IOG.L Regulatory News (IOG)

26 May 2017

Independent Oil and Gas plc

Final Results for the Year Ended 31 December 2016

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 preliminary results for the Year Ended 31 December 2016.

Highlights:

Strategy

· The Company is delivering its gas hubs strategy in the Southern North Sea ('SNS') prioritising core assets and acquisition opportunities.

Operational

· Increased the Company's 2P+2C gas resource base to almost 400 BCF through strategic acquisitions at compelling entry prices as part of the SNS gas hubs strategy.

o Acquired the other 50% of the Blythe licence, giving 100% ownership and operatorship of the Blythe Hub area.

o Acquired the Vulcan Satellite fields which hold independently estimated 2C resources of 320.7 BCF across three nearby fields.

o Identified significant potential upside through the Harvey appraisal asset, with P50 Resources of 113 BCF, bringing the mid-case resource base to almost 500 BCF.

· Progressed the technical understanding of the Company's SNS portfolio and actively working on delivering a successful project.

o Successful 3D-seismic reprocessing and interpretation project advanced the Company's understanding of the potential of the wider Blythe area and increased internal estimates of P50 probabilistic gas resources from 382 BCF to 490 BCF (85 MMBoe).

o Appointed Technical Director, SNS Project Manager and Pipeline Engineer, and continue to invest in technical and operational team to maintain project momentum.

· Drilled Company's first North Sea well as operator with no safety incidents.

o Established IOG as a UK offshore operator.

o Recovered reservoir condition oil from the Skipper appraisal well in the Northern North Sea.

· Significant strengthening of Board and senior management.

o Andrew Hockey joined as Deputy CEO and Hywel John joined as CFO, with both also joining the Board.

o Andrew Hay appointed as independent Non-Executive Director.

o Martin Ruscoe appointed as London Oil & Gas Limited ('LOG') nominee.

o The Rt. Hon. Charles Hendry appointed to Board as LOG nominee.

· Agreed post year end to acquire 300 MMcfd capacity Thames Pipeline for nominal consideration.

o Pipeline to export all of the Company's gas resources to shore. To be 100% owned and operated, giving the Company control from field to market and significantly reducing project capex and opex.

o Contracts and Letter of Intent signed with contractors for the pipeline pigging and onshore facility refurbishment work.

Financial and management

· Extension of debt facilities provided by strategic investor LOG.

o £10 million convertible loan facility from LOG provided additional working capital and access to funding for acquisitions, augmenting pre-existing facilities of £2.75 million and £0.8 million.

· Cash balance at year end of £247,000 (2015: £23,000) with available facilities from LOG to finance ongoing working capital requirements.

o At 31 December 2016, approximately £8.0 million remained to be drawn of the aggregate availability of £13.55 million from LOG.

· Loss for the year of £21.4 million (2015: £5.3 million profit).

o Annual impairment test resulted in a write-down of £22.1 million relating to Skipper, offset by a write-back of £2.1 million in relation to Blythe reflecting the relative commercial attractiveness of the SNS and the Company's decision not to focus on the Skipper heavy oil project at this stage.

Outlook

· Clear objective in 2017 to secure an appropriate capital structure for the Company and obtain full financing for the SNS and future UKCS opportunities.

o Continuing negotiations with Skipper well creditors seeking agreement for the conversion of up to £6.5 million of outstanding creditor balances to equity.

o Progressing discussions with potential new strategic partners to broaden the investor base through introduction of additional capital and to work alongside LOG.

o Working collaboratively with LOG, major contractors, gas offtakers and banks to implement an innovative financing structure for the Company's SNS gas hubs developments.

· Busy work programme over the coming 12 months as the Company focuses on successfully delivering the gas hubs strategy.

o Commissioned independent third party reserves audit reports to validate the estimated recoverable volumes in both the Blythe Hub and Vulcan Satellites Hub.

o Draft Blythe FDP submitted in late 2016; the final version, incorporating Elgood into a Blythe Hub FDP, to be submitted in mid-2017 with a view to approval by late 2017 or early 2018.

o Vulcan Satellites FDP to be submitted shortly after Blythe Hub FDP with a view to approval in same timeframe.

o Environmental Impact Assessment process for the SNS developments started early in 2017.

· Met all licence commitments and secured approval for the requested licence extensions with the Oil & Gas Authority to progress the SNS development project.

· Committed to value accretive production deals.

o Evaluated several potential acquisition transactions and continue to actively pursue new opportunities.

Mark Routh, CEO of IOG, said:

"2016 was a year of substantial progress for IOG. We established a sizeable resource base as part of our strategy to create high-value gas hubs in the UK Southern North Sea and we acquired a viable potential export route following the negotiation to acquire the Thames pipeline.

"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:

Chief Executive's Review

2016 was a year of substantial progress for Independent Oil and Gas plc (the 'Company') in which we established a sizeable resource base as part of our strategy to create high-value gas hubs in the UK Southern North Sea ('SNS'). Capitalising on the industry downturn, we acquired over 330 BCF of gas resources (2P+2C) at compelling entry values. From below 50 BCF, we expanded in 2016 to nearly 400 BCF of 2P+2C recoverable gas across five fully-owned assets, with significant further appraisal upside that could lift the total to well over half a TCF. The acquisitions of 50% of Blythe and 100% of the Vulcan Satellites in 2016 were landmarks in the evolution of the Group. While relatively small, the Blythe transaction was strategically critical, giving us 100% ownership, operatorship and control of the full hub area. This position was then enhanced significantly with the addition of 100% ownership of the three Vulcan Satellite fields to the east. By negotiating to acquire the Thames pipeline post year-end at nominal cost alongside these two deals we have created an economically robust, high-margin dual gas-hub project in familiar UK waters, with a viable potential exit route and without resorting to expensive and risky exploration.

The Thames pipeline acquisition, then, is the key that unlocks our low-risk development and production strategy. In the SNS we are capturing latent value by identifying new ways to monetise assets that were either defunct or deemed to be of low value, thereby breathing new economic life into a mature basin. Recommissioning the Thames pipeline will not only save the Group up to £100 million in capital costs, but will turn stranded fields into valuable gas for the benefit of all: our investors, the economy and the exchequer. This innovative thinking is exactly what the next phase of the North Sea requires, especially in an era of increasing gas imports and coal's decline as an energy source.

Creative problem solving at the Company is not confined to acquisitions. Our approach to financing has, we believe, been similarly pioneering in the North Sea context. In 2016 we demonstrated how upstream operations can be funded by aligning the interests of all project participants. In that context, the £10 million convertible debt funding in February 2016 reinforced our alliance with London Oil and Gas Limited ('LOG') and ensured more robust finances for the road ahead. With the high-value SNS project to be developed, we now have the opportunity to demonstrate that our progressive approach to project funding will further enhance value. Indeed, this is an opportunity we are already taking, with a core group of blue-chip industry partners lining up to help fast-track the dual gas hubs into development. We anticipate the majority of the funding requirement for our SNS developments will come from contractor funding and gas offtake backed funding to be repaid from cashflows.

Alongside these successful acquisitions, the Company's gas business has been greatly strengthened by the 3D-seismic reinterpretation work undertaken during 2016. Through it we have gained a far better understanding of the geophysics of our licence areas and thereby substantially high-graded our portfolio. In particular, the emergence of Harvey as a gas appraisal asset of very exciting potential, favourably positioned between the Blythe and Vulcan hubs, has clearly validated the investment in this work. The Harvey structure has a previous gas discovery well. A further appraisal well may confirm it as the largest single asset in the Group portfolio. This would significantly further enhance what is already a very attractive two-hub development. Moreover, the 3D-seismic reinterpretation work also enabled the most efficient allocation of our capital, by showing that there were better value options than completing the previously negotiated Cronx acquisition. We have also recently commissioned an independent Competent Persons Report ('CPR') across the whole SNS portfolio which will be published later in 2017.

This successful year for the core gas business then continued with submission of the draft Blythe Field Development Plan ('FDP'), which summed up the extensive progress made on the Blythe hub. The final version, to be submitted in 2017, will also incorporate Elgood into a full Blythe Hub FDP, followed in short order by the Vulcan Satellites Hub FDP. The IOG team continues to work very hard on behalf of all investors to achieve first gas from these assets in a safe and prudent manner at the earliest feasible date. The Environmental Impact Assessment process for the SNS developments started early in 2017 to ensure that the process of FDP approvals remains on track.

Alongside this very satisfying progress in our gas business, in the summer of 2016 the Group drilled its first well as operator, a 100% working interest holder of the Skipper licence in the Northern North Sea. This was a key development for the Group, demonstrating that our small team could deliver an appraisal well in 100 metre water depth in the Northern North Sea with no HSE incidents. While the sample results did not live up to expectations, the well nevertheless confirmed the Group as a credible North Sea operator, establishing a commercial template and cementing relationships with industry and regulatory partners. The management team can take pride in drilling a well against a difficult macro-economic backdrop and in the creativity they showed in securing the financing to drill the well. In any event, we must acknowledge that at current oil prices Skipper is less attractive than our gas portfolio, where the breakeven price is less than USD 20/BOE. We must channel our resources into the most lucrative projects for our shareholders and accordingly, the gas hubs will take priority. We have thus decided not to focus on the Skipper heavy oil project at this stage which has resulted in a write-down of its book value in this year's accounts.

Management has clear objectives in 2017 to secure an appropriate capital structure for the Company and obtain full financing for the SNS and future UKCS opportunities. We are continuing negotiations with Skipper well creditors and seeking agreement for the conversion of up to £6.5 million of outstanding creditor balances to equity. We are progressing discussions with potential new strategic partners to broaden the investor base through the introduction of additional capital and to work alongside LOG. We are also working collaboratively with LOG, major contractors, gas offtakers and banks to implement an innovative financing structure for our SNS gas hubs development.

Government support for our North Sea strategy from the UK Oil & Gas Authority ('OGA') and the Department for Business, Energy & Industrial Strategy ('BEIS'), while something we never take for granted, has been very encouraging throughout this period. We continue to enjoy very constructive dialogues with these bodies in 2017 on FDPs, licence milestones, and infrastructure commitments.

The past year also witnessed the continued strengthening of the Board, management and technical team. We deepened our executive team with the additions of Andrew Hockey as Deputy CEO and Hywel John as CFO, with both joining the Board. Their considerable expertise will be invaluable to our future progress. We also welcomed the appointments of the vastly experienced Martin Ruscoe and the Rt. Hon. Charles Hendry as nominees of LOG to the Board of directors, as well as Andrew Hay as an independent Non-Executive Director. On the management side, our technical capabilities were greatly enhanced with the appointments of Doug Fenwick as Technical Director and Graham Cox as SNS Project Manager, and the team continues to be strengthened as we move forward.

The Company also undertook extensive M&A activity in addition to the successful transactions above, evaluating several potential acquisition opportunities. It remains one of the Company's strategic objectives to acquire value accretive producing assets that can provide a predictable operating cashflow to the business, help fund development activities and further enhance our operating capabilities. We have the skills in the team to do just that and we also have the benefit of significant tax losses that came with the Vulcan Satellites acquisition. It is, however, critical to remain disciplined in such processes and to ensure the right balance of risk and reward. Some of these discussions remain live at the time of writing, while further suitable opportunities are also likely to arise in 2017 and beyond. As ever, the management and Board will be primarily focused on finding compelling value propositions where we believe we have a differentiated position as a buyer.

IOG has a busy work programme over the coming twelve months and the newly strengthened management and operations team are focused on successfully delivering our gas hub strategy alongside pursuing acquisition opportunities which are value accretive and a strategic fit.

Strategic Report

Highlights of 2016: -

· £10 million convertible loan funding: The Group secured a £10 million convertible loan facility from LOG, providing additional working capital and access to funding for acquisitions. £3 million of the facility was designated to cover corporate G&A and licence fees up to July 2018, whilst £7 million was dedicated to fund acquisitions to add value to the Group portfolio. This transaction took the total funding from LOG up to £13.55 million.

· Blythe acquisition: The Group agreed and completed the acquisition of the other 50% of licence P1736 (Blocks 48/22b & 48/23a) containing the Blythe discovery and assumed operatorship of the asset. At £1.5 million, with a deferred consideration of USD 5 million at first gas, this acquisition was low-cost and a strategically important addition to the portfolio, giving the Group full ownership and control over the assets designated for the Group's first development hub. It also doubled the Group's independently verified 2P reserves by 17.2 BCF to 34.3 BCF which is 6.2 million barrels of oil equivalent ('MMBoe'), based on the 2013 CPR, and enabled the Group to focus on progressing the Field Development Plan.

· Blythe Draft FDP Submission: In December, the Group submitted the draft of the Blythe FDP to the OGA. This was a licence requirement and a key milestone for the Group as it gears up towards full development of the field.

· Completion of 3D-Seismic reprocessing and increase in SNS resource estimates: The Company undertook detailed new interpretations of 1990s 3D-seismic data of its licences around the Blythe Hub area, in collaboration with Beagle Geoscience. Analysis of the data across these licences increased the Group's internal estimates of P50 probabilistic gas resources from 382 BCF to 490 BCF. In particular, the P50 resources at Harvey increased to 113 BCF (previously 16 BCF) and the P50 resources at Elgood increased to 22 BCF (previously 11 BCF). Independent CPRs will be completed and published in 2017.

· Vulcan Satellites acquisition: The Company agreed and completed the acquisition of Oyster Petroleum Limited (renamed IOG UK Limited), a subsidiary of Verus Petroleum containing the Vulcan Satellites gas fields in the UK SNS for an initial consideration of £1 million, £0.75 million payable nine months after completion and further deferred payments of up to £3.25 million upon the achievement of certain milestones. The acquisition increased the Group's 2C recoverable resources by 320.7 BCF, or 55.3 MMBoe, at an effective cost of USD 0.22/Boe. The Vulcan Satellites, which require no further appraisal, lie 30-45km east of the Blythe field. IOG UK Limited also holds approximately USD 25.6 million in UK pre-trading expenditure which may reduce the future amount of tax payable by the Group.

· Board changes: During 2016, Marie-Louise Clayton, Paul Murray and Michael Jordan stepped down as Non-Executive Directors to concentrate on other activities. The Company appointed Martin Ruscoe as a Non-Executive Director as the appointed representative on IOG's Board pursuant to the loan agreements with LOG. The Company also appointed Andrew Hay as a Senior Independent Non-Executive Director. David Peattie was appointed as Chairman of the Company. He since resigned in 2017 to take over as Chief Executive of the UK Nuclear Decommissioning Authority.

· Accreditation as operator: Ahead of the appraisal well on the Skipper field, the UK OGA approved the Group's subsidiary company, IOG North Sea Limited, as exploration operator. Qualifying as an exploration operator was an important step forward for the business, not only with respect to drilling the appraisal well, but also in terms of opening up other asset opportunities and progressing on to production operatorship in due course.

Post year-end developments: -

· Acquisition of the Thames Pipeline: In April 2017, the Company signed a Sales & Purchase Agreement ('SPA') to acquire the recently decommissioned Thames Gas Pipeline in the SNS 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 all the Group's current SNS asset portfolio. Estimated initial capacity of the 24-inch Thames pipeline is 300 million cubic feet per day ('MMcfd'). The Group will own 100% and operate the pipeline, giving the Company control from field to market. No tariff will be payable for the transportation of the gas to the onshore Bacton Gas Terminal. Completion is subject to the standard regulatory consents and provision of security to Perenco to cover the cost of additional pipeline integrity surveys that may be required in the future (estimated maximum cost of £500,000). Upon completion of the acquisition the Group is planning to undertake an intelligent pigging inspection to ensure the pipeline's integrity for safe re-use. The Group has already undertaken extensive engineering studies to evaluate the current condition of the Thames Pipeline, based on latest data on wall thickness and corrosion rates from the previous operator and comparable North Sea pipelines. This work firmly indicates that the pipeline's current condition is well within the parameters required to perform its intended function safely. The purpose of the pigging operations is to confirm that the pipeline's condition is in line with expectations and to identify any potential areas that may require remediation. This in turn will allow the Group to confirm the optimal operating pressures and maximum throughput capacity of the pipeline and will provide essential input into the flow assurance work and safety case for the Blythe, Elgood and Vulcan Satellite field developments. The operation will involve cutting the pipeline on the seabed at the nearest point to the Vulcan South gas field and installing the necessary hardware to facilitate the pigging operations and to allow the pipeline to be connected to the Company's two gas development hubs in due course. Onshore facilities will also be refurbished at the Bacton gas terminal including manufacturing and installing a temporary pig trap. Basic pigs will initially be used to clear the line before an intelligent pig is run to ensure the best quality data can be obtained. The Group has now awarded a contract to Rosen Europe BV and has signed a Letter of Intent with Subsea 7 to undertake the offshore pigging work. The Group has also awarded a further contract to EnerMech Ltd for the onshore support and refurbishment work. The pigging operation is scheduled to take place in the third quarter of 2017 subject to the Company arranging the requisite financing. Initial results would be available at the time with full results following within three months. Further security is expected to be provided to the former Thames owners three months prior to first gas.

· Harvey Licence Extension: The OGA confirmed the continuation of licence P2085, which contains the Harvey discovery, until 20 December 2017. If successfully appraised, Harvey has the potential to be the largest gas discovery in the Group portfolio and significantly enhance the economics of the Group's SNS business. The range of resources estimated by management is large with the P90, P50, P10 of 44 BCF, 113 BCF and 290 BCF respectively. Harvey is 100% owned and operated by IOG North Sea Limited. The gas reservoir is in the well understood Leman Sandstone Formation play. A commitment to drill an appraisal well is required to extend the term further and IOG North Sea Limited would expect to make that commitment later in 2017.

· Acceptance of Elgood work: The OGA also accepted the technical work prepared and submitted by the Group in relation to the Elgood discovery and agreed that Elgood should be added to the Blythe FDP as a subsea satellite development. The FDP is being prepared with submission to the OGA expected in mid-2017. Both Elgood and Blythe are 100% owned and operated by IOG North Sea Limited.

· Strengthening of Board and management team: In March 2017, the Company significantly strengthened the Board and management team through the appointments of Andrew Hockey as Deputy Chief Executive and Director, Hywel John as Chief Financial Officer 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 Vulcan Satellites development. Hywel John was previously CEO of Bayfield Energy, CFO of Candax Energy and senior executive at Burren Energy. 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. 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.

Health, Safety and Environmental Policy

The Company Health, Safety and Environmental ('HSE') Policy has been developed for the formal Company Environmental Management System ('EMS') in accordance with the requirements of the ISO14001 Standard. The most recent version of the policy was approved by the Board in June 2016 as part of the preparations to drill the Skipper appraisal well. This policy will guide the development of the EMS and its operating practices going forward.

Environmental Management

As referenced above, an EMS has been developed to manage the environmental aspects of the Group's offshore operations. The scope of the EMS covers offshore exploration drilling, site and environmental surveys and office based activities carried out in support of offshore operations. It is the goal of the Company to achieve both external certification of the EMS to ISO14001 and associated verification to OSPAR Recommendation 2003/5 in 2018.

A key part of the function of the EMS is to identify the significant environmental aspects of the Group's offshore operations and related legal and other requirements. The EMS focusses on the development of an Environmental Aspects Register and Register of Environmental Legislation. This allows the Group to focus on managing the key environmental aspects of its operations and help maintain legal compliance throughout. This also facilitates the setting of appropriate objectives and targets for the control of environmentally significant aspects.

EMS requirements will be implemented and monitored on a practical basis during the planning of drilling operations (and ongoing general office activities). The Company is aware of its position as a small operator relying on major contractors to conduct operations offshore where its significant environmental aspects and related impacts will be found. As such operational control procedures and bridging documents have been designed to ensure the effective implementation of the EMS and its standards throughout both the planning and execution of offshore operations. This focusses on key areas such as contractor appraisal, competency and training, interfacing of management systems and monitoring of operations offshore. This takes account of key ongoing communication from OGA/DECC, regarding operator and contractor EMS interfacing, circulated since the Deepwater Horizon incident.

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 investor LOG.

The aim is to build upon the existing development 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 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 remainder of the Blythe licence, along with operatorship, in addition to the acquisition of the Vulcan Satellites and the successful award of the Harvey and Elgood licences.

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 Company was granted exploration operator status by the OGA with respect to the Skipper licence, which is the step before production operatorship status which the Company will achieve at its SNS gas hubs at the point of FDP approval. This will give the Company control over field development plans and is therefore vital for executing the hub strategy.

Operatorship is also strategically important for other, related reasons. Third party consents to tie in additional discoveries are easier to facilitate for operators of owned infrastructure. 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. 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;

Statement of Reserves & Resources

SNS Hubs GIIP and Resources

Sources:

* ERC Equipoise CPR September 2013. Note: The Company acquired 50% of the Blythe licence in June 2016, so these numbers are doubled from the 2015 Annual Report.

** AGR Tracs Technical Summary - April 2015.

*** IOG internal view - December 2016.

Skipper STOIIP and Resources

Source: AGR Tracs CPR - September 2013.

Operational Update

Blythe

The Blythe gas discovery in the Rotliegendes Leman formation, straddles Blocks 48/22b and 48/23a in the SNS in licence P1736. In June 2016, the Group completed the purchase of the remaining 50% of the licence from Alpha Petroleum Resources Limited, obtaining operatorship with 100% working interest. The acquisition, which doubled the Company's independently verified 2P reserves, assumed consideration of £1.5 million payable at completion with a further USD 5 million payable upon first gas.

In December 2016, IOG North Sea Limited submitted a draft FDP to the OGA. Submission of a final FDP for the Blythe Hub, including both the Blythe and Elgood fields, is targeted for mid-2017. In March 2017, the OGA agreed to extend the Blythe licence until 31 December 2017, conditional upon the achievement of certain milestones including final FDP submission. Upon approval of the final FDP, it is expected that the licence would then continue into the development phase.

Blythe needs no further appraisal and has independently verified gross 2P reserves of 34.3 BCF or 6.2 MMBoe (Source: ERC Equipoise Competent Person's Report dated September 2013.) On completion of the 3D-seismic reinterpretation and re-mapping work undertaken by Beagle Geoscience in 2016, dynamic reservoir modelling has been undertaken for the Group in the first half of 2017 by ERC Equipoise. Consequently, the Group's view of the mid-case recoverable gas at Blythe has been updated to 41.5 BCF. This estimate remains subject to potential change depending on the completion of reservoir modelling on the Vulcan Satellites assets which may impact the forecast production profiles for the Blythe hub assets. The Company intends to validate the increase in estimated recoverable volumes through an updated CPR during 2017.

The Group has, in the meantime, been progressing its field development work on Blythe and the other SNS assets. The current development plan for Blythe incorporates a single high-angle development well, a Normally Unmanned Installation ('NUI') platform at the field, and gas exported via the acquired and recommissioned Thames pipeline to the Bacton Gas Terminal. Final Investment Decision ('FID') on Blythe is expected to be reached by the first quarter of 2019, with first gas expected to follow by the second quarter of 2019. The Company is in advanced discussions regarding the financing, commercial and offtake arrangements for the asset. The Group's latest economic forecasts estimate that Blythe has an un-risked net present value (using a 10% discount rate) in the region of £35 million, with a life-of-field average breakeven gas price in the range of 24-25p/therm.

Gas tested to surface from three separate intervals in the Carboniferous formation, beneath the Blythe Leman gas discovery from one of the Blythe discovery wells, 48/23-3 drilled by Arco in 1987. The maximum rate achieved was 0.9 MMcfd from an unstimulated vertical test (source: End of Well Report 48/23-3 - November 1987). This was deemed uncommercial at the time, before the advent of horizontal multi-fracture stimulated wells. Further technical work including seismic reprocessing and remapping needs to be completed to evaluate this potential resource to refine the gas-in-place estimates which are between 70 BCF and 310 BCF (source: Tullow Oil 48/23a Relinquishment Report - May 2009).

Oil has flowed to surface from the naturally fractured Zechstein Carbonates in the Hauptdolomit formation above the Blythe Leman gas discovery from two wells. Well 48/22-1 drilled by Burmah in 1966 flowed 39° API oil at rates up to 2,000 barrels per day (source: Composite Well Log 48/22-1 - October 1966) and well 48/23-3 drilled by Arco in 1987 flowed 38° API oil at a maximum rate of 1,128 barrels of oil a day (source: End of Well Report 48/23-3 - November 1987). The extent of the structure and potential oil resources in the Hauptdolomit remains unknown. Previous estimates considered that the mapped closure was probably small. Oil-in-place has been estimated between 2 MMBbls and 4 MMBbls (source: Tullow Oil 48/23a Relinquishment Report - May 2009). Further evaluation and re-mapping is continuing now that a development will proceed on the main Blythe gas discovery.

Elgood

IOG North Sea Limited 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. The Company is now working on the development plan for Elgood as part of the wider Blythe hub field development plan to be submitted in final form during 2017. Under this plan, Elgood would be developed as a subsea tie-back to the NUI platform at Blythe and first gas would come after Blythe in 2019.

Based on the 3D-seismic reinterpretation and remapping work undertaken in 2016 by Beagle Geoscience, the internal management probabilistic estimates of the P90/P50/P10 gas initially in place for Elgood are 26/35/48 BCF and probabilistic estimates of the P90/P50/P10 resources are 15/22/31 BCF. Dynamic reservoir modelling work undertaken by ERC Equipoise in the first half of 2017 has further updated management's view of the recoverable volumes at Elgood. Developed as part of a hub with Blythe, the Company's view of the mid-case recoverable volumes at Elgood is now 27.0 BCF. This estimate remains subject to potential change depending on the completion of reservoir modelling on the Vulcan Satellites assets which may impact the forecast production profiles for the Blythe hub assets. The Company intends to validate the increase in estimated recoverable volumes through an updated CPR during 2017.

Elgood is a good quality Rotliegend Leman sandstone reservoir that tested gas at rates in excess of 17 MMcfd when it was first drilled by Enterprise Oil in 1991. Gas was also tested from the Hauptdolomit interval 700 feet above the Leman interval but at low rates without stimulation. The field was not progressed by Enterprise due to the understanding of its size and gas prices at that time. Based on the Group's latest recoverable volume numbers, however, and developed as a subsea tie-back to Blythe, the Company estimates that Elgood has an un-risked net present value (using a 10% discount rate) in the region of £30 million, with a life-of-field average breakeven gas price in the range of 16-17p/therm.

Vulcan Satellites

In October 2016, the Group added the three Vulcan Satellites fields to its portfolio through the acquisition of Oyster Petroleum Limited from Verus Petroleum. Oyster Petroleum Limited has been renamed IOG UK Limited and is a wholly owned subsidiary of the Company. The acquisition increased the Group's 2C gas resources by 320.7 BCF (55.3 MMBoe) at a total consideration of £5 million, £1 million of which was paid upon completion.

The Vulcan Satellites comprise three fields, Vulcan East, Vulcan North West and Vulcan South, which hold independently estimated 2C resources of 77.4 BCF, 131.3 BCF and 112.0 BCF respectively, 320.7 BCF or 55.3 MMBoe collectively. These fields lie in Block 49/21a (Licence P039), Block 49/21d (Licence P2122), Block 48/25b (Licence P130) and Block 49/21c (Licence P1915) in the UK sector of the SNS, approximately 30-45km east of the Group's Blythe field. The fields are considered ready for development with no further appraisal required.

The Company is preparing a joint Vulcan Satellites hub FDP for these three assets, which will be co-developed as a gas hub using up to three NUI platforms with gas exported via the acquired and recommissioned Thames pipeline. This FDP is expected to be submitted in the second half of 2017. Reservoir modelling and other technical and engineering studies are ongoing in the second quarter of 2017 as inputs to this FDP. Once that work is complete, the Company intends to commission an updated CPR on the Vulcan Satellite fields during the course of 2017.

The Company provisionally anticipates the development plan to consist of a total of seven fracture stimulated wells. FID on the Vulcan Satellites is expected to be reached by the first quarter of 2018, with first gas expected to follow by the second quarter of 2019. The Company is in increasingly advanced discussions regarding the financing, commercial and gas offtake arrangements for the assets. The Group's latest economic forecasts estimate that the Vulcan Satellites collectively have an un-risked net present value (using a 10% discount rate) in the region of £290 million, with a life-of-field average breakeven gas price in the 15-16p/therm range.

IOG UK Limited has assumed liability for decommissioning a suspended well on Vulcan East, which in April 2015 was independently estimated to cost £3.5 million as part of a development campaign, based on prevailing rig rates at that time.

Harvey

IOG North Sea Limited 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. Recent 3D-seismic reprocessing and remapping by Beagle Geoscience Limited has led to an improved understanding of the complex faulting that exists in the overlying strata. Based on this work, the internal management probabilistic estimates of the P90/P50/P10 gas initially in place for Harvey are 77/176/403 BCF and probabilistic estimates of the P90/P50/P10 resources are 44/113/290 BCF. Therefore, if appraisal confirms these volumes, Harvey has the potential to be the biggest single asset in the Group's SNS portfolio.

Appraisal drilling will be required to better understand gas volumes in place, build a reservoir model and prepare a development plan. Under the P2085 licence, the Group would need to commit to this well before the end of 2017. It would most likely be drilled as part of the Blythe and Vulcan hubs development drilling campaign, which is expected in 2019, however depending on other factors it may be possible to accelerate this to 2018. If the appraisal well is successful, the Company believes that the most likely development plan would be to install a NUI platform at the field and a connector pipeline exporting the gas to the acquired and recommissioned Thames Pipeline approximately 20km to the south. Based on management's understanding of the reservoir to date, fracture stimulation activity is deemed not likely to be required for field development.

Skipper

In the second quarter of 2016, the Group completed its first operated well, the appraisal of the 100%-owned and operated Skipper oil discovery which lies in Block 9/21a in licence P1609 in the Northern North Sea. The well was drilled to a total vertical depth of 5,578ft with no safety incidents and achieved its primary objective of retrieving good quality reservoir condition oil samples from the reservoir. Sample analysis results subsequently indicated that oil has a high density of approximately 11° API, a high viscosity and a high Total Acid Number ('TAN'). 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 our gas portfolio and not to focus on the Skipper heavy oil project at this stage.

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 is at the time of writing assessing a number of potential opportunities in the UK North Sea.

Finance Review

Income Statement

The Group made a loss for the year of £21.44 million during 2016 (2015 - profit of £5.32 million). The principal component was a net impairment made against oil and gas properties of £20.01 million (2015 - £6.17 million impairment reversal) together with net administration expenses of £0.28 million (2015 - £0.83 million) which includes non-cash share-based payments of £0.2 million (2015 - £0.32 million).

The net impairment relates to the full impairment taken on the Skipper field, £22.10 million, as previously discussed in the Operational Update, offset by the impairment reversal on Blythe, £2.09 million. As a full impairment was taken on the Skipper field, this released long term trade creditors of £0.30 million and these have been credited to the Statement of Comprehensive Income. Net administration expenses comprised general and administration expenses of £1.52 million (2015 - £1.04 million) including share-based payment expense above, offset by £1.24 million (2015 - £0.21 million) expensed to business development ('BD') projects and capitalised to assets throughout the Group. This highlights the significant increase in BD and asset activity throughout the year. Cash settled personnel costs have been maintained at a low level during both 2016 (and 2015) in favour of a sacrificed salary element taken as equity-based incentives. Pre-licence exploration expenses in the sum of £0.71 million (2015 - £0.01 million) again represent the significant increase in BD activity in the year; these costs are expensed whilst post award costs are capitalised. A finance expense of £0.90 million (2015 - gain £0.06 million) includes accrued interest payable on loans and both current and amortised expenses on loan finance facilities.

Balance Sheet

The decrease in exploration and evaluation ('E&E') intangible oil and gas assets during 2016 from £14.818 million to £5.825 million is represented by the Skipper impairment, together with the reclassification of the Blythe oil and gas asset to property, plant and equipment ('PPE'). This is offset by the acquisition of Oyster Petroleum Limited, incorporating the Vulcan Satellite assets.

Current assets have decreased to £0.53 million from £1.52 million mainly resulting from the reclassification of prepaid loan finance costs. Such prepayment is now offset against non-current liabilities with the current year amortisation taken to the Statement of Comprehensive Income.

Total liabilities have increased to £18.19 million from £2.86 million mainly resulting from the drawings on the loans provided by London Oil & Gas Limited and GE Oil & Gas UK Limited - see table below. These liabilities include Skipper deferred trade creditors of £4.36 million, deferred consideration of £0.75 million, LOG loan facilities of £5.75 million, GE Oil & Gas Limited loan facility of £2.08 million and Weatherford Technical Service Limited loan facility of £1.99 million. The outstanding loan from Weatherford Technical Services Limited was discharged in full on 24 May 2017.

Cash Flow

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 London Oil & Gas Limited ('LOG') in parallel with a £2.0 million loan from GE Oil & Gas UK Limited ('GE'). On 11 December 2015, a further loan of £0.8 million was provided by LOG. On 5 February 2016, a further £10.0 million loan was provided by LOG.

The loans are secured over the Group's assets and, following an amendment to these agreements in 1Q 2016, all LOG loans are now due to be redeemed thirty-six months following each individual drawdown; the GE loan is fully repayable at the end of 2017. Interest of LIBOR + 9% per annum accrues on a cumulative monthly basis on each drawdown. GE also agreed to provide wellhead equipment to the Group for the Skipper appraisal well on a fully deferred basis, to be paid for at the same time as repaying the GE loan at the end of 2017.

In support of these loans, the Company agreed to issue 5,777,310 warrants over the Company's ordinary shares to each of LOG and GE. GE exercised their warrants in full in 4Q 2016.

Table 1: Summary Loans with LOG and GE

All Conditions Precedent to the LOG and GE loans have been met and have been drawn with agreement from both LOG and GE. As at 1 January 2017, £250k per month has been committed to cover the Group's general and administration expenses through to 30 June 2018.

The aim of the £10.0 million LOG loan 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.

Including the loan from Weatherford Technical Services Limited the Group and Company had £9,825,000 borrowings outstanding at 31 December 2016 (2015 - £1,460,000) including accrued interest. It had in place further undrawn debt on the London Oil & Gas Limited facilities of a total £8,009,000, excluding accrued interest, at that date.

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.

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 2016 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.

Funding & Liquidity

The Board has reviewed the Group's cash flow forecasts up until December 2018 having regard to its current financial position and operational objectives. These forecasts indicate that the Group will need additional funding to enable it to meet its liabilities as they fall due in the next twelve months. The Board is satisfied that the Group will have sufficient financial resources available to meet its commitments based on the amount of available cash within the Group, its existing debt facilities that can be drawn down, the likelihood of it being able to secure additional funding from existing shareholders or new investors and to agree either the rescheduling of certain existing liabilities to creditors or conversion of such amounts to equity. Additionally, the Group can cut discretionary expenditure and reduce headcount to reduce financing requirements further. Accordingly, the Board continues 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 either fundraising or the deferral or settlement of existing creditors through equity issues. There can be no certainty that additional funds will be forthcoming or the creditors will agree to changes in contractual terms and these conditions indicate 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.

Hywel John

Chief Financial Officer

25 May 2017

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME FOR THE YEAR ENDED 31 DECEMBER

Consolidated Statement of Comprehensive Income

The loss for the year (2015: profit for the year) arose from continuing operations.

CONSOLIDATED AND COMPANY STATEMENTS OF CHANGES IN EQUITY FOR THE YEAR ENDED 31 DECEMBER

Consolidated and Company Statements of Changes in Equity

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

Share premium - Amounts received on the issue of shares, more than 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 AT 31 DECEMBER

Consolidated Statement of Financial Position

Company Number: 07434350

The financial statements were approved and authorised for issue by the Board of Directors on 25 May 2017 and were signed on its behalf by:

Hywel John

Director

COMPANY STATEMENT OF FINANCIAL POSITION AT 31 DECEMBER

Company Statement of Financial Position

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 £1,784,000 (2015: £5,667,000).

The financial statements were approved and authorised for issue by the Board of Directors on 25 May 2017 and were signed on its behalf by: -

Hywel John

Director

CONSOLIDATED CASH FLOW STATEMENT FOR THE YEAR ENDED 31 DECEMBER

Consolidated Cash Flow Statement

Company Cash Flow Statement

NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2016

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 2016 were authorised for issue by the Board of Directors on 25 May 2017 and the balance sheets were signed on the Board's behalf by the CFO, Hywel John.

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 Note 1 on page 41.

The consolidated financial statements have been prepared on a historical cost basis, except for derivative financial instruments at fair value as disclosed in Note 1 on page 39.

Going concern

The Board has reviewed the Group's cash flow forecasts up until December 2018 having regard to its current financial position and operational objectives. These forecasts indicate that the Group will need additional funding to enable it to meet its liabilities as they fall due in the next twelve months. The Board is satisfied that the Group will have sufficient financial resources available to meet its commitments based on the amount of available cash within the Group, its existing debt facilities that can be drawn down, the likelihood of it being able to secure additional funding from existing shareholders or new investors and to agree either the rescheduling of certain existing liabilities to creditors or conversion of such amounts to equity. Additionally, the Group can 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 either fundraising or the deferral or settlement of existing creditors through equity issues. There can be no certainty that additional funds will be forthcoming or the creditors will agree to changes in contractual terms and these conditions indicate the existence of a material uncertainty which may cast significant doubt about the Group's ability to continue as a going concern and therefore it may be unable to realise its assets and discharge its liabilities in the normal course of business. The financial statements do not include the adjustments that would result if the Group was unable to continue as a going concern.

New and revised accounting standards

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

The accounting policies adopted are consistent with those of the previous financial year. 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: -

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

IFRS9 introduces significant changes to the classification and measurement requirements for financial instruments. Management are currently assessing the impact of this standard on the consolidated and Company statement of financial positon.

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. De-facto control exists in situations where the Company has the practical ability to direct the relevant activities of the investee without holding most its voting rights. In determining whether de-facto control exists the Company considers all relevant facts and circumstances, including:

- the size of the Company's voting rights relative to both the size and dispersion of other parties who hold voting rights;

- substantive potential voting rights held by the Company and by other parties;

- other contractual arrangements; and

- historic patterns in voting attendance.

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. During the year, the Company acquired Oyster Petroleum Limited and the results of this Group subsidiary are included from the date that control commenced, being 28 October 2016.

Joint arrangements

Joint arrangements are arrangements in which the Group shares joint control with one or more parties. Joint control is the contractually agreed sharing of control of an arrangement, and exists only when decisions about the activities that significantly affect the arrangement's returns require the unanimous consent of the parties sharing control.

Joint arrangements are classified as either joint operations or joint ventures based on the rights and obligations of the parties to the arrangement. In joint operations, the parties have rights to the assets and obligations for the liabilities relating to the arrangement, whereas in joint ventures, the parties have rights to the net assets of the arrangement.

Joint arrangements that are not structured through a separate vehicle are always joint operations. Joint arrangements that are structured through a separate vehicle may be either joint operations or joint ventures depending on the substance of the arrangement. In these cases, consideration is given to the legal form of the separate vehicle, the terms of the contractual arrangement and, when relevant, other facts and circumstances. When the activities of an arrangement are primarily designed for the provision of output to the parties, and the parties are substantially the only source of cash flows contributing to the continuity of the operations of the arrangement, this indicates the parties to the arrangements have rights to the assets and obligations for the liabilities.

The Group accounts for all its joint arrangements as joint operations by recognising the assets, liabilities, and expenses for which it has rights or obligations, including its share of such items held or incurred jointly.

Business Combinations

The Company uses the acquisition method of accounting to account for business combinations. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured at their fair values at the acquisition date.

Business combinations requires the excess (or shortfall) of the purchase price of acquisitions over the net book value of assets acquired to be allocated to the assets and liabilities of the acquired entity. The Company makes judgements and estimates in relation to the fair value allocation of the purchase price.

The fair value exercise is performed at the date of acquisition. Owing to the nature of fair value assessments in the oil and gas industry, the purchase price allocation exercise and acquisition-date fair value determinations require subjective judgements based on a wide range of complex variables at a point in time. Management uses all available information to make these fair value determinations.

In determining fair value for the acquisition, the Company has utilised valuation methodologies including discounted cash flow analysis. The assumptions made in performing these valuations include assumptions as to discount rates, foreign exchange rates, commodity prices, the timing of developments, capital costs and future operating costs. Any significant change in key assumptions may cause the acquisition accounting to be revised. Acquisition related expenses may be included in the underlying cost of investment.

Revenue

Sales of oil and gas are recognised, net of any sales taxes, when risks and rewards of ownership have passed to the customer, typically, this is at the point of physical lifting. Royalties and tariff income, if applicable, are recognised as earned on an entitlement basis.

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 costs written off.

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 reserves on an entitlement basis. On commencement of production, the D&P asset is amortised on a unit-of-production ('UOP') basis over the life of the commercial reserves of the asset to which they relate.

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.

Oil and gas interests (continued)

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. 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.

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.

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 proven and probable 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. The impairment review of D&P assets is carried out on an annual, 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.

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, a decommissioning asset is also established, since the future cost of decommissioning is regarded as part of the total investment to gain access to future economic benefits, and 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.

Disposals

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

Foreign currencies

The functional and presentation currency of the Group and the Company is GBP Sterling.

The Group translates foreign currency transactions into the functional currency at the rate of exchange prevailing at the transaction date. Monetary assets and liabilities denominated in foreign currency are translated into the functional currency at the rate of exchange prevailing at the reporting date. Exchange differences arising are taken to the Consolidated Statement of Comprehensive Income except for those incurred on borrowings specifically allocable to development projects, which are capitalised as part of the cost of the asset.

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.

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.

Derivative financial instruments

Derivative financial instruments are held at fair value with any changes in fair value arising charged to profit or loss.

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.

Convertible loan notes

Upon issue of a convertible loan note, the proceeds are split between the liability component and the equity component at the date of issue, as necessary. The fair value of the equity component is included in equity and is not re-measured whilst the liability component is included in liabilities, which is increased by the effective rate of interest charged in each period. Upon conversion, the face value of the loan notes is transferred to the share capital and share premium accounts. Interest is expensed to the Statement of Comprehensive Income.

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-based payments to certain employees, to incentivise and reward successful corporate 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. This 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 equity instruments are used to settle liabilities, the liability is extinguished by the share options and the difference between the fair value of the options issued and the liability is debited or credited to the Statement of Comprehensive Income.

The fair value of warrants issued to third parties is calculated by reference to the service provided or if this 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 where the charge 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.

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.

Key areas of estimation uncertainty are:

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 Note 16 for further details of these assumptions.

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 Note 11.

Commercial Reserves

Commercial reserves are proven and probable 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.

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.

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

Key assumptions 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:

· production volumes;

· commodity prices;

· fixed and variable operating costs;

· capital expenditure; and

· discount rates.

Production volumes/recoverable reserves

Annual estimates of oil and gas reserves are generated internally by the Group with external input from operator profiles. 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 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 budgets or specific contracts where available. The Company and Group were not exposed to development capital expenditures in the year.

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 (2015: 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.

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

Decommissioning

The Company has obligations in respect of decommissioning the Vulcan Satellites' E&E 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 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.

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)/profit

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

4 Staff costs and directors' remuneration

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

An amount of £448,000 has been capitalised in exploration and evaluation assets relating to the personnel costs.

No pension plans are provided for directors nor staff. Key management personnel are deemed to be directors.

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;

5 Martin Ruscoe was appointed on 9 February 2016;

6 Andrew Hay was appointed on 29 July 2016.

The share-based incentive amounts represent the fair value of options issued on both 1 March 2016 and 1 September 2016 in lieu of cash salary and/or director fees.

Social security costs for the year for key management personnel were £39,000 (2015 - £21,000).

The service agreements for Mark Routh, Peter Young, David Peattie, Martin Ruscoe and Andrew Hay 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 2016 were 30% for Mark Routh, 94% for Peter Young, 50% for Michael Jordan and 0% for each of Marie-Louise Clayton, Paul Murray, David Peattie, Martin Ruscoe and Andrew Hay. 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 2016 to which these terms relate totalled £91,000 (31 December 2015 - £83,000) for directors and £36,000 (2015 - £81,000) for other personnel and were subsequently settled in share options on 1 March 2017.

Share option exercise transactions for Marie-Louise Clayton and Michael Jordan were made following their departure from the Board; however, for completeness, these are included in the table below.

Directors' interests in options on 1p ordinary shares of the Company at 31 December 2016 were as follows:

1 Options granted to Clayton Consulting Partners Ltd, a company in which Marie-Louise Clayton is a majority shareholder and a director;

2 Options granted to Acura Oil & Gas Ltd, a company in which Mike Jordan is the majority shareholder and a director

Mark Routh as CEO and Peter Young as CFO were entitled to participate under the Group's Long Term Incentive Plan ("LTIP"). All LTIPs expired on 30 September 2016 and no options vested as none of the conditions set by the Remuneration Committee were met.

The Company paid £10,000 for Directors and Officers Liability insurance during the year (2015: £11,000).

5 Finance expense/(gain)

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: