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Final Results for the Year Ended 31 December 2017

29 Mar 2018 15:04

RNS Number : 4685J

Independent Oil & Gas PLC

29 March 2018

Independent Oil and Gas plc

Final Results for the Year Ended 31 December 2017

Independent Oil and Gas plc ("IOG" or the "Company") (AIM: IOG.L), the development and production focused oil and gas company, is pleased to announce its results for the Year Ended 31 December 2017.

Operational highlights:

· Strong progress made delivering its gas hub strategy in the UK Southern North Sea ('SNS') prioritising its core assets and acquisition opportunities

· Significant reserves and contingent resources upgrade, net 2P reserves now 303bcf (45bcf at Blythe Hub, 258bcf at Vulcan Satellites Hub.)

· Submitted the Blythe Hub Field Development Plan ('FDP'), comprising the Blythe and Elgood fields and Vulcan Satellites hub development FDP to the OGA

· Licence P1736 containing the Blythe gas discovery extended by 12 months to 31 December 2018

Licence P2342 comprising Block 48/25a including the western part of the Nailsworth field awarded by the OGA in the 29th Supplementary Offshore Oil and Gas Licensing Round

· Acquisition of Thames Gas Pipeline for a nominal consideration providing the proposed export route for IOG's Southern North Sea assets.

· Letters of Intent ('LoI') signed with key contractors on SNS Gas Development Project

· Significant Prospective Resources confirmed with Best Estimate Gross Prospective Resources of 114bcf (90 bcf on Block) and commitment well for Harvey

Financial highlights

· New £10 million convertible loan facility (the 'New Facility') successfully signed with existing lender LOG convertible ordinary shares in the Company at a conversion price of 19p, being a 15% premium to the closing share price of the Company post period end

· Cash balance at year end of £145k (2016: £247k) with available facilities from LOG to finance ongoing working capital requirements

· Approx £1.0 million remained to be drawn of the aggregate availability of £13.55 million from LOG (including accrued interest on the £10 million facility) at year end

· Loss for the year of £2.75 million (2016: £21.44 million loss)

· Successful conclusion to Skipper Well Creditors' discussions

Outlook

· Clear objective in 2018 to progress the SNS Dual Hub Project to FID and to FDP approval by demonstrating the viability of the recommissioned Thames Pipeline and progressing development planning and execution.

· Deliver an appropriate capital structure for the Company and obtain full financing for the SNS Hubs.

· Progress Harvey appraisal plans.

· Evaluate accretive production deals.

· Expand the portfolio through Licensing Round activity and acquisition.

Andrew Hockey, CEO of IOG, said:

"I am pleased to be able to report that 2017 has seen strong progress on all fronts for IOG on our UK Southern North Sea project. 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. The classification of our gas resources as reserves at the Vulcan Satellites Hub and Blythe Hub was an important milestone in the development of the company and we are making good progress in defining the development and putting in place the necessary funding to ensure its execution. Harvey provides exciting upside in our portfolio and we are planning to appraise it as soon as possible.

We have a busy work programme over the coming 12 months and the newly strengthened management and operations team are focused on successfully delivering our gas hub strategy and creating value for all our stakeholders."

-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)

+44 (0) 20 3879 0510

finnCap Ltd

Christopher Raggett / Anthony Adams(Corporate Finance)

+44 (0) 20 7220 0500

Camarco

Georgia Edmonds / Tom Huddart

+44 (0) 20 3757 4980

Chief Executive's Review

I am pleased to be able to report that 2017 has seen strong progress on all fronts for Independent Oil and Gas plc (the 'Company') and the Group ('IOG') on our UK Southern North Sea ('SNS') project. 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.

The first nine months of the year saw a step change in our understanding of the resource base at our 100% owned gas hubs, Blythe and the Vulcan Satellites and at our appraisal opportunity, Harvey. The high quality of our resource base was independently confirmed in October when ERC Equipoise ('ERCE') delivered a Competent Person's Report ('CPR') in which the Blythe and Vulcan Satellites Hub resources were upgraded from Contingent Resources to Reserves (Justified for Development).

Our gas portfolio now comprises 303 bcf of Proven and Probable ('2P') Reserves at the Blythe Hub (45 bcf) and the Vulcan Satellites Hub (258 bcf) and 114 bcf Gross Best Estimate Prospective Resources at Harvey, our exciting appraisal opportunity. Indeed, we were pleased to announce the publication by ERCE of a CPR in November that showed a best estimate gross unrisked post-tax NPV-10 of £159 million for the overall Harvey Structure.

Our extensive proprietary subsurface work means that we can now forecast production performance from our portfolio with our own reservoir models. Folding in our development team's approach to engineering studies and market analysis, we have been able to quantify the cost base associated with developing our portfolio and to submit Field Development Plans ('FDP') to the Oil and Gas Authority ('OGA') in July 2017 for the Blythe Hub (comprising the Blythe and Elgood Fields) and in October 2017 for the Vulcan Satellites Hub (comprising the Nailsworth, Elland and Southwark fields). We plan to develop our assets via four simple unmanned wellhead platforms and a subsea tieback, with up to ten long reach wells to be drilled. Final Investment Decision ('FID') is planned for August 2018 and first gas is planned for the fourth quarter of 2019. At Harvey we see material upside, sufficient to double the size of the Blythe Hub, 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.

The key to unlocking the value of our gas assets is the recommissioning of the 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 2017, we signed a Sales and Purchase Agreement ('SPA') with PL370 owners Perenco UK Limited, Tullow Oil SK Limited and Centrica to purchase the 90 km of the 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 ensure we will become pipeline operator in early 2018. Our engineering studies to date indicate that pipeline integrity should not be a barrier to the re-use of this equipment. To confirm our view, we are preparing to survey the exterior of PL370 and to carry out an extensive intelligent pigging programme to demonstrate its internal integrity in the first half of 2018. Assessment and refurbishment of the Bacton facilities where our pipeline comes ashore will follow later in 1H 2018.

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 Schlumberger (technical and project support), Offshore Design Engineering ('ODE') (duty holder, operations and maintenance contractor) and Heerema Fabrication Group ('Heerema') (offshore platform fabrication) and discussions are ongoing with drilling rig owners and subsea and pipeline fabrication and installation contractors.

We are also pleased that in July 2017 the OGA granted new licences over Nailsworth and in December 2017 granted a two-year extension of the Harvey licence and an extension of the Blythe licence for a further year. We look forward to working ever closer with the OGA as we seek to bring our SNS gas assets into production.

Successful development execution requires firm funding to be in place at FID and the Company has been hard at work to deliver this. The progress made in 2017 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. I am pleased to say that LOG has continued to offer support to the Company and in February 2018 we agreed a second convertible loan of £10 million at a conversion price of 19p/share. This second loan gives the Company scope to execute the necessary pigging, surveys and engineering studies to reach FID, targeted for August 2018. We were also pleased to announce in December the agreement of terms with the Skipper well creditors which placed the Group on a much firmer footing moving in to 2018.

With regard to post-FID development funding, in addition to conventional debt and equity finance, the Company continues to evaluate options to utilise finance linked to gas off-take and contractor finance. Debt markets for independent oil and gas operators have normalised considerably after the period of low oil prices and weak profitability in the North Sea over 2014-16. The Company's independently assessed 2P reserves of 303 bcf, equivalent to 54 MMBOE, provides a solid footing to secure an optimal development funding package for the portfolio during 2018.

For tangible progress to be made toward development, the Company obviously needs a high-quality team of individuals and this year we have strengthened our capability at all levels of the organisation. In March, we welcomed the Rt. Hon. Charles Hendry, former Energy Minister to the Board of Directors along with myself as Deputy Chief Executive. In parallel with strengthening the Board, our SNS Project Manager Graham Cox has added key individuals to his team including Jonathan Walker as Engineering Manager and Ian Pollard as HSE Manager both bringing material SNS experience to the project. Subsequently post period end in February 2018, I am pleased to say I have assumed the role of Chief Executive and Mark Routh has stepped up to be full time Chairman. I look forward to continuing to progress our exciting projects with Mark's help and support on the board.

In conclusion, I am happy to say that the Company is now moving towards cash flow generation from our SNS gas fields and unlocking possible 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 2018.

Andrew Hockey

Chief Executive Officer

28 March 2018

Strategic Report

Highlights of 2017

· Board & Management Changes: In March 2017, the Company significantly strengthened the Board and management team through the appointments of Andrew Hockey as Deputy Chief Executive and Director, and the Rt. Hon. Charles Hendry as Non-Executive Director and nominee of LOG to the Board. Andrew Hockey has 35 years' experience in the oil and gas industry, most recently with Fairfield Energy and Sound Energy, and led the early development of Clipper South, a successful SNS producing gas field which is analogous to the Company's Vulcan Satellites Hub development. The Rt. Hon. Charles Hendry was Minister of State for Energy between May 2010 and September 2012. David Peattie resigned as Chairman to assume the role of Chief Executive of the UK Nuclear Decommissioning Authority and Mark Routh was appointed as Interim Executive Chairman. Hywel John joined the board as Chief Financial Officer and Director in March 2017 but departed to pursue other opportunities in September 2017. His role (although on a non-board basis) was assumed by James Chance, formerly of Standard Chartered Bank. Graham Cox, previously Project Manager on the Clipper South development, also joined the Company as SNS Project Manager and Peter Young moved to become Head of Business Origination. The IOG SNS project team was also strengthened by Ian Pollard who joined as the Company's Health & Safety and Environment ('HS&E') Manager and Jonathan Walker who joined as Engineering Manager. Ian and Jonathan work directly with Graham Cox, the Company's SNS Project Manager.

· Acquisition of SNS Pipeline: In April 2017, the Company signed an SPA regarding the acquisition of the recently decommissioned Thames Gas Pipeline in the Southern North Sea for a nominal consideration of £1 from Perenco UK Limited, Tullow Oil SK Limited and Centrica Resources Limited. The pipeline will provide the proposed export route for IOG's Southern North Sea assets.

· Award of New Licence P2342: In July 2017, the Company announced that it had been awarded a new licence by the OGA in the 2016 29th Supplementary Offshore Oil and Gas Licensing Round, Licence P2342 comprising Block 48/25a. The licence includes the western part of the Nailsworth field that extends into 48/25a.

· Blythe / Elgood FDP Submission: In July 2017, the Company announced that it had submitted the FDP to the OGA for the Blythe Hub, which comprises the Blythe and Elgood fields. This follows on from the Company's submission of a draft FDP for only the Blythe field in December 2016.

· Letter of Intent and Consultancy Agreement signed with Schlumberger on SNS Gas Development Project: In September 2017, the Company announced that it had signed a Letter of Intent and Consultancy Master Services Agreement ('CMSA') with Schlumberger in relation to development of its two SNS gas hubs, the Blythe Hub and the Vulcan Satellites Hub.

· Letter of Intent signed for up to four SNS Gas platforms: In October 2017, the Company announced that it had signed a Letter of Intent with Heerema for Front End Engineering and Design ('FEED') and Engineering, Procurement, Construction and Installation ('EPCI') of up to four Normally Unmanned Installation platforms ('NUIs').

· CPR confirms Significant Reserves Upgrade - Blythe, Elgood & Vulcan Satellites: In October 2017, the Company announced the results of a CPR on the Vulcan Satellites, Blythe and Elgood assets by ERCE indicating a significant reserves upgrade.

· Letter of Intent signed with Key SNS Project Development Contractor ODE: In October 2017, the Company announced that it had signed a Letter of Intent with ODE to perform several key contractor roles for its Blythe Hub and Vulcan Satellites Hub developments starting with technical and operational support ahead of FID.

· Vulcan Satellites FDP Submission: In October 2017, the Company announced that it had submitted the FDP for the Vulcan Satellites hub development to the OGA.

· Significant Prospective Resources confirmed and Commitment Well for Harvey: In November 2017, the Company announced its commitment to drill an appraisal well on Harvey and the results of a CPR on the Harvey licence by ERCE. The CPR confirmed the significant prospective resources on the Harvey prospect.

· Harvey Licence Valuation Update: In November 2017, the Company announced the recent CPR by ERCE had been updated to include a fully risked, expected monetary value ('EMV') for the Harvey licence.

· Drilling Extension - Harvey: In November 2017, the Company announced that the OGA had agreed a two-year extension to the initial term for licence P2085 that includes Harvey. The licence will be extended to 20 December 2019.

· Blythe Licence Extension: In December 2017, the Company announced that licence P1736 that contains the Blythe gas discovery had been extended by 12 months to 31 December 2018. To date, the Company has met all 2018 specific milestones as set by the OGA pursuant to the agreement for the extension.

· Successful conclusion to Skipper Well Creditors' discussions: In December 2017, the Company announced that discussions with creditors, for the remaining liabilities relating to the 2016 Skipper well, had been successfully concluded. This included a debt to equity conversion for two of the major creditors, together with revised payment terms for both these and all remaining creditors with final payments due either by the end of August 2018 or Field Development Plan Approval for the Company's SNS developments, whichever occurs first. The Company announced on 21 December 2017 the issue of 10,479,260 shares and all remaining creditors are now classified as current trade creditors as at 31 December 2017. Both Deferred Payment and Conversion Deed documentation was executed on 21 December 2017 to finalise these arrangements.

Post Year End Developments

· Andrew Hay steps down from the Board of Directors on 13 February 2018. The Company is seeking a new independent Non-Executive Director to join the Board.

· £10 million convertible loan facility (the 'New Facility') successfully signed with existing lender LOG: Subject to shareholder approval, the loan is convertible into 1p ordinary shares in the Company ('Ordinary Shares') at a conversion price of 19p (the 'Conversion Price'), being a 15% premium to the closing share price of the Company on 20 February 2018. Tranches drawn down under the New Facility will carry a coupon of LIBOR+9%. The New Facility is secured against all of the current and future assets of the Company and of the Company's subsidiaries, IOG North Sea Limited ('IOGNSL') and IOG UK Limited ('IOGUKL'), and is repayable 36 months after the drawdown of each tranche.

Health, Safety and Environment ('HS&E')

The corporate HS&E policies were reviewed, renewed and re-issued in anticipation of further Licence Round applications during the period and the progressive selection and procurement of contracted services for the development of the Blythe and Vulcan Satellites gas hub developments. The revised policies provide clear corporate expectation and direction for the effective HS&E planning and performance of activities.

The Company continued to develop its HS&E organisation, arrangements and capabilities during the period. These corporate developments formed a significant part of the demonstration of necessary operator competencies that were submitted to the OGA in support of our field licences for Blythe, Elgood, Nailsworth, Elland and Southwark. The arrangements also support our applications in the OGA 30th Licensing Round.

Selection of suitable contracted services for the engineering design and operation of the Blythe and Vulcan Satellites gas hub development incorporated suitable HS&E criteria, and has been followed by the development and implementation of HS&E bridging documentation with our partnered and contracted enterprises, some of whom are intended to undertake 'duty holder' responsibilities in the operations and maintenance of our eventual offshore facilities, pipelines and wells.

Effective briefing and consultation with the regulatory authorities has been an essential activity during the period, in order to assure compliance and secure necessary permits and consents for the range of project activities. This has involved close contact with the OGA, HSE Pipelines Inspectorate and the BEIS Offshore Petroleum Regulator for Environment and Decommissioning ('OPRED').

In preparation of statutorily Environmental Impact Assessments ('EIA') that are required to support our Blythe and Vulcan Satellites gas hub developments, an Early Consultation Document ('ECD') was circulated to over 40 identified potential stakeholder parties, including oil & gas operators, windfarm operators, regulatory bodies, non-government organisations ('NGO') and others with potential interest in the development. Responses to the ECD are being taken into account as our project develops, and in the preparation of the formal EIAs that follow. The EIAs will themselves be subject to public review and statutory consultation.

Business Strategy

The Company's strategy is to target stranded assets and dormant discoveries, especially those near to existing and ideally, owned infrastructure (the 'Hub Strategy'). These are assets that are no longer targets for the major oil companies but are potentially profitable developments which can be beneficially developed by a smaller independent company, focused on the North Sea. This strategy has previously been successfully deployed in the North Sea by CH4 Energy Limited (of which Mark Routh was the founder), among others and is fully endorsed by our main stakeholder LOG.

Given the steady rise of imported vs domestic gas in the UK over the last decade and the country's dependency on gas for power, industry and heating, the maximising of gas resources in the North Sea makes strategic sense and will help deliver energy security in the UK.

The aim is to build upon the existing development gas assets in order to achieve a diversified and balanced portfolio of near and long-term developments, ideally with appraisal upside that complement the existing operations. This will include the acquisition of producing fields or near-term production if the risk is positively assessed and the acquisition price results in value accretion. The Directors believe that there is a significant opportunity for the Company to exploit this strategy, given that there are over 400 undeveloped and underdeveloped assets in the UK Continental Shelf ('UKCS').

The Hub Strategy targets strategic control over a number of dormant discoveries and appraisal assets that can be developed through common existing infrastructure, thereby generating significant economies of scale. The Company is executing this strategy in order to create UK SNS gas hubs with the acquisition of the Blythe licence, along with operatorship, in addition to the acquisition of the Vulcan Satellites, the award of Licence P2342 (Nailsworth NW Extension) in the 2016 29th Offshore Supplementary Licensing Round and the successful award of the Harvey and Elgood licences. The Company also seeks to acquire low cost development ready assets through the Licensing Round system and applied for three areas in the 30th UKCS Licensing Round.

The Company seeks to operate all its assets. Operatorship is strategically important for several reasons: firstly, third party consents to tie in additional discoveries are easier to facilitate for operators of owned infrastructure. Secondly, as the major oil companies continue to divest late-life producing assets they often prefer to assign operatorship and redeploy their own resources and so additional opportunities arise. Finally, in the UK licensing rounds, certain licences will only be made available to pre-qualified operators.

Overall, the Board is confident that the Company has the management, experience and technical expertise to create and seize new opportunities for future growth.

Licences

The Company, through its wholly owned subsidiaries IOG North Sea Limited and IOG UK Limited is currently a licensee on six Traditional Licences and two Promote Licences, all in the UK North Sea;

Licence	Blocks	Subsidiary	Interest	Discovery Name	Licence Type
Licence	Blocks	Subsidiary	Interest	Discovery Name	Licence Type
Blythe/Elgood Hub
P1736	48/22b ALL and 48/23a ALL	IOG North Sea Limited	100%	Blythe	Traditional
P2260	48/22c ALL	IOG North Sea Limited	100%	Elgood	Promote
P2085	48/23c ALL and 48/24b ALL	IOG North Sea Limited	100%	Harvey	Promote

Vulcan Satellites Hub
P039	49/21a J	IOG UK Limited	100%	Elland [1]	Traditional
P2342	48/25a ALL	IOG UK Limited	100%	Nailsworth [2]	Innovate C
P130	48/25b NW VULCAN	IOG UK Limited	100%	Nailsworth [2]	Traditional
P1915	49/21c ALL	IOG UK Limited	100%	Southwark [3]	Traditional

Skipper
P1609	9/21a ALL	IOG North Sea Limited	100%	Skipper	Traditional

[1] Formerly Vulcan East

[2] Formerly Vulcan North West

[3] Formerly Vulcan South

In July 2017, IOG was awarded P2342, Block 48/25a which contains an extension of the Nailsworth field as an Innovate C licence. The Innovate Licence replaces several earlier types of Seaward Production Licence: Traditional, Promote and Frontier. The Innovate Licence offers greater flexibility in the durations of the Initial and Second Terms (which was the main difference between the older licence types). An applicant for an Innovate Licence is able to propose the durations of the Initial and Second Terms, and among the permutations that may be proposed are those that represent those associated with each of the older licence types.

The Initial Term can now be subdivided into up to three phases, with the Work Programme being correspondingly divided:

· Phase A is a period for carrying out geotechnical studies and geophysical data reprocessing;

· Phase B is a period for undertaking seismic surveys and acquiring other geophysical data; and

· Phase C is for drilling.

Phases A and B are optional and depend on the applicant's plans. Every Work Programme must have at least a Phase C (just as a drilling commitment was the minimum Work Programme before the Innovate concept).

It remains the case that a Licence may only continue from the Initial Term into the Second Term if (among other things) the Initial Term Work Programme has been completed and surrendered 50% of the initial acreage. Similarly, an Innovate Licence may only continue from one Phase into another if that part of the Term Work Programme associated with the earlier Phase has been completed and if the Licensee has committed to complete that part associated with the next. When continuing into Phase C, the licensee must also demonstrate the technical and financial capacity to carry out the Phase C part of the Work Programme.

In special cases where an applicant does not propose any exploration at all and proposes to develop an existing field discovery or redevelop a field, a Licence may be awarded with no Initial Term; this is called a 'Straight to Second Term' Licence. Again, this was an option that was available before the Innovate concept.

Statement of Reserves & Resources

SNS Hubs Reserves

SNS Portfolio	Gas Reserves			Condensate Reserves
Field	(BCF)			(MMBbls)
Blythe Hub
	1P	2P	3P	1P	2P	3P
Blythe	25.2	33.0	44.1	0.3	0.3	0.4
Elgood	14.7	21.7	32.6	0.1	0.2	0.3
Total Blythe Hub	39.9	44.7	76.7	0.4	0.5	0.7
Vulcan Satellites Hub
	1P	2P	3P	1P	2P	3P
Nailsworth	60.4	99.4	147.2	0.6	1.0	1.5
Elland	39.9	55.0	72.9	0.0	0.0	0.1
Southwark	61.2	94.2	137.7	0.0	0.1	0.1
Total Vulcan Satellites Hub	161.5	258.5	357.8	0.7	1.2	1.7
Totals SNS Portfolio	201.4	303.2	434.5	1.1	1.7	2.4

Source: ERC Equipoise Competent Person's Report 11th October 2017

Harvey Prospective Resources

	Prospective Gas Resources			Prospective Condensate Resources
Field	(BCF)			(MMBbls)
	Low	Best	High	Low	Best	High
Harvey Appraisal Gross	45	114	286	0.5	1.1	2.9
Harvey Appraisal (79% on Licence P2085)	36	90	226	0.4	0.9	2.3

Source: ERC Equipoise Competent Person's Report 8th November 2017

Skipper STOIIP and Resources

	Discovered Oil Initially in Place			Contingent Resources
Field	(MMBbls)			(MMBbls)
	P90	P50	P10	1C	2C	3C
Skipper	123.1	136.5	150.8	17.9	26.2	34.9

Source: AGR Tracs CPR - September 2013.

Operational Update

Thames Pipeline

The SPA for the acquisition of PL370 for a nominal consideration of £1 was signed on 10 April 2017 and will facilitate the export of IOG's gas from all its portfolio to the Bacton Gas Terminal onshore. The acquisition of the line involves the transfer of PWA370 to IOG Infrastructure Limited ('IOGIL') and IOGIL becoming the Pipeline Operator. To allow time for this regulatory process to complete, intelligent pigging and engineering and execution work and field surveys will commence at Bacton in early 2018. The deadline for the completion of the SPA for PL370 was extended until 31 March 2018 to allow regulatory approvals to be sought and transfer of operatorship to be progressed.

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 of Licence P1736.

In early 2017 Blythe/Elgood reservoir modelling by ERCE and preliminary well design work by Fraser Well Management ('Fraser') were completed. Further refinement to the cost model was made and a combined Blythe/Elgood FDP was then submitted to the OGA on 18 July 2017.

All reservoir and cost data were then provided to ERCE as Competent Person and their review was completed, adjudging Blythe to have 1P/2P/3P reserves 'Justified for Development' of 25.2/33.0/44.1 bcf and 0.3/0.3/0.4 MMBbls of condensate. Blythe is planned to be developed with a single well tied back to the Thames Pipeline via a NUI.

Discussions with key contractors for well construction, platform fabrication, pipeline and subsea works, drilling rig hire and duty holder has progressed and Letters of Intent were signed with Schlumberger, ODE and Heerema. Fugro GB Marine ('Fugro') was contracted to carry out pipeline and site survey work which commenced in late January 2018. An extension for Licence P1736 was requested to allow sufficient time for FDP approval and this was granted by the OGA to 31 December 2018 subject to certain performance milestones being met, including the submission of a FDP capable of approval by the OGA. First gas at Blythe is expected 4Q 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 April 2017, it was decided to relinquish the southern half of the Licence containing the Hambleton Prospect owing to its limited size.

In early 2017 reservoir modelling at ERCE and preliminary well design work by Fraser were completed on Elgood and the cost model refined. A combined Blythe/Elgood FDP was submitted to the OGA on 18 July 2017. Elgood is expected to reach first gas 1Q 2020 on current estimates and is to be developed via a single well subsea tieback to the Blythe NUI.

All reservoir and cost data was then provided to ERCE as Competent Person and their review was completed in October 2017 adjudging Elgood to have 1P/2P/3P reserves 'Justified for Development' of 14.7/21.7/32.6 bcf and 0.1/0.2/0.3 MMBbls of condensate.

Vulcan Satellites

In October 2016, IOG added the three Vulcan Satellites fields to its portfolio through the acquisition from Verus Petroleum. GBP 750,000 was paid to Verus Petroleum on 1 August 2017 being the initial deferred consideration being part of the financial transaction to acquire the assets. Further amounts of £1.75 million and £1.50 million are payable to Verus Petroleum on successful FDP approval and first gas production respectively. Further to the progress made on the project in the current year, an amount of £2.90 million has been recognised as a contingent consideration payable which represents the present value of these deferred payments.

In 2017 the three satellites were re-named: Vulcan North West becoming Nailsworth, Vulcan East becoming Elland and Vulcan South becoming Southwark.

Following the application made in the 2016 29th Supplementary Offshore Licensing Round for Licence P2342, Block 48/25a was awarded to IOGUKL in August 2017 securing the western end of the Nailsworth structure and seeking FDP approval by 31 July 2019. A request for an extension to Licence P130 also on Nailsworth was made and was successful, being extended until 31 December 2021 with a requirement to deliver FDP approval by 31 July 2019. Nailsworth was also determined by the OGA as a Pre-Producing Area, Field Number 587. Licence P2122 was relinquished in Dec-17 as this licence area fell outside the Elland structure. This will save costs by negating future licence fees.

Seismic interpretation and mapping over the three Vulcan Satellites was carried out and was complete by early June 2017. Hydraulic stimulation studies for the Vulcan Satellites by Fenix Delft were also completed in June 2017. Reservoir modelling by ERCE was completed in August 2017. Preliminary well design work by Fraser was also completed for the Vulcan Satellites. Discussions with key contractors for well construction, platform fabrication, pipeline and subsea works, drilling rig hire and duty holder progressed and Letters of Intent were signed with Schlumberger, ODE and Heerema. Fugro were contracted to carry out pipeline and site survey work.

The cost model was further refined and IOG's technical view and cost estimates were provided to Competent Person, ERCE, and in October 2017 their report was released, adjudging the Vulcan Satellites to contain 1P/2P/3P reserves 'Justified for Development' as follows:

Vulcan Satellites	Gas Reserves(BCF)			Condensate Reserves (MMBbls)
Field	1P	2P	3P	1P	2P	3P
Nailsworth	60.4	99.4	147.2	0.6	1.0	1.5
Elland	39.9	55.0	72.9	0.0	0.0	0.1
Southwark	61.2	94.2	137.7	0.0	0.1	0.1
Total (arithmetic sum)	161.5	248.6	357.8	0.6	1.1	1.7

The Vulcan Satellites FDP was submitted to the OGA on 28 October 2017. On current estimates first gas at the Vulcan Satellites is expected Q4 2019 from Southwark via a NUI exporting to Bacton via the re-commissioned Thames Pipeline. First gas from Nailsworth and Elland is expected in Q2 and Q3 2020 respectively.

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. The 2016 subsurface work on P2085 confirmed that Truman and Harvey are essentially one structure hereinafter referred to as Harvey.

In early 2017 the OGA agreed that this licence could continue as per the Terms of the first two years of a Promote Initial Term until 20 December 2017. Competencies had to be demonstrated and a commitment to drill Harvey made by 20 November 2017 to allow an extension of the Initial Term to drill the well. In November 2017 competency documents were submitted and a request made to extend the Harvey Licence P2085 Initial Term to 19 December 2019 with a firm commitment to drill an appraisal well on the structure by that date. This request was granted by the OGA subject to a rig contract, to drill the Harvey well, to be in place by 20 November 2018. 50% of licence P2085 was relinquished, confirmed by the OGA on 6 January 2018.

In October, IOG's technical assessment of Harvey was provided to ERCE as Competent Person for review. ERC adjudged Harvey to contain on block un-risked Low/Best/High Estimated Prospective Resources of 36/90/226 bcf of gas and 0.4/0.9/2.3 MMBbls of condensate.

Skipper

The Skipper oil discovery is in Block 9/21a in the Northern North Sea in Licence P1609. In the third quarter of 2016, the Group completed its first operated well and the appraisal of the discovery. The well was drilled to a total vertical depth of 5,578ft with no safety incident. Further technical and commercial evaluation has led to a decision to focus on the SNS gas development hubs near term given the highly attractive economics of the Group's gas portfolio and not to focus on the Skipper heavy oil project at this stage.

Skipper creditors which remain subject to Deferred Payment and Conversion Deed agreements are forecast to be fully discharged prior to 31 December 2018.

Asset Acquisitions

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

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.

Investment Returns: Management seeks to raise funds and then to generate shareholder returns though investment in a portfolio of exploration and development acreage leading to the drilling of wells, the discovery of commercial reserves followed by their exploitation. Delivery of this business model carries several key risks.
Risk	Mitigation
Market support may be eroded obstructing fundraising and lowering the share price	· Management regularly communicates its strategy to shareholders · Focus is placed on building an asset portfolio capable of delivering regular news flow and offering continuing prospectivity
General market conditions may fluctuate hindering delivery of the Company's business plan	· Management aims to retain adequate working capital and secure finance facilities sufficient to ride out downturns should they arise
Each asset carries its own risk profile and no outcome can be certain	· Management aims to avoid over-exposure to individual assets and to identify the associated risks objectively
Company may not be able to raise funds to exploit its assets or continue as a going concern	· Management maintains regular dialogue with a variety of potential funding partners.

Operations: Operations may not go to plan, leading to damage, pollution, cost overruns and poor outcomes.
Risk	Mitigation
Individual wells may not deliver recoverable oil and gas reserves	· Thorough pre-drill evaluations are conducted to identify the risk/reward balance · Exposure selectively mitigated through farm-out
Operations may take far longer or cost more than expected	· Management applies rigorous budget control · Adequate working capital is retained to cover reasonable eventualities
Resource estimates may be misleading curtailing actual reserves recovered	· The Group deploys qualified personnel · Regular third-party reports are commissioned · A prudent range of possible outcomes are considered within the planning process

Licensing & Regulation: The Group may be unable to meet its licence and regulatory obligations.
Risk	Mitigation
UKCS Licences may be revoked	· Continue thorough communications with the OGA to determine licence status and meet requirements

Principal Risks and Uncertainties (cont'd)

Personnel: The Company relies upon a pool of experienced and motivated personnel to identify and execute successful investment strategies
Risks	Mitigation
Key personnel may be lost to other companies	· The Remuneration Committee regularly evaluates incentivisation schemes to ensure they remain competitive
Difficulty in attracting the necessary talent as the Group moves into development of its projects.	· The Group continues to review and adopt attractive packages for both staff and contractors

Commercial environment: World and regional markets continue to be volatile with fluctuations and infrastructure access issues that might hinder the Company's business success
Risk	Mitigation
Volatile commodity prices mean that the Company cannot be certain of the future sales value of its products	· Price mitigation strategies may be employed at the point of major capital commitment · Gas may be sold under long-term contracts reducing exposure to short term fluctuations · Oil and gas price hedging contracts may be utilised where viable. · Budget planning considers a range of commodity pricing
Brexit	· The Group does not see Brexit having any significant impact on its business model.
The Group may not be able to get access, at reasonable cost, to infrastructure and product markets when required	· A range of different off-take options are pursued wherever possible
Credit to support field development programmes may not be available at reasonable cost	· The Company seeks to build and maintain strong banking relationships and initiates funding discussions at as early a stage a practicable

Corporate Hedging Strategy and Implementation

The primary objective of the Company's hedging policy is to protect projected future cash flows, generated from operations, against unforeseen changes in short and medium-term market conditions.

No hedging instruments were utilised during 2017 in view of the limited exposures carried during the year. As the Company's capital investment programmes increase, hedging will be carried out in a simple and cost-effective manner, retaining exposure to upside but avoiding any speculative exposure to commodity prices or exchange rates. The application of the policy is within a range to require exercise of management judgement in the light of market conditions and business variables.

Details of the Group's financial instruments can be found in Note 19 to the financial statements.

Insurance

The Group insures the risks it considers appropriate for the Group's needs and circumstances. However, the Group may elect not to have insurance for certain risks, due to the high premium costs associated with insuring those risks or for various other reasons, including an assessment that the risks are remote.

Finance Review

Income Statement

The Group made a loss for the year of £2.75 million (2016 - £21.44 million).

The relinquishment of Licence P2122, together with post well drilling expenses on the Skipper asset, resulted in an impairment charge to the Income Statement of £119k (refer Note 8). There was no other impairment made against oil and gas properties during the year. This compares with the £20.01 million net impairment charged in 2016. The 2016 net impairment related to full impairment taken on the Skipper field, £22.10 million, offset by the impairment reversal on Blythe, £2.09 million. As a result of the 2016 Skipper impairment, long term trade creditors in the sum of £307k were released and credited to the Income Statement in 2016.

A charge of £430k (2016: £712k) to the Income Statement reflects the expenses incurred for pre-licence business development ('BD') and other project expenses.

Administration expenses of £700k (2016 - £279k) for the year comprise total general and administration ('G&A') expenses of £2.12 million (2016 - £1.38 million) including non-cash share-based payment expense of £298k (2016 - £358k), offset by £666k (2016 - £591k) absorbed by BD and other projects, as included in the pre-licence BD figure above, and £757k (2016 - £515k) capitalised to assets throughout the Group. The increase in total G&A expenses highlights the 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 £1k (2016: £458k gain) reflects both realised and unrealised movements on the settlement of liabilities via the issue of shares.

The foreign exchange gain of £333k (2016: £299k loss) reflects foreign exchange movements on non-GBP denominated loans, provisions and trade creditors.

Finance expense of £1.83 million (2016 - £0.90 million) includes accrued interest payable on loans (net of capitalised interest £22k), discount accretion and both current and amortised finance expenses. These expenses relate to fees incurred on both loan finance facilities and those trade creditors subject to deferred payment and equity conversion terms.

Balance Sheet

In addition to Blythe, following the submission of both the Blythe Hub (including Elgood) and Vulcan Satellites Hub Field Development Plans ('FDP') in 2H 2017, the Elgood and Vulcan Satellite assets have now been reclassified as Property, Plant & Equipment ('PPE') oil and gas assets. PPE oil and gas assets have increased to £21.32 million (2016: £7.51 million) during the year, which represents the transfer of capitalised E&E and includes capital expenditure on Front End Engineering Design ('FEED') and other activities pre-development. Deferred consideration has now been recognised for those payments due on milestone events (FDP Approval and First Gas) associated with these PPE oil and gas assets.

Harvey now remains the only exploration and evaluation ('E&E') asset in the portfolio at 31 December 2017, with a net book value of £185k to the Group at 31 December 2017.

Current assets have increased to £1.11 million (2016: £0.53 million) mainly resulting from an increase in UK VAT receivable from £22k to £285k and recognition of the Thames Pipeline PL370 prepayment of £408k. This prepayment includes the capitalisation of £131k of direct third-party costs, plus £277k of both direct personnel costs and other attributable overheads incurred since the signing of the Thames Pipeline PL370 SPA on 10 April 2017. The SPA had not yet completed at the date of this report.

Total liabilities have increased to £27.40 million (2016: £18.19 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 £13.00 million offset by £0.61 million prepaid loan finance costs, Skipper deferred trade creditors of £4.46 million, deferred consideration in relation to acquisitions of £6.01 million, Vulcan East suspended well abandonment provision of £3.60 million, accruals of £0.57 million and other current liabilities of £0.37 million.

Cash Flow

Net cash outflows of £1.05 million (2016: £0.65 million) from operations, £3.40 million (2016: £7.39 million) from investing activities and £2.02 million (2016: £nil) from loan repayments were funded via loan drawings and the proceeds from the issue of equity instruments in the Company.

The £2.02 million loan repayment to Weatherford Technical Services Limited in 1H 2017 allowed the loan to be discharged in full at 24 May 2017.

The Directors will not be recommending payment of a dividend.

London Oil and Gas Limited and GE Oil and Gas UK Limited Loans

On 4 December 2015, the Company secured agreement for a loan of £2.75 million from LOG in parallel with a £2.00 million loan from GE Oil & Gas UK Limited ('GE'). On 11 December 2015, a further loan of £0.80 million was provided by LOG. On 5 February 2016, a further £10.00 million loan was provided by LOG.

On 21 December 2017, both the outstanding GE loan and GE Skipper creditor (provision of wellhead equipment and services) were renegotiated under the terms of a Conversion Deed ('CD') and a Deferred Payment Deed ('DPD') allowing circa 50% of the total outstanding liability to be converted to equity, with the remaining cash liability to be repaid by 31 August 2018. Similar CD and/or DPD arrangements were negotiated for all other remaining Skipper creditors which resulted in a total of £1.98 million being subject to conversion with a further £2.44 million and USD 2.75 million to be settled in cash.

The LOG loans are secured over the Group's assets and are due to be redeemed thirty-six months following each individual drawdown. All outstanding LOG debt is redeemable after 31 December 2018. Interest of LIBOR + 9% per annum accrues on a cumulative monthly basis on each drawdown.

Table 1: Summary Loans with LOG

	Facility Amount (£ million)	Available until	Interest rate	Warrants / Convertible details	Repayment by
LOG	£2.75	31 Dec-19	LIBOR + 9%.	5,777,310 warrants @ 11.9p	36 months from drawing
LOG	£0.80	31 Dec-19	LIBOR + 9%.	7,500,000 warrants @ 8p	36 months from drawing
LOG	£10.00	31 Dec-19	LIBOR + 9%.	8p conversion price	36 months from drawing
	£13.55

All Conditions Precedent to the LOG loans have been met and have been drawn with agreement from LOG. Included within the above facilities, from 1 January 2017, £250k per month was committed from LOG to cover the Group's general and administration expenses through to 30 June 2018, including those directly attributable project overheads.

The aim of the £10.00 million LOG loan from February 2016 is to support general and administration expenditures, together with acquisitions in the endemic oil and gas E&P sector low-price environment, but also organic growth. During 2016, the additional 50% acquisition of the Blythe licence was funded from this facility, together with the acquisition of Oyster Petroleum Limited (renamed IOG UK Limited), incorporating the Vulcan Satellite assets. The loan, including accrued interest, may be converted into new ordinary Company shares at a price of 8p per share at LOG's election prior to repayment. This loan has a coupon of LIBOR + 9%, consistent with the other LOG loan facilities, which is deferred until maturity.

The Group had £13.00 million borrowings outstanding on its LOG facilities at 31 December 2017 (2016 - £5.75 million) including accrued interest. It had in place further undrawn debt from the LOG facilities of a total £1.64 million, excluding accrued interest, at that date.

On 21 February 2018, it was announced that a further £10.00 million loan was to be provided by LOG to meet the requirements of the Group. The aim of this additional loan is to support general and administration expenditures, together with funding for the Group's SNS development project expenditures in advance of 31 August 2018, to allow the Company to reach Final Investment Decision ('FID') by that date.

The loan is convertible into ordinary shares of 1p in the Company at a conversion price of 19p. The loan will carry the same coupon as to existing loans, being LIBOR + 9%. This new facility is secured against existing Group assets and is redeemable 36 months following each drawdown.

This loan allows the Group to be fully funded through to FID, anticipated to be 31 August 2018, on its 100% owned UK SNS dual gas hub development project (Blythe Hub & Vulcan Satellites Hub).

Funding & Liquidity

The Board has reviewed the Group's cash flow forecasts up until June 2019 having regard to its current financial position and operational objectives. In February 2018, the Group has secured an additional £10 million convertible loan facility which, at the current rate, will be sufficient to fund the Company to August 2018; however, the 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 next fifteen months. The Board is satisfied that the Group will have sufficient financial resources available to meet its commitments based on the existing debt facilities that can be drawn down and the likelihood of the Group being able to secure additional funding from existing stakeholders or new investors. Additionally, the Group would be able to cut discretionary expenditure and reduce headcount to reduce financing requirements further. 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 for any fundraising. 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.

Andrew Hockey

Chief Executive Officer

28 March 2018

Consolidated Statement of Comprehensive Income

	Notes	2017		2016
		£000		£000


Administration expenses		(700)		(279)
Impairment of oil and gas properties	8	(119)		(20,013)
Release of creditors		-		307
Project, pre-licence and exploration expenses		(430)		(712)
Net (loss)/gain on settlement of liabilities	3	(1)		458
Foreign exchange gain/(loss)		333		(299)

		_________		_________

Operating loss	3	(917)		(20,538)

Finance expense	5	(1,834)		(899)
		_________		_________

Loss for the year before taxation		(2,751)		(21,437)

Taxation	6	-		-
		_________		_________

Loss and total comprehensive loss for the year attributable to equity holders of the parent	7	(2,751)		(21,437)
		_________		_________


Loss for the year per ordinary share - basic	7		2.5p	23.2p
Loss for the year per ordinary share - diluted	7		2.5p	23.2p

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
	Share capital	Share premium	Share-based payment reserve	Accumulated losses	Total equity
Group:	£000	£000	£000	£000	£000

At 1 January 2016	787	17,649	3,347	(8,307)	13,476
Loss for the year	-	-	-	(21,437)	(21,437)
	_____	________	________	________	_______
Total comprehensive loss attributable to owners of the parent	-	-	-	(21,437)	(21,437)
Settle creditors via issue of shares	208	2,181	-	-	2,389
Issue of warrants	-	-	31	-	31
Lapse/exercise of warrants	58	630	(186)	186	688
Issue of share options	-	-	513	-	513
Lapse/exercise of share options	40	-	(820)	820	40
	_____	________	________	________	_______
At 31 December 2016	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)
	_____	________	_______	________	_______
Company:
At 1 January 2016	787	17,649	3,347	(7,962)	13,821
Profit for the year	-	-	-	1,784	1,784
	_____	________	________	________	_______
Total comprehensive income attributable to owners of the parent	-	-	-	1,784	1,784
Settle creditors via issue of shares	208	2,181	-	-	2,389
Issue of warrants	-	-	31	-	31
Lapse/exercise of warrants	58	630	(186)	186	688
Issue of share options	-	-	513	-	513
Lapse/exercise of share options	40	-	(820)	820	40
	_____	________	________	________	_______
At 31 December 2016	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
	______	________	_______	________	_______

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

Company Number: 07434350

	Notes	2017	2016
		£000	£000

Non-current assets
Intangible assets: exploration & evaluation	8	185	5,825
Intangible assets: other	8	1	2
Property, plant and equipment: development & production	9	21,316	7,506
Property, plant and equipment: other	9	20	24
		_________	_________
		21,522	13,357
		_________	_________
Current assets
Other receivables and prepayments	13	968	285
Cash and cash equivalents	17	145	247
		_________	_________
		1,113	532
		_________	_________

Total assets		22,635	13,889

Current liabilities
Loans	14	-	(4,076)
Trade and other payables	14	(7,038)	(5,782)
		_________	_________
		(7,038)	(9,858)
		_________	_________
Non-current liabilities
Loans	15	(12,394)	(4,733)
Provisions	15	(7,969)	(3,598)
		_________	_________
		(20,363)	(8,331)
		_________	_________

Total liabilities		(27,401)	(18,189)
		_________	_________
NET LIABILITIES		(4,766)	(4,300)
		_________	_________
Capital and reserves
Share capital	16	1,203	1,093
Share premium account	16	22,337	20,460
Share-based payment reserve		3,099	2,885
Accumulated losses		(31,405)	(28,738)
		_________	_________
		(4,766)	(4,300)
		_________	_________

The financial statements were approved and authorised for issue by the Board of Directors on 28 March 2018 and were signed on its behalf by: -

Andrew Hockey

Chief Executive Officer

28 March 2018

Company Statement of Financial Position

Company Number: 07434350	Notes	2017	2016
		£000	£000
Non-current assets
Intangible assets	8	1	2
Property, plant and equipment	9	20	24
Investments	11	17,416	14,514
Amounts due from subsidiaries	11	12,280	10,125
		_________	_________
		29,717	24,665
		_________	_________
Current assets
Other receivables and prepayments	13	767	80
Cash and cash equivalents	17	145	247
		_________	_________
		912	327
		_________	_________

Total assets		30,629	24,992


Current liabilities
Trade and other payables	14	(6,643)	(5,726)

Non-current liabilities
Provisions	15	(1,259)	-
		_________	_________

Total liabilities		(7,902)	(5,726)
		_________	_________
NET ASSETS		22,727	19,266
		_________	_________

Capital and reserves
Called-up equity share capital	16	1,203	1,093
Share premium account	16	22,337	20,460
Share-based payment reserve		3,099	2,885
Accumulated losses		(3,912)	(5,172)
		_________	_________
		22,727	19,266
		_________	_________

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 profit for the year was £1,176k (2016: £1,784k).

The financial statements were approved and authorised for issue by the Board of Directors on 28 March 2018 and were signed on its behalf by: -

Andrew Hockey

Chief Executive Officer

28 March 2018

Consolidated Cash Flow Statement

			Restated
	Notes	2017	2016
		£000	£000

Loss for the year	7	(2,751)	(21,437)

Depreciation, depletion and amortisation		3	4
Exploration asset write off	8	119	20,013
Release of creditors	3	-	(307)
Loss/(gain) on settlement of liabilities		1	(351)
Share based payments		174	269
Movement in trade and other receivables		(278)	(143)
Movement in trade and other payables		178	104
Finance fees	5	1,834	899
Foreign exchange differences	3	(333)	299
		_________	_________

Net cash used in operating activities		(1,053)	(650)

Investing activities
Purchase of intangible assets and property, plant and equipment		(2,648)	(4,556)
Acquisitions	10	(750)	(2,835)
		_________	_________

Net cash used in investing activities		(3,398)	(7,391)

Financing activities
Proceeds from issue of equity instruments of the Group		8	723
Cash received from loans		6,372	7,542
Amounts repaid on loans		(2,019)	-
Finance fees paid		(12)	-
		_________	_________

Net cash generated from financing activities		4,349	8,265

Net (decrease) / increase in cash and cash equivalents		(102)	224

Cash and cash equivalents at the beginning of the year		247	23
		_________	_________

Cash and cash equivalents at end of year	17	145	247
		_________	_________

The Directors have reviewed the cash flow statement produced in the prior year and decided to restate these to reflect a correct allocation of the working capital movement. The impact has been to reduce operating cash outflows by £745k, increase investing cash outflows by £740k and reduce financing cash inflows by £5k.

Company Cash Flow Statement

	Notes	2017	Restated 2016
		£000	£000

Profit for the year		1,176	1,784

Depreciation charges		3	3
Investment write back	11	(1,870)	(2,085)
Loss/(gain) on settlement of liabilities		1	(351)
Share based payments		96	244
Movement in trade and other receivables		(284)	63
Movement in trade and other payables		214	87
Inter-company service charge uplift		(105)	(65)
Finance fees		166	-
Foreign exchange differences		(200)	(5)
		_________	_________

Net cash used in operating activities		(803)	(325)

Investing activities
Purchase of intangible assets and property, plant and equipment		(371)	(33)
Loans to subsidiary undertakings		(2,539)	(6,511)
Investments in subsidiary undertakings	10	(750)	(1,172)
		_________	_________

Net cash used in investing activities		(3,660)	(7,716)

Financing activities
Proceeds from issue of equity instruments of the Company		8	723
Cash received from loans		6,372	7,542
Amounts repaid on loans		(2,019)	-
		_________	_________

Net cash generated from financing activities		4,361	8,265

Net (decrease) / increase in cash and cash equivalents		(102)	224

Cash and cash equivalents at the beginning of the year		247	23
		_________	_________

Cash and cash equivalents at end of year	17	145	247
		_________	_________

The Directors have reviewed the cash flow statement produced in the prior year and decided to restate these to reflect a correct allocation of the working capital movement. The impact has been to increase operating cash outflows by £880k, reduce investing cash outflows by £885k and reduce financing cash inflows by £5k.

Notes Forming Part of the Financial Statements

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 2017 were authorised for issue by the Board of Directors on 28 March 2018 and the balance sheets were signed on the Board's behalf by the CEO, Andrew Hockey.

Basis of preparation and accounting

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 in this Note 1.

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

Going concern

1 Accounting policies (continued)

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. There are no new or amended financial standards or interpretations adopted during the year that have a significant impact upon the financial statements.

(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 9	Financial Instruments	1 January 2018
IFRS 15	Revenue from Contracts with Customers	1 January 2018
IFRS 16	Leases	1 January 2019
IFRS 17	Insurance Contracts	1 January 2021
IFRIC 22	Foreign Currency Transactions and Advance Consideration	1 January 2018
IFRIC 23	Uncertainty over Income Tax Treatments	1 January 2019
IFRS 15	Clarifications to IFRS 15 - Revenue from Contracts with Customers	1 January 2018
IFRS 2	Classification and Measurement of Share-based Payment Transactions (Amendments)	1 January 2018
IFRS 4	Applying IFRS 9 'Financial Instruments' with IFRS 4 'Insurance Contracts' (Amendments)	1 January 2018
IAS 40	Transfers of Investment Property (Amendments)	1 January 2018
IFRS1, IAS28	Annual Improvements to IFRS Standards 2014-2016 Cycle	1 January 2018
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

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

IFRS 9 "Financial Instruments" introduces significant changes to the classification and measurement requirements for financial instruments. The new standard will replace existing accounting standards. It is applicable to financial assets and liabilities and will introduce changes to existing accounting concerning classification, measurement and impairment (introducing an expected loss method). This could impact on the Company balance sheet in respect of the consideration of intercompany debtors and could also result, in the Company, recording an amount for the financial guarantee issued under the loan agreement with LOG.

1 Accounting policies (continued)

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 costs, 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) 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

1 Accounting policies (continued)

Oil and gas interests (continued)

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 property, plant and equipment. 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 10 and Note 19 for further details.

Depreciation and depletion

All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is calculated on a UOP basis based on the 2P reserves of the asset. Any re-assessment of reserves affects the depreciation 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 depreciation 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.

1 Accounting policies (continued)

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.

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 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 development and production asset. Depletion on this asset is calculated under the UOP method based on commercial reserves.

Provisions, contingent liabilities and contingent assets

Provisions are recognised when:

(i) the Group has a present legal or constructive obligation as a result of past events;

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

(iii) the amount can be reliably estimated.

Disposals

Net proceeds from any disposal of an E&E or D&P 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 as a whole 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.

1 Accounting policies (continued)

Taxation (continued)

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and associates, and interests in Joint Ventures, 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. Provisions are made for any impairment in value.

Operating Leases

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

Financial instruments

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.

Trade payables

Trade payables and other short-term monetary liabilities are held at amortised cost which, in view of their short-term nature, is not materially different from their undiscounted cost.

Loans and borrowings

Loans and borrowings are initially recognised at fair value; less any issue costs. They are subsequently held at amortised cost using the effective interest method.

Financial liabilities

Financial liabilities are classified per the substance of the contractual arrangements entered.

1 Accounting policies (continued)

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 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 share options awarded for 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 employee turnover before vesting and 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 share options as detailed above. Typically, these amounts have related to equity issues where the amount deducted from share premium or other finance facilities is treated as an arrangement fee and included in the effective interest rate calculation of borrowings.

Loss/earnings per share

Loss/earnings per share is calculated as profit/loss 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.

1 Accounting policies (continued)

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 8 and 9. The carrying value of related investments in the Company Statement of Financial Position is disclosed in Note 11. Exploration and evaluation 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 to 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 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.

1 Accounting policies (continued)

Critical accounting judgements and key sources of estimation uncertainty (continued)

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 (2016: 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 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

The Company has obligations in respect of decommissioning a suspended well on the Vulcan Satellites D&P asset. The extent to which a provision is recognised depends on the legal requirements at the date of decommissioning, 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.

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.

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.

3 Operating loss

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

	2017	Restated 2016
	£000	£000

Fees payable to the Company's auditor: - for the audit of the Company's and Group's financial statements	50	44

Depreciation, depletion and amortisation	8	7
Project, pre-licence and exploration expenses Impairment of oil and gas properties	430 119	712 20,013
Release of creditors	-	(307)
Personnel costs - direct expenses	1,306	694
Personnel costs - share-based payments	298	358

Net loss/(gain) on settlement of liabilities	1	(458)
Foreign exchange (gain)/loss	(333)	299

Further to the above, amounts of £5k (2016: £4k) for depreciation and £869k (2016: £448k) for personnel costs were capitalised to both oil and gas properties and prepaid property plant and equipment.

4 Staff costs and directors' remuneration

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

	2017	2016
	Number	Number
Management / technical / operations	17	13
of which: Directors	5	5

Personnel costs Group and Company	£000	£000

Wages, salaries and fees	1,229	645
Social security costs	77	49
Share-based incentives	298	358
	________	________
	1,604	1,052
	________	________

No pension plans are provided for directors nor staff. Key management personnel are deemed to be directors and the current Chief Financial Officer (previously Commercial Director).

Directors' remuneration	Salary	Share-based payment	2017 Total	Salary	Share-based payment	2016 Total
	£000	£000	£000	£000	£000	£000
Mark Routh	149	79	228	59	139	198
Marie-Louise Clayton1	-	-	-	-	13	13
Michael Jordan2	-	-	-	10	15	25
Paul Murray3	-	-	-	-	29	29
David Peattie4	-	35	35	-	6	6
Martin Ruscoe5	15	20	35	-	15	15
Andrew Hay6	18	23	41	-	3	3
Peter Young7	38	-	38	141	22	163
Hywel John8	69	13	82	-	-	-
Andrew Hockey9	101	19	120	-	-	-
Charles Hendry10	12	7	19	-	-	-
	_______	________	________	_______	________	________
	402	196	598	210	242	452
	_______	________	________	_______	________	________

Other key management personnel	97	30	127	-	-	-

Total key management personnel	499	226	725	210	242	452

1 Marie-Louise Clayton resigned on 9 February 2016;

2 Michael Jordan resigned on 31 August 2016;

3 Paul Murray resigned on 29 July 2016;

4 David Peattie was appointed on 29 July 2016, resigned on 21 March 2017

5 Martin Ruscoe was appointed on 9 February 2016;

6 Andrew Hay was appointed on 29 July 2016, resigned on 13 February 2018;

7 Peter Young resigned on 21 March 2017;

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

9 Andrew Hockey was appointed on 21 March 2017;

10 Charles Hendry was appointed on 21 March 2017.

The salary amounts are those cash amounts received during the year. The share-based payment amounts represent the fair value of options issued on both 1 March 2017 (1 March 2016) and 1 September 2017 (1 September 2016) respectively in lieu of cash salary and/or director fees.

4 Staff costs and directors' remuneration (continued)

Social security costs for the year for key management personnel were £53k (2016 - £39k).

For the current directors at 31 December 2017, the service agreements for Mark Routh, Andrew Hockey, Martin Ruscoe and Charles Hendry provide that only a proportion of the full contractual amount will be paid with the balance to be settled in share options granted.

The proportions paid in 2017 for all directors were 100% for Peter Young, 75% for each of Mark Routh, Andrew Hockey and Hywel John, 50% for Martin Ruscoe, Andrew Hay and Charles Hendry and 0% for David Peattie. 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 outstanding at 31 December 2017 to which these terms relate totalled £60k (31 December 2016 - £91k) for directors and key management personnel and £9k (2015 - £36k) for other personnel and were subsequently settled in share options on 1 March 2018.

Directors' interests in options on 1p ordinary shares of the Company at 31 December 2017 were as follows:

	Granted	Total 31 Dec 2016	Awarded / (Exercised) in 2017	Total 31 Dec 2017	Exercise price	Expiry date

Mark Routh	23 Sept 2013	2,933,946	-	2,933,946	1p	30 Sep 2018
	19 Nov 2014	162,114	-	162,114	1p	28 Feb 2019
	19 Nov 2014	218,672	-	218,672	1p	31 Aug 2019
	1 Mar 2015	638,361	-	638,361	1p	28 Feb 2020
	31 Aug 2015	611,601	-	611,601	1p	31 Aug 2020
	1 Mar 2016	888,494	-	888,494	1p	28 Feb 2021
	1 Sep 2016	365,550	-	365,550	1p	31 Aug 2021
	1 Mar 2017	-	298,628	298,628	1p	28 Feb 2022
	1 Sep 2017	-	147,507	147,507	1p	31 Aug 2022
Andrew Hockey	1 Sep 2017	-	110,800	110,800	1p	31 Aug 2022
Martin Ruscoe1	1 Sep 2016	79,558	-	-	1p	31 Aug 2021
	1 Mar 2017	-	68,555	-	1p	28 Feb 2022
			(148,113)	-
	1 Sep 2017	-	44,699	44,699	1p	31 Aug 2022
Andrew Hay	1 Sep 2016	11,430	-	11,430	1p	31 Aug 2021
	1 Mar 2017	-	79,981	79,981	1p	28 Feb 2022
	1 Sep 2017	-	52,149	52,149	1p	31 Aug 2022
Charles Hendry	1 Sep 2017	-	39,745	39,745	1p	31 Aug 2022
David Peattie	1 Sep 2016	22,861	-	22,861	1p	31 Aug 2021
	1 Mar 2017	-	191,955	191,955	1p	28 Feb 2022
Peter Young	23 Sept 2013	1,700,000	-	1,700,000	1p	30 Sep 2018
	19 Nov 2014	122,814	-	122,814	1p	28 Feb 2019
	19 Nov 2014	71,405	-	71,405	1p	31 Aug 2019
	1 Mar 2015	172,717	-	172,717	1p	28 Feb 2020
	31 Aug 2015	165,476	-	165,476	1p	31 Aug 2020
	1 Mar 2016	240,393	-	240,393	1p	28 Feb 2021
	1 Sep 2016	34,270	-	34,270	1p	31 Aug 2021
Hywel John	1 Sep 2017	-	72,737	72,737	1p	31 Aug 2022

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

The Company has paid £25k for Directors and Officers Liability insurance during the year (2016: £10k).

5 Finance expense/(gain)

	2017	2016
	£000	£000

Interest on loans	1,092	489
Interest on deferred payment creditors	12	-
Fair value of warrants issued	-	31
Amortisation of loan finance charges	411	339
Current year loan finance charges	44	40
Current year finance charges on deferred payment creditors	122	-
Unwinding of Blythe deferred consideration provision	153	-
	________	________
	1,834	899
	________	_________

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:

	2017	2016
	£000	£000

Loss for the year	(2,751)	(21,437)
Income tax expense	-	-
	_________	_________
Loss before income taxes	(2,751)	(21,437)

Expected tax (credit) based on the standard rate of United Kingdom corporation tax at the domestic rate of 40% (2016: 40%)	(1,100)	(8,575)

Difference in tax rates	(244)	-
Expenses not deductible for tax purposes	(220)	-
Income /(expense) not taxable/allowable	(3,107)	7,994
Unrecognised taxable losses carried forward	4,671	581
	_________	_________
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 exploration and development 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 £57.72 million (2016: £32.86 million). There are also accelerated capital allowances of £18.1 million (£2016: £15.7 million).

The Group has not recognised the net deferred tax asset at 31 December 2017 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.

7 Loss per share

	2017	2016
	£000	£000

Loss for the year attributable to shareholders	(2,751)	(21,437)
	___________	___________

Weighted average number of ordinary shares - basic and diluted	109,538,499	92,489,621

	___________	___________

Loss per share in pence - basic and diluted	2.5p	23.2p

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 2017 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.

8 Intangible assets

Group

	Exploration & evaluation assets	Company & IT software assets	Total	Exploration & evaluation assets	Company & IT software assets	Total

	2017	2017	2017	2016	2016	2016
	£000	£000	£000	£000	£000	£000
At cost
At beginning of the year	27,923	3	27,926	16,903	-	16,903
Additions	1,484	-	1,484	11,331	3	11,334
Blythe asset acquisition (Note 10)	-	-	-	1,662	-	1,662
Vulcan Satellites asset acquisition (Note 10)	-	-	-	5,533	-	5,533
Reclassified as Development & Production assets	(7,005)	-	(7,005)	(7,506)	-	(7,506)
	_________	_________	________	________	________	________
At end of the year	22,402	3	22,405	27,923	3	27,926
	_________	_________	________	________	________	________

Impairments and write-downs
At beginning of the year	(22,098)	(1)	(22,099)	(2,085)	-	(2,085)
DD&A	-	(1)	(1)	-	(1)	(1)
Net Impairment	(119)	-	(119)	(20,013)	-	(20,013)
	_________	_________	________	________	________	________
At end of the year	(22,217)	(2)	(22,219)	(22,098)	(1)	(22,099)
	_________	_________	________	________	________	________

Net book value
At 31 December 2017	185	1	186
A t 1 January 2017	5,825	2	5,827
At 1 January 2016	14,818	-	14,818

8 Intangible assets (continued)

In 2016 the Skipper impairment of £22.10 million reflects the decision that the Skipper field is currently non-commercial.

Exploration & evaluation assets at 31 December 2017 comprise the Group's interest in the Harvey prospect only.

An impairment charge of £149k was recognised during the year reflecting the relinquishment of Licence P2215, together with those expenses incurred on the Skipper asset.

Following submission of the Vulcan Satellites hub and Blythe/Elgood joint hub FDPs in 2H17, as per the Group's accounting policy, the Vulcan Satellites and Elgood assets have been re-categorised as property, plant and equipment.

In accordance with IFRS6 and the Group's accounting policy, Blythe was assessed at the point of transfer in December 2016 and it was determined that based on the project economics; the impairment on Blythe of £2.08 million originally charged in 2014 should be reversed.

9 Property, plant and equipment

Group	Development & production assets	Company & admin assets	Total	Development & production assets	Company & admin assets	Total


	2017	2017	2017	2016	2016	2016
	£000	£000	£000	£000	£000	£000
At cost
At beginning of the year	7,506	30	7,536	-	-	-
Additions	825	4	829	-	30	30
Reclassified from E&E assets (see Note 8)	7,005	-	7,005	7,506	-	7,506
Blythe asset acquisition (Note 10)	3,078	-	3,078	-	-	-
Vulcan Satellites asset acquisition (Note 10)	2,902	-	2,902	-	-	-
	_________	_________	________	_________	_________	_______
At end of the year	21,316	34	21,350	7,506	30	7,536
	_________	_________	________	_________	_________	_______

Accumulated depreciation
At beginning of the year	-	(6)	(6)	-		-
DD&A	-	(8)	(8)	-	(6)	(6)
	_________	_________	________	_________	_________	_______
At end of the year	-	(14)	(14)	-	(6)	(6)
	_________	_________	________	_________	_________	_______
Net book value

At 31 December 2017	21,316	20	21,336
At 1 January 2017	7,506	24	7,530
At 1 January 2016	-	-	-

All development and production assets are awaiting approval from the OGA expected 31 August 2018.

10 Asset Acquisitions

Vulcan Satellites

On 28 October 2016, the Company announced the completion of the acquisition of Oyster Petroleum Limited 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, 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 15 for further details.


31 December 2016
Exploration and evaluation assets		5,533 (Note 8)
Less:
Current assets less current liabilities Decommissioning provision Net assets acquired		(13) (3,598) (Note 15) ------------- 1,922

31 December 2017
Milestone payments recognised within D&P assets		2,902 (Note 9)

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. An amount of £1.66 million was recorded in the prior year financial statements for the upfront payments, interim cash adjustments and direct costs of the acquisition.

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.

			£000
31 December 2016
Blythe asset acquisition			1,662 (Note 8)

31 December 2017
Milestone payments recognised within D&P assets			3,078 (Note 9)

11 Investments

	Shares	Loans
	in Group	to Group
Company	companies	companies	Total

	£000	£000	£000
At cost
At 1 January 2016	12,592	4,778	17,370
Additions	1,922	7,217	9,139
	_________	_________	_________
At 31 December 2016	14,514	11,995	26,509
Additions	2,902	285	3,187
	_________	_________	_________
At 31 December 2017	17,416	12,280	29,696

Impairment
At 1 January 2016	(2,085)	(1,870)	(3,955)
Impairment reversal	2,085	-	2,085
	_________	_________	_________
At 31 December 2016	-	(1,870)	(1,870)
Impairment reversal	-	1,870	1,870
	_________	_________	_________
At 31 December 2017	-	-	-

Net book value
At 31 December 2017	17,416	12,280	29,696

At 1 January 2017	14,514	10,125	24,639

At 1 January 2016	10,507	2,908	13,415

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.

In recognition of the 2016 impairment reversal against the carrying value of the Group's exploration and evaluation assets in 2016, as described in Note 8 above, an equivalent impairment reversal of £2.08 million against the carrying value of the Company's investment in its subsidiaries was credited to the Company's Statement of Comprehensive Income. The impairment of £1.87 million taken on loans to Group companies was also subsequently 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 (dormant)	United Kingdom	United Kingdom	100
IOG North Sea Limited	United Kingdom	United Kingdom	100
IOG UK Limited	United Kingdom	United Kingdom	100

IOG Infrastructure Limited will hold the Thames Pipeline when the transaction is completed. However, it was dormant throughout the year ended 31 December 2017. Upon completion of this transaction all three subsidiaries incorporated in the United Kingdom will be engaged in the business of oil and gas exploration and/or operations in the North Sea. The financial reporting periods for each subsidiary entity are consistent with the Company and end on 31 December.

12 Interests in production licences

All eight Group UK Offshore Production Licences, as at 31 December 2017, are held 100% by either IOG North Sea Limited or IOG UK Limited.

13 Receivables and prepayments

	2017	2016
	£000	£000
Group
VAT recoverable	285	22
Prepayments	465	43
Debtors	18	20
Decommissioning guarantees	200	200
	_________	_________
	968	285
	_________	_________
Company
VAT recoverable	285	22
Prepayments	465	38
Debtors	17	20
	_________	_________
	767	80
	_________	_________

Included in Prepayments (both Group and Company) is capital of £408k (2016: £nil) representing expenditure incurred, cumulative to date at 31 December 2017, on progressing the Thames Pipeline deal acquisition and completion. This will be transferred to, and capitalised within IOG Infrastructure Limited following acquisition completion in Q1 2018. As part of the deal the Group will be required to provide security of £3 million.

14 Current liabilities

	2017	2016
	£000	£000
Group
Loans	-	4,076
Trade payables	4,827	5,577
Accruals	569	205
Contingent consideration payable	1,642
	_________	_________
	7,038	9,858
	_________	_________
Company
Trade payables	4,827	5,577
Accruals	174	149
Contingent consideration payable	1,642
	_________	_________
	6,643	5,726
	_________	_________

Of the Group's short-term loans in 2016:

· £1.99 million was due to Weatherford Technical Services Limited at 31 December 2016. Following Amendment, No. 6, to the loan agreement, the loan repayable to Weatherford Technical Services Limited was discharged by cash in full on 24 May 2017. The interest rate on the Weatherford loan was 12% effective 1 January 2017.

· £2.08 million was due to GE Oil & Gas UK Limited ('GE') at 31 December 2016. On 21 December 2017, the loan together with the outstanding GE Skipper creditor (provision of wellhead equipment and services), was renegotiated under the terms of both a deferred Payment Deed and Conversion Deed. This allowed for a total of £1.85 million to be converted into 9,736,842 new ordinary shares in the Company. The remaining balance accrues interest at LIBOR+9% and is repayable by 31 August 2018. Up to 20 December 2017 the interest rate on the GE loan was LIBOR + 9%.

The remaining Skipper creditors are subject to similar Conversion and/or Deferred Payment Deed arrangements whereby remaining balances accrue interest at 9% (+ LIBOR where applicable) from 21 December 2017. Outstanding amounts of £4.49 million are again repayable by 31 August 2018.

15 Non-current liabilities

	2017	2016
	£000	£000
Group
Long-term loans	12,394	4,733
Contingent consideration payable	4,371	-
Decommissioning provision	3,598	3,598
	_________	_________
	20,363	8,331
	_________	_________

Company
Contingent consideration payable	1,259	-
	_________	_________

Long-term loans:

On 7 December 2015, a loan facility was announced for £2.75 million with LOG, interest bearing at LIBOR + 9%.

On 11 December 2015, a further loan was announced for £0.80 million with LOG, interest bearing at LIBOR + 9%.

On 5 February 2016, a further loan was announced arranged with LOG and provided for £10.0 million of secured convertible debt funding. This loan is secured against the Group's assets and fully convertible at LOG's election into the Company's shares at a conversion price of 8p. It is proposed that the loan would need to be drawn in full within three years and converted into ordinary shares in the Company within 36 months following each drawing. No drawing matures earlier than 16 June 2019. The loan is interest bearing at LIBOR + 9%.

The amounts drawn at 31 December 2017 (excluding accrued interest) were as follows:

Loan Facility	Amount Drawn
LOG £2.75 million facility	£2.75 million
LOG £0.80 million facility	£0.80 million
LOG £10.00 million facility	£8.36 million

There were warrants issued to LOG in respect of the former two facilities. The valuation of these warrants is detailed in Note 16 and is amortised over the life of the facilities. Any outstanding non-amortised amount is treated as a prepayment and debited against the loan facility.

The balance on the Group's long-term loans at 31 December 2017 is represented by drawings of £11.91 million plus accrued interest of £1.09 million on the LOG facilities, less the non-amortised value £0.61 million of loan finance (which includes the non-amortised amount of warrants as detailed above). Interest accrued during the year was £0.89 million (2016: £0.21 million).

The interest rate on all LOG loans is LIBOR + 9%. This is deemed to be a market rate and hence no equity element has been recognised for the £10.00 million convertible loan.

15 Non-current liabilities (continued)

Contingent consideration payable:

As indicated in Note 10, the Group is required under the terms of the acquisition of the additional 50% of Blythe and for the acquisition of Vulcan Satellites there are further amounts payable on FDP approval and first gas. Given the progress in projects in the current year the milestone events triggering deferred consideration payments are now considered to be more certain than not. Provisions in the sum of £4.37 million have now been recognised in the Group financial statements (2016: £nil). 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 payments are anticipated to be 1 Nov-19.

	£000
Additional Blythe consideration	3,078
Additional Vulcans considerations	2,901
Foreign exchange	(118)
Unwinding of discount	152
Total	6,013

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

	£000
Current Deferred consideration payable	1,642
Non-Current Deferred consideration payable	4,371

Decommissioning provision:

The Company has obligations in respect of decommissioning a suspended well on the Elland Licence P039. 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. As per Note 1, the current estimate of £3.60 million is based upon a recent technical valuation.

16 Equity share capital

		Share	Share
		capital	premium	Total
	Number	£000	£000	£000
Allotted, issued and fully paid
At 1 January 2016
- Ordinary shares of 1 pence each	78,717,695	787	17,649	18,436
Equity issued	3,961,382	40	-	40
Equity issued	5,777,310	58	630	688
Creditor settlement via issue of shares	20,811,776	208	2,181	2,389
	_________	_________	_________	_________
At 31 December 2016
- Ordinary shares of 1 pence 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 1 pence each	120,209,629	1,203	22,337	23,540
	_________	_________	_________	_________

2016:

During 2016, the Company issued 3,961,382 ordinary shares at a subscription price of 1 pence from the exercise of management and other personnel share options.

During 2016, the Company issued 5,777,310 ordinary shares at a subscription price of 11.9p from the exercise of warrants by GE Oil & Gas UK Limited.

During 2016, the Company issued 20,811,776 ordinary shares in lieu of creditor settlement cash payments.

2017:

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

On 29 December 2017, 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.

16 Equity share capital (continued)

Share options and warrants

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

	Number	Price	Date of Grant	Expiry

1 January 2016	15,466,003	11.09p	various	various

Staff options	2,888,561	1p	1 Mar 2016	28 Feb 2021
Staff options	103,462	1p	29 Jul 2016	31 Aug 2021
Staff options	1,032,499	1p	1 Sep 2016	31 Aug 2021
Options exercised	(3,961,382)
Options lapsed	(4,500,000)

31 December 2016	11,029,143	1p

Staff options	905,099	1p	1 Mar 2017	28 Feb 2022
Staff options	5,718	1p	28 Jun 2017	28 Jun 2022
Staff options	845,912	1p	1 Sep 2017	31 Aug 2022
Options exercised	(462,206)

31 December 2017	12,323,666	1p

Of the remaining staff options granted prior to 31 December 2015, 3,117,362 were exercised during 2016. Of those staff options granted during 2016, 844,020 were exercised during 2016.

All LTIP options awarded to both Mark Routh and Peter Young in September 2013, 4,500,000 outstanding at 31 December 2015, expired on 30 September 2016 and lapsed at that date. Accordingly, the fair value of these awards was transferred from the Share-based Payment Reserve to Accumulated Loss.

Of the remaining staff options, 11,029,143, outstanding at 31 December 2016, 308,860 were exercised during 2017. Of those staff options granted during 2017, 153,346 were exercised during 2017.

All outstanding options at 31 December 2017 were issued at an exercise price of 1p per share and carry no additional performance conditions.

The remaining average contractual life of the 12,323,666 share options outstanding at 31 December 2017 (2016 - 11,029,143) was 2.14 years at that date (2015 - 2.81 years). All such share options were exercisable at 31 December 2017.

The weighted average exercise price of the options remaining was 1.00 pence at 31 December 2017 (2016 - 1.00 pence). No further options have been exercised as at 28 March 2018.

The Company calculates the value of personnel sacrificed share-based compensation as the actual value of sacrificed salary/fees. This is deemed to be the fair value of such awards. The fair value of share options granted in 2017 is calculated as £298k (2016 - £358k) and this has been fully charged to the Statement of Comprehensive Income. The exercise price of such awards was determined as 1p (2016 - 1p).

Further details for directors are provided in Note 4.

16 Equity share capital (continued)

The Company has granted warrants in the prior year as follows:

	Number	Price	Date of Grant	Expiry

1 January 2016	20,010,707	11.37p	various	various

Issued to Weatherford Technical Services Ltd	500,000	8p	29 Mar 2016	31 Mar 2019
Lapsed - Charles Stanley Securities	(630,000)
Exercised by GE Oil & Gas UK Ltd	(5,777,310)

31 December 2016	14,103,397	10.48p

Lapsed - Darwin Strategic	(326,087)

31 December 2017	13,777,310	9.64p

630,000 warrants awarded to Charles Stanley Securities in September 2013, expired and lapsed on 30 September 2016. The fair value of these awards has been transferred from the Share-based Payment Reserve to Accumulated Loss.

All 2015 warrants granted to GE Oil & Gas UK Limited were exercised prior to 31 December 2016. The fair value of these awards has been transferred from the Share-based Payment Reserve to Accumulated Loss.

326,087 warrants awarded to Darwin Strategic in June 2014, expired and lapsed on 4 September 2017. Accordingly, the fair value of these awards has been 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 500,000 warrants granted to Weatherford Technical Services Ltd on 29 March 2016 was calculated as £31k, all of which was recognised as a current financing cost. The average exercise price was determined as 8 pence.

The following assumptions were applied in the Weatherford award calculation:


Risk free interest rate				1.46%
Dividend yield				nil
Weighted average life expectancy				3 years
Volatility factor				100%

An estimated volatility of 100% has been applied based upon the approximate volatility of the Company's share price over the period from the Company's listing on AIM on 30 September 2013 until 29 March 2016.

The remaining average contractual life of the 13,777,310 warrants outstanding at 31 December 2017 (2016 - 14,103,397) was 1.97 years at that date (2016 - 2.92 years). All such warrants were exercisable at 31 December 2017.

The weighted average exercise price of the warrants remaining was 9.64 pence at 31 December 2017 (2016 - 10.48 pence). No further warrants have been exercised as at 28 March 2018.

17 Cash and cash equivalents

	2017	2016
Group and Company	£000	£000

Cash at bank	145	247
	_________	_________

18 Company profit 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 profit for the year was £1,176k (2016: £1,784k).

19 Financial instruments

Significant accounting policies

Details of the significant accounting policies in respect of financial instruments are disclosed in 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

19 Financial instruments (continued)

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-eighteen months for overheads and as commitments dictate for capital spend.

Rolling cash forecasts, identifying the liquidity requirements of the Group and Company, are produced frequently. These are reviewed regularly by management and the Board to ensure that sufficient financial resources are made available. All Group activities are funded through the Company. Post year end the Group and company secured an additional £10m convertible facility to pursue projects to FID, expected August 2018. Notwithstanding this the Board have identified that further funds will be required within the next twelve-eighteen 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
2017 Group	£000	£000	£000	£000	£000

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
	________	_________	________	_________	________

2016 Group
Current financial assets
Cash and cash equivalents	247	-	-	247	247
	________	_________	________	_________	________

	247	-	-	247	247
	________	_________	________	_________	________

Current financial liabilities
Loans	2,086	2,282	-	4,368	4,076
Trade and other payables	696	5,086	-	5,782	5,782

Non-current financial liabilities
Loans	-	-	5,749	5,749	5,749
	________	_________	________	_________	________

	2,782	7,368	5,749	15,899	15,607
	________	_________	________	_________	________

19 Financial instruments (continued)

		Greater than	Greater	Total
	6 months	6 months, less	than	undiscounted	Carrying
	or less	than 12 months	12 months		amount
2017 Company	£000	£000	£000	£000	£000

Current financial assets
Cash and cash equivalents	145	-	-	145	145
	________	_________	________	_________	________

	145	-	-	145	145
	________	_________	________	_________	________

Current financial liabilities
Trade and other payables	1,038	5,979	-	7,017	6,643

Non-current financial liabilities
Provisions	-	-	1,500	1,500	1,259
	________	_________	________	_________	________

	1,038	5,979	1,500	8,517	7,902
	________	_________	________	_________	________
2016 Company

Current financial assets
Cash and cash equivalents	247	-	-	247	247
	________	_________	________	_________	________

	247	-	-	247	247
	________	_________	________	_________	________

Current financial liabilities
Trade and other payables	639	5,087	-	5,726	5,726
	________	_________	________	_________	________

	639	5,087	-	5,726	5,726
	________	_________	________	_________	________

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.

The Group made investments and advances into subsidiary companies during the year and these mostly relates to the funding of the Projects and the Company expects to recoup these loans when the Projects starts to generate positive cash flows.

The Group's and Company's external other receivables comprise Atlantic Petroleum UK Limited and have not been impaired and which are non-interest bearing. The Group and Company do not hold any collateral as security and do not hold any significant provision in the impairment account for other receivables as they relate to third parties with no default history.

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
	2017	2016	2017	2016
	£000	£000	£000	£000
Other receivables	17	20	17	20
Loans to subsidiaries	-	-	12,280	11,995
Cash and cash equivalents	145	247	145	247

19 Financial instruments (continued)

Cash flow interest rate risk

As cash is non-interest bearing, and loans and creditors are subject to only fixed interest rates, variations in commercial interest rates would have no impact upon the Group's and Company's result for the year ended 31 December 2016.

Foreign exchange risk

At 31 December 2017, 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 2,754k (£2,041k) of current liabilities held by the Company. 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 the US dollar would give rise to a £186k gain or £227k loss in the Company's and Group'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 exploration 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 14 and 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 and 2017, the Group made drawings of £11.91 million against its London Oil & Gas Limited loan facilities.

Borrowing facilities

The Group and Company had £13.00 million of borrowings outstanding at 31 December 2017 (2016 - £9,83 million) including accrued interest. It had in place further undrawn debt on the London Oil & Gas Limited facilities of a total £1.64 million excluding accrued interest, at that date.

Hedges

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

20 Financial commitments and contingent liabilities

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

	2017	2016
	£000	£000

Authorised but not contracted	7,560	-
Contracted	1,358	408
	_________	_________

	8,918	408
	_________	_________

All 2017 contracted amounts relate to contracted UKCS Licence Fee and associated OGA Levy payments together with contracted service awards to suppliers procured for the development of the Group's SNS assets. Remaining authorised amounts relate to projected expenditures on the development of the Group's SNS assets through to Final Estimate Decision ('FID'), anticipated 31 August 2018.

All 2016 capital commitments relate to contracted UKCS Licence Fee and associated OGA Levy payments from the Group's participation in its UK North Sea operations.

Skipper:

The Skipper asset, and development of the field, is currently non-commercial and a full write down of the asset value was made at 31 December 2016. There is no material change at 31 December 2017.

If the underlying factors change in the future, then under the terms of the Sale and Purchase Agreement, completed with Alpha Petroleum Resources Ltd in 2015, the Company would have the following contingent liabilities:

· USD 3.00 million upon approval of a Skipper FDP; and

· USD 15.00 million following first oil production from the field.

Other Skipper creditors to the value of £307k, contingent on sustained oil production from the field, were also released at 31 December 2016. These creditors would be reinstated if indicators suggested that development of the Skipper field was more certain than not.

Thames Pipeline:

Security in the sum of £0.50 million, the Initial Thames Decommissioning Pipeline Security Amount, is to be provided on completion of the Thames Pipeline SPA.

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 to its facilities with LOG.

21 Related party transactions

Details of directors' remuneration are provided in Note 4.

Mark Routh acquired no additional shares during the year (2016 - nil). He held 4,303,010 shares at 31 December 2017 (2016 - 4,303,010) shares being 3.58% of the total issued share capital.

Peter Young acquired no additional shares during the year (2016 - nil). He held 13,831,725 shares at 31 December 2017 (2016 - 13,831,725) being 11.51% of the total issued share capital.

During the year, South Riding Consultancy Limited ('SRCL') of which Martin Ruscoe is a director, acquired 113,254 share options (2016: 79,558) and exercised 148,113 share options (2016: nil) respectively. SRCL is the current holder of 148,113 shares and 44,699 share options as at 31 December 2017.

Details of loans and interest charged by LOG are detailed in Note 15. The relevant loans were booked by IOG North Sea Limited.

22 Notes supporting statements of cash flows

Details of significant non-cash transactions

	2017	2016
	£000	£000
Equity consideration for settlement of liabilities	1,982	2,389

Non-current loans and borrowings	Current loans and borrowings£000	Non-currentloans and borrowings£000	Total loans and borrowings£000
At 1 January 2016	1,460	-	1,460
Drawdowns (Repayments)	2,000	5,542	7,542
Effects of foreign exchange	294	-	294
Debt converted into equity	-	-	-
Finance fees in period	41	-	41
Interest accruing in period	281	208	489
Unamortised finance fees	-	(1,017)	(1,017)
At 31 December 2016	4,076	4,733	8,809

Non-current loans and borrowings	Current loans and borrowings£000	Non-currentloans 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

23 Subsequent events

The key events after 31 December 2017 are as follows:

This loan allows the Group to be fully funded through to FID on its 100% owned UK SNS dual gas hub development project (Blythe Hub & Vulcan Satellites Hub).

This information is provided by RNS

The company news service from the London Stock Exchange

END

FR EALDNAEEPEFF

Date		Source	Headline
13th Nov 2023	7:00 am	RNS	Cancellation - IOG PLC
11th Oct 2023	6:00 pm	RNS	IOG
11th Oct 2023	11:40 am	RNS	Appointment of Administrators
28th Sep 2023	2:10 pm	RNS	Intent to Appoint Administrators &Share Suspension
28th Sep 2023	2:10 pm	RNS	Suspension - IOG plc
13th Sep 2023	7:00 am	RNS	Operational & Corporate Update
3rd Aug 2023	1:52 pm	RNS	Approval of Bond Waiver
2nd Aug 2023	2:47 pm	RNS	Proposed Bond Waiver
31st Jul 2023	10:00 am	RNS	Bondholder discussions
12th Jul 2023	7:00 am	RNS	Half-Year Operational Update
26th Jun 2023	7:00 am	RNS	Successful Blythe H2 Intervention
22nd Jun 2023	9:34 am	RNS	Approval of short-term Bond amendments
16th Jun 2023	4:53 pm	RNS	Proposed short-term Bond amendments
16th Jun 2023	11:10 am	RNS	Update on bond discussions
13th Jun 2023	7:00 am	RNS	Blythe H2 First Gas
7th Jun 2023	7:00 am	RNS	Corporate Update
15th May 2023	7:00 am	RNS	Operational Update
2nd May 2023	2:49 pm	RNS	Result of AGM
2nd May 2023	7:00 am	RNS	Corporate and Operational Update
25th Apr 2023	7:00 am	RNS	Appointment of Independent Non-Executive Director
24th Apr 2023	7:00 am	RNS	Notice of AGM
18th Apr 2023	7:12 am	RNS	Drilling Update
17th Mar 2023	1:52 pm	RNS	Director/PDMR Shareholding
17th Mar 2023	7:00 am	RNS	Award of Long-Term Incentive Options
16th Mar 2023	7:00 am	RNS	Final Results for the Year Ended 31 December 2022
6th Mar 2023	7:00 am	RNS	Blythe H2 well spud
3rd Mar 2023	10:00 am	RNS	FY2022 Reserves and Resources Update
24th Feb 2023	7:00 am	RNS	Board Changes
13th Feb 2023	7:00 am	RNS	2023 Operational Update
8th Feb 2023	2:26 pm	RNS	TR-1: Notification of major holdings
7th Feb 2023	12:50 pm	RNS	TR-1: Notification of major holdings
7th Feb 2023	12:08 pm	RNS	TR-1: Notification of major holdings
7th Feb 2023	9:00 am	RNS	Price Monitoring Extension
6th Feb 2023	7:00 am	RNS	Southwark update
27th Jan 2023	9:06 am	RNS	Second Price Monitoring Extn
27th Jan 2023	9:00 am	RNS	Price Monitoring Extension
25th Jan 2023	7:00 am	RNS	Corporate update
19th Jan 2023	1:55 pm	RNS	TR-1: Notification of major holdings
18th Jan 2023	11:05 am	RNS	Second Price Monitoring Extn
18th Jan 2023	11:00 am	RNS	Price Monitoring Extension
18th Jan 2023	7:00 am	RNS	Southwark update
22nd Dec 2022	7:00 am	RNS	Operational update
29th Nov 2022	2:27 pm	RNS	TR-1: Notification of major holdings
28th Nov 2022	11:06 am	RNS	Second Price Monitoring Extn
28th Nov 2022	11:00 am	RNS	Price Monitoring Extension
25th Nov 2022	9:05 am	RNS	Second Price Monitoring Extn
25th Nov 2022	9:00 am	RNS	Price Monitoring Extension
25th Nov 2022	7:00 am	RNS	Saturn Banks production restart
11th Nov 2022	10:58 am	RNS	Board change and grant of LTIP Options
11th Nov 2022	7:00 am	RNS	Phase1 operational update & corporate presentation

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Final Results for the Year Ended 31 December 2017

Health, Safety and Environment ('HS&E')

Business Strategy

Licences

SNS Hubs Reserves

Harvey Prospective Resources

Skipper STOIIP and Resources

Thames Pipeline

Blythe

Elgood

Vulcan Satellites

Harvey

Skipper

Asset Acquisitions

Key Performance Indicators

Principal Risks and Uncertainties

Principal Risks and Uncertainties (cont'd)

Corporate Hedging Strategy and Implementation

Insurance

Income Statement

Balance Sheet

Cash Flow

London Oil and Gas Limited and GE Oil and Gas UK Limited Loans

Funding & Liquidity

Basis of consolidation

Asset Acquisition

Oil and gas exploration, development and producing assets

Investments & Loans (Company)

Operating Leases

Financial instruments

Convertible loan notes

Equity

Loss/earnings per share

Critical accounting judgements and key sources of estimation uncertainty

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