015: £86.4m).

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;

·     Successful development of shale gas resources;

·     Loss of key staff;

·     Market price risk through variations in the wholesale price of oil in the context of the production from oil fields it owns and operates;

·     Market price risk through variations in the wholesale price of gas and electricity in the context of its future unconventional production volumes;

·     Exchange rate risk through both its major source of revenue and its major borrowings being priced in US$ while most of the Group's operating and G&A costs are denominated in UK pounds sterling.

·     Liquidity risk through its operations;

·     Capital risk resulting from its capital structure, including operating within the covenants of its existing bond agreements; and

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

Going concern

The Group closely monitors and manages 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 borrowing facilities. Sensitivities are run to reflect different scenarios including, but not limited to, possible further reductions in commodity prices below the current forward curve and reductions in forecast oil and gas production rates.

The ability of the Group to operate as a going concern is dependent upon the continued availability of future cash flows and the availability of the monies drawn under its Bonds, which in turn is dependent on the Group not breaching its bond covenants. In response to the significant reduction in oil prices, the Board implemented a series of cost saving initiatives during the period that have materially reduced both operating costs and G&A spend. In addition, following positive discussions with the bondholders, the net leverage covenant, inter alia, was amended to take account of the Group's improved cash position following the INEOS farm-out, which was completed during the period.

Whilst the Group has delivered on the above initiatives and has significant cash balances, the continuing low commodity price environment means that the Group's current forecasts, utilising the current oil price forward curve, project non-compliance with certain of its covenants in the second half of 2016. The Board is pursuing actions to alleviate a covenant breach including, but not limited to, further cost reductions, monetising existing hedged oil positions, bond buy-backs, and asset portfolio management.  Concurrently, the Board will continue to evaluate all other options, including transactions that would increase the Group's cash and/or earnings, which could reduce the need for the mitigating actions set out above. Nevertheless, based on the current oil price and forward curve, the directors cannot be certain that these will fully mitigate any potential covenant shortfall in respect of the testing period ending 31 December 2016. Whilst pursuing the options listed above, the Board will continue its proactive dialogue with bondholders and, if appropriate, seek to modify or temporarily waive the existing covenants ahead of the time at which the Group submits its compliance certificate in respect of that testing period, which would be by 30 April 2017.

The risk that the Group will be unable to either enact appropriate mitigating actions to a sufficient extent before the 31 December 2016 measurement date or secure an appropriate relaxation or amendment of its financial covenants prior to 30 April 2017 represents a material uncertainty that may cast doubt upon the Group's ability to continue as a going concern.

The Board believes, after making appropriate enquiries, and on the information currently available, that the Group is likely to be able to either implement sufficient mitigating actions to ensure that the Group is compliant with its covenants and/or secure a relaxation to the covenants as described above and it is therefore considered appropriate to adopt the going concern basis in preparing the financial statements.

Directors' responsibility statement

The Directors confirm that, to the best of their knowledge:

·  The financial statements, prepared in accordance with International Financial Reporting Standards as adopted by the European Union, give a true and fair view of the assets, liabilities, financial position and profit and loss of the Group and the undertakings  included in the consolidation taken as a whole; and

·  The Strategic Report and the Directors' Report includes a fair review of the development and performance of the business and the position of the Group, together with a description of the principal risks and uncertainties faced.

 

By order of the Board,

 

 

Stephen Bowler                                               Julian Tedder

Chief Executive Officer                                Chief Financial Officer

15 March 2016                                                   15 March 2016

 

 

 

Consolidated Income Statement

For the nine months ended 31 December 2015

 

 

 

Notes

Nine months ended

31 December 2015

£000

Year ended

31 March 2015

£000

Revenue

 

3

 

25,123

 

58,160

 

Cost of sales:

 

 

 

 

Depletion, depreciation and amortisation

 

 

(7,105)

 

(12,805)

 

Other costs of sales

 

 

(14,416)

 

(29,927)

 

 

 

(21,521)

 

(42,732)

 

Gross profit

 

 

3,602

 

15,428

 

Administrative expenses

 

 

(5,973)

 

(9,412)

 

Restructuring costs

 

 

(2,117)

  

-

  

Impairment of goodwill

 

10

 

(39,227)

 

-

 

Exploration and evaluation assets written off

 

11

 

(12,900)

 

(15,406)

 

Impairment of property, plant and equipment

 

12

 

(17,720)

 

(3,946)

 

Profit on disposal of oil and gas assets

 

5

 

3,998

 

-

 

Gain on oil price derivatives

 

 

8,618

 

7,018

 

Other income

 

6

5,070

 

254

 

Operating loss

 

 

(56,649)

 

Finance income

 

7

 

1,302

 

6,902

 

Finance costs

 

7

 

(9,127)

 

(19,362)

 

Loss from continuing activities before tax

 

 

(64,474)

 

(18,524)

 

Income tax credit

 

8

 

17,257

 

23,769

 

(Loss)/profit after tax from continuing operations attributable to equity

shareholders of the Group

 

 

(47,217)

 

5,245

 

Profit/(loss) after tax from discontinued operations

 

 

2,395

 

(80)

 

Net (loss)/profit attributable to equity shareholders of the Group

 

 

(44,822)

 

5,165

 

(Loss)/profit attributable to equity shareholders:

 

 

 

 

Basic (loss)/earnings per share (pence/share)

 

9

 

(15.15p)

 

2.09p

 

Diluted (loss)/earnings per share (pence/share)

 

9

 

(15.15p)

 

2.05p

 

 

 

Consolidated Statement of Comprehensive Income

For the nine months ended 31 December 2015

 

Nine months ended

31 December 2015

£000

Year ended

31 March 2015

£000

(Loss)/profit for the period/year

(44,822)

5,165

Other comprehensive (loss) for the period/year

 

 

Currency translation adjustments recycled to the income statement

1,229

-

Currency translation adjustments

(5,058)

(3,035)

Total comprehensive (loss)/income for the period/year

(48,651)

2,130

 

 

Consolidated Balance Sheet

As at 31 December 2015

 

Notes

31 December

 2015

£000

31 March

 2015

£000

ASSETS

 

 

 

 

Non-current assets

 

 

 

 

Intangible exploration and evaluation assets

 

11

 

113,394

 

151,615

 

Property, plant and equipment

 

12

 

82,911

 

104,314

 

Goodwill

 

10

 

4,801

 

44,028

 

 

 

201,106

 

299,957

 

Current assets

 

 

 

 

Inventories

 

 

1,208

 

960

 

Trade and other receivables

 

 

14,809

 

8,151

 

Cash and cash equivalents

 

 

28,614

 

19,025

 

Other financial assets - restricted cash

 

 

1,007

 

2,097

 

Derivative financial instruments

 

 

6,654

 

1,574

 

Assets classified as held for sale

 

 

1,837

 

5,013

 

 

 

54,129

36,820

Total assets

 

 

255,235

 

336,777

 

LIABILITIES

 

 

 

 

Current liabilities

 

 

 

 

Trade and other payables

 

 

(9,218)

 

(7,981)

 

Current tax liabilities

 

7

 

(2,004)

 

(1,085)

 

Borrowings

 

13

 

(4,819)

 

(5,310)

 

Other liabilities

 

 

(147)

 

(349)

 

Derivative financial instruments

 

 

-

 

(201)

 

Liabilities associated with assets classified as held for sale

 

14

 

(1,837)

 

(5,998)

 

 

 

(18,025)

(20,924)

Non-current liabilities

 

 

 

 

Borrowings

 

13

 

(98,060)

 

(102,229)

 

Deferred tax liabilities

 

7

 

(14,636)

 

(32,811)

 

Provisions

 

 

(25,323)

 

(28,826)

 

Contingent deferred consideration

 

 

(420)

 

(5,367)

 

 

 

(138,439)

 

(169,233)

 

Total liabilities

 

(156,464)

(190,157)

Net assets

 

98,771

146,620

EQUITY

 

 

 

 

Capital and reserves

 

 

 

 

Called up share capital

 

 

26,636

 

26,446

 

Share premium account

 

 

117,731

 

117,463

 

Capital redemption reserve

 

 

41,239

 

41,239

 

Foreign currency translation reserve

 

 

(6,864)

 

(3,035)

 

Other reserves

 

 

1,322

 

1,264

 

Accumulated deficit

 

(81,293)

(36,757)

Shareholders' funds

 

98,771

146,620

 

 

Consolidated Statement of Changes in Equity

For the nine months ended 31 December 2015

 

 

 

Called up

share

capital      

 £000

Share

premium

account       

  £000

 

Capital

redemption

 reserve   

 £000

 

 

Foreign

currency

translation

 reserve*

 £000

 

 

 

Other

reserves**  

 £000

Accumulated

deficit

 £000

 

 

 

 

Total

 £000

At 1 April 2014

17,226

58,933

41,239

-

 

(667)

(42,409)

74,322

 

Profit for the year

 

-

 

-

 

-

 

-

 

-

5,165

5,165

 

Employee share plans

 

-

 

-

 

-

-

2,418

 

-

 

2,418

Lapse of LTIPs under the employee share plan

 

-

 

-

 

-

 

-

 

(487)

 

487

 

-

Warrants exercised

 

-

 

1,117

 

-

-

-

 

-

 

1,117

 

Issue of shares

 

9,220

 

57,413

 

-

-

-

 

-

 

66,633

 

Currency translation adjustments

 

-

 

-

 

-

 

(3,035)

 

-

 

-

 

(3,035)

 

At 31 March 2015

26,446

117,463

41,239

 

(3,035)

 

1,264

(36,757)

146,620

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 Loss for the period

-

-

-

 

-

 

-

(44,822)

(44,822)

 

Employee share plans

-

-

-

 

-

 

1,344

-

1,344

 

Forfeiture of LTIPs under the employee share plan

 

 

 

-

 

 

 

 

-

 

 

-

 

-

(1,000)

-

(1,000)

Lapse of LTIPs under the employee share plan

 

 

-

 

-

 

-

 

-

 


(286)

 


286

-

Issue of shares

190

268

-

-

-

-

458

Currency translation adjustments

-

-

-

(3,829)

 

-

 

-

(3,829)

 

At 31 December 2015

26,636

 

117,731

 

41,239

 

(6,864)

 

1,322

 

(81,293)

 

98,771

 

 

 

 

 

 

 

 

 

*      The foreign currency translation reserve represents exchange gains and losses arising on translation of foreign currency subsidiaries net assets and results for the nine months ended 31 December 2015 and on translation of those subsidiaries intercompany balances which form part of the net investment of the Group.

**    Other reserves include: 1) LTIP/VCP/EDRP reserves which represent the cost of share options issued under the long term incentive plans; 2) share investment plan reserve which represents the cost of the partnership and matching shares; 3) treasury shares reserve which represents the cost of shares in IGas Energy plc purchased in the market and held by the IGas Employee Benefit Trust to satisfy awards held under the Group incentive plans; and 4) capital contribution reserve which arose following the acquisition of IGas Exploration UK Limited.

 

 

Consolidated Cash Flow Statement

For the nine months ended 31 December 2015

 

 

 

 

 

Notes

Nine months

ended

31 December 2015

£000

 

Year ended

31 March 2015

£000

Cash flows from operating activities:

 

 

 

Loss before tax for the period/year

 

(64,474)

(18,524)

Adjustment for non-operating gain relating to farm-out

 

(3,998)

-

Adjustment for gain relating to deferred consideration

6

(4,947)

-

Depreciation, depletion and amortisation

12

7,233

13,031

Abandonment costs incurred

 

(6)

(95)

Share based payment charge

 

600

1,487

Impairment of goodwill

10

39,227

-

Exploration and evaluation assets written off

11

12,900

15,407

Impairment of property, plant and equipment

12

17,720

3,946

Unrealised gain on oil price derivatives

 

(5,281)

(1,422)

Finance income

7

(1,302)

(6,902)

Finance costs

7

9,127

19,362

Other non-cash adjustments

 

(326)

(24)

Operating cash flow before working capital movements

 

6,473

26,266

(Increase)/decrease in trade and other receivables and other financial assets

 

(5,568)

5,755

Increase/(decrease) in trade and other payables, net of accruals related to investing activities

 

130

(5,920)

(Increase)/decrease in inventories

 

(248)

383

Cash generated from continuing operating activities

 

787

26,484

Cash generated from discontinued operating activities

 

175

-

Taxation paid

 

-

(15)

Net cash generated from operating activities

 

962

26,469

Cash flows from investing activities:

 

 

 

Purchase of intangible exploration and evaluation assets

 

(2,963)

(11,033)

Purchase of property, plant and equipment

 

(6,396)

(5,775)

Acquisitions, net of cash acquired

 

-

2,524

Disposal of investment

 

-

1,500

Disposal of exploration and evaluation assets

 

30,000

375

Disposal of oil and gas assets

 

181

-

Interest received

 

107

70

Cash generated from/(used in) continuing investing activities

 

20,929

(12,339)

Cash used in discontinued investing activities

 

(52)

-

Net cash generated from/(used in) investing activities

 

20,877

(12,339)

 

 

 

 

Cash flows from financing activities:

 

 

 

Cash proceeds from issue of ordinary share capital

 

125

997

Share issue costs

 

-

(1,882)

Interest paid

 

(5,925)

(11,548)

Bond renegotiation costs

 

(940)

-

Repayment of borrowings

 

(6,147)

(13,688)

Cash used in continuing financing activities

 

(12,887)

(26,121)

Net cash used in financing activities

 

(12,887)

(26,121)

Net increase/(decrease) in cash and cash equivalents in the period/year

 

8,952

(11,991)

Net foreign exchange difference

 

637

2,715

Cash and cash equivalents at the beginning of the period/year

 

19,025

28,301

Cash and cash equivalents at the end of the period/year

 

28,614

19,025

 

  

 

Consolidated Financial Statements - Notes

As at 31 December 2015

 

1 Corporate information

The financial information for the nine months ended 31 December 2015 set out in this announcement does not constitute statutory accounts within the meaning of section 434 of the Companies Act 2006. Statutory accounts for the nine months ended 31 December 2015 were approved by the Board of Directors on 15 March 2016; however these have not yet been delivered to the registrar. The latest statutory accounts delivered to the registrar were for the year ended 31 March 2015.  The auditor has reported on both the accounts for the nine months ended 31 December 2015 and the year ended 31 March 2015; the reports were unqualified and did not contain statements under section 498(2) or 498(3) of the Companies Act 2006. The auditor's report on the accounts for the nine months ended 31 December 2015 drew attention, by way of emphasis of matter, to the existence of a material uncertainty which may cast significant doubt upon the Group's ability to continue as a going concern as described in note 2 below.

 

IGas Energy plc is a public limited Company incorporated, registered in England and Wales and is listed on the Alternative Investment Market ("AIM"). The Company's principal area of activity is exploring for, appraising, developing and producing oil and gas resources in Great Britain.

 

2 Accounting policies    

The accounting policies applied in this announcement are consistent with those of the annual financial statements for the year ended 31 March 2015, as described in those annual financial statements.

 

Changes in presentation and disclosures

In previous years, certain exceptional items, as defined in the Group's accounting policies, were disclosed separately under the heading "exceptional items" in the income statement after operating profit.  During the current period, all exceptional items are reported within operating profit, thereby increasing administrative expenses and reducing operating profit by £867k in the year ended 31 March 2015, which represent costs relating to acquisitions. Administrative expenses for the nine months ended 31 December 2015 include £107k of costs relating to acquisitions. The directors consider this change to provide more reliable and relevant information as the nature of separately disclosed exceptional items was not sufficiently distinct from other separately disclosed material items in the income statement.

 

In addition, the Group no longer presents adjusted earnings per share (EPS); the comparative period disclosures have therefore also not been presented. Management considers the removal of adjusted EPS to result in clearer disclosure and more reliable and relevant information, recognising that the adjusted earnings measure is not defined by IFRS and required judgement in determining the relevant adjustments.

Furthermore, the Group no longer presents intangible exploration and evaluation ("E&E") asset impairments and E&E write offs separately.  During the nine months to 31 December 2015, impairment of £5.9 million (year ended 31 March 2015: £15.2 million) and write offs of £7.0 million (year ended 31 March 2015:  £0.2 million) have been aggregated in "Exploration and evaluation assets written off" in the income statement. The directors consider this change to provide more reliable and relevant information as the nature of the two concepts was not sufficiently distinct from each other to merit separate disclosure.

 

Statement of compliance

The consolidated financial statements of the Group have been prepared under the historical cost convention in accordance with International Financial Reporting Standards, adopted for use by the European Union ("IFRSs") as they apply to the Group for the nine months ended 31 December 2015 and with the Companies Act 2006.

 

The financial statements are presented in UK pounds sterling and all values are rounded to the nearest thousand (£000) except when otherwise indicated. The comparative amounts have been amended to reflect the finalisation of acquisition accounting for the Dart acquisition. 

 

Going Concern

The Group closely monitors and manages 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 borrowing facilities. Sensitivities are run to reflect different scenarios including, but not limited to, possible further reductions in commodity prices below the current forward curve and reductions in forecast oil and gas production rates.

The ability of the Group to operate as a going concern is dependent upon the continued availability of future cash flows and the availability of the monies drawn under its Bonds, which in turn is dependent on the Group not breaching its bond covenants. In response to the significant reduction in oil prices, the Board implemented a series of cost saving initiatives during the period that have materially reduced both operating costs and G&A spend. In addition, following positive discussions with the bondholders, the net leverage covenant, inter alia, was amended to take account of the Group's improved cash position following the INEOS farm-out, which was completed during the period.

Whilst the Group has delivered on the above initiatives and has significant cash balances, the continuing low commodity price environment means that the Group's current forecasts, utilising the current oil price forward curve, project non-compliance with certain of its covenants in the second half of 2016. The Board is pursuing actions to alleviate a covenant breach including, but not limited to, further cost reductions, monetising existing hedged oil positions, bond buy-backs, and asset portfolio management.  Concurrently, the Board will continue to evaluate all other options, including transactions that would increase the group's cash and/or earnings, which could reduce the need for the mitigating actions set out above. Nevertheless, based on the current oil price and forward curve, the directors cannot be certain that these will fully mitigate any potential covenant shortfall in respect of the testing period ending 31 December 2016. Whilst pursuing the options listed above, the Board will continue its proactive dialogue with bondholders and, if appropriate, seek to modify or temporarily waive the existing covenants ahead of the time at which the Group submits its compliance certificate in respect of that testing period, which would be by 30 April 2017.

The risk that the Group will be unable to either enact appropriate mitigating actions to a sufficient extent before the 31 December 2016 measurement date or secure an appropriate relaxation or amendment of its financial covenants prior to 30 April 2017 represents a material uncertainty that may cast doubt upon the Group's ability to continue as a going concern.

The Board believes, after making appropriate enquiries, and on the information currently available, that the Group is likely to be able to either implement sufficient mitigating actions to ensure that the Group is compliant with its covenants or secure a relaxation to the covenants as described above and it is therefore considered appropriate to adopt the going concern basis in preparing the financial statements.

3 Revenue and segment information

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

 

All revenue, which represents turnover, arises solely within the United Kingdom and relates to external parties. Revenues of approximately £11.8 million and £10.1 million were derived from the Group's two largest customers (Year ended 31 March 2015: £25.1 million and £26.9 million).

 

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

 

 

UK/

Europe

£000

Rest of the World

£000

Nine months ended

31 December 2015
Group

£000

 

 

 

 

Oil sales to external customers

24,753

-

24,753

Electricity sales to external customers

370

-

370

 

25,123

-

25,123

 

 

 

 

 

 

 

 

Segment operating loss

(56,408)

(241)

(56,649)

 

 

 

 

Interest expense (note 6)

(8,731)

-

(8,731)

Interest income (note 6)

105

-

105

Other finance income - net (note 6)

801

-

801

Loss before tax and discontinued operations

(64,223)

(241)

(64,474)

 

 

 

 

Other segment information

 

 

 

Capital expenditure - exploration and evaluation (note 11)

2,931

-

2,931

Capital expenditure - property, plant and equipment (note 12)

7,573

-

7,573

Depletion, depreciation and amortisation (note 12)

7,249

-

7,249

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

UK/

Europe

£000

 

 

Rest of the

World

£000

Year ended

31 March 2015
Group

£000

 

 

 

 

Oil sales to external customers

57,297

-

57,297

Electricity sales to external customers

863

-

863

 

58,160

-

58,160

 

 

 

 

 

 

 

 

Segment operating loss

(5,589)

(475)

(6,064)

 

 

 

 

Interest expense (note 6)

(12,582)

-

(12,582)

Interest income (note 6)

119

-

119

Other finance income - net (note 6)

3

-

3

Loss before tax and discontinued operations

(18,049)

(475)

(18,524)

 

 

 

 

 

Other segment information

 

 

 

Capital expenditure - exploration and evaluation (note 11)

77,784

-

77,784

Capital expenditure - property, plant and equipment

5,811

6

5,817

Depletion, depreciation and amortisation (note 10)

13,031

1

13,032

 

 

  

4 Basis of consolidation

The consolidated financial statements present the results of IGas Energy plc and its subsidiaries as if they formed a single entity. The financial statements of subsidiaries used in the preparation of consolidated financial statements are based on consistent accounting policies to the parent. All intercompany transactions and balances between Group companies, including unrealised profits arising from them, are eliminated in full. Where shares are issued to an Employee Benefit Trust, and the Company is the sponsoring entity, it is treated as an extension of the entity.

 

At 31 December 2015, the Group comprised the Company and entities controlled by IGas Energy plc (its subsidiaries). There have been no new subsidiaries acquired during the period.

 

5 Profit on disposal of oil and gas assets

Profit on disposal of oil and gas assets has arisen as a result of the farm-out agreement entered into between the Group and INEOS Upstream Limited ("INEOS") which completed on 7 May 2015. 

 

INEOS acquired a 50% interest in IGas' UK Onshore PEDLs 147, 184, 189 and 190 and a 60% interest in IGas' UK Onshore PEDLs 145, 193 and EXL 273, (the "Bowland Licences") in the North West of England. In addition, INEOS acquired IGas' entire working interest in the acreage held under PEDL 133 in Scotland. In the East Midlands, INEOS also acquired a 20% interest in in PEDLs 012 and 200. INEOS will assume operatorship of PEDLs 145 and 193 and EXL 273.  IGas will retain operatorship of all other Bowland Licences.

 

INEOS made a cash payment to IGas of £30.0 million on completion of the deal (resulting in a gain of £4.0 million) and will provide a fully funded future work programme of up to £138.0 million gross, of which IGas' share is expected to amount to approximately £65.0 million.

 

6 Other income

Included within other income is £4.9m relating to the release of deferred consideration.

 

The deferred consideration amount relates to the amount payable by a wholly owned subsidiary of the Group (acquired as part of the Dart acquisition), GP Energy Ltd, to its earlier joint venture partner in certain licences contingent upon various exploration and development success outcomes, which  has been risked at 10%. Should the relevant contingent outcomes materialise, the amounts are expected to fall due in two equal tranches on each of 31 July 2022 and 30 June 2024.

 

7 Finance income and costs 

 

 

9 months

ended

31 December

2015

£000

Year

ended

31 March

2015

£000

Finance income:

 

 

Interest on short-term deposits

105

 

119

 

Foreign exchange gains

51

-

Other interest

1

6

Gain on Bond buyback (note 12)

943

 

1,439

 

Gain on fair value of warrants

202

 

5,338

 

Finance income recognised in income statement

1,302

6,902

 

 

 

Finance expense:

 

 

Finance lease charges

-

 

7

 

Other interest

-

 

12

 

Interest on borrowings

8,731

 

12,563

 

Interest expense:

8,731

 

12,582

 

Foreign exchange loss

-

 

6,249

 

Unwinding of discount on provisions

396

 

531

 

Finance expense recognised in income statement

9,127

19,362

 

 

8 Taxation

Tax charge on (loss)/profit on ordinary activities

 

 

Nine months ended

31 December 2015

£000

Year ended

31 March 2015

£000

UK corporation tax:

 

 

Current tax on income for the year

1,253

 

1,085

 

Credit in relation to prior year

  (335)

 

-

 

Total current tax charge

918

1,085

Deferred tax:

 

 

Current year credit relating to the origination or reversal of temporary differences

(16,418)

 

(8,151)

 

Current year credit relating to the movement due to the tax rate changes

-

 

(14,200)

 

Credit in relation to prior year

(1,757)

(2,503)

Total deferred tax credit

(18,175)

(24,854)

Tax credit on profit on ordinary activities

(17,257)

(23,769)

 

With effect from 1 January 2015, the rate of supplementary charge has been reduced from 32% to 20%. This change has been reflected in the current period credit included in the deferred tax credit for the period relating to the group's ring-fence activities.

 

During the year legislation was enacted to reduce the main rate of corporation tax from 21% to 20% with effect from 1 April 2015. These rates are reflected in the calculation of deferred tax balances in respect of the group's non ring-fence activities.

Finance (No. 2) Act 2015 for which Royal Assent was received on 18 November 2015 further reduced the main rate of corporation tax to 19% effective for the periods starting from 1 April 2017 and to 18% for the periods from 1 April 2020. It is anticipated that the majority of the non-ring fence losses would be utilised prior to 2020 and it is considered that the impact of the change in the tax rate is immaterial to the Group's results.

 

9 Earnings per share (EPS)

 

Basic EPS amounts are based on the loss for the period after taxation attributable to ordinary equity holders of the parent of £44.8m (31 March 2015: £5.2m) and the weighted average number of ordinary shares outstanding during the period of 295.9 million (31 March 2015: 247.6 million).

 

Diluted EPS amounts are based on the loss after taxation attributable to the ordinary equity holders of the parent and the weighted average number of shares outstanding during the period plus the weighted average number of ordinary shares that would be issued on the conversion of all the potentially dilutive ordinary shares into ordinary shares, except where these are anti-dilutive.

 

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

 

 

Nine months ended

31 December 2015

 

Year ended

31 March 2015

 

Basic EPS - ordinary shares of 10p each (Pence)

(15.15p)

 

2.09p

 

Diluted EPS - ordinary shares of 10p each (Pence)

(15.15p)

 

2.05p

 

(Loss)/profit for the period/year attributable to equity holders of the parent - £000

(44,822)

 

5,245

 

Weighted average number of ordinary shares in the period/year - basic EPS

295,947,728

 

247,605,481

 

Weighted average number of ordinary shares in the period/year - diluted EPS

295,947,728

 

251,739,366

 

 

There are 23,305,330 potentially dilutive warrants and options over the ordinary shares at 31 December 2015 (31 March 2015: 11,757,913), 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.

 

 

 

10 Goodwill

 

 

31 December

2015

£000

31 March

2015

£000

Opening balance

44,028

 

39,227

 

Acquisitions

-

 

4,801

 

Impairments

(39,227)

 

-

 

 

4,801

44,028

 

Impairment testing of goodwill

Due to the change in the portfolio of assets resulting from the Dart acquisition, management has now assigned goodwill to the conventional and unconventional CGUs, the level at which goodwill is monitored for internal management purposes. The goodwill related to the conventional assets was impaired in full; the carrying value of goodwill as at 31 December 2015 relates entirely to the unconventional assets.

 

The Group tests goodwill for impairment annually or more frequently if there are indications that goodwill might be impaired. During the period ended 31 December 2015, the Group has undertaken an impairment test of goodwill due to the decline in the oil price. The Group assessed whether goodwill was impaired by calculating fair value less cost of disposal ("FVLCD") using discounted future cash flows of the cash generating unit and comparing this to the total carrying value of the cash generating unit including goodwill.

 

FVLCD calculations are based on cash flows expected to be generated by projected oil production profiles (including incremental production projects) up to the expected cessation of production dates. Future operating and capital expenditure were based on management's assessment, and production and reserve profiles were based on proved and probable reserves as determined by internal estimates.

 

The calculation of FVLCD includes the following key assumptions:

·   Future production volumes

·   Crude oil prices

·   Discount rate

 

Estimated future production volumes are based on detailed data for each of the Group's fields and take into account development plans for the fields which would be expected to be undertaken by a market participant.

 

The crude oil prices used are based on the forward oil price curve for three years followed by management's view of long term price ($75/bbl).

 

The post-tax discount rate in 2015 is 9.0 per cent. The period over which the Group has projected cash flows is in excess of five years and is considered to be appropriate by the Group as it is underpinned by estimates of reserves and resources.

 

It was determined that the carrying amount of goodwill is impaired by £39.2 million (31 March 2015: £nil). The fair value is a level 3 fair value measurement. There is no tax effect in respect of the impairment of goodwill.

 

During the interim period ended 30 September 2015, the Group recognised impairment in goodwill of £14.5 million.  The increase in the recorded impairment loss during the three months to period ended 31 December 2015 is triggered by reduced short-term oil prices.

 

11 Intangible exploration and evaluation assets

 

 

 

 

Period ended

31 December  2015

 £'000

 

Year ended

31 March 2015

 £'000

At 1 April

151,615

 

90,997

 

Additions

2,931

 

14,235

 

Farm-out

(28,252)

 

-

 

Acquisitions

-

 

61,175

 

Transfer from intangible assets

-

 

2,374

 

Transfers to assets held for sale

-

 

(1,903)

 

Changes in decommissioning

-

 

143

 

Amounts written off*

(12,900)

 

(15,406)

 

At 31 December/31 March

113,394

 

151,615

 

* Amounts written off relate to impairment of UK-conventional E&E assets of £5.9 million (31 March 2015: £15.2 million) and £7.0 million of unconventional E&E assets written off (31 March2015: £0.2 million).

                                                                 

Under the terms of the Secured Bond agreement, the Bondholders have a fixed and floating charge over these assets.

 

 

Impairment of exploration and evaluation assets

Due to the continued decline in the oil price, assets with conventional oil resources were tested for impairment. As a result of these tests, there was impairment of £5.9 million pre-tax (£2.9 million post-tax) in the UK-conventional E&E assets (31 March 2015: £15.2 million pre-tax (£6.2 million post-tax)).

 

In calculating this impairment, management used risked contingent resource estimates, internal cost estimates and a range of assumptions with regard to future oil prices. The recoverable amount was based on management's estimate of the FVLCD.  The fair value is a level 3 fair value measurement.

 

 

Trigger for  impairment

Nine months ended  31 December 2015 impairment   £000

 

Year ended   31 March 2015 impairment  £000

Post tax discount rate  assumption

Oil price  short-term price assumption

   Oil  price  long-term price assumption

UK Conventional

a

 

5,884

 

15,182

 

b

 

c

 

d

 

 

5,884

 

15,182

 

 

 

 

Associated deferred tax credit

 

(2,942)

 

(8,963)

 

 

 

 

Total impairment after tax

 

2,942

 

6,219

 

 

 

 

 

a.         Reduction in crude oil commodity forward curve and long-term price

b.         31 December 2015 (9%), 31 March 2015 (10%) 

c.         31 December  2015 (3 year forward curve), 31 March 2015 (5 year forward curve)

d.         31 December  2015 ($75/bbl), 31 March 2015 ($85/bbl)

 

Sensitivity of changes in assumptions

As discussed above the principal assumptions are recoverable future production and resources and the estimated price per boe of risked resource.  A 10% boepd reduction in production would result in a full impairment of UK-conventional E&E assets.  An average US$10.0/boe reduction in the estimated price per boe of production would result in a full impairment of UK-conventional E&E assets.

 

 

12 Property, plant and equipment

 

Nine months ended 31 December 2015

 

 

Year ended 31 March 2015

 

Oil and gas

 assets

£'000

Other fixed assets

 £'000

Total

£'000

 

 

Oil and gas assets

 £'000

Other fixed assets

 £'000

Total

£'000

Cost

 

 

 

 

 

 

 

 

At 1 April

144,230

4,318

148,548

 

 

139,163

3,699

142,862

Additions

7,480

93

7,573

 

 

5,069

686

5,755

Disposals

(383)

(555)

(938)

 

 

-

(128)

(128)

Acquisitions

-

-

-

 

 

-

338

338

Transfers to assets held for sale

-

-

-

 

 

-

(277)

(277)

Changes in decommissioning

(3,893)

-

(3,893)

 

 

(2)

-

(2)

Write off

-

(118)

(118)

 

 

-

-

-

Foreign exchange

-

(7)

(7)

 

 

-

-

-

At 31 December/31 March

147,434

3,731

151,165

 

 

144,230

4,318

148,548

Depreciation and Impairment

 

 

 

 

 

 

 

 

At 1 April

42,524

1,710

44,234

 

 

25,829

1,555

27,384

Charge for the period/year

6,956

293

7,249*

 

 

12,749

283

13,032

Disposals

(383)

(440)

(823)

 

 

-

(128)

(128)

Impairment

17,720

-

17,720

 

 

3,946

-

3,946

Write off

-

(118)

(118)

 

 

-

-

-

Foreign exchange

(2)

(6)

(8)

 

 

-

-

-

At 31 December/31 March

66,815

1,439

68,254

 

 

42,524

1,710

44,234

NBV at 31 December/31 March

80,619

2,292

82,911

 

 

101,706

2,608

104,314

* Charge for the period includes £15 thousand relating to capitalised equipment used for E&E not in the income statement

Under the terms of the Secured Bond agreement, the Bondholders have a fixed and floating charge over these assets.

 

 

 

Impairment of oil and gas properties

Due to the continued decline in the oil price, oil and gas properties were tested for impairment. As a result, an impairment charge of £17.7 million pre-tax (£8.8 million post-tax) was recognised in the period to 31 December 2015 (Year to 31 March 2015: £3.9 million pre-tax (£1.6 million post-tax)). The impairment charge and recoverable amount of the CGUs where impairment was charged are set out below.

 

Previously, IGas has identified its CGUs based on the individual fields, or pools of fields where there is shared infrastructure such as a common processing facility.  During the period, management has reassessed its CGUs for impairment testing due to the restructuring of the operations of the Group which include changes in the way the Group operates, manages and monitors its oil and gas properties.  Management concluded that the 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 recoverable values of CGUs were calculated based on management's estimate of the FVLCD. The fair value is a level 3 fair value measurement.

 

During the interim period ended 30 September 2015, the Group recognised impairment in oil and gas properties of £10.1 million.  The increase in the recorded impairment loss during the three months to period ended 31 December 2015 is triggered by reduced short-term prices.

                       

 

Trigger for
 impairment

Nine months ended

 31 December

2015

impairment

£000

Year ended  

  31 March

 2015

impairment

£000

Post tax discount rate assumption

Oil price 
short-term price assumption

Oil price long term price assumption

North

a

2,540

 

1,381

 

b

 

c

 

d

 

South

a

13,303

 

2,565

 

b

 

c

 

d

 

Scotland

a

1,877

 

-

 

b

 

c

 

d

 

Total impairment before tax

 

17,720

 

3,946

 

 

 

 

Associated deferred tax credit

 

(8,860)

 

(2,330)

 

 

 

 

Total impairment after tax

 

8,860

 

1,616

 

 

 

 

 

a.         Reduction in crude oil commodity forward curve and long-term price assumption

b.         31 December 2015 (9%), 31 March 2015 (10%)

c.         31 December 2015 (3 year forward curve), 31 March 2015 (5 year forward curve)

d.         31 December 2015 ($75/bbl), 31 March 2015 ($85/bbl)

 

 

Sensitivity of changes in assumptions

As discussed above the principal assumptions are recoverable future production and resources and the estimated dollar per boe of risked resource.  A 10% boepd reduction in production would result in a further impairment of £15.7 million.  An average US$10.0/boe reduction in the estimated dollar per boe of production would result in a further impairment of £29.9 million.

 

13 Borrowings

 

 

31 December 2015

 

31 March 2015

 

 

Within

1 year

£000

Greater

than 1 year

£000

Total

£000

Within

 1 year

£000

Greater

than 1 year

£000

Total

£000

Bonds - secured*

4,819

 

80,125

 

84,944

 

5,310

 

83,294

 

88,604

 

Bonds - unsecured*

-

 

17,935

 

17,935

 

-

 

18,935

 

18,935

 

Total

4,819

98,060

102,879

5,310

102,229

107,539

 

 

*      Additional transaction costs relating to the debt of £1.0 million were incurred during the period (31 March 2015: nil) and have been netted off against the liability.

 

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

 

 

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

 

During the period to 31 December 2015, the Company repurchased a total of 5,414,747 secured bonds resulting in an aggregate gain of £0.5 million (Year ended 31 March 2015: 14,667,530 secured bonds resulting in a gain of £1.3m). 

 

During the period to 31 December 2015, the Company repurchased a total of 1,600,000 unsecured bonds resulting in an aggregate gain of £0.4 million (Year ended 31 March 2015: 1,000,000 unsecured bonds resulting in a gain of £0.1million).

 

 

14  Employee share plans - equity settled

The Group continues to recognise the Long Term Incentive Plan (LTIP) and the Value Creation Plan (VCP) was replaced during the period by the Executive Directors' Retention Plan (EDRP). Additionally, management were granted share options under the new Management Retention Plan (MRP). The EDRP and MRP, which are the Group's new share-based payment arrangements in the period are explained below.

 

Management Retention Plan ("MRP")

In December 2015, the Group adopted a new share-based payment scheme, the Management Retention Plan ("MRP"). Under the MRP, participants are granted nil cost options which vest and become exercisable on the first anniversary of grant subject to the Directors' continued employment and to a one year holding period following the date of vesting.

 

Employees were granted 7,143,610 options in the MRP in lieu of waived options granted under the 2011 Long Term Incentive Plan (LTIP) and 2015 cash bonuses. The options designated by the Group as replacement awards were accounted for as a modification of the original scheme and were valued at grant date and the options awarded in lieu of cash bonuses were measured with reference to the fair value of the services received.

 

The fair value of the cancelled awards was re-measured at the replacement date based on the Monte Carlo valuation model.  The key inputs into the model were:  replacement date share price of £0.14, threshold price of between £1.351 and £1.664, a risk free interest rate of between 0.37% and 0.42% and an implied share price volatility of between 73% and 86%.  It was also assumed that no dividends would be paid during the life of the options. This resulted in an incremental fair value of £0.17 million.

 

The MRPs outstanding at 31 December 2015 had both a weighted average remaining contractual life and maximum term remaining of 7.9 years. The fair value of the replacement awards granted under the MRP was the grant date share price.

 

The total charge for the year was £0.14 million. Of this amount, £0.05 million was capitalised and £0.09 million was charged to the Income Statement.

 

Executive Director Retention Plan ("EDRP")

In July 2015, the Group adopted a new share-based payment scheme, the Executive Director Retention Plan ("EDRP"). Under the EDRP, participants are granted nil cost options which vest and become exercisable on the first anniversary of grant subject to the Directors' continued employment and to a one year holding period following the date of vesting.

 

Executives were granted 6,500,000 options in the EDRP in lieu of waived options granted under the 2011 Long Term Incentive Plan (LTIP) and the Value Creation Plan (VCP). The options have been designated by the Group as replacement awards at grant date and were accounted for as a modification of the original scheme.

 

The fair value of the cancelled awards was re-measured at the replacement date based on the Monte Carlo valuation model.  The fair value of waived options was based on the share price at grant date of £0.2475.  The fair value of replacement awards was based on the Monte Carlo valuation model.  The key inputs into the model were: replacement date share price of £0.2475, threshold price of between £0.945 and £1.664, a risk free interest rate of between 0.49% and 0.60% and an implied share price volatility of between 70% and 78%.  It was also assumed that no dividends would be paid during the life of the options. This resulted in an incremental fair value of £1.5 million.

 

The EDRPs outstanding at 31 December 2015 had both a weighted average remaining contractual life and maximum term remaining of 7.5 years. The fair value of the replacement awards granted under the EDRP was the grant date share price.

 

The total charge for the year was £0.7 million. Of this amount, £0.3 million was capitalised and £0.4 million was charged to the Income Statement.

 

15 Assets classified as held for sale and discontinued operations

Certain assets acquired as part of the Dart Acquisition, namely the Rest of the World segment principally consisting of Australian and Indonesian assets, were acquired with the intention to divest all business and activities in all these countries.  The sale of these assets completed in October and November 2015, which resulted in a gain of £1.4 million.  There was £0.07 million tax charged on this amount.

 

The gain for the period before tax in respect of discontinued operations was £2.4 million (31 March 2015: a loss of £0.1 million). Other than the tax on disposal described above, there is no tax charged on this amount

 

16 Subsequent events

Issued shares

On 22 January 2016, the Company issued 757,096 Ordinary 10p shares in relation to the Group's SIP scheme.


17 Preliminary results announced

The Annual Report and Accounts 2015 will be posted to shareholders in due course and will be available on the Company's website

(www.igasplc.com)

 

 

 

 

 


This information is provided by RNS
The company news service from the London Stock Exchange
 
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