Final Results for the Year Ended 31 December 2018

RNS Number : 0678V

Independent Oil & Gas PLC

04 April 2019

 

4 April 2019

Independent Oil and Gas plc

("IOG" or the "Company")

Final Results for the Year Ended 31 December 2018

Independent Oil and Gas plc (AIM: IOG.L), the development and production focused oil and gas company, is pleased to announce its results for the Year Ended 31 December 2018.

Operational highlights:

·      Completion of the transformational acquisition of 100% operated ownership of the Thames Pipeline ('PL370') and the demonstration of its viability to provide a stable export route for the Company's 100% owned gas assets straight to the UK market and National Transport System ('NTS').

o  Offshore site and route survey along PL370, all proposed platform locations and intra-field connecting pipelines completed in May 2018;

o  Completion of the Intelligent Pigging Programme ('IPP') confirmed excellent condition of the PL370 infrastructure; and

o  Completion of tethered pig inspection together with 150-bar pressure hydrotest confirms PL370 economic life good for the next two decades and condition 'as new' confirmed by analysis undertaken by Oilfield Testing Services.

·      Significant operational progress towards delivering IOG's SNS gas hub strategy.

o  Environmental Impact Assessment ('EIA') submitted for the Blythe Hub in January 2018 and the Vulcan Satellites Hub in April 2018;

o  Platform fabrication Front End Engineering and Design ('FEED') undertaken by the Heerema Fabrication Group; and

o  FEED completed by Wood for the Subsea, Umbilicals, Risers and Flowlines ('SURF') scope of work on the Phase 1 development

·      Strengthened portfolio around PL370 with the award of 100% ownership of three new licence areas, during the UKCS 30th Licensing Round acquiring Goddard, Harvey SE and Abbeydale. Goddard adds 108 BCF of independently assessed 2C Contingent Resources of gas and 73 BCF Best Case Prospective Gas Resources at Goddard.

·      Core Project comprises Blythe and Vulcan Satellites Hub with Goddard 2C Contingent Resources.

·      3D seismic reprocessing over the Harvey structure completed and re-interpreted leading to revised management estimate of Best-Case Prospective Resources of 129 BCF.

o  Harvey appraisal well planned to spud in 2019, with the potential to significantly increase the Company's resource base.

Financial highlights:

·      Additional £10 million convertible loan facility signed with London Oil & Gas Limited ('LOG') on 21 February 2018, with a further £15 million loan (not convertible) secured from LOG on 13 September 2018. As at 31 December 2018, £7.85 million remains undrawn on the £15 million facility. A further £3.925 million was drawn in January 2019 and £3.925 million outstanding remains.

·      Cash balance at period end of £0.70 million.

·      Post tax loss for the year was £5.64 million.

·      Continue to progress funding process for Final Investment Decision ('FID') on Phase 1 of the core development, including debt and equity discussions as well as an announced farm-out process to bring in an industrial partner.

·      FID targeted for 1H 2019, with first gas targeted at the start of Q1 2021.

Outlook:

·      Progress ongoing farm-out discussions on Core Project, with decision expected in 1H 2019 between industrial or capital markets funding to FID and development and SNS portfolio

·      Drill appraisal well at Harvey, expected to spud in mid-2019

·      Progress work on a field development plan for the Goddard gas field

·      Continue to develop and expand the asset base via license applications and M&A activity

·      Post period end, on 1 April 2019 the Company announced a conditional Fundraising comprising a Placing to raise £16.6 million, a Subscription to raise £0.325 million and an Open Offer to raise up to approximately £2 million

Andrew Hockey, CEO of IOG, said:

"I'm pleased to report that 2018 was a year of progress across our SNS portfolio. We continued to advance development plans for our Core Project and wider SNS portfolio. The purchase of the Thames Pipeline in April 2018 and its subsequent recommissioning has also been key to unlocking the value of our SNS portfolio, providing us with a secure, low-cost export route to bring our gas onshore at the Bacton Terminal.

"Looking forward, two key catalysts to value growth should come to fruition in 2019. We look forward to concluding our Core Project development discussions and expect to be in a position to select our preferred party to deliver either a farm-in or capital markets solution to reach FID on the Core Project in 1H 2019. The second near term value catalyst is the high-impact Harvey appraisal well which could significantly enhance the value of our SNS development. In addition to this we [expect to submit / will continue to progress] our Field Development Plan for Goddard which will add significant incremental value to our Core Project."

-ENDS-

The information communicated in this announcement is inside information for the purposes of Article 7 of Regulation 596/2014.

Enquiries:

Independent Oil and Gas plc Andrew Hockey (CEO) James Chance (CFO)	[phone]
finnCap Ltd Christopher Raggett / Anthony Adams (Corporate Finance)	[phone]
Peel Hunt LLP Richard Crichton David McKeown	[phone]
Vigo Communications Patrick d'Ancona Chris McMahon Simon Woods	[phone]

Chief Executive's Review

I am pleased to be able to report progress on all fronts in 2018 for Independent Oil and Gas plc (the 'Company') and the Group ('IOG') across our UK Southern North Sea ('SNS') portfolio.  We continue to move toward our goal of bringing indigenous UK gas into the import-dependent UK market safely and at a low unit cost to generate material cash flows for the Group and attractive returns for our shareholders.

During the year we have successfully added to our portfolio at low cost through successful awards made in the UK 30th Offshore Licensing Round. On 23 May 2018 IOG was offered three new licences containing the Goddard discovery, the south eastern Harvey structure and the Abbeydale discovery. Our core gas portfolio now comprises 302 BCF of Proven and Probable ('2P') Reserves at the Blythe Hub (67 BCF)¹ and the Vulcan Satellites Hub (235 BCF)1, 108 BCF of Contingent 2C resources at Goddard with incremental upside of an additional 73BCF of Best Estimate Prospective Resources at Goddard and a further 129 BCF Gross Best Estimate Prospective Resources at Harvey, our exciting appraisal opportunity.  The combined development of core and incremental upside is very valuable, targeting total daily production of approximately 230mmcfd and an NPV10 of £688million as at year end 2018.

Throughout the year our development team has progressed the necessary engineering studies and benchmarked our capital and operating costs versus the market, such that we have been able to quantify the cost base associated with developing our portfolio and then to submit a revised Field Development Plan ('FDP') to the Oil and Gas Authority ('OGA') in October 2018. This Field Development Plan envisages a phased approach to our core portfolio. Phase 1 comprises the Blythe Hub (the Blythe and Elgood Fields) and the Southwark Field from the Vulcan Satellites Hub. The Nailsworth and Elland fields from the Vulcan Satellites form part of Phase 2 of the development.  We plan to develop Phase 1 via two simple unmanned wellhead platforms at Blythe and Southwark and a subsea tieback at Elgood, with up to five long reach wells to be drilled. Initial analysis of the Goddard discovery acquired in the 30^th UKCS Licensing Round indicates that the 108 BCF of 2C Contingent Resources recognised within it may be included in the Core Project development. Final Investment Decision ('FID') is planned within 1H 2019 and First Gas is targeted for the start of 2021, from the Southwark field. In early 2018 an offshore survey campaign acquired all necessary environmental and survey data for platform locations and connecting pipelines for Phase 1 and 2 core developments, excluding Goddard, and external survey data for the Thames Pipeline. A second campaign in November 2018 acquired the necessary geotechnical data for the Phase 1 development and for the Harvey appraisal well. At Harvey, PSDM reprocessing of 3D seismic data in the first half of 2018 and subsequent remapping in 3Q 2018 improved our understanding of the incremental upside and we are seeking to appraise this structure at the earliest opportunity having committed to the OGA to drill a well by the end of 2019. In the Harvey appraisal success case we would seek to incorporate this asset into Phase 1 of the core development. On 11th February 2019 the Company allowed the Skipper Licence to expire in order to focus our portfolio fully in the UK Southern North Sea Gas Basin.

The key to unlocking the value of our gas assets is the recommissioned Thames Pipeline ('PL370').  This 24" gas line was decommissioned in 2015 and bringing it back into operation will provide us with a low-cost export route via which we can bring our gas to market at Bacton Terminal on the North Norfolk coast.  In April 2018, we completed a Sales and Purchase Agreement ('SPA') with PL370 owners Perenco UK Limited, Tullow Oil SK Limited and Centrica to purchase the 90 km offshore line for a nominal sum and we have worked closely with the OGA, the Department of Business, Energy & Industrial Strategy ('BEIS') and the Health & Safety Executive ('HSE') to become pipeline owner and operator. As part of our offshore surveys campaign, the exterior of PL370 was surveyed and an extensive pigging programme was executed to demonstrate its internal integrity in the first half of 2018. In view of equipment failure on the intelligent pig run in May, a further crawler pig run was executed in September, demonstrating the viability of the shoreward end of the line. A 150 bar 24 hour hydrotest in September demonstrated the capability of the line to accommodate up to 550 mmcfd, providing us with ample capacity for our own portfolio, for any add-on opportunities we deliver and for third-party business we may attract.  Progress on the assessment and refurbishment of the Bacton facilities, where the Thames Pipeline comes ashore, will commence in 1H 2020.

In support of our subsurface and engineering efforts the Company has been busy engaging with the supply chain who we hope will be highly engaged partners in developing our gas hubs.  To date, Letters of Intent have been signed with Maersk (development drilling), Halliburton (well services), Offshore Design Engineering ('ODE') (duty holder, operations and maintenance contractor), Heerema Fabrication Group ('Heerema' - offshore platform fabrication) and Allseas (subsea and pipeline fabrication and installation contractors).

We are also pleased that in December 2018 the OGA granted an extension of the Blythe licence for a further year and confirmed the waiver of the drill or drop commitment at Elgood allowing the Licence to pass into its second term.  We look forward to working ever closer with the OGA as we seek to bring our SNS gas assets into production.

Successful development execution will require firm funding to be in place at FID and the Company has been hard at work to deliver this. Operational progress in 2018 was due in large part to the funding provided to us in the form of a £10 million convertible loan in February 2016 by our largest stakeholder, London Oil and Gas Ltd. ('LOG') at a conversion price of 8p/share, in February 2018 a second convertible loan of £10 million at a conversion price of 19p/share, and in September 2018 a third non-convertible loan of £15 million backed by 20 million warrants at a strike price of 32.16p was agreed. In November 2018 the decision was taken not to attempt development funding through the equity capital markets and a Norwegian bond owing to volatile market conditions. At time of writing the company is pursuing multiple funding strands including a well progressed farm-out process, funding via the capital markets and has announced a £16.6 million Placing, £0.325 million Subscription and an approximate £2 million intended Open Offer (together 'Fundraising') on 1 April 2019 to secure FID and ensure sufficient funds are available for the drilling of the Harvey well at the earliest opportunity. The Company notes that at time of writing LOG has been placed into administration as has London Capital and Finance ('LCAF'), from whom LOG secured loan finance to provide IOG's funding above. The Company has engaged with LOG and LCAF administrators who have agreed to restructure the LOG loans and have stated publicly that they will support IOG and the LOG/LCAF administration process will have no impact on the Company's business. The Company's independently assessed 2P reserves of 303 BCF, equivalent to 54 MMBOE, along with 108BCF of 2C Contingent Resources at Goddard and 202 BCF of Prospective Resources at Harvey and Goddard provides a solid footing to secure an optimal development funding package for the portfolio during 2019.

For tangible progress to be made toward development, the Company obviously needs a high-quality team of individuals and this year we have increased our capability at all levels of the organisation. In February, Andrew Hay left the Board and we wish him well. Also, in February, Mark Routh, CEO and Interim Chairman became Non-Executive Chairman of the Board. I succeeded Mark as Chief Executive Officer having previously been Deputy CEO. In April, Mark Hughes joined the Board as Chief Operating Officer bringing valuable Southern North Sea development experience with him. In July, we welcomed Fiona MacAulay to the Board of Directors as Senior Independent Non-Executive Director.  In parallel with strengthening the Board, the Executive Management Team was strengthened by the addition of Rupert Newall as Head of Corporate Finance in November 2018. At year end, Mark Routh stepped down from the Board and Fiona MacAulay took over as Non-Executive Chair. I would like to thank Mark personally for his wisdom and competence and wish him well for the future. Esa Ikaheimonen was appointed Non-Executive Director and Chair of the Audit Committee on 14 March 2019.

In conclusion, I am pleased to report that the Company continues to move toward cash flow generation from our core SNS gas portfolio and toward unlocking valuable incremental upside at our Harvey appraisal opportunity with genuine intent and focus.

I thank all shareholders for their support throughout the year and look forward to further progress in 2019

Andrew Hockey

Chief Executive Officer

4 April 2019

--_________________________

[1] Management Adjustment Estimates based on ERC Equipoise CPR, October 2017

Operational Update

Thames Pipeline

The acquisition of the Thames Pipeline from Perenco UK Limited, Tullow Oil SK Limited and Spirit Energy Resources Limited (Sale and Purchase Agreement, SPA1) completed on 16 April 2018.

On this date, the pre-acquisition costs for the Thames Pipeline and associated onshore Bacton Facility, previously held as a prepayment in the books of the parent company, IOG plc, were brought across to IOG Infrastructure Limited. Also, on this date, the Initial Thames Pipeline Decommissioning Security Amount of £500k was paid to Perenco UK. IOG Infrastructure Limited is the owner, user, holder and operator of the pipeline under the Pipeline Works Authority ('PWA').

The MV Fugro Galaxy mobilised in late January 2018 and as part of its work programme carried out surveys along the Thames Pipeline.

Preparation for the Intelligent Pigging Programme ('IPP') commenced on 20 February 2018 with onshore mechanical preparation work at the Bacton Terminal. The main IPP work took place in May 2018 and early June 2018. Three 12m pipeline sections were cut 60km offshore and retrieved to surface and indicated the pipeline to be in extremely good condition. Two successful pipeline pressure tests confirmed pipeline integrity and initial 60km gauge pigging runs from Bacton to the offshore tie-in point were successfully executed. The initial IPP run gathered insufficient data due to technical malfunction with the pig and an alternative strategy was planned and presented to the HSE.

In September 2018, a crawler pig run was completed from Bacton to c.1km offshore demonstrating the viability of this nearshore element of the line and the viability of the whole line and thus this export route was then confirmed by a 150 bar 24 hour hydrotest completed on 23 September 2019.  Progress continued through 2H 2018 toward signing the Sales and Purchase Agreement (SPA2) for the Thames Reception Facility with owners Perenco, Tullow and Spirit Energy.

Other capital costs associated with the Thames Pipeline acquisition include potential tie-in studies (offshore à onshore), the Crown Estate lease associated with the 12-mile onshore boundary (of which the Thames Pipeline lies in situ), capitalised G&A and other directly attributable expenses.

Blythe

The Blythe gas discovery in the Rotliegend Leman Formation, straddles Blocks 48/22b and 48/23a in the SNS in licence P1736.  IOGNSL has 100% working interest in and is operator. Blythe is planned to be developed with a single well tied back to the Thames Pipeline via an unmanned platform ('NUI').

The MV Fugro Galaxy mobilised in late January 2018 and as part of its work programme carried out surveys across the Blythe Hub (Blythe and Elgood fields) in support of field development. At Blythe this work included site surveys for platform location and pipeline route surveys to the tie-in point at the Thames pipeline, and environmental sampling. The Environmental Impact Assessment ('EIA') for the Blythe Hub was submitted on 31 January 2018 in line with milestones agreed with the UK Oil & Gas Authority ('OGA').

During development engineering studies in 1H 2018, it was decided to split the development into two Phases with Phase 1 development comprising Blythe, Elgood and Southwark and Phase 2 to include Nailsworth and Elland.

The Phase 1 Field Development Plan comprising Blythe, Elgood and Southwark was submitted to the OGA in August 2018 and following bilateral meetings was resubmitted in late October 2018 taking account of OGA comments. At year end, FID and subsequent EIA and FDP approval was expected to occur in late Q1 2019 with first gas from Southwark 20 months later in Q4 2020 and Blythe first gas in early Q1 2021, subject to project financing.

In July 2018 Wood carried out FEED studies to assess costs and schedule for the tie-in lines to the Thames Pipeline for the Phase 1 development including Blythe. In November 2018, offshore geotechnical surveys for the Blythe Platform were completed alongside geotechnical surveys at Southwark and at Harvey, where a geophysical site survey was also executed. Heerema also made progress with the FEED studies for the Blythe Platform in 2H 2018.

In December 2018 the initial Term of Licence P1736 containing Blythe was extended to 31 December 2019 subject to the condition that an FDP capable of approval would be received by the OGA by 30 June 2019 and FID would occur by 30 September 2019.

Elgood

IOGNSL has 100% working interest in and is operator of Licence P2260 (Block 48/22c), which was awarded in the 28th Licensing Round.  The licence, which lies immediately to the north-west of the Blythe licence, contains the Elgood discovery in the Rotliegend Leman Sandstone.

Elgood is planned to be developed with a single well tied back subsea to the Thames Pipeline via a NUI at Blythe. The MV Fugro Galaxy mobilised in late January 2018 and as part of its work programme carried out surveys across the Blythe Hub (Blythe and Elgood fields) in support of field development. At Elgood this work included site surveys for pipeline route surveys to the tie-in point at Blythe and environmental sampling. The EIA for the Blythe Hub was submitted on 31 January 2018 in line with milestones agreed with the OGA.

The Phase 1 Field Development Plan comprising Blythe, Elgood and Southwark was submitted to the OGA in August 2018 and following bilateral meetings was resubmitted in late October 2018 taking account of OGA comments. At year end, FID and subsequent EIA and FDP approval was expected to occur at end Q1 2019 with first gas at Southwark 20 months later in Q4 2020 and Elgood first gas in Q2 2021 subject to project financing.

In July 2018 Wood carried out FEED studies to assess costs and schedule for the tie-in lines to the Thames Pipeline for the Phase 1 development including Elgood.

In January 2019 IOG received notification from the OGA that the drill or drop commitment for the initial Term of Elgood Licence P2260 had been waived and the Licence could proceed into the Second Term, subject to the condition that an FDP capable of approval would be received by the OGA by 30 June 2019 and FID would occur by 30 September 2019.

Vulcan Satellites - Southwark, Elland and Nailsworth

The Vulcan Satellites are planned to be developed with NUIs at Southwark (three wells), Elland (two wells) and Nailsworth (three wells) to the Thames Pipeline. All three satellites have their reservoirs in the Rotliegend Leman Sandstone.

The MV Fugro Galaxy mobilised in late January 2018 and as part of its work programme carried out surveys across the Vulcan Satellites Hub (Southwark, Nailsworth and Elland fields) in support of field development. This work included site surveys for platform locations and pipeline route surveys to the tie-in point at the Thames Pipeline and environmental sampling. The EIA for the Vulcan Satellites Hub was submitted in April 2018 in line with milestones agreed with the OGA.

During development engineering studies in 1H 2018 it was decided to include Southwark as part of a Phase 1 development comprising Blythe, Elgood and Southwark.

The Phase 1 Field Development Plan comprising Blythe, Elgood and Southwark was submitted to the OGA in August 2018 and following bilateral meetings was resubmitted in late October 2018 taking account of OGA comments. At year end, FID and subsequent EIA and FDP approval was expected to occur at end Q1 2019 with first gas at Southwark 20 months later in Q4 2020, subject to project financing.

In July 2018, Wood carried out FEED studies to assess costs and schedule for the tie-in lines to the Thames Pipeline for the Phase 1 development including Southwark. In November 2018, offshore geotechnical surveys for the Southwark platform were completed alongside geotechnical surveys at Blythe and at Harvey, where a geophysical site survey was also executed. Heerema made progress with the FEED studies for the Southwark platform in 2H 2018 and FEED works were also completed by ODE for the refurbishment at the Bacton Terminal.

Elland and Nailsworth, the other two Vulcan Satellites, will be part of Phase 2 of the development.

Given the development deferral of both Elland and Nailsworth (Phase 2), most current year 2018 fixed asset additions have been attributable to the Southwark development area.

Further to the Vulcan East suspended well decommissioning paper, prepared by Acona in April 2015, IOGUKL believes that the abandonment provision of £3.60 million continues to represent a reasonable cost estimate.  Decommissioning of this suspended well has been targeted as part of the Vulcan Satellites development program; however, as this particular well is not assigned for development, this activity remains uncertain and may be further deferred subject to agreement with the OGA.

Harvey

IOGNSL has a 100% working interest in Licence P2085 to the east of Blythe (Blocks 48/23c & 48/24b) which was awarded in the 27th Licensing Round and in Licence P2441 awarded in the 30th Licensing Round. These blocks contain 100% of the Harvey Structure with the reservoir targeted in the Rotliegend Leman Sandstone Formation.

In the first half of 2018 work on P2085 and adjacent open areas focused on reprocessing of existing 3D seismic data to Pre-Stack Depth Migration level with Schlumberger WesternGeco to support the selection of a well location for the firm Harvey well committed on P2085 in late 2017.

Following the completion of seismic reprocessing in July 2018, the dataset was reinterpreted and remapped. This remapping led to a new volumetric assessment of gross unrisked Prospective Resources (as estimated by management) at Harvey of 85-129-199BCF (Low-Mid-Best Estimate) versus the 2017 CPR estimate of 45-114-286BCF. Management's assessment of Geological Chance of Success at Harvey is 63%. The gross volumes were secured by IOG with the award of Licence P2441 (SE Harvey) in the 30th UKCS Offshore Licensing Round, with licence commencement on 1 October 2018. Under the licence a firm commitment was made to the Oil and Gas Authority ("OGA") to reprocess 87km2 of 3D seismic to PSDM and drill a well to 2,345m TD or drop the Licence.

In support of the Licence P2085 firm well commitment a Letter of Intent was signed with Ensco for the Ensco 72 Jack-Up Drilling Unit for the drilling of a Harvey appraisal well in 2019 to be spud before 20 September 2019. Halliburton are under LOI to provide well services and Fraser Well Management were identified as drilling operator. Technical work proceeded to the point where a well location was selected for the Harvey well in October 2018 and permitting and planning to drill the well in 1Q 2019 subject to funding were advanced.

All costs associated with developing the Harvey SE extension are now incorporated within the main Harvey licence P2085, as determined by one single field area. Management will continue to account for any minor licence admin costs (licence fee, OGA levy etc.) associated with P2441 separately.

Resources in the other discoveries and prospects on the Harvey area blocks will be subject to evaluation and appraisal following the results of the 3D seismic reprocessing.

Goddard

On 23 May 2018, IOG was offered Blocks 48/11c & 48/12b in the 30th UKCS Licensing Round and accepted the offer as Provisional Licence P2438 which contains Goddard, hitherto known as Glein, a dormant gas discovery.

Licence P2438 formally commenced on 1 October 2018. Under the licence a firm commitment was made to the Oil and Gas Authority ("OGA") to reprocess 175 km2 of 3D seismic to PSDM and drill an appraisal well on Goddard to 3,140m TD within three years.

In the second half of 2018 work on Goddard focused on securing access to 3D seismic data processed to PSDM level across the Goddard licence. This dataset was secured from a previous operator. On licence commencement it was decided to submit the work done to date to ERC Equipoise, as the Competent Person, for audit purposes. Based on the 30th Round Licence Application document, management estimates of Contingent Resources were 1C/2C/3C 45/189/396BCF. ERC Equipoise completed their work and assessed gross unrisked 1C/2C/3C Contingent Resources of 54.3/107.8/202.8 BCF and Low/Best/High gross unrisked prospective gas resources are 41.8/73.0/121.4 BCF. The CPR assesses the geological chance of success of the prospective gas resources at 48%. The chance of development of Goddard is estimated by ERC Equipoise as being 75%.

In the light of the relative maturity of Goddard's Contingent Resources it was decided in early 2019 to commence Goddard FDP planning and to include Goddard in Phase 1 Core development planning.

Abbeydale

On 23 May 2018, IOG was offered Block 53/1b in the 30th UKCS Licensing Round and accepted the offer as Provisional Licence P2442 which contains the Abbeydale dormant gas discovery, hitherto known as Aberdonia, which was discovered in 1996.  Licence P2442 formally commenced on 1 October 2018. Under the four-year Licence, a commitment was made to reprocess 150 km2 3D seismic data to PSDM and drill a well to 1,960m TD or drop the licence. 2H 2018 work focused on securing prices for 3D reprocessing.

Management estimates contingent resources on Abbeydale are 1C/2C/3C 5/11/24 BCF. The new 3D seismic work programme is expected to increase these estimates to more commercial levels with a view to tying into IOG's Thames Pipeline as the export route.

Skipper

The Skipper licence, P1609, was formally relinquished on 11 February 2019, as determined by the OGA.

Asset Acquisitions

The Company continues to assess the potential for the acquisition of a number of assets, particularly those already in production, to support the wider development and growth of the business.

Key Performance Indicators

The Group's main business is the acquisition and exploitation of oil and gas acreage.  Non-financial performance is tracked through the accumulation of licence interests followed by the successful discovery and exploitation of oil and gas reserves as indicated through prospective, contingent and proved reserves inventories.  Financial performance is tracked through the raising of finance to fund proposed programmes and the control of costs against budgets.

Principal Risks and Uncertainties

The Group operates in the oil and gas industry, an environment subject to a range of inherent risks and uncertainties.  Being at an early stage the prime risks to which the Group is subject are the access to sufficient funding to continue its operations, the status and financing of its partners, changes in cost and reserves estimates for its assets, changes in forward commodity prices and the successful development of its oil and gas reserves.  Key risks and associated mitigation are set out below.

Finance Review

Income Statement

The Group made a loss for the year of £5.64 million (2017 - £2.75 million).

Further post 2016 well drilling expenses on the Skipper asset, resulted in an impairment charge to the Income Statement of £184k (refer Note 8).  There was no other impairment made against oil and gas properties during the year.  This compares with the £119k impairment charged in 2017 which included £85k for Skipper post well drilling expenses together with £34k on the relinquishment of Licence P2122.

A charge of £922k (2017: £430k) to the Income Statement reflects the expenses incurred for pre-licence activity, business development ('BD') and other corporate project activity and expenses.

Administration expenses of £974k (2017 - £700k) for the year comprise gross general and administration ('G&A') expenses of £3.19 million (2017 - £2.12 million) including non-cash share-based payment expense of £378k (2017 - £298k), net of both the allocation of £702k (2017 - £666k) attributable to pre-licence activity, BD and other corporate projects, as included in the £922k above, and the allocation of £1.52 million (2017 - £757k) capitalised to assets throughout the Group.  The increase in gross G&A expenses highlights the further significant increase in resource required to support the Group's accelerating SNS capital projects and other capital activities during the year.

The net loss on settlement of liabilities of £106k (2017: £1k) reflects both realised and unrealised movements on the settlement of liabilities via the issue of shares.

The foreign exchange loss of £334k (2017: gain £333k) reflects foreign exchange movements on non-GBP denominated loans, provisions and trade creditors.

Finance expense of £3.12 million (2017 - £1.83 million) includes accrued interest payable on loans (net of capitalised interest £752k (2017 - £22k)), discount accretion and both current and amortised finance expenses.  These expenses relate to fees and interest incurred on both loan finance facilities and those trade creditors subject to deferred payment and equity conversion terms.

Balance Sheet

PPE oil and gas assets have increased to £41.53 million (2017: £21.32 million) during the year, which represents capital expenditure on Front End Engineering Design ('FEED'), the Thames Pipeline acquisition and other pre-development activities with respect to Blythe, Elgood and the Vulcan Satellites. The £20.21 million increase includes the Thames Pipeline acquisition, pigging operations and other associated onshore and offshore pipeline engineering studies. The Group also completed several subsea activities including surveys on all pre-development pipeline routes together with subsurface geotechnical surveys for both Blythe and Southwark. Other capital cost drivers included further platform studies and miscellaneous pre-FID work programmes associated with the dual hub development strategy.

The Harvey, Goddard and Abbeydale exploration and evaluation ('E&E') assets represent the E&E portfolio at 31 December 2018, with a net book value of £2.35 million (2017: £185k) to the Group at 31 December 2018. This increase essentially consists of capital costs associated with the aforementioned Harvey appraisal well, including geophysical, geotechnical and well site surveys and pre-drill engineering and planning.

Current assets have increased to £1.37 million (2017: £1.11 million) mainly resulting from an increase in cash resources of £557k to £702k and recognition of prepaid financing costs of 291k. This prepayment includes miscellaneous direct financing fees incurred with regard to the Company's debt and equity funding efforts.

Total liabilities have increased to £51.07 million (2017: £27.40 million) mainly resulting from further drawings on the loans provided by London Oil & Gas Limited ('LOG') (see table below).  Total liabilities comprise LOG Loan facilities of £34.03 million (2017: £13.00 million) offset by £4.21 million (2017: £0.61 million) loan finance costs, Skipper deferred trade creditors of £2.22 million (2017: £4.46 million), SNS Project creditors £3.41 million (2017: £0.18 million), other creditors £0.32 million (2017: £0.19 million), deferred consideration in relation to acquisitions of £6.19 million (2017: £6.01 million), the Vulcan East suspended well abandonment provision of £3.60 million (2017: £3.60 million), the Thames Pipeline decommissioning provision of £2.04 million (2017: £nil) and accruals of £3.47 million (2017: £0.57 million).

Cash Flow

Net cash outflows of £3.04 million (2017: £1.05 million) from operations, £14.82 million (2017: £3.40 million) from investing activities and £0.43 million (2017: £2.03 million) from loan repayments and financing activities were funded via loan drawings and the issue of equity instruments in the Company totalling £18.85 million (2017: £6.38 million).

The Directors will not be recommending payment of a dividend.

Funding & Liquidity

The Board has reviewed the Group's cash flow forecasts up until April 2020 having regard to its current financial position and operational objectives. Notwithstanding the recent announcements made on 1 April 2019 with regard to both fundraising and the restructuring of the LOG debt, these forecasts indicate that the Group will need additional funding to enable it to progress with its planned development activities and to meet its liabilities as they fall due in the period from 1 January 2020. The Board; however, is satisfied that the Group will have sufficient financial resources available to meet its commitments based on the likelihood of the Group being able to secure additional funding from existing stakeholders, the farmout of existing assets and/or funding from new investors. The Consolidated Statement of Financial Position at 31 December 2018 details a net liability position of the Group of £5.8 million; however, the funding and LOG restructuring, pursuant to the announcement on 1 April 2019, will both provide increased equity and the reduction of debt on the balance sheet, Management identify this trend as an important steer to deliver its dual Hub Strategy and the development of its gas asset portfolio. Accordingly, the Board continue to adopt the going concern basis for the preparation of these financial statements.

However, at the date of approval of these financial statements there are no legally binding agreements in place relating to future fundraising. There can be no certainty that additional funds will be forthcoming which therefore indicates the existence of a material uncertainty which may cast significant doubt about the Group's ability to continue as a going concern and therefore it may be unable to realise its assets and discharge its liabilities in the normal course of business.  The financial statements do not include the adjustments that would result if the Group was unable to continue as a going concern.

The Strategic Report and Finance Review have been issued and signed on behalf of the Board.

Andrew Hockey

Chief Executive Officer

04 April 2019

Consolidated Statement of Comprehensive Income

	Notes	2018	2017
		£000	£000
Administration expenses		(974)	(700)
Impairment of oil and gas properties	8	(184)	(119)
Project, pre-licence and exploration expenses		(922)	(430)
Net loss on settlement of liabilities	3	(106)	(1)
Foreign exchange (loss)/gain		(334)	333
		_________	_________
Operating loss	3	(2,520)	(917)
Finance expense	5	(3,124)	(1,834)
		_________	_________
Loss for the year before taxation		(5,644)	(2,751)
Taxation	6	-	-
		_________	_________
Loss and total comprehensive loss for the year attributable to equity holders of the parent	7	(5,644)	(2,751)
		_________	_________
Loss for the year per ordinary share - basic	7	4.6p	2.5p
Loss for the year per ordinary share - diluted	7	4.6p	2.5p

The loss for the year arose from continuing operations.

Consolidated and Company Statements of Changes in Equity

	Share capital	Share premium	Share-based payment reserve	Accumulated losses	Total equity
Group:	£000	£000	£000	£000	£000
At 1 January 2017	1,093	20,460	2,885	(28,738)	(4,300)
Loss for the year	-	-	-	(2,751)	(2,751)
	_____	________	________	________	_______
Total comprehensive loss attributable to owners of the parent	-	-	-	(2,751)	(2,751)
Settle creditors via issue of shares	105	1,877	-	-	1,982
Lapse of warrants	-	-	(10)	10	-
Issue of share options	-	-	298	-	298
Exercise of share options	5	-	(74)	74	5
	_____	________	________	________	_______
At 31 December 2017	1,203	22,337	3,099	(31,405)	(4,766)
Loss for the year	-	-	-	(5,644)	(5,644)
	_____	________	________	________	_______
Total comprehensive loss attributable to owners of the parent	-	-	-	(5,644)	(5,644)
Issue of warrants	-	-	4,190	-	4,190
Issue of share options	-	-	378	-	378
Exercise of share options	66	-	(1,359)	1,359	66
	_____	______	________	________	_______
At 31 December 2018	1,269	22,337	6,308	(35,690)	(5,776)
	_____	________	_______	________	_______
Company:
At 1 January 2017	1,093	20,460	2,885	(5,172)	19,266
Profit for the year	-	-	-	1,176	1,176
	_____	________	________	________	_______
Total comprehensive income attributable to owners of the parent	-	-	-	1,176	1,176
Settle creditors via issue of shares	105	1,877	-	-	1,982
Lapse of warrants	-	-	(10)	10	-
Issue of share options	-	-	298	-	298
Exercise of share options	5	-	(74)	74	5
	_____	________	________	________	_______
At 31 December 2017	1,203	22,337	3,099	(3,912)	22,727
Loss for the year	-	-	-	(2,604)	(2,604)
	_____	________	________	________	_______
Total comprehensive loss attributable to owners of the parent	-	-	-	(2,604)	(2,604)
Issue of warrants	-	-	4,190	-	4,190
Issue of share options	-	-	378	-	378
Exercise of share options	66	-	(1,359)	1,359	66
	_____	________	_______	_______	_______
At 31 December 2018	1,269	22,337	6,308	(5,157)	24,757
	______	________	_______	________	_______

Share capital - Amounts subscribed for share capital at nominal value.

Share premium - Amounts received on the issue of shares, in excess of the nominal value of the shares.

Share-based payment reserve - Amounts reflecting fair value of options and warrants issued.

Accumulated losses - Cumulative net losses recognised in the Statement of Comprehensive Income net of amounts recognised directly in equity.

Consolidated Statement of Financial Position

	Notes	2018	2017
		£000	£000
Non-current assets
Intangible assets: exploration & evaluation	8	2,352	185
Intangible assets: other	8	3	1
Property, plant and equipment: development & production	9	41,527	21,316
Property, plant and equipment: other	9	41	20
		_________	_________
		43,923	21,522
		_________	_________
Current assets
Other receivables and prepayments	13	672	968
Cash and cash equivalents	17	702	145
		_________	_________
		1,374	1,113
		_________	_________
Total assets		45,297	22,635
Current liabilities
Loans	14	(6,934)	-
Trade and other payables	14	(11,137)	(7,038)
		_________	_________
		(18,071)	(7,038)
		_________	_________
Non-current liabilities
Loans	15	(22,884)	(12,394)
Provisions	15	(10,118)	(7,969)
		_________	_________
		(33,002)	(20,363)
		_________	_________
Total liabilities		(51,073)	(27,401)
		_________	_________
NET LIABILITIES		(5,776)	(4,766)
		_________	_________
Capital and reserves
Share capital	16	1,269	1,203
Share premium	16	22,337	22,337
Share-based payment reserve		6,308	3,099
Accumulated losses		(35,690)	(31,405)
		_________	_________
		(5,776)	(4,766)
		_________	_________

Company Number: 07434350

The financial statements were approved and authorised for issue by the Board of Directors on 4 April 2019 and were signed on its behalf by: -

Andrew Hockey

Chief Executive Officer

4 April 2019

Company Statement of Financial Position

Company Number: 07434350	Notes	2018	2017
		£000	£000
Non-current assets
Intangible assets	8	3	1
Property, plant and equipment	9	41	20
Investments	11	17,197	17,416
Amounts due from subsidiaries	11	29,526	12,280
		_________	_________
		46,767	29,717
		_________	_________
Current assets
Other receivables and prepayments	13	672	767
Cash and cash equivalents	17	702	145
		_________	_________
		1,374	912
		_________	_________
Total assets		48,141	30,629
Current liabilities
Trade and other payables	14	(8,071)	(6,643)
Non-current liabilities
Loans	15	(14,054)	-
Provisions	15	(1,259)	(1,259)
		_________	_________
		(15,313)	(1,259)
		_________	_________
Total liabilities		(23,384)	(7,902)
		_________	_________
NET ASSETS		24,757	22,727
		_________	_________
Capital and reserves
Share capital	16	1,269	1,203
Share premium	16	22,337	22,337
Share-based payment reserve		6,308	3,099
Accumulated losses		(5,157)	(3,912)
		_________	_________
		24,757	22,727
		_________	_________

The Company has taken advantage of the exemption allowed under Section 408 of the Companies Act 2006 and has not presented its own Statement of Comprehensive Income in these financial statements.

The Company loss for the year was £2,604k (2017: profit £1,176k).

The financial statements were approved and authorised for issue by the Board of Directors on 4 April 2019 and were signed on its behalf by: -

Andrew Hockey

Chief Executive Officer

4 April 2019

Consolidated Cash Flow Statement

	Notes	2018	2017
		£000	£000
Loss for the year	7	(5,644)	(2,751)
Depreciation, depletion and amortisation		9	3
Exploration asset write off	8	184	119
Loss on settlement of liabilities	3	106	1
Share based payments		187	174
Movement in trade and other receivables		(812)	(278)
Movement in trade and other payables		(415)	178
Interest received		(2)	-
Finance fees		3,206	1,834
Foreign exchange differences		142	(333)
		_________	_________
Net cash used in operating activities		(3,039)	(1,053)
Investing activities
Purchase of intangible and tangible assets		(14,327)	(2,648)
Interest received		2	-
Acquisitions	10	-	(750)
Initial Thames Pipeline decommissioning security		(500)	-
		_________	_________
Net cash used in investing activities		(14,825)	(3,398)
Financing activities
Proceeds from issue of equity instruments of the Group		67	8
Cash received from loans	23	18,787	6,372
Amounts repaid on loans	23	-	(2,019)
Finance fees paid		(433)	(12)
		_________	_________
Net cash generated from financing activities		18,421	4,349
Net increase / (decrease) in cash and cash equivalents		557	(102)
Cash and cash equivalents at the beginning of the year		145	247
		_________	_________
Cash and cash equivalents at end of year	17	702	145
		_________	_________

Company Cash Flow Statement

	Notes	2018	2017
		£000	£000
(Loss)/profit for the year	18	(2,604)	1,176
Depreciation charges		8	3
Investment write back	11	-	(1,870)
Loss on settlement of liabilities	3	106	1
Share based payments		138	96
Movement in trade and other receivables		(312)	(284)
Movement in trade and other payables		(415)	214
Inter-company service charge uplift		(206)	(105)
Interest received		(2)	-
Finance fees		1,322	166
Foreign exchange differences		142	(200)
		_________	_________
Net cash used in operating activities		(1,823)	(803)
Investing activities
Purchase of intangible and tangible assets		(573)	(371)
Loans to subsidiary undertakings		(15,470)	(2,539)
Interest received		2	-
Investments in subsidiary undertakings	10	-	(750)
		_________	_________
Net cash used in investing activities		(16,041)	(3,660)
Financing activities
Proceeds from issue of equity instruments of the Company		67	8
Cash received from loans	23	18,787	6,372
Amounts repaid on loans	23	-	(2,019)
Finance fees paid		(433)	-
		_________	_________
Net cash generated from financing activities		18,421	4,361
Net (decrease) / increase in cash and cash equivalents		557	(102)
Cash and cash equivalents at the beginning of the year		145	247
		_________	_________
Cash and cash equivalents at end of year	17	702	145
		_________	_________

Notes Forming Part of the Financial Statements

Note 1.            Accounting policies

General information

Independent Oil and Gas plc is a public limited company incorporated and domiciled in England and Wales.  The Group's and Company's financial statements for the year ended 31 December 2018 were authorised for issue by the Board of Directors on 04 April 2019 and the balance sheets were signed on the Board's behalf by the CEO, Andrew Hockey.

Basis of preparation and accounting

The preliminary results, which are audited, do not include all the notes of the type normally included in an annual financial report. Accordingly, this preliminary announcement does not constitute financial statements as defined by the Companies Act 2006 and should therefore be read in conjunction with the Annual Report for the year ended 31 December 2018, and any public announcements made by the Group during the reporting period. The annual financial report for the year ended 31 December 2018 was prepared in accordance with International Financial Reporting Standards as adopted by the European Union ("IFRS's") and the accounting policies applied in this preliminary announcement are consistent with the polices applied in the annual financial report for the year ended 31 December 2017 unless otherwise noted. The annual financial report for the year ended 31 December 2017 has been filed with the Registrar of Companies at Companies House. The audit report on these financial statements was unmodified but did make reference to an emphasis of matter in respect of going concern.

The principal accounting policies adopted in the preparation of the financial statements are set out below.  The policies have been consistently applied to all years presented, unless otherwise stated.  The consolidated financial statements are presented in GBP Sterling, which is also the functional currency of the Company and its subsidiaries.  Amounts are rounded to the nearest thousand, unless otherwise stated.

These financial statements have been prepared in accordance with International Financial Reporting Standards adopted by the European Union, International Accounting Standards and Interpretations (collectively 'IFRSs') and with those parts of Companies Act 2006 applicable to companies preparing their accounts under IFRS.

The preparation of financial statements in compliance with adopted IFRSs requires the use of certain critical accounting estimates.  It also requires Group management to exercise judgment in applying the Group's accounting policies.  The areas where significant judgments and estimates have been made in preparing the financial statements and their effect are disclosed within this Note 1 on pages 62 and 63.

The consolidated financial statements have been prepared on a historical cost basis.

Going concern

The Board has reviewed the Group's cash flow forecasts up until September 2020 having regard to its current financial position and operational objectives. On 1 April 2019 the Group announced it had raised approximately £16.6m (gross) of equity via the placing of 165,795,050 shares for 10p per ordinary share and had simultaneously renegotiated the term of £7.1m of LOG debt whereby repayments previously scheduled for 2019, which are now rescheduled to 1 January 2020 at the earliest. The Group have continued to draw down against the LOG £15m facility having taken a further drawdown of £3.925 million in January 2019. The Group have received confirmation from the LOG Administrators that the remaining £3.93m available to the Group under the £15m LOG will remain available to the Group under the original terms of the facility, and as publicly noted by the LOG Administrators, they will continue to support the Group in its endeavours to develop its dual Hub Strategy in order to generate shareholder return.

Notwithstanding this announcement the Group's cashflow forecast to September 2020 indicates that the Group will need additional funding to enable it to progress with its planned development activities and to meet its liabilities (working capital and LOG scheduled debt repayments) as they fall due in the period from 1 January 2020. The Board; however, is satisfied that the Group will have sufficient financial resources available to meet its commitments based on the likelihood of the Group being able to secure additional funding from existing stakeholders, the farmout of existing assets and/or funding from new investors. The Consolidated Statement of Financial Position at 31 December 2018 details a net liability position of the Group of £5.8 million; however, the funding and LOG restructuring, pursuant to the announcement on 1 April 2019, will both provide increased equity and the reduction of debt on the balance sheet, Management identify this trend as an important steer to deliver its dual Hub Strategy and the development of its associated oil and gas asset portfolio. Accordingly, the Board continue to adopt the going concern basis for the preparation of these financial statements.

However, at the date of approval of these financial statements there are no legally binding agreements in place relating to future fundraising. Therefore, there can be no certainty that additional funds will be forthcoming which indicates the existence of a material uncertainty which may cast significant doubt about the Group's ability to continue as a going concern and therefore it may be unable to realise its assets and discharge its liabilities in the normal course of business.  The financial statements do not include the adjustments that would result if the Group was unable to continue as a going concern.

New and revised accounting standards

(i) New and amended standards adopted by the Group:

The accounting policies adopted are consistent with those of the previous financial year.  New or amended financial standards or interpretations adopted during the year and that have a significant impact upon the financial statements are detailed below.

(ii) The following standards, amendments and interpretations, which are effective for reporting periods beginning after the date of these financial statements, have not been adopted early: -

Standard	Description	Effective date
IFRS 16	Leases	1 January 2019
IFRIC 23	Uncertainty over Income Tax Treatments	1 January 2019
IFRS 9	Prepayment Features with Negative Compensation (Amendments)	1 January 2019
IAS 28	Long-term Interest in Associates and Joint Ventures (Amendments)	1 January 2019
IFRS 3, IFRS 11, IAS 12, IAS 23	Annual Improvements to IFRS Standards 2015-2017 Cycle	1 January 2019
IAS 19	Plan Amendment, Curtailment or Settlement (Amendments)	1 January 2019
IFRS 3	Definition of a Business (Amendments to IFRS 3)	1 January 2020
IAS1, IAS8	Definition of Material (amendments to IAS1 and IAS 8)	1 January 2020
n/a	Amendments to References to the Conceptual Framework in IFRS Standards	1 January 2020
IFRS 17	Insurance Contracts	1 January 2021

IFRS 16 "Leases" - the Board assesses that the net impact to the Income Statement in 2019 and future years will be dependent on those prevailing lease contracts and other such similar oil and gas development contractual agreements which may have been executed prior to 31 December 2019. The Board is uncertain as to the length of time such contracts may cover; however, if such contracts cover any continuous period of greater than one year, then such contracts will be subject to IFRS16. Such contracts will result in both assets and liabilities on the Balance Sheet to increase by corresponding amounts, which, as at 31 December 2018 would have been immaterial. At 31 December 2018 the Group was not subject to any long-term lease contracts, other than for the rental of its office premises at 10 Arthur Street, London EC4R 9AY and the Crown Estate lease where the Thames Pipeline crosses the foreshore at Bacton. The Company has not adopted this standard early and has not made any IFRS16 provision, for its office lease or Crown Estate agreements, or otherwise, in the financial statements for the year ending 31 December 2018.

The application of the other standards above in future financial statements is not expected to have a material impact on those financial statements.

New significant standards and amendments effective 1 January 2018

IFRS 9 Financial Instruments

IFRS 9, Financial Instruments introduced new requirements for the recognition, classification and measurement of financial assets and liabilities, derecognition of financial instruments, impairment of financial assets and hedge accounting.  IFRS 9 replaced the multiple classification and measurement models for financial assets and financial liabilities that existed under IAS 39 Financial Instruments, and the basis on which financial assets are measured will determine their classification as either, at amortised cost, fair value through profit and loss, or fair value through other comprehensive income.  The Group's principal financial assets comprise cash and other receivables. All these financial assets continue to be classified and measured at amortised cost. The Group's principal financial liabilities comprise trade and other payables and loans.  All these financial liabilities continue to be classified and measured at amortised cost.

The adoption of IFRS 9 has changed the Group's accounting for impairment losses for financial assets by replacing IAS 39's incurred loss approach with a forward-looking expected credit loss approach. IFRS 9 requires the Group to measure and recognise expected credit losses on all applicable financial assets.

The Company did not choose to adopt IFRS 9 early and have chosen not to apply the standard retrospectively on the basis of the impact not being significant in terms of impairment and or additional expected credit losses ('ECL's) recognised with regard to intercompany balances. The Company has assessed the resulting impact on the financial statements and there was no material quantitative impact on the financial statements. There are a number of additional disclosures that have been added to the financial statements. 

Basis of consolidation

Where the Company has control over an investee, it is classified as a subsidiary.  The Company controls an investee if all three of the following elements are present: power over the investee, exposure to variable returns from the investee, and the ability of the investor to use its power to affect those variable returns.  Control is reassessed whenever facts and circumstances indicate that there may be a change in any of these elements of control. 

The consolidated financial statements present the results of the Company and its subsidiaries as if they formed a single entity.  Inter-company transactions and balances between Group companies are therefore eliminated in full.  The financial statements of subsidiaries are included in the Group's financial statements from the date that control commences until the date that control ceases. 

Asset Acquisition

In the event of an asset acquisition, the cost of the acquisition is assigned to the individual assets and liabilities based on their relative fair values.  All directly attributable costs are capitalised.  Contingent consideration is accrued for when these amounts are considered probable and are discounted to present value based on the expected timing of payment.

Oil and gas exploration, development and producing assets

The Group adopts the following accounting policies for oil and gas asset expenditure, based on the stage of development of the assets:

1)    Pre-Licence

Expenditure incurred prior to the acquisition and/or award of a licence interest is expensed to the Statement of Comprehensive Income as 'exploration expenses'.

2)    Exploration and evaluation ('E&E')

Capitalisation

Costs incurred after rights to explore have been obtained, such as geological and geophysical surveys, drilling and commercial appraisal costs, and other directly attributable costs of exploration and appraisal including technical and administrative overheads, are capitalised as intangible exploration and evaluation ('E&E') assets.  The assessment of what constitutes an individual E&E asset is based on technical criteria but essentially either a single licence area or contiguous licence areas with consistent geological features are designated as individual E&E assets.  Costs relating to the exploration and evaluation of oil and gas interests are carried forward until the existence, or otherwise, of commercial reserves have been determined.

E&E costs are not amortised prior to the conclusion of appraisal activities.  Once active exploration is completed the asset is assessed for impairment.  If commercial reserves are discovered then the carrying value of the E&E asset is reclassified as a development and production ('D&P') asset, within property, plant and equipment ('PPE'), following development sanction by the Board, but only after the carrying value is assessed for impairment at point of transfer and, where appropriate, its carrying value adjusted.  Following development sanction by the Board, a Field Development Plan ('FDP') may be submitted.  If it is subsequently assessed that commercial reserves have not been discovered, the E&E asset is written off to the Statement of Comprehensive Income.  The Group's definition of commercial reserves for such purpose is proven and probable ('2P') reserves on an entitlement basis.

Intangible E&E assets that relate to E&E activities that are not yet determined to have resulted in the discovery of commercial reserves remain capitalised as intangible E&E assets at cost, subject to impairment assessments as set out below.

Impairment

The Group's oil and gas assets are analysed into cash generating units ('CGU') for impairment reporting purposes, with E&E asset impairment testing being performed at an individual asset level.  E&E assets are reviewed for impairment when circumstances arise which indicate that the carrying value of an E&E asset exceeds the recoverable amount.  Such indicators would include but not limited to:

(i)   adequate and sufficient data exists that render the resource uneconomic and unlikely to be developed;

(ii)   title to the asset is compromised;

(iii)  budgeted or planned expenditure is not expected in the foreseeable future; and

(iv)  insufficient discovery of commercially viable resources leading to the discontinuation of activities.

The recoverable amount of the individual asset is determined as the higher of its fair value less costs to sell and value in use.  Impairment losses resulting from an impairment review are separately recognised and written off to the Statement of Comprehensive Income.

Impaired assets are reviewed annually to determine whether any substantial change to their fair value amounts previously impaired would require reversal.

A previously recognised impairment loss is reversed if the recoverable amount increases because of a change in the estimates used to determine the recoverable amount, but not to an amount higher than the carrying amount that would have been determined (net of depletion or amortisation) had no impairment loss been recognised in prior periods.  Reversal of impairments and impairment charges are credited/(charged) to a separate line item within the Statement of Comprehensive Income.

3)    Development and production ('D&P')

Capitalisation

Costs of bringing a field into production, including the cost of facilities, wells and sub-sea equipment together with E&E assets reclassified in accordance with the above policy, are capitalised as a D&P asset within PPE. Normally each individual field development will form an individual D&P asset but there may be cases, such as phased developments, or multiple fields around a single production facility when fields are grouped together to form a single D&P asset.  The cost of development and production assets also include the cost of acquisitions and purchases of such assets, directly attributable overheads, applicable borrowing costs and the cost of recognising provisions for future consideration payments - see Note 9 and Note 10. The discounted cost for future decommissioning is also added to the D&P asset.

Depreciation and depletion

All costs relating to a development are accumulated and not depreciated/depleted until the commencement of production.  Depletion is calculated on a UOP basis based on the 2P reserves of the asset.  Any re-assessment of reserves affects the depletion rate prospectively.  Significant items of plant and equipment will normally be fully depreciated over the life of the field; however, these items are assessed to consider if their useful lives differ from the expected life of the D&P asset and should this occur a different depreciation rate may be charged.  The key areas of estimation regarding depletion and the associated unit of production calculation for oil and gas assets are recoverable reserves and future capital expenditures.

Impairment

A review is carried out for any indication that the carrying value of the Group's D&P assets may be impaired.  If any indicators are identified, a review of D&P assets is carried out on an asset by asset basis and involves comparing the carrying value with the recoverable value of an asset.  The recoverable amount of an asset is determined as the higher of its fair value less costs to sell and value in use.  The value in use is determined from estimated future net cash flows, being the present value of the future cash flows expected to be derived from production of commercial reserves.  Impairment resulting from the impairment testing is charged to a separate line item within the Statement of Comprehensive Income.

The pre-tax future cash flows are adjusted for risks specific to the CGU and are discounted using a pre-tax discount rate.  The discount rate is derived from the Group's post-tax weighted average cost of capital and is adjusted where applicable to consider any specific risks relating to the country where the CGU is located, although other rates may be used if appropriate to the specific circumstances.  The discount rates applied in assessments of impairment are reassessed each year.  The Company uses a risk adjusted discount rate of 10%, unless otherwise stated.

The CGU basis is generally the field, however, oil and gas assets, including infrastructure assets may be accounted for on an aggregated basis where such assets are economically inter-dependent. 

4)    Offshore Pipelines

Capitalisation

Costs of commissioning an offshore pipeline to transport hydrocarbons, including the cost of related onshore facilities and subsea equipment are capitalised as a tangible asset within PPE. Each contiguous pipeline will form an exclusive individual asset but there may be cases, such as phased developments, when pipelines are grouped together to form

a single tangible pipeline asset. The cost of offshore pipeline assets also includes the cost of acquisitions and purchases of such assets, directly attributable overheads, applicable borrowing costs and the discounted cost of future decommissioning.

Depreciation

All costs relating to pipeline commissioning are not depreciated until the commencement of transportation of hydrocarbons.  Depreciation is calculated on a straight-line basis over the period in which transportation is likely to take place.  Any re-assessment of this timeline will impact on the depreciation rate prospectively. The key areas of estimation regarding depreciation are future capital expenditures and recoverable reserves for those fields where such pipelines are utilised for the transportation of oil and gas production.

Impairment

A review is carried out for any indication that the carrying value of the pipeline asset may be impaired.  If any indicators are identified, such as the pipeline's inability to continue to operate safely and effectively in its current environment, a review of the pipeline asset is carried out. Impairment resulting from the impairment review is charged to a separate line item within the Statement of Comprehensive Income.

Assets other than oil and gas interests

Assets other than oil and gas interests are stated at cost, less accumulated depreciation and any provision for impairment.  Depreciation is provided at rates estimated to write off the cost, less estimated residual value, of each asset over its expected useful life as follows: -

·      Computer and office equipment: 33% straight line, with one full year's depreciation in year of acquisition; and

·      Tenants improvements: 20% straight line, with one full year's depreciation in year of acquisition.

Provisions

Provisions are recognised when:

·      the Group has a present legal or constructive obligation resulting from past events;

·      it is more likely than not that an outflow of resources will be required to settle the obligation; and

·      the amount can be reliably estimated.

Decommissioning

Provisions for decommissioning costs are recognised in accordance with IAS 37 Provisions, Contingent Liabilities and Contingent Assets.  Provisions are recorded at the present value of the expenditures expected to be required to settle the Group's future obligations.

Provisions are reviewed at each reporting date to reflect the current best estimate of the cost at present value.  Any change in the date on which provisions fall due will change the present value of the provision.  These changes are treated as an administration expense.  The unwinding of the discount is reflected as a finance expense.

In the case of a D&P and/or pipeline asset, since the future cost of decommissioning is regarded as part of the total investment to gain access to future economic benefits, this is included as part of the cost of the relevant D&P and/or pipeline asset.

Disposals

Net proceeds from any disposal of an E&E, D&P or pipeline asset are initially credited against the previously capitalised costs of that asset and any surplus proceeds are credited to the Statement of Comprehensive Income. 

Foreign currencies

The Group's presentational currency is GBP Sterling and has been selected based on the currency of the primary economic environment in which the Group operates.  The Group's primary product is generally traded by reference to its pricing in GBP Sterling.  The functional currency of all companies in the Group is also considered to be GBP Sterling.  Transactions in currencies other than the functional currency of a company are recorded at a rate of exchange approximating to that prevailing at the date of the transaction.  At each balance sheet date, monetary assets and liabilities that are denominated in currencies other than the functional currency are translated at the amounts prevailing at the balance sheet date and any gains or losses arising are recognised in the Consolidated Statement of Comprehensive Income.

Taxation

Current Tax

Tax is payable based upon taxable profit for the year.  Taxable profit differs from net profit as reported in the Statement of Comprehensive Income because it excludes items of income or expense that are taxable or deductible on other years and it further excludes items that are never taxable or deductible.  Any Group liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the reporting date.

Deferred Tax

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit.  Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised.

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries, except where the Group can control the reversal of the temporary differences and it is probable that the temporary difference will not reverse in the foreseeable future.

The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled, or the asset is realised.  Deferred tax is charged or credited in the Statement of Comprehensive Income, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also dealt with in equity.  Deferred tax assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current tax liabilities and when they relate to income taxes levied by the same taxation authority and the Group intends to settle its current tax assets and liabilities on a net basis.

The amount of the asset or liability is determined using tax rates that have been enacted or substantively enacted by the reporting date and are expected to apply when the deferred tax liabilities/(assets) are settled/(recovered).  Deferred tax balances are not discounted.

Investments & Loans (Company)

Non-current investments in subsidiary undertakings are shown in the Company's Statement of Financial Position at cost less any provision for permanent diminution of value.

Loans to subsidiary undertakings are stated at amortised cost and recognised in accordance with IFRS9. The loans have no maturity date and are not repayable until the respective subsidiary entity has sufficient cash to repay the loan and thus are expected to continue indefinitely.

Operating Leases

Rentals under operating leases are charged on a straight-line basis over the lease term.

Financial instruments

Financial instruments are recognised when the Group becomes a party to the contractual provisions of the instrument and are subsequently measured at amortised cost.

Classification and measurement of financial assets

The initial classification of a financial asset depends upon the Group's business model for managing its financial assets and the contractual terms of the cash flows. The Group's financial assets are measured at amortised costs and are held within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest.

The Group's cash and cash equivalents and other receivables are measured at amortised cost. Other receivables are initially measured at fair value. The Group holds other receivables with the objective to collect the contractual cash flows and therefore measures them subsequently at amortised cost.

The Group has no financial assets measured at FVOCI (Fair Value Through Other Comprehensive Income) or FVTPL (Fair Value Through the Statement of Profit or Loss)

Cash and cash equivalents

Cash includes cash on hand and demand deposits with any bank or other financial institution.  Cash equivalents are short-term, highly liquid investments that are readily convertible to known amounts of cash which are subject to an insignificant risk of changes in value.

Impairment of financial assets

The Group recognises loss allowances for expected credit losses ('ECL's) on its financial assets measured at amortised cost. Due to the nature of its financial assets, the Group measures loss allowances at an amount equal to the lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses.

Classification and measurement of financial liabilities

A financial liability is initially classified as measured at amortised cost or FVTPL. A financial liability is classified as measured at FVTPL if it is held-for-trading, a derivative or designated as FVTPL on initial recognition.

The Group's accounts payable, accrued liabilities and long-term debt are measured at amortised cost.

Accounts payable and accrued liabilities are initially measured at fair value and subsequently measured at amortised cost. Accounts payable and accrued liabilities are presented as current liabilities unless payment is not due within 12 months after the reporting period.

Long-term debt is initially measured at fair value, net of transaction costs incurred. The contractual cash flows of the long-term debt are made up of solely of principal and interest, therefore long-term debt is subsequently measured at amortised cost. Long-term debt is classified as current when payment is due within 12 months after the reporting period.

Where warrants are issued in lieu of arrangement fees on debt facilities, the fair value of the warrants are measured at the date of grant as determined through the use of the Black‑Scholes technique. The fair value determined at the grant date of the warrants is recognised in the Group's warrant reserve and is amortised as a finance cost over the life of the facility.

The Group has no financial liabilities measured at FVTPL.

The LOG loans are securitised by guarantees over the assets of IOG North Sea Limited, IOG UK Limited and IOG Infrastructure Limited. These guarantees are considered to be insurance contracts and accounted for in accordance with the provisions of IFRS 4.

Convertible loan notes

Upon issue, convertible notes are separated into the equity and liability components at the date of issue.  The liability component is recognised initially at its fair value.  Subsequent to initial recognition, it is carried at amortised carrying value using the effective interest method until the liability is extinguished on conversion or redemption of the notes.  The equity component is the residual amount of the convertible note after deducting the fair value of the liability component.  This is recognised and included in equity and is not subsequently re-measured.

Equity

Equity instruments issued by the Company are recorded at the proceeds received, net of direct issue costs, allocated between share capital and share premium.

Share issue expenses and share premium account

The costs of issuing new share capital are written off against the share premium account arising out of the proceeds of the new issue.

Share-based payments

The Company and Group have applied the requirements of IFRS 2 Share-based payments.  The Company issues equity share options, to certain employees and contractors, as direct compensation for both salary and fees sacrificed in lieu of such share options.  Other Long-Term Incentive Plan ('LTIP') share options may be awarded to incentivise and reward successful corporate and individual performance.  The fair value of these awards has been determined at the date of the grant of the award allowing for the effect of any market-based performance conditions.

The fair value of share options awarded, in lieu of salary sacrifice, is expensed on the effective date of grant, with no vesting conditions applied.  The fair value is deemed to be the actual salary sacrificed.

For LTIP share option awards, based upon incentive and performance, the fair value, adjusted by the estimate of the number of awards that will eventually vest because of non-market conditions, is expensed uniformly over the vesting period and is charged to the Statement of Comprehensive Income, together with an increase in equity reserves, over a similar period.  The fair values are calculated using an option pricing model with suitable modifications to allow for early exercise. The inputs to the model include: the share price at the date of grant; exercise price; expected volatility; expected dividends; risk-free rate of interest; and patterns of exercise of the plan participants.  Where the terms and conditions of options are modified before they vest, the increase in the fair value of the options, measured immediately before and after the modification, is also charged to the Statement of Comprehensive Income over the remaining vesting period.  No expense is recognised for options that do not ultimately vest except where vesting is only conditional upon a market condition.

Where the Group renegotiates the terms of its debt, with the result that the liability is extinguished by the issuing of its own equity instruments to the creditor (referred to as a 'debt for equity swap'), the equity instruments issued to settle a liability represent 'consideration paid'.  In accordance with IFRIC 19 'Extinguishing Financial Liabilities with Equity Instruments' the Group therefore recognises a gain or loss in profit or loss when a liability is settled through the issuance of the Group's own equity instruments.  The amount of the gain or loss recognised in profit or loss is determined as the difference between the carrying value of the financial liability and the fair value of the equity instruments issued.  The fair value of the equity instruments issued is used to measure the gain or loss on the settlement of the existing financial liability.

The fair value of warrants issued to third parties is calculated by reference to the service provided, or if this is not considered possible, calculated in the same way as for LTIP share options as detailed above.  Typically, these amounts have related to debt issues and are included in the effective interest rate calculation of borrowings.

Loss/earnings per share

Loss/earnings per share is calculated as loss/profit attributable to shareholders divided by the weighted average number of ordinary shares in issue for the relevant period.  Diluted earnings per share is calculated using the weighted average number of ordinary shares in issue plus the weighted average number of ordinary shares that would be in issue on the conversion of all relevant potentially dilutive shares to ordinary shares adjusted for any proceeds obtained on the exercise of any options and warrants.  Where the impact of converted shares would be anti-dilutive they are excluded from the calculation.

Critical accounting judgements and key sources of estimation uncertainty

The preparation of financial statements in conformity with IFRS requires management to make judgements, estimates and assumptions that affect the application of policies and reported amounts of assets and liabilities, income and expenses.  The estimates and associated assumptions are based on historical experience and factors that are believed to be reasonable under the circumstances, the results of which form the basis of making judgements about carrying values of assets and liabilities that are not clear from other sources.  Actual results may differ from these estimates.

The following are the critical judgements that management has made in the process of applying the entity's accounting policies and that have the most significant effect on the amounts recognised in financial statements.

Impairment of assets

Management is required to assess oil and gas assets for indicators of impairment and has considered the economic value of individual E&E and D&P assets.  The carrying value of oil and gas assets is disclosed in Notes Note 8 and Note 9.  The carrying value of related investments in the Company Statement of Financial Position is disclosed in Note Note 11.  E&E assets are subject to a separate review for indicators of impairment, by reference to the impairment indicators set out in IFRS 6, which is inherently judgmental.

Key estimates used in the value-in-use calculations

The calculation of value-in-use for oil and gas assets under development or in production is most sensitive to the following assumptions:

·      Commercial reserves

·      production volumes;

·      commodity prices;

·      fixed and variable operating costs;

·      capital expenditure; and

·      discount rates.

Commercial Reserves

Commercial reserves are proven and probable ('2P') oil and gas reserves, calculated on an entitlement basis.  Estimates of commercial reserves underpin the calculation of depletion and amortisation on a UOP basis.  Estimates of commercial reserves include estimates of the amount of oil and gas in place, assumptions about reservoir performance over the life of the field and assumptions about commercial factors which, in turn, will be affected by the future oil and gas price.

Production volumes/recoverable reserves

Annual estimates of oil and gas reserves are generated internally by the Group with external input from operator profiles and/or a Competent Person.  These are reported annually by the Board.  The self-certified estimated future production profiles are used in the life of the fields which in turn are used as a basis in the value-in-use calculation.

Commodity prices

An average of published forward prices and the long-term assumption for natural UKNBP gas and Brent oil are used for future cash flows in accordance with the Group's corporate assumptions.  Field specific discounts and prices are used where applicable.

Fixed and variable operating costs

Typical examples of variable operating costs are pipeline tariffs, treatment charges and freight costs.  Commercial agreements are in place for most of these costs and the assumptions used in the value-in-use calculation are sourced from these where available.  Examples of fixed operating costs are platform costs and operator overheads.  Fixed operating costs are based on operator and/or third-party duty holder budgets.

Capital expenditure

Field development is capital intensive and future capital expenditure has a significant bearing on the value of an oil and gas development asset.  In addition, capital expenditure may be required for producing fields to increase production and/or extend the life of the field.  Cost assumptions are based on operator and/or service contractor cost estimates or specific contracts where available.

Discount rates

Discount rates reflect the current market assessment of the risks specific to the oil and gas sector and are based on the weighted average cost of capital for the Group.  Where appropriate, the rates are adjusted to reflect the market assessment of any risk specific to the field for which future estimated cash flows have not been adjusted.  The Group has applied a risk adjusted discount rate of 10% for the current year (2018: 10%).

Sensitivity to changes in assumptions

A potential change in any of the above assumptions may cause the estimated recoverable value to be lower than the carrying value, resulting in an impairment loss.  The assumptions which would have the greatest impact on the recoverable amounts of the fields are production volumes (linked to recoverable reserves) and commodity prices.

Investments (Company)

If circumstances indicate that impairment may exist, investments in subsidiary undertakings of the Company are evaluated using market values, where available, or the discounted expected future cash flows of the investment.  If these cash flows are lower than the Company's carrying value of the investment, an impairment charge is recorded in the Company.  Evaluation of impairments on such investments involves significant management judgement and may differ from actual results - see above.

Decommissioning

At 31 December 2018, the Group has obligations in respect of decommissioning a suspended well on the Vulcan Satellites D&P asset, together with the acquired offshore Thames Pipeline.

The extent to which a provision is recognised depends on the legal requirements at the date of decommissioning, regulatory activity required to ensure such infrastructure meets safety and environmental requirements, the estimated costs and timing of the work and the discount rate applied.

A full decommissioning estimate for the Vulcan Satellites asset remains uncertain until all development infrastructure has been installed and production volumes and time to abandonment has been considered.  Prior to full development infrastructure and commissioning, the Group will utilise technical reports, and advice from the UK Oil & Gas Authority, to estimate costs of abandonment.

On acquisition of the Thames Pipeline, the Group assumed the decommissioning liability for the pipeline, which is based upon a regulatory framework determined by the OGA. A discounted cost estimate provision has been made in the financial statements as at 31 December 2018 and this provision will continue to be reviewed on an annual basis, given the regulatory framework is subject to constant change and is inherently uncertain over future years. 

The estimates and underlying assumptions are reviewed on an ongoing basis.  Revisions to accounting estimates are recognised in the period in which the estimate is revised, if the revision only affects that period, or, in the period of revision and future periods, if the revision affects both current and future periods.

Fair value of share options and warrants

The fair value of options and warrants is calculated using appropriate estimates of expected volatility, risk free rates of return, expected life of the options/warrants, the dividend growth rate, the number of options expected to vest and the impact of any attached conditions of exercise.  See above for further details of these assumptions.

Note 2.            Segmental information

The Group complies with IFRS 8, Operating Segments, which requires operating segments to be identified based upon internal reports about components of the Group that are regularly reviewed by the directors to allocate resources to the segments and to assess their performance.  In the opinion of the directors, the operations of the Group comprise one class of business, being the exploration and development of oil and gas opportunities in the UK North Sea.

Note 3.            Operating loss

The Group operating loss is stated after charging/(crediting) the following:

		2018	2017
		£000	£000
	Fees payable to the Company's auditor: -     for the audit of the Company's and Group's financial statements	58	50
	Depreciation, depletion and amortisation	21	8
	Project, pre-licence and exploration expenses Impairment of oil and gas properties	922 184	430 119
	Personnel costs - direct expenses	2,115	1,306
	Personnel costs - share-based payments	378	298
	Net loss on settlement of liabilities	106	1
	Foreign exchange loss/(gain)	334	(333)

Of those charges above for both depreciation and personnel costs, respective sums of £12k (2017: £5k) and £1,268k (2017: £869k) were reallocated and capitalised to oil and gas / pipeline properties.

Note 4.            Personnel costs and directors' remuneration

During the year, the average number of personnel, including contract personnel, for both the Company and Group was:

2018 2017 Number Number Management / technical / operations  18 17 of which: Directors 5 5 Personnel costs Group and Company £000 £000 Wages, salaries, fees and other direct costs 1,882 1,229 Social security costs 232 77 Pension costs 1 - Share-based payments 378 298 ________ ________ 2,493 1,604 ________ ________

Note that project contract personnel, capitalised directly to project cost centres, are excluded from the above figures.

Key management personnel are deemed to be directors, the Chief Financial Officer and Head of Corporate Finance.

	Directors' remuneration	Salary	Share-based payment	2018 Total	Salary	Share-based payment	2017 Total
		£000	£000	£000	£000	£000	£000
	Mark Routh1	141	52	193	149	79	228
	Fiona MacAulay2	17	-	17	-	-	-
	Mark Hughes3	90	52	142	-	-	-
	David Peattie4	-	-	-	-	35	35
	Martin Ruscoe	15	15	30	15	20	35
	Andrew Hay5	11	8	19	18	23	41
	Peter Young6	-	-	-	38	-	38
	Hywel John7	-	-	-	69	13	82
	Andrew Hockey	179	118	297	101	19	120
	Charles Hendry	15	15	30	12	7	19
		_______	________	________	_______	________	________
		468	260	728	402	196	598
		_______	________	________	_______	________	________
	Other key management personnel	143	79	222	97	30	127
	Total key management personnel	611	339	950	499	226	725

¹ Mark Routh resigned on 31 December 2018;

² Fiona MacAulay was appointed on 10 July 2018;

³ Mark Hughes was appointed on 18 April 2018;

⁴ David Peattie resigned on 21 March 2017;

⁵ Andrew Hay resigned on 13 February 2018;

⁶ Peter Young resigned on 21 March 2017;

⁷ Hywel John was appointed on 21 March 2017, resigned on 13 September 2017

The salary amounts are those cash amounts paid to directors and key management personnel during the year. The share-based payment amounts represent the fair value of options issued and/or expensed in the year, for both LTIPs and those in lieu of cash salary and/or director fees paid.

In addition to the above, an amount of £470 was paid in employer pension contributions for Mark Hughes.

Social security costs for the year for key management personnel were £134k (2017 - £53k).

For the current directors at 31 December 2018, the service agreements for Mark Hughes, Andrew Hockey, Martin Ruscoe and Charles Hendry provide that only a proportion of the full contractual amount will be paid in cash with the balance to be settled in share options granted.

The proportions paid in 2018 for all directors were 100% for Fiona MacAulay, 75% for each of Mark Routh, Andrew Hockey, Mark Hughes and other key management personnel and 50% for Martin Ruscoe, Andrew Hay and Charles Hendry.  For each six-month interval, ending on 28 (or 29) February and 31 August respectively, the Company settles the difference between the reduced rate and the full rate through the granting of options over ordinary shares of the Company at the volume-weighted average share price over the period to which they relate.  Amounts of salary and/or fees outstanding at 31 December 2018 to which these terms relate totalled £76k (31 December 2017 - £60k) for directors and key management personnel and £11k (2017 - £9k) for other personnel. These were subsequently settled in share options, issued on 1 March 2019.

Directors' interests in options on 1p ordinary shares of the Company at 31 December 2018 were as follows:

	Granted	Total 31 Dec 2017	Awarded / (Exercised) in 2018	Total 31 Dec 2018	Exercise price	Expiry date
Andrew Hockey	1 Sep 2017	110,800	-	110,800	1p	31 Aug 2022
	1 Mar 2018	-	102,537	102,537	1p	28 Feb 2023
	1 Mar 2018	-	1,600,000	1,600,000	20p	28 Feb 2028
	1 Sep 2018	-	128,700	128,700	1p	31 Aug 2023
Mark Hughes	27 Jul 2018	-	1,000,000	1,000,000	35p	27 July 2028
	1 Sep 2018	-	62,417	62,417	1p	31 Aug 2023
Martin Ruscoe1	1 Sep 2017	44,699	-	44,699	1p	31 Aug 2022
	1 Mar 2018	-	34,179	34,179	1p	28 Feb 2023
	1 Sep 2018	-	30,888	30,888	1p	31 Aug 2023
Charles Hendry	1 Sep 2017	39,745	-	39,745	1p	31 Aug 2022
	1 Mar 2018	-	34,179	34,179	1p	28 Feb 2023
	1 Sep 2018	-	30,888	30,888	1p	31 Aug 2023

¹ Options granted to South Riding Consultancy Limited, a company in which Martin Ruscoe is a majority shareholder and a director.

Note 5.            Finance expense

		2018	2017
		£000	£000
	Interest on loans	1,493	1,092
	Interest on deferred payment creditors	373	12
	Amortisation of loan finance charges	617	411
	Current year loan finance charges	49	44
	Current year finance charges on deferred payment creditors	-	122
	Unwinding of deferred consideration provisions	592	153
		________	________
		3,124	1,834
		________	_________

Note 6.            Taxation

a) Current taxation

There was no tax charge during the year as the Group loss was not chargeable to corporation tax.  Applicable expenditures to-date will be accumulated for offset against future tax charges.

The reasons for the difference between the actual tax charge for the year and the standard rate of corporation tax in the United Kingdom applied to profits for the year are as follows:

		2018	2017
		£000	£000
	Loss for the year	(5,644)	(2,751)
	Income tax expense	-	-
		_________	_________
	Loss before income taxes	(5,644)	(2,751)
	Expected tax credit based on the standard rate of United Kingdom corporation tax at the domestic rate of 40% (2017: 40%)	(2,258)	(1,100)
	Difference in tax rates	826	(244)
	Expenses / (income) not deductible for tax purposes	137	(220)
	Income not taxable/allowable	(2,617)	(3,107)
	Unrecognised taxable losses carried forward	3,912	4,671
		_________	_________
	Total tax expense	-	-
		_________	_________

b) Deferred taxation

Due to the nature of the Group's E&P activities there is a long lead time in either developing or otherwise realising E&P assets. The amount of deductible temporary differences, unused tax losses and unused tax credits for which no deferred tax asset is recognised in the statement of financial position is £80.72 million (2017: £57.72 million). Included within this figure are accelerated capital allowances of £32.6 million (2017: £18.1 million).

The Group has not recognised a deferred tax asset at 31 December 2018 on the basis that the Group would expect the point of recognition to be when the Group has some level of production history showing that the Group is making profits in line with the underlying economic model which would support the recognition.

Note 7.            Loss per share

	2018	2017
	£000	£000
Loss for the year attributable to shareholders	(5,644)	(2,751)
	___________	___________
Weighted average number of ordinary shares - basic and diluted	123,581,926	109,538,499
	___________	___________
Loss per share in pence - basic and diluted	4.6p	2.5p

Diluted loss per share is calculated based upon the weighted average number of ordinary shares plus the weighted average number of ordinary shares that would be issued upon conversion of potentially dilutive share options and warrants into ordinary shares.  As the result for 2018 was a loss, the options and warrants outstanding would be anti-dilutive.  Therefore, the dilutive loss per share is considered as the same as the basic loss per share.

Note 8.            Intangible assets

Group

	Exploration & evaluation assets	Company & IT software assets	Total	Exploration & evaluation assets	Company & IT software assets	Total
	2018	2018	2018	2017	2017	2017
	£000	£000	£000	£000	£000	£000
At cost
At beginning of the year	22,402	3	22,405	27,923	3	27,926
Additions	2,351	4	2,355	1,484	-	1,484
Disposals	(34)	-	(34)	-	-	-
Reclassified as Development & Production assets	-	-	-	(7,005)	-	(7,005)
	_________	_________	________	________	________	________
At end of the year	24,719	7	24,726	22,402	3	22,405
	_________	_________	________	________	________	________
Impairments and write-downs
At beginning of the year	(22,217)	(2)	(22,219)	(22,098)	(1)	(22,099)
DD&A	-	(2)	(2)	-	(1)	(1)
Net Impairment	(184)	-	(184)	(119)	-	(119)
Disposals	34	-	34	-	-	-
	_________	_________	________	________	________	________
At end of the year	(22,367)	(4)	(22,371)	(22,217)	(2)	(22,219)
	_________	_________	________	________	________	________
Net book value
At 31 December 2018	2,352	3	2,355
A t 1 January 2018	185	1	186
At 1 January 2017	5,825	2	5,827

E&E assets at 31 December 2018 comprise the Group's interest in the Harvey and Abbeydale appraisal prospects and the Goddard pre-development prospect.

An impairment charge of £184k was recognised during the year reflecting those post 2016 drilling expenses and licence administration costs incurred on the previously impaired Skipper asset, Licence P1609. Licence P2122 which had been relinquished in 2017, was formally released from the balance sheet in 2018.

Note 9.            Property, plant and equipment

Group	D&P assets	Pipeline assets	Company & admin assets	Total	D&P assets	Company & admin assets	Total
	2018	2018	2018	2018	2017	2017	2017
	£000	£000	£000	£000	£000	£000	£000
At cost
At beginning of the year	21,316	-	34	21,350	7,506	30	7,536
Additions	9,676	10,447	40	20,163	825	4	829
Reclassified from current assets	200	-	-	200	-	-	-
Initial Thames Pipeline decommissioning security	-	500	-	500	-	-	-
Reclassified from E&E assets (see Note Note 8)	-	-	-	-	7,005	-	7,005
Blythe asset acquisition (Note Note 10)	(392)	-	-	(392)	3,078	-	3,078
Vulcan Satellites asset acquisition (Note Note 10)	(220)	-	-	(220)	2,902	-	2,902
	________	______	_________	______	_________	_________	______
At end of the year	30,580	10,947	74	41,601	21,316	34	21,350
	________	______	_________	______	_________	_________	______
Accumulated depreciation
At beginning of the year	-	-	(14)	(14)	-	(6)	(6)
DD&A	-	-	(19)	(19)	-	(8)	(8)
	________	______	_________	______	_________	_________	______
At end of the year	-	-	(33)	(33)	-	(14)	(14)
	________	______	_________	______	_________	_________	______
Net book value
At 31 December 2018	30,580	10,947	41	41,568
At   1 January 2018	21,316	-	20	21,336
At 1 January 2017	7,506	-	24	7,530

All development and production assets are awaiting approval from the OGA expected 31 March 2019.

Amounts paid as decommission security guarantees in respect of both the Elland P039 Licence suspended well, £200k (paid on acquisition to the prior owners of the Vulcan Satellites in October 2016 and previously held as a current asset) and the Initial Thames Pipeline Decommissioning Security, £500k (paid on completion of the Thames Pipeline acquisition in April 2018) have been classified as fixed assets at 31 December 2018.

Note 10.          Asset Acquisitions

Vulcan Satellites

On 28 October 2016, the Company announced the completion of the acquisition of Oyster Petroleum Limited, from Verus Petroleum, comprising the Vulcan Satellites.  This has been accounted for as an asset acquisition given the status of the projects held by Oyster Petroleum on the acquisition date.  Under the terms of the agreement the Company paid £1 million, plus interim cash adjustments payable at completion.  In accordance with the Vulcan Satellites purchase agreement a further £0.75 million was payable nine months after completion and was subsequently paid on 1 August 2017.  Further payments of £3.25 million are payable upon achievement of certain further milestones which are;

·      £1.75 million on FDP approval and

·      £1.50 million on first gas production.

After further work on the project during 2017 and 2018, the achievement of future milestones, which are now considered more certain than not and as the transaction was considered an asset acquisition, these future payments have therefore been recognised in the financial statements and recorded within the cost base of the Vulcan Satellites asset.  See Note Note 15 for further details.

		2018	2017
		£000	£000
At 1 January		2,902	-
Milestone payments recognised within D&P assets		-	2,902 (Note 9)
Discount adjustment on future milestone payments		(220) (Note 9)	-
At 31 December		2,682	2,902

Blythe

On 21 June 2016, the Company announced the completion of the additional 50% operated stake in the Blythe field, thereby increasing its interest to 100%.  The consideration comprised an upfront payment of £1.50 million, plus interim cash adjustments payable at completion with deferred consideration of a further USD 5.00 million to be paid at first gas production.

Given the USD 5.00 million is dependent on achievement of a future milestone event, which is now considered more certain than not, and the transaction is considered an asset acquisition, this amount of £3,078k has now been recognised in the financial statements and recorded within the cost base of the Blythe asset.  See Note 15 for further details.

		2018	2017
		£000	£000
At 1 January		3,078	-
Milestone payments recognised within D&P assets		-	3,078 (Note 9)
Discount adjustment on future milestone payments		(392) (Note 9)	-
At 31 December		2,686	3,078

Note 11.          Investments

		Shares	Loans
		in Group	to Group
	Company	companies	companies	Total
		£000	£000	£000
	At cost
	At 1 January 2017	14,514	11,995	26,509
	Additions	2,902	285	3,187
		_________	_________	_________
	At 31 December 2017	17,416	12,280	29,696
	Additions	(219)	17,246
		_________	_________	_________
	At 31 December 2018	17,197	29,526
	Impairment
	At 1 January 2017	-	(1,870)	(1,870)
	Impairment reversal	-	1,870	1,870
		_________	_________	_________
	At 31 December 2017	-	-	-
	Impairment	-	-	-
		_________	_________	_________
	At 31 December 2018	-	-	-
	Net book value
	At 31 December 2018	17,197	29,526	46,723
	At 1 January 2018	17,416	12,280	29,696
	At 1 January 2017	14,514	10,125	24,639

The Company has undertaken not to seek repayment of loans from other Group subsidiary companies until each subsidiary has sufficient funds to make such payments however they are technically due on demand.  These loans are non-interest bearing.

The impairment of £1.87 million taken on loans to Group companies in prior years was reversed in 2017.

The Company's subsidiaries, all registered at 60 Gracechurch Street, London EC3V 0HR, are as follows:

		Country of	Area of
	Directly held	incorporation	operation	%
	IOG Infrastructure Limited	United Kingdom	United Kingdom	100
	IOG North Sea Limited	United Kingdom	United Kingdom	100
	IOG UK Limited	United Kingdom	United Kingdom	100
	Avalonia Energy Limited (dormant)	United Kingdom	United Kingdom	100
	Avalonia Goddard Limited (dormant)	United Kingdom	United Kingdom	100
	Avalonia Abbeydale Limited (dormant)	United Kingdom	United Kingdom	100

IOG Infrastructure Limited completed the Thames Pipeline acquisition on 16 April 2018 and became an active subsidiary at that time.  All three active subsidiaries are now engaged in the business of oil and gas appraisal, development and/or operations in the UK North Sea.

The three dormant companies were incorporated in 2H18 and have been made available to support any potential Group restructure following refinancing of the Group.

The financial reporting periods for each subsidiary entity are consistent with the Company and end on 31 December.

Note 12.          Interests in production licences

All ten Group UK Offshore Production Licences, held at 31 December 2018, are owned 100% by either IOG North Sea Limited or IOG UK Limited. The Thames Pipeline P370 asset is owned 100% by IOG Infrastructure Limited.

Note 13.          Other receivables and prepayments

		2018	2017
		£000	£000
	Group
	VAT recoverable	311	285
	Prepayments	361	465
	Debtors	-	18
	Decommissioning guarantees (Note 9)	-	200
		_________	_________
		672	968
		_________	_________
	Company
	VAT recoverable	311	285
	Prepayments	361	465
	Debtors	-	17
		_________	_________
		672	767
		_________	_________

Included in 2018 Prepayments (both Group and Company) are financing costs of £291k (2017: £nil) incurred, cumulative at 31 December 2018, on progressing further refinancing for the Company and Group. These will be either transferred to equity (share capital issue costs), set off against debt, or expensed to the Statement of Comprehensive Income, dependent upon the outcome of such refinancing. Included in 2017 Prepayments (both Group and Company) is capital of £408k representing expenditure incurred, cumulative to date at 31 December 2017, on progressing the Thames Pipeline deal acquisition and completion. This was transferred to PPE within the Group on acquisition completion of the Thames Pipeline facility in April 2018.

Note 14.          Current liabilities

		2018	2017
		£000	£000
	Group
	Loans	6,934	-
	Trade payables	5,961	4,827
	Accruals	3,467	569
	Contingent consideration payable (see Note 15)	1,709	1,642
		_________	_________
		18,071	7,038
		_________	_________
	Company
	Trade payables	5,961	4,827
	Accruals	401	174
	Contingent consideration payable (see Note 15)	1,709	1,642
		_________	_________
		8,071	6,643
		_________	_________

Accruals for the Group have increased significantly in the period, due to the value of SNS Project work undertaken for the year to 31 December 2018, which remains unbilled by vendors and suppliers as at 31 December 2018.

Of the Group's current liabilities at 31 December 2018:

·      £6.93 million (2017: £nil) was owing to LOG consisting £5.54 million principal and £1.39 million interest. These loans accrue interest at LIBOR+9%. See also below Note 15;

·      Trade payables consist Skipper deferred creditors £2.22 million (2017: £4.46 million), SNS Project creditors £3.42 million (2017: £0.18 million) and other creditors £0.32 million (2017: £0.19 million);

·      Accrued expenditures consist SNS Projects £3.07 million (2017: £0.42 million) and other accruals £0.40 million (2017: £0.15 million); and

·      Verus Petroleum deferred consideration payable £1.71 million (2017: £1.64 million).

Note 15.          Non-current liabilities

		2018	2017
		£000	£000
	Group
	Long-term loans	22,884	12,394
	Contingent consideration payable	4,478	4,371
	Decommissioning provision	5,640	3,598
		_________	_________
		33,002	20,363
		_________	_________
	Company
	Long-term loans	14,054	-
	Contingent consideration payable	1,259	1,259
		_________	_________
		15,313	1,259
		_________	_________

Long-term loans:

The amounts drawn on LOG loans at 31 December 2018 were as follows:

Loan Facility	Entity	Effective Date	Principal	Interest
£2.75 million facility1	IOG North Sea Limited	7 December 2015	£2.75 million	£0.66 million
£0.80 million facility1	IOG North Sea Limited	11 December 2015	£0.80 million	£0.19 million
£10.00 million facility2	IOG North Sea Limited	5 February 2016	£10.00 million	£1.67 million
£10.00 million facility2	IOG plc	21 February 2018	£10.00 million	£0.67 million
£15.00 million facility1	IOG plc	13 September 2018	£7.15 million	£0.14 million

¹ Warrants were issued to LOG in respect of these facilities. The valuation of these warrants is detailed in Note Note 16 and is amortised over the life of the facilities.

² Both these 2016 and 2018 £10.00 million loans are convertible into ordinary shares of 1p in the Company at 8p and 19p respectively.

The balance on the Group's long-term loans at 31 December 2018 is represented by drawings of £30.70 million (2017: £11.91 million) plus accrued interest of £3.33 million (2017: £1.09 million) on these LOG facilities, less the non-amortised value £4.21 million (2017: £0.61 million) of loan finance (which includes both the non-amortised amount of warrants as detailed above and prepaid financing costs), less the £6.93 million included in current liabilities (2017: £nil). Interest accrued during the year was £2.24 million (2017: £0.88 million) of which £0.75 million (2017: £0.02 million) has been capitalised to SNS Projects

The interest rate on all LOG loans is LIBOR+9% for the duration of the term other than the September 2018 £15.00 million facility where the rate increases to LIBOR+11% from 1 December 2018.  These interest rates are determined as market debt rates and hence no equity element has been recognised for either of the £10.00 million convertible loans.

The LOG loans are securitised by guarantees over the assets of IOG North Sea Limited, IOG UK Limited and IOG Infrastructure Limited. These guarantees are considered to be insurance contracts and accounted for in accordance with the provisions of IFRS 4.

Contingent consideration payable:

As indicated in Note Note 10, the Group is required under the terms of the 2016 acquisition of the additional 50% of Blythe and the 2016 acquisition of Vulcan Satellites, to make further amounts payable on both the FDP approval (Vulcans), being a current liability expected 31 March 2019, and first gas (Blythe and Vulcans) being non-current liabilities, see below.

As disclosed in the 2017 financial statements, these milestone events triggering deferred consideration payments are now considered to be more certain than not and a non-current amount of £4.37 million was recognised. These amounts have been provided for and the payments discounted to the point where the Board expect the milestones to be achieved based on the current development programme.  Timings for these non-current payments, pursuant to first gas, are now anticipated to be 31 October 2020 (Vulcans) and 31 January 2021 (Blythe).

The movements in the year are as follows:

	2018	2017
	£000	£000
at 1 January	6,013	-
Additional Blythe consideration	-	3,078
Additional Vulcans consideration	-	2,901
Prospective adjustment for change in payment dates (Note 10)	(612)	-
Foreign exchange	194	(118)
Unwinding of discount	592	152
at 31 December	6,187	6,013

Given the timing of the expected payments, the total balance is split between current and non-current as below:

	2018	2017
	£000	£000
Current contingent consideration payable (FDP approval)	1,709	1,642
Non-Current contingent consideration payable (first gas)	4,478	4,371
	6,187	6,013

Decommissioning provision:

	2018	2017
	£000	£000
at 1 January	3,598	3,598
additions: Thames Pipeline	2,042	-
At 31 December	5,640	3,598

The Group has regulatory and financial obligations in respect of decommissioning a suspended well on the Elland Licence P039 - £3.60 million (2017: £3.60 million) and decommissioning the Thames Pipeline - £2.04 million (2017: £nil).

A full decommissioning estimate for the Elland suspended well remains uncertain until an appropriate drilling programme has been reviewed and considered for the Elland development, which may include the abandonment of that particular well. The timing and thus payment of this decommissioning program remains inherently uncertain. As per Note Note 1, the current estimate of £3.60 million is based upon a recent technical valuation.

The £2.04 million provision for the Thames Pipeline decommissioning obligation has been calculated on a discounted cash flow basis, whereby the present value of the regulatory marine surveys has been inflated at 2% and then discounted at the risk-free discount rate of 1.8%. It has been estimated that the Thames Pipeline has a useful life over the next 25 years; however, the judgements made on this and other variables, currently provided by the OGA, are inherently uncertain. 

Note 16.          Equity share capital

			Share	Share
			capital	premium	Total
		Number	£000	£000	£000
	Authorised, allotted, issued and fully paid
	At 1 January 2017
	- Ordinary shares of 1p each	109,268,163	1,093	20,460	21,553
	Equity issued	462,206	5	-	5
	Creditor settlement via issue of shares	10,479,260	105	1,877	1,982
		_________	_________	_________	_________
	At 31 December 2017
	- Ordinary shares of 1p each	120,209,629	1,203	22,337	23,540
	Equity issued	6,658,527	66	-	66
		_________	_________	_________	_________
	At 31 December 2018
	- Ordinary shares of 1p each	126,868,156	1,269	22,337	23,606
		_________	_________	_________	_________

2017:

During 2017, the Company issued 462,206 ordinary shares at a subscription price of 1p from the exercise of management and other personnel share options.

On 29 December 2018, the Company issued 10,479,260 ordinary shares in lieu of Skipper creditor settlement cash payments to both GE Oil & Gas UK Limited and AGR Well Management Limited.

2018:

During 2018, the Company issued 6,658,527 ordinary shares at a subscription price of 1p from the exercise of management and other personnel share options.

Share options and warrants

During the current and prior year, the Company granted share options under its share option plans as follows:

	Number	Price	Date of Grant	Expiry
1 January 2017	11,029,143	1p
Salary/fee sacrifice options	905,099	1p	1 Mar 2018	28 Feb 2023
Salary/fee sacrifice options	5,718	1p	28 Jun 2017	28 Jun 2022
Salary/fee sacrifice options	845,912	1p	1 Sep 2017	31 Aug 2022
Options exercised	(462,206)
31 December 2017	12,323,666	1p
Salary/fee sacrifice options	483,166	1p	1 Mar 2018	28 Feb 2023
LTIP options	2,600,000	20p	1 Mar 2018	28 Feb 2028
LTIP options	1,000,000	35p	27 Jul 2018	26 Jul 2028
Salary/fee sacrifice options	534,420	1p	1 Sep 2018	31 Aug 2023
Options exercised	(6,658,527)
31 December 2018	10,282,725	9.11p

Of the remaining personnel options, 11,029,143 outstanding at 1 January 2017, 308,860 were exercised during 2017.  Of those personnel options granted during 2017, 153,346 were exercised during 2017. Total personnel options exercised in 2017 is thus 462,206.

Of the remaining staff options, 12,323,66, outstanding at 31 December 2017, 6,652,717 were exercised during 2018.  Of those staff options granted during 2018, 5,810 were exercised during 2018. Total personnel options exercised in 2018 is thus 6,658,527.

The fair value of these options exercised was transferred from the Share-based Payment Reserve to Accumulated Loss.

All salary/fee sacrifice options outstanding at 31 December 2018 were issued at an exercise price of 1p per share and carry no additional performance conditions. All LTIP options outstanding at 31 December 2018 were issued to option holders with, other than the target price, several performance criteria including the delivery, measurement, control and management of an appropriate HSE statement and policy together with a Group-wide HSE focussed culture.

The remaining average contractual life of the 10,282,725 options outstanding at 31 December 2018 (2017 - 12,323,666) was 4.91 years at that date (2017 - 2.14 years) of which 6,682,725 were exercisable at 31 December 2018 (2017 - all 12,323,666 options were exercisable at 31 December 2017).

The weighted average exercise price of the options remaining was 9.11p at 31 December 2018 (2017 - 1p).

A further 612,856 options were exercised during March 2019; however, no further share options have been issued during 2019 as at the date of this report.

The Company calculates the value of personnel salary/fee sacrificed share-based compensation as the actual value of the sacrificed amount.  This is deemed to be the fair value of such awards.  The fair value of sacrificed salary/fee share options granted in 2018 is calculated as £236k (2017 - £298k) and this has been charged to the Statement of Comprehensive Income.  The exercise price of such awards was determined as 1p (2017 - 1p).

The Company calculates the fair value of LTIP share-based compensation using a Black-Scholes options pricing model. The fair value of LTIP options granted in 2018 is calculated as £633k (2017 - £nil), of which £141k (2017 - £nil) has been charged to the Statement of Comprehensive Income, being the amortised amount over the vesting period attributable to the current year. The exercise price of these options has been determined as 20p for those issued on 1 March 2018 and 35p for those issued on 27 July 2018.

Further details for directors are provided in Note Note 4.

The Company has granted warrants in the current year as follows (2017: lapsed warrants):

	Number	Price	Date of Grant	Expiry
1 January 2017	14,103,397	10.48p
Lapsed - Darwin Strategic	(326,087)
31 December 2017	13,777,310	9.64p
London Oil & Gas Ltd	20,000,000	32.18p	13 Sep 2018	12 Sep 2023
31 December 2018	33,777,310	22.98p

326,087 warrants awarded to Darwin Strategic in June 2014 expired and lapsed on 4 September 2017. Accordingly, the fair value of these awards was transferred from the Share-based Payment Reserve to Accumulated Loss.

The Company calculates the value of share-based compensation using the Black-Scholes option pricing model to estimate the fair value of warrants at the date of grant.

The fair value of 20,000,000 warrants granted to London Oil & Gas Limited on 13 September 2018 was calculated as £4.19 million, all of which was recognised as an issue cost of the £15 million LOG loan facility, held at amortised cost using the effective interest method. The exercise price of these warrants was determined as 32.18p.

The following assumptions were applied in the LOG warrant award calculation:

Risk free interest rate	1.50%
Dividend yield	nil
Weighted average life expectancy	4 years
Volatility factor	96.45%

A volatility of 96.45% has been applied based upon the Company's share price over the period from the Company's listing on AIM on 30 September 2013 until 13 September 2018.

The remaining average contractual life of the 33,777,310 warrants outstanding at 31 December 2018 (2017 - 13,777,310) was 3.18 years at that date (2017 - 1.97 years).  All such warrants were exercisable at 31 December 2018.

The weighted average exercise price of the warrants remaining was 22.98p at 31 December 2018 (2017 - 9.64p).  No further warrants have been issued or exercised as at 28 March 2019.

Note 17.          Cash and cash equivalents

		2018	2017
	Group and Company	£000	£000
	Cash at bank	702	145
		_________	_________

Note 18.          Company loss for the year

The Company has taken advantage of the exemption allowed under Section 408 of the Companies Act 2006 and has not presented its own Statement of Comprehensive Income in these financial statements.

The Company loss for the year was £2,604k (2017: profit £1,176k).

Note 19.          Operating Leases

	Group		Company
	2018	2017	2018	2017
	£000	£000	£000	£000
Minimum lease payments under operating leases recognised as a gross expense in the year	73	64	73	64
Minimum lease payments under operating leases recognised as capital expenditure in the year	87	-	-	-

At 31 December 2018, outstanding commitments for operating lease payments fall due as follows:

	Group		Company
	2018	2017	2018	2017
	£000	£000	£000	£000
Within one year	187	73	73	73
In the second to fifth year inclusive	454	200	126	200

Operating lease payments represent the Group and Company's share of office lease rental payments at 10 Arthur Street, London EC4R 9AY, together with the Crown Estate lease for the rights for the Thames Pipeline to cross the foreshore at Bacton.

Note 20.          Financial instruments

Significant accounting policies

Details of the significant accounting policies in respect of financial instruments are disclosed in Note Note 1 of the financial statements.

Financial risk management

The Board seeks to minimise its exposure to financial risk by reviewing and agreeing policies for managing each financial risk and monitoring them on a regular basis.  At this stage, no formal policies have been put in place to hedge the Group and Company's activities to the exposure to currency risk or interest risk and no derivatives or hedges were entered during the year.

General objectives, policies and processes

The Board has overall responsibility for the determination of the Group and Company's risk management objectives and policies and, whilst retaining ultimate responsibility for them, it has delegated the authority for designing and operating processes that ensure the effective implementation of its objectives and policies to the Group's finance function.  The Board receives regular reports from the Chief Financial Officer through which it reviews the effectiveness of the processes put in place and the appropriateness of the objectives and policies it sets.

The Group is exposed through its operations to the following financial risks:

•    Liquidity risk;

•    Credit risk;

•    Cash flow interest rate risk; and

•    Foreign exchange risk

The overall objective of the Board is to set policies that seek to reduce risk as far as possible without unduly affecting the Group and Company's competitiveness and flexibility.  Further details regarding these policies are set out below.

Principal financial instruments

The principal financial instruments used by the Group and Company, from which financial instrument risk may arise are as follows:

•    Cash and cash equivalents

•    Loans

•    Trade and other payables

Liquidity risk

The Group and Company's policy is to ensure that it will always have sufficient cash to allow it to meet its liabilities when they become due.  To achieve this aim, it seeks to maintain readily available cash balances supplemented by borrowing facilities sufficient to meet expected requirements for a period of at least twelve à eighteen months for personnel costs, overheads, working capital and as commitments dictate for capital spend.

Rolling cash forecasts, which are essentially the current budgeting and reforecasting process, identifying the liquidity requirements of the Group and Company, are produced frequently.  These are reviewed and approved regularly by management and the Board to ensure that sufficient financial resources are made available.  The Group's oil and gas exploration and development activities are currently funded through the Company. The Board has identified that further funds will be required within the next twelve months and are implementing various courses of action as detailed in the Finance Review to ensure that adequate funding is available.

			Greater than	Greater	Total
		6 months	6 months, less	than	undiscounted	Carrying
		or less	than 12 months	12 months		amount
2018 Group		£000	£000	£000	£000	£000
Current financial assets
Cash and cash equivalents		702	-	-	702	702
		________	_________	________	_________	________
		702	-	-	702	702
		________	_________	________	_________	________
Current financial liabilities
Trade and other payables		6,017	-	-	6,017	5,961
Deferred consideration		1,750	-	-	1,750	1,709
Accruals		3,467	-	-	3,467	3,467
Loans		3,138	4,213	-	7,351	6,934
Non-current financial liabilities
Deferred Consideration		-	-	5,426	5,426	4,478
Loans		-	-	34,118	34,118	22,884
Decommissioning Provisions		-	-	6,291	6,291	4,331
		________	_________	________	_________	________
		14,372	4,213	45,835	64,420	49,764
		________	_________	________	_________	________
2017 Group
Current financial assets
Cash and cash equivalents		145	-	-	145	145
		________	_________	________	_________	________
		145	-	-	145	145
		________	_________	________	_________	________
Current financial liabilities
Trade and other payables		1,225	5,979	208	7,412	7,038
Non-current financial liabilities
Provisions		-	-	5,206	5,206	4,371
Loans		-	-	15,705	15,705	13,000
		________	_________	________	_________	________
		1,225	5,979	21,119	28,323	24,409
		________	_________	________	_________	________

			Greater than	Greater	Total
		6 months	6 months, less	than	undiscounted	Carrying
		or less	than 12 months	12 months		amount
2018 Company		£000	£000	£000	£000	£000
Current financial assets
Cash and cash equivalents		702	-	-	702	702
Loans to Group companies		-	-	29,526	29,526	29,526
		________	_________	________	_________	________
		702	-	29,526	30,228	30,228
		________	_________	________	_________	________
Current financial liabilities
Trade and other payables		6,017	-	-	6,017	5,961
Deferred Consideration		1,750	-	-	1,750	1,709
Accruals		402	-	-	402	402
Non-current financial liabilities
Deferred Consideration		-	-	1,500	1,500	1,259
Loans		-	-	23,543	23,543	14,054
		________	_________	________	_________	________
		8,169	-	25,043	33,212	23,385
		________	_________	________	_________	________
2017 Company
Current financial assets
Cash and cash equivalents		145	-	-	145	145
Loans to Group companies		-	-	12,280	12,280	12,280
		________	_________	________	_________	________
		145	-	12,280	12,425	12,425
		________	_________	________	_________	________
Current financial liabilities
Trade and other payables		1,038	5,979	-	7,017	6,643
Non-current financial liabilities
Deferred Consideration		-	-	1,500	1,500	1,259
		________	_________	________	_________	________
		1,038	5,979	1,500	8,517	7,902
		________	_________	________	_________	________

Credit risk

Credit risk arises principally from the Group's and Company's other receivables, cash and cash equivalents, and loans to subsidiaries (Company). It is the risk that the counterparty fails to discharge its obligation in respect of the instrument. The credit risk on liquid funds is limited because the counterparties are banks with credit ratings assigned by international credit rating agencies. The Group places funds only with selected organisations with ratings of 'A' or above as ranked by Standard & Poor's for both long and short-term debt. All funds are currently placed with the National Westminster Bank plc. IFRS 9 provides an updated framework for the accounting recognition and treatment of the Group's and Company's other receivables held. The Group and Company adopted IFRS 9 in this financial year. Management have chosen not to apply the standard retrospectively on the basis of the impact not being material, both in terms of impairment or additional Expected Credit Losses ('ECLs') recognised. The Company has assessed that the resulting impact on the financial statements is not material. 

The Group made investments and advances into subsidiary undertakings during the year and these mostly relate to the funding of the SNS Hub Development Projects, and the Company expects to recover these loans when these Projects start to generate positive cash flows. Loans to subsidiary undertakings are recognised at amortised cost in accordance with IFRS 9. The loans have no maturity date and are not repayable until the respective subsidiary entity has sufficient cash to repay the loan. The Board has accordingly assessed the expected repayment dates based on the strategic forecasts approved by the Board.

As at the Balance Sheet date, the Group and Company do not have any other external receivables (2017: £17k).

IFRS 9 introduces a new impairment model that requires the recognition of ECLs on financial assets at amortised cost. The ECL computation must also consider forward looking information to recognise impairment allowances earlier. IFRS 9 consequently is likely to increase the volatility of impairment allowances as the economic outlook changes although cash flows and cash losses are expected to remain unchanged. Intercompany exposures, where appropriate, are also in scope under IFRS 9. The Company has assessed the loans made to subsidiary undertakings on the basis of the relevant subsidiaries' long-term strategic forecasts and alongside the Board's commercial rationale for providing the specific loan. The loans are not repayable on demand and are expected to be repaid once the underlying assets progress into the production phase when cash inflows are generated. Based on the methodology set out by the standard, the Board has for each intercompany loan, assessed the probability of the default, the loss given default and the expected exposure to compute the ECLs. The Board has incorporated relevant medium and long-term macroeconomic forecasts in their assessment which is included as a principle consideration in the entity's strategic forecasts. Such factors include oil price sensitivities, funding requirements, reserve and resource estimates. The Board has concluded that any ECLs to be recognised are not material to these financial statements and that there has been no significant increase in credit risk that would warrant the recognition of a material provision. Accordingly, the Company has not recognised any expected credit loss for the balances owed by subsidiary undertakings recognised on the Balance Sheet at amortised cost. The Group and Company do not hold any collateral as security for any external financial instruments, or otherwise.

The maximum exposure to credit risk is the same as the carrying value of these items in the financial statements as shown below.

		Group			Company
		2018	2017		2018	2017
		£000	£000		£000	£000
Other receivables		-	17		-	17
Loans to subsidiaries		-	-		29,526	12,280
Cash and cash equivalents		702	145		702	145

Cash flow interest rate risk

Cash is essentially non-interest bearing. Loans and trade creditors are subject only to fixed interest rates (albeit with low volatility LIBOR+ variation); accordingly, commercial interest rates would have no significant impact upon the Group's and Company's result for the year ended 31 December 2018 (nor 31 December 2017).

Foreign exchange risk

At 31 December 2018, the Group's and Company's monetary assets and liabilities are denominated in GBP Sterling, the functional currency of the Group and each of its subsidiaries, other than USD 1,848k (£1,451k), EURO 717k (£644k) and NOK 891k (£81k) of current liabilities held by the Group and Company and USD 4,100k (£3,219k) of long-term liabilities held by the Group. This exposure gives rise to net currency gains and losses recognised in the Statement of Comprehensive Income.

A 10% fluctuation in the GBP sterling rate compared to USD would give rise to a £425k gain or £519k loss in the Group's Statement of Comprehensive Income and a £132k gain or £161k loss in the Company's Statement of Comprehensive Income.

A 10% fluctuation in the GBP sterling rate compared to EURO would give rise to a £58k gain or £72k loss in the Group and Company's Statement of Comprehensive Income.

A 10% fluctuation in the GBP sterling rate compared to NOK would give rise to a £8k gain or £9k loss in the Group and Company's Statement of Comprehensive Income.

The Group has no current revenues. The Group and the Company's cash balances are maintained in GBP Sterling which is the functional and reporting currency of each Group company.  Consequently, no formal policies have been put in place to hedge the Group and Company's activities to the exposure to currency risk.  It is the Group's policy to ensure that individual Group entities enter transactions in their functional currency wherever possible.  The Group considers this minimises any foreign exchange exposure.

Management regularly monitor the currency profile and obtain informal advice to ensure that the cash balances are held in currencies which minimise the impact on the results and position of the Group and the Company from foreign exchange movements.

Capital management

The primary objective of the Group's capital management is to maintain appropriate levels of funding to meet the commitments of its forward programme of appraisal and development expenditure, and to safeguard the entity's ability to continue as a going concern and create shareholder value.  The Director's consider capital to include equity as described in the Statement of Changes in Equity, and loan notes, as disclosed in Notes Note 14 and Note 15.  Prior to 1 January 2016, the Group has been principally equity financed, reflecting the early stage and consequent relatively high risk of its activities.  During 2016, 2017 and 2018 the Group made drawings of £30.70 million against its London Oil & Gas Limited loan facilities.

Borrowing facilities

The Group had £34.03 million of borrowings outstanding at 31 December 2018 (2017 - £13.00 million) including accrued interest.  It had in place further undrawn debt on the London Oil & Gas Limited facilities of a total £7.85 million excluding accrued interest, at that date. A further £3.925 million was drawn in January 2019 and £3.925 million outstanding remains.

Hedges

The Group did not hold any hedge instruments at the reporting date.

Note 21.          Financial commitments and contingent liabilities

The Group has contracted capital expenditure in the current period as part of the appraisal and development work programmes for the licences in which it participates:

		2018	2017
		£000	£000
	Authorised but not contracted	-	7,560
	Contracted	1,287	1,358
		_________	_________
		1,287	8,918
		_________	_________

All 2018 contracted amounts relate to contracted UKCS Licence Fee and associated OGA Levy payments (estimate) together with contracted service awards to suppliers procured for the development of the Group's SNS assets (Harvey well long lead items, project personnel and offshore engineering duty holder commitments). There are no further authorised amounts, at 31 December 2018, as the Group awaits the outcome of discussions and negotiations on Group fund raising and refinancing.

All 2017 capital commitments, in addition to contracted UKCS Licence Fee and associated OGA Levy payments, were owing to 2018 activities committed at 31 December 2017 in conjunction with the Group's participation in its UK North Sea operations.

Skipper:

As detailed in Note 24, Subsequent Events, the Skipper licence P1609 was relinquished in February 2019, discharging all contingent liabilities at that date.

Thames Pipeline:

Security in the sum of £0.50 million, the Initial Thames Decommissioning Pipeline Security Amount, was provided on completion of the Thames Pipeline SPA in April 2018.

Further security in the sum of £2.50 million, the Thames Decommissioning Pipeline Security Amount, is to be provided on the earlier of:

·      one month after the variation issued by the OGA to the Pipeline Works Authorisation to allow for the tie-in of one or more of the Group's fields; or

·      at the date of sale or alternative use of the Thames Pipeline

Cross-Guarantees:

The Company acts as guarantor to its subsidiary IOG North Sea Limited and its facilities with LOG. These cross guarantees are considered insurance contracts in accordance with IFRS4.

Note 22.          Related party transactions

Details of directors' and key management personnel remuneration are provided in Note Note 4.

Mark Hughes, COO, acquired 178,000 ordinary shares of 1p each in the capital of the Company and is the current holder of these shares at 31 December 2018. Mark is also the current holder of 1,062,417 share options at 31 December 2018; these were also acquired during the year.

South Riding Consultancy Limited ('SRCL') of which Martin Ruscoe is a director acquired a further 65,067 share options (2017: 113,254) and exercised nil share options (2017: 148,113) during the year. SRCL is the current holder of 148,113 shares and 109,766 share options as at 31 December 2018.

Details of loans and interest charged by LOG are detailed in Notes 14 and Note 15.  The relevant loans were issued to both IOG North Sea Limited and the Company.

Note 23.          Notes supporting statements of cash flows

Details of significant non-cash transactions

	2018	2017
	£000	£000
Equity consideration for settlement of liabilities	-	1,982

Group - Loans and borrowings
	Current  loans and borrowings £000	Non-current loans and borrowings £000	Total  loans and borrowings £000
At 1 January 2017	4,076	4,733	8,809
Drawdowns (Repayments)	(2,019)	6,372	4,353
Effects of foreign exchange	(15)	-	(15)
Debt converted into equity	(1,750)	-	(1,750)
Debt converted into current liability	(527)	-	(527)
Amortisation of finance fees	-	411	411
Interest accruing in period	235	878	1,113
At 31 December 2017	-	12,394	12,394

Of the interest accruing in the period, £22k was capitalised to D&P assets, leaving £1.09 million expensed to the Statement of Comprehensive Income (Note 5).

Group - Loans and borrowings
	Current  loans and borrowings £000	Non-current loans and borrowings £000	Total  loans and borrowings £000
At 1 January 2018	-	12,394	12,394
Drawdowns (Repayments)	-	18,787	18,787
Debt converted into current liability	6,934	(6,934)	-
Issue of warrants and finance fees	-	(4,225)	(4,225)
Amortisation of finance fees	-	617	617
Interest accruing in period	-	2,245	2,245
At 31 December 2018	6,934	22,884	29,818

Of the interest accruing in the period, £752k was capitalised to D&P and Pipeline assets, leaving £1.49 million expensed to the Statement of Comprehensive Income (Note 5).

Company - Loans and borrowings
	Current  loans and borrowings £000	Non-current loans and borrowings £000	Total  loans and borrowings £000
At 1 January 2018	-	-	-
Drawdowns (Repayments)	-	17,150	17,150
Issue of warrants and finance fees	-	(4,224)	(4,224)
Amortisation of finance fees	-	314	314
Interest accruing in period	-	814	814
At 31 December 2018	-	14,054	14,054

The Company was not subject to loans and borrowings in 2017.
 

Note 24.          Subsequent events

The key events after 31 December 2018 are as follows:

Fiona MacAulay was appointed non-executive Chair effective 1 January 2019.

Robin Storey was appointed General Counsel and Company Secretary on 9 January 2019.

Esa Ikaheimonen was appointed Non-Executive Director and Chair of the Audit Committee on 14 March 2019.

On 4 January 2019, it was announced that the Financial Conduct Authority ('FCA') was investigating the affairs of LCAF. LCAF was subsequently put into administration during February 2019. Furthermore, LOG entered administration on 19 March 2019. The Company has engaged with LOG and LCAF administrators who have agreed to restructure the LOG loans and have stated publicly that they will support IOG and the LOG/LCAF administration process will have no impact on the Company's business.

The Skipper licence, P1609, was formally relinquished on 11 February 2019, as determined by the OGA.

The Company announced on 25 February 2019 that it had initiated a focused farm-out process with a carefully selected shortlist of motivated and well-funded potential farm-in partners.

The Company announced on 5 March 2019 that it had received and promptly rejected an unsolicited pre-conditional proposal from RockRose Energy plc ('RockRose') in respect of a possible cash offer for the entire issued share capital of the Company at a price of 20 pence per Company share. Subsequently on 25 March 2019, the Company announced that RockRose had approached the joint administrators of LOG to acquire the entire debt and accrued interest due to LOG from the Company for the sum of £40 million in cash. The Board concluded to reject the proposal unequivocally and continue to state that this subsequent offer is a further transparent attempt by RockRose to deny both LOG's and LCAF's creditors, and by extension to LCAF's mini-bond holders, of fundamental value, seeking instead to reserve that value for the benefit of RockRose and those directly associated with RockRose. RockRose withdrew their proposal on 1 April 2019.

The Company announced on 1 April 2019 that it had conditionally placed 165,795,050 new ordinary shares of £0.01 each in the capital of the Company by way of a placing at a price of 10 pence per Ordinary Share to raise gross proceeds of approximately £16.6 million. In addition, a further proposed issue of 3,250,000 new Ordinary Shares by way of a subscription at a price of 10 pence per Ordinary Share by certain directors and key executives of the Company. Furthermore, the Company announced that it intends to launch an open offer to shareholders to raise approximately £2 million through the issue of approximately 20,128,580 new Ordinary Shares, also at an issue price of 10 pence per share. This Fundraising is conditional, inter alia, upon the approval of shareholders at a general meeting of the Company that will take place on or around 23 April 2019 and the admission of the relevant new Ordinary Shares to London AIM.

The Company announced on 1 April 2019, that concurrent to the Fundraising announcement above, the Company has restructured its debt with LOG (in administration) by rescheduling by twelve months an amount of £7.1 million of debt service due to LOG, the conversion of £1.64 million in interest due from LOG's existing convertible debt into 20,497,204 new Ordinary Shares and a one year maturity extension to existing warrants being those 13,277,310 warrants which were granted by the Company in December 2015.

 

END

 

 

FR EAFLDEFENEAF