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| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Iog Plc | LSE:IOG | London | Ordinary Share | GB00BF49WF64 | ORD 1P |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 2.00 | 0.00 | 01:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| 0 | 0 | N/A | 0 |
From Apr 2019 to Apr 2024
TIDMIOG
RNS Number : 2982G
Independent Oil & Gas PLC
26 May 2017
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.
Hot Features
Premium
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 GBP10 million convertible loan facility from LOG provided additional working capital and access to funding for acquisitions, augmenting pre-existing facilities of GBP2.75 million and GBP0.8 million.
-- Cash balance at year end of GBP247,000 (2015: GBP23,000) with available facilities from LOG to finance ongoing working capital requirements.
o At 31 December 2016, approximately GBP8.0 million remained to be drawn of the aggregate availability of GBP13.55 million from LOG.
-- Loss for the year of GBP21.4 million (2015: GBP5.3 million profit).
o Annual impairment test resulted in a write-down of GBP22.1 million relating to Skipper, offset by a write-back of GBP2.1 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 GBP6.5 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."
-S-
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 Mark Routh (CEO) +44 (0) 20 3879 Hywel John (CFO) 0510 finnCap Ltd Christopher Raggett / Anthony Adams +44 (0) 20 7220 (Corporate Finance) 0500 Camarco +44 (0) 20 3757 Georgia Edmonds / Tom Huddart 4980
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 GBP100 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 GBP10 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 GBP6.5 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: -
-- GBP10 million convertible loan funding: The Group secured a GBP10 million convertible loan facility from LOG, providing additional working capital and access to funding for acquisitions. GBP3 million of the facility was designated to cover corporate G&A and licence fees up to July 2018, whilst GBP7 million was dedicated to fund acquisitions to add value to the Group portfolio. This transaction took the total funding from LOG up to GBP13.55 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 GBP1.5 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 GBP1 million, GBP0.75 million payable nine months after completion and further deferred payments of up to GBP3.25 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 GBP1 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 GBP500,000). 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;
Licence Blocks Subsidiary Interest Discovery Licence
Name Type
-------- ----------------- --------------- --------- ---------- ------------
Blythe/Elgood Hub
---------------------------------------------------------------------------------
P1736 48/22b ALL and IOG North 100% Blythe Traditional
48/23a ALL Sea Limited
-------- ----------------- --------------- --------- ---------- ------------
P2260 48/22c ALL IOG North 100% Elgood Promote
Sea Limited
-------- ----------------- --------------- --------- ---------- ------------
P2085 48/23c ALL and IOG North 100% Harvey Promote
48/24b ALL Sea Limited
-------- ----------------- --------------- --------- ---------- ------------
Vulcan Satellites Hub
---------------------------------------------------------------------------------
P039 49/21a J IOG UK Limited 100% Vulcan Traditional
E
-------- ----------------- --------------- --------- ---------- ------------
P2122 49/21d ALL IOG UK Limited 100% Vulcan Traditional
E
-------- ----------------- --------------- --------- ---------- ------------
P130 48/25b NW VULCAN IOG UK Limited 100% Vulcan Traditional
NW
-------- ----------------- --------------- --------- ---------- ------------
P1915 49/21c ALL IOG UK Limited 100% Vulcan Traditional
S
-------- ----------------- --------------- --------- ---------- ------------
Skipper
---------------------------------------------------------------------------------
P1609 9/21a ALL IOG North 100% Skipper Traditional
Sea Limited
-------- ----------------- --------------- --------- ---------- ------------
Statement of Reserves & Resources
SNS Hubs GIIP and Resources
SNS Portfolio Gas Initially in Estimated resources
Place
------------------ --------------------- ------------------------
Field (BCF) (BCF)
------------------ --------------------- ------------------------
Blythe Hub
-------------------------------------------------------------------
P90 P50 P10 1P 2P 3P
------------------ ------ ----- ------ ------- ------- ------
Blythe Discovery
* 39 52 84 22 34 48
------------------ ------ ----- ------ ------- ------- ------
P90 P50 P10 1C 2C 3C
------------------ ------ ----- ------ ------- ------- ------
Elgood Discovery
*** 26 35 48 15 22 31
------------------ ------ ----- ------ ------- ------- ------
Harvey Appraisal
*** 77 176 403 44 113 290
------------------ ------ ----- ------ ------- ------- ------
Total Blythe
Hub 142 263 535 81 169 369
------------------ ------ ----- ------ ------- ------- ------
Vulcan Satellites Hub **
-------------------------------------------------------------------
P90 P50 P10 1C 2C 3C
------------------ ------ ----- ------ ------- ------- ------
Vulcan North
West 184 215 251 112 131 153
------------------ ------ ----- ------ ------- ------- ------
Vulcan East 104 124 145 64 77 91
------------------ ------ ----- ------ ------- ------- ------
Vulcan South 117 186 275 59 112 193
------------------ ------ ----- ------ ------- ------- ------
Total Vulcan
Satellites
Hub 405 526 671 234 321 438
------------------ ------ ----- ------ ------- ------- ------
Totals SNS
Portfolio 547 789 1206 315 490 806
------------------ ------ ----- ------ ------- ------- ------
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
Discovered Oil Initially Contingent Resources
in Place
--------- ----------------------------- -------------------------
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
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 GBP1.5 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 GBP35 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 39deg 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 38deg 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 GBP30 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 GBP5 million, GBP1 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 GBP290 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 GBP3.5 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 11deg 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 GBP21.44 million during 2016 (2015 - profit of GBP5.32 million). The principal component was a net impairment made against oil and gas properties of GBP20.01 million (2015 - GBP6.17 million impairment reversal) together with net administration expenses of GBP0.28 million (2015 - GBP0.83 million) which includes non-cash share-based payments of GBP0.2 million (2015 - GBP0.32 million).
The net impairment relates to the full impairment taken on the Skipper field, GBP22.10 million, as previously discussed in the Operational Update, offset by the impairment reversal on Blythe, GBP2.09 million. As a full impairment was taken on the Skipper field, this released long term trade creditors of GBP0.30 million and these have been credited to the Statement of Comprehensive Income. Net administration expenses comprised general and administration expenses of GBP1.52 million (2015 - GBP1.04 million) including share-based payment expense above, offset by GBP1.24 million (2015 - GBP0.21 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 GBP0.71 million (2015 - GBP0.01 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 GBP0.90 million (2015 - gain GBP0.06 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 GBP14.818 million to GBP5.825 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 GBP0.53 million from GBP1.52 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 GBP18.19 million from GBP2.86 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 GBP4.36 million, deferred consideration of GBP0.75 million, LOG loan facilities of GBP5.75 million, GE Oil & Gas Limited loan facility of GBP2.08 million and Weatherford Technical Service Limited loan facility of GBP1.99 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 GBP2.75 million from London Oil & Gas Limited ('LOG') in parallel with a GBP2.0 million loan from GE Oil & Gas UK Limited ('GE'). On 11 December 2015, a further loan of GBP0.8 million was provided by LOG. On 5 February 2016, a further GBP10.0 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
Facility Available Interest Warrants / Convertible Repayment
Amount until rate details by
(GBP million)
---- --------------- ---------- --------- ----------------------- --------------
GE GBP2.00 30 Dec-17 LIBOR 5,777,310 warrants 30 Dec-17
+ 9% @ 11.9p
---- --------------- ---------- --------- ----------------------- --------------
LOG GBP2.75 31 Dec-19 LIBOR 5,777,310 warrants 36 months
+ 9%. @ 11.9p from drawing
---- --------------- ---------- --------- ----------------------- --------------
LOG GBP0.80 31 Dec-19 LIBOR 7,500,000 warrants 36 months
+ 9%. @ 8p from drawing
---- --------------- ---------- --------- ----------------------- --------------
LOG GBP10.00 31 Dec-19 LIBOR 8p conversion 36 months
+ 9%. price from drawing
---- --------------- ---------- --------- ----------------------- --------------
GBP15.55
---------------
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, GBP250k per month has been committed to cover the Group's general and administration expenses through to 30 June 2018.
The aim of the GBP10.0 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 GBP9,825,000 borrowings outstanding at 31 December 2016 (2015 - GBP1,460,000) including accrued interest. It had in place further undrawn debt on the London Oil & Gas Limited facilities of a total GBP8,009,000, 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.
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 * Management regularly communicates its strategy to
fundraising and lowering shareholders
the share price
* Focus is placed on building an asset portfolio
capable of delivering regular news flow and offering
continuing prospectivity
--------------------------- ------------------------------------------------------------
General market conditions
may fluctuate hindering * Management aims to retain adequate working capital
delivery of the company's and secure finance facilities sufficient to ride out
business plan downturns should they arise
--------------------------- ------------------------------------------------------------
Each asset carries
its own risk profile * Management aims to avoid over-exposure to individual
and no outcome can assets and to identify the associated risks
be certain objectively
--------------------------- ------------------------------------------------------------
Company may not be
able to raise funds * Management maintains regular dialogue with a variety
to exploit its assets of potential funding partners.
or continue as a going
concern
--------------------------- ------------------------------------------------------------
Operations: Operations may not go to plan, leading
to damage, pollution, cost overruns and poor
outcomes.
-------------------------------------------------------------------------------------------
Risk Mitigation
------------------------------ -----------------------------------------------------------
Individual wells may
not deliver recoverable * Thorough pre-drill evaluations are conducted to
oil and gas reserves identify the risk/reward balance
* Exposure selectively mitigated through farm-out
------------------------------ -----------------------------------------------------------
Operations may take
far longer or cost * Management applies rigorous budget control
more than expected
* Adequate working capital is retained to cover
reasonable eventualities
------------------------------ -----------------------------------------------------------
Resource estimates
may be misleading curtailing * The Group deploys qualified personnel
actual reserves recovered
* Regular third-party reports are commissioned
* A prudent range of possible outcomes are considered
within the planning process
------------------------------ -----------------------------------------------------------
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
------------------------- ------------------------------------------------------
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 * Price mitigation strategies may be employed at the
company cannot be certain point of major capital commitment
of the future sales
value of its products
* 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
--------------------------- -----------------------------------------------------------
The Group may not be
able to get access, * A range of different off-take options are pursued
at reasonable cost, wherever possible
to infrastructure and
product markets when
required
--------------------------- -----------------------------------------------------------
Credit to support field
development programmes * The Company seeks to build and maintain strong
may not be available banking relationships and initiates funding
at reasonable cost 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 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 YEARED 31 DECEMBER
Consolidated Statement of Comprehensive Income
Notes 2016 2015
GBP000 GBP000
Other administration expense (279) (833)
(Impairment)/impairment reversal
of oil and gas properties 8 (20,013) 6,169
Impairment of creditors 307 -
Exploration costs written off (712) (10)
Net gain on settlement of liabilities 458 -
Foreign exchange loss (299) (65)
_________ _________
Operating (loss)/profit 3 (20,538) 5,261
Finance (expense)/gain 5 (899) 61
_________ _________
(Loss)/profit for the year before
taxation (21,437) 5,322
Taxation 6 - -
_________ _________
Loss and total comprehensive (loss)/profit
for the year attributable to equity
holders of the parent 7 (21,437) 5,322
_________ _________
(Loss)/profit for the year per
ordinary share - basic 7 (23.2p) 7.4p
(Loss)/profit for the year per
ordinary share - diluted 7 (23.2p) 6.5p
The loss for the year (2015: profit for the year) arose from continuing operations.
CONSOLIDATED AND COMPANY STATEMENTS OF CHANGES IN EQUITY FOR THE YEARED 31 DECEMBER
Consolidated and Company Statements of Changes in Equity
Share Share Share-based Accumulated Total equity
capital premium payment losses
reserve
Group GBP000 GBP000 GBP000 GBP000 GBP000
At 1 January 2015 692 17,163 1,754 (13,629) 5,980
Profit for the year - - - 5,322 5,322
_____ ________ ________ ________ _______
Total comprehensive income
attributable to owners
of the parent - - - 5,322 5,322
Share capital issued 30 315 - - 345
Issue costs - (10) - - (10)
Settlement of loan via
issue of shares 65 181 - 246
Issue of warrants - - 1,272 - 1,272
Issue of share options - - 321 - 321
_____ ________ ________ ________ _______
At 31 December 2015 787 17,649 3,347 (8,307) 13,476
Loss for the year - - - (21,437) (21,437)
_____ ________ ________ ________ _______
Total comprehensive expense
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)
_____ ________ _______ ________ _______
Company
At 1 January 2015 692 17,163 1,754 (13,629) 5,980
Profit for the year - - - 5,667 5,667
_____ ________ ________ ________ _______
Total comprehensive income - - - 5,667 5,667
Share capital issued 30 315 - - 345
Issue costs - (10) - - (10)
Settlement of loan via
issue of shares 65 181 - - 246
Issue of warrants - - 1,272 - 1,272
Issue of share options - - 321 - 321
_____ ________ ________ ________ _______
At 31 December 2015 787 17,649 3,347 (7,962) 13,821
Profit for the year - - - 1,784 1,784
_____ ________ ________ ________ _______
Total comprehensive income - - - 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
______ ________ _______ ________ _______
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
Notes 2016 2015
GBP000 GBP000
Non-current assets
Intangible assets: exploration
& evaluation 8 5,825 14,818
Intangible assets: other 8 2 -
Property, plant and equipment:
development & production 9 7,506 -
Property, plant and equipment:
other 9 24 -
_________ _________
13,357 14,818
_________ _________
Current assets
Other receivables and prepayments 13 285 1,493
Cash and cash equivalents 17 247 23
_________ _________
532 1,516
_________ _________
Total assets 13,889 16,334
Current liabilities
Loans 14 (4,076) (1,460)
Trade and other payables 14 (5,782) (1,105)
_________ _________
(9,858) (2,565)
_________ _________
Non-current liabilities
Loans 15 (4,733) -
Trade and other payables 15 - (293)
Provisions 15 (3,598) -
_________ _________
(8,331) (293)
_________ _________
Total liabilities (18,189) (2,858)
_________ _________
NET (LIABILITIES)/ASSETS (4,300) 13,476
_________ _________
Capital and reserves
Called-up equity share capital 16 1,093 787
Share premium account 16 20,460 17,649
Share-based payment reserve 2,885 3,347
Accumulated losses (28,738) (8,307)
_________ _________
(4,300) 13,476
_________ _________
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
Company Number: 07434350 Notes 2016 2015
GBP000 GBP000
Non-current assets
Intangible assets 8 2 -
Property, plant and equipment 9 24 -
Investments 11 14,514 10,507
Amounts due from subsidiaries 11 10,125 2,908
_________ _________
24,665 13,415
_________ _________
Current assets
Other receivables and prepayments 13 80 1,493
Cash and cash equivalents 17 247 23
_________ _________
327 1,516
_________ _________
Total assets 24,992 14,931
Current liabilities
Trade and other payables 14 (5,726) (1,086)
Non-current liabilities
Trade and other payables 15 - (24)
_________ _________
Total liabilities (5,726) (1,110)
_________ _________
NET ASSETS 19,266 13,821
_________ _________
Capital and reserves
Called-up equity share capital 16 1,093 787
Share premium account 16 20,460 17,649
Share-based payment reserve 2,885 3,347
Accumulated losses (5,172) (7,962)
_________ _________
19,266 13,821
_________ _________
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 GBP1,784,000 (2015: GBP5,667,000).
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 YEARED 31 DECEMBER
Consolidated Cash Flow Statement
Notes 2016 2015
GBP000 GBP000
(Loss)/profit for the year (21,437) 5,322
Adjustments for:
Depreciation and amortisation 8,9 4 -
Impairment of intangible oil and
gas assets 8 20,013 (6,169)
Impairment of creditors (307) -
Gain on settlement of liabilities 3 (73) -
Share based payments 3 206 321
Movement in trade and other receivables (146) (136)
Movement in trade and other payables (853) 187
Interest and financing fees 5 899 123
Impairment/(gain on) of derivative
financial assets - (204)
Foreign exchange loss 3 299 65
_________ _________
Net cash used in operating activities (1,395) (491)
Cash flows from investing activities
Purchase of intangible oil and
gas assets (3,784) (494)
Purchase of intangible assets
- other 8 (3) -
Purchase of PP&E - other 9 (30) -
Acquisitions 10 (2,834) -
_________ _________
Net cash used in investing activities (6,651) (494)
Cash flows from financing activities
Proceeds from issue of ordinary
shares 16 728 345
Costs of share issue - (10)
Net proceeds from loans received/(repaid) 7,542 (237)
Amounts received for derivative
financial instruments - 512
_________ _________
Net cash generated from financing
activities 8,270 610
Increase/(decrease) in cash and
cash equivalents in the year 224 (375)
Cash and cash equivalents at start
of year 23 398
_________ _________
Cash and cash equivalents at end
of year 17 247 23
_________ _________
Company Cash Flow Statement
Notes 2016 2015
GBP000 GBP000
Profit for the year 1,784 5,667
Adjustments for:
Depreciation, depletion and amortisation 8,9 4 -
Impairment/(impairment reversal)
of investments in and amounts
due from subsidiaries 11 (2,085) (6,169)
Gain on settlement of liabilities 3 (73) -
Recharges to subsidiary for management
and technical services - (200)
Share-based payment charges 3 206 321
Movement in trade and other receivables 1,413 (136)
Movement in trade and other payables (689) 184
Interest and financing fees - 22
Foreign exchange loss (5) (204)
_________ _________
Net cash used in operating activities 555 (515)
Cash flows from investing activities
Purchase of intangible assets 8 (3)
Purchase of property, plant and
equipment 9 (30) -
Amounts loaned to subsidiaries (7,396) (470)
Amounts paid to acquire subsidiary (1,172)
_________ _________
Net cash used in investing activities (8,601) (470)
Cash flows from financing activities
Proceeds from issue of ordinary
shares 728 345
Costs of share issue - (10)
Net proceeds from loans received/(repaid) 7,542 (237)
Amounts received for derivative
financial instruments - 512
_________ _________
Net cash generated from financing
activities 8,270 610
Increase/(decrease) in cash and
cash equivalents in the year 224 (375)
Cash and cash equivalents at start
of year 23 398
_________ _________
Cash and cash equivalents at end
of year 17 247 23
_________ _________
NOTES FORMING PART OF THE FINANCIAL STATEMENTS FOR THE YEARED 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: -
Standard Description Effective
date
-------------------- ------------------------------- -----------
IFRS 15 Revenue from contracts 1 January
with customers 2018
-------------------- ------------------------------- -----------
IFRS 9 Financial instruments 1 January
2018
-------------------- ------------------------------- -----------
IFRS 16 Leases 1 January
2019
-------------------- ------------------------------- -----------
IAS 12 Recognition of deferred 1 January
tax assets for unrealised 2017
losses (amendments)
-------------------- ------------------------------- -----------
IAS 7 Disclosure initiative 1 January
(amendments) 2017
-------------------- ------------------------------- -----------
IFRS 15 Clarifications to IFRS 1 January
15 - revenue from contracts 2018
with customers
-------------------- ------------------------------- -----------
IFRS 2 Classification and measurement 1 January
of share-based payment 2018
transactions (amendments)
-------------------- ------------------------------- -----------
Annual improvements 2012-2014 cycle 1 January
to IFRSs 2017 and
1 January
2018
-------------------- ------------------------------- -----------
IFRIC 22 Foreign currency transactions 1 January
and advance consideration 2018
-------------------- ------------------------------- -----------
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:
2016 2015
GBP000 GBP000
Fees payable to the Company's auditor:
* for the audit of the Company's and Group's financial
statements 40 28
Depreciation, depletion and amortisation 4 -
Exploration costs written off 712 10
Net impairment/(impairment reversal)
of oil and gas properties 20,013 (6,169)
Impairment of creditors (307) -
Personnel costs 399 247
Personnel costs - share-based payments 206 321
Net gain on settlement of liabilities (458) -
Foreign exchange loss 299 65
_________ _________
4 Staff costs and directors' remuneration
During the year, the average number of personnel for both the Company and Group was: -
2016 2015
Number Number
Management/operational 13 10
________ ________
Directors 5 5
________ ________
Personnel costs GBP000 GBP000
Wages, salaries and fees 645 301
Social security costs 49 21
Share-based incentives 358 321
________ ________
1,052 643
________ ________
An amount of GBP448,000 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.
Directors' remuneration Salary Share-based 2016 Salary Share-based 2015
incentives Total incentives Total
GBP000 GBP000 GBP000 GBP000 GBP000 GBP000
Mark Routh 59 139 198 106 156 262
Peter Young 141 22 163 124 63 187
Marie-Louise
Clayton(1) - 13 13 9 19 28
Michael Jordan(2) 10 15 25 20 10 30
Paul Murray(3) - 29 29 10 17 27
David Peattie(4) - 6 6 - - -
Martin Ruscoe(5) - 15 15 - - -
Andrew Hay(6) - 3 3 - - -
_______ ________ ________ ________ ________ ________
210 242 452 269 265 534
_______ ________ ________ ________ ________ ________
(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 GBP39,000 (2015 - GBP21,000).
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 GBP91,000 (31 December 2015 - GBP83,000) for directors and GBP36,000 (2015 - GBP81,000) 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:
Granted Total Awarded Total Exercise Expiry
31 Dec / (Exercised) 31 Dec price date
2015 in 2016 2016
23 Sept 30 Sep
Mark Routh 2013 2,933,946 - 2,933,946 1p 2018
23 Sept 23 Sept
2013 1,500,000 - 1,500,000 29.74p 2023
23 Sept 23 Sept
2013 1,500,000 - 1,500,000 41.63p 2023
19 Nov 28 Feb
2014 162,114 - 162,114 1p 2019
19 Nov 31 Aug
2014 218,672 - 218,672 1p 2019
1 Mar 28 Feb
2015 638,361 - 638,361 1p 2020
31 Aug 31 Aug
2015 611,601 - 611,601 1p 2020
1 Mar 28 Feb
2016 - 888,494 888,494 1p 2021
1 Sep 31 Aug
2016 - 365,550 365,550 1p 2021
23 Sept 30 Sep
Peter Young 2013 1,700,000 - 1,700,000 1p 2018
23 Sept 23 Sept
2013 750,000 - 750,000 29.74p 2023
23 Sept 23 Sept
2013 750,000 - 750,000 41.63p 2023
19 Nov 28 Feb
2014 122,814 - 122,814 1p 2019
19 Nov 31 Aug
2014 71,405 - 71,405 1p 2019
1 Mar 28 Feb
2015 172,717 - 172,717 1p 2020
31 Aug 31 Aug
2015 165,476 - 165,476 1p 2020
1 Mar 28 Feb
2016 - 240,393 240,393 1p 2021
1 Sep 31 Aug
2016 - 34,270 34,270 1p 2021
23 Sept 30 Sept
Marie-Louise 2013 570,000 (570,000) - 1p 2018
19 Nov 28 Feb
Clayton(1) 2014 24,563 (24,563) - 1p 2019
19 Nov 31 Aug
2014 45,699 (45,699) - 1p 2019
1 Mar 28 Feb
2015 138,173 (138,173) - 1p 2020
31 Aug 31 Aug
2015 132,381 (132,381) - 1p 2020
1 Mar 28 Feb
2016 - 168,742 - 1p 2021
(168,742)
Michael 23 Sept 30 Sept
Jordan(2) 2013 290,000 (290,000) - 1p 2018
19 Nov 28 Feb
2014 24,563 (24,563) - 1p 2019
19 Nov 31 Aug
2014 24,754 (24,754) - 1p 2019
1 Mar 28 Feb
2015 69,087 (69,087) - 1p 2020
31 Aug 31 Aug
2015 66,191 (66,191) - 1p 2020
1 Mar 28 Feb
2016 - 96,157 - 1p 2021
(96,157)
1 Sep 31 Aug
2016 - 39,562 39,562 1p 2021
19 Nov 31 Aug
Paul Murray 2014 51,878 (51,878) - 1p 2019
1 Mar 28 Feb
2015 138,173 (138,173) - 1p 2020
31 Aug 31 Aug
2015 132,381 (132,381) - 1p 2020
1 Mar 28 Feb
2016 - 192,315 - 1p 2021
(192,315)
29 Jul 28 Jul
2016 - 103,462 - 1p 2021
(103,462)
1 Sep 31 Aug
David Peattie 2016 - 22,861 22,861 1p 2021
Martin 1 Sep 31 Aug
Ruscoe 2016 - 79,558 79,558 1p 2021
Andrew 1 Sep 31 Aug
Hay 2016 - 11,430 11,430 1p 2021
(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 GBP10,000 for Directors and Officers Liability insurance during the year (2015: GBP11,000).
5 Finance expense/(gain)
2016 2015
GBP000 GBP000
Interest on loans 489 123
Fair value of warrants issued 31 -
Amortisation of loan finance charges 339 -
Current year loan finance charges 40 20
Gain on derivative financial asset - (204)
________ ________
899 (61)
________ _________
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:
2016 2015
GBP000 GBP000
(Loss)/profit for the year (21,437) 5,322
Income tax expense - -
_________ _________
(Loss)/profit before income taxes (21,437) 5,322
Expected tax (credit)/charge based
on the standard rate of United Kingdom
corporation tax at the domestic
rate of 40% (2015: 40%) (8,575) 2,129
Expenses not deductible for tax
purposes - 100
Expense/(income) not taxable/allowable 7,994 (2,498)
Unrecognised taxable losses carried
forward 581 269
_________ _________
Total tax expense - -
_________ _________
b) Deferred taxation
Due to the nature of the Group's exploration activities there is a long lead time in either developing or otherwise realising exploration 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 GBP32,864,000 (2015: GBP693,000). This includes a figure of GBP20,788,000 on acquisition of Oyster Petroleum Limited. A deferred tax asset will only be created if there is reasonable certainty that profits will be earned in the foreseeable future.
7 (Loss)/profit per share
2016 2015
GBP000 GBP000
(Loss)/profit for the year attributable
to shareholders (21,437) 5,322
_________ _________
Weighted average number of ordinary
shares 92,489,621 71,510,947
Weighted average number of ordinary
shares - diluted basis 134,400,703 81,608,317
_________ _________
(Loss)/profit per share in pence
- undiluted (23.2p) 7.4p
(Loss)/profit per share in pence
- diluted (23.2p) 6.5p
_________ ________
Diluted loss per share is calculated based upon the weighted average number of ordinary shares plus the weighted average number of ordinary shares that would be issued upon conversion of potentially dilutive share options and warrants into ordinary shares. As the result for 2016 was a loss, the calculation of the diluted EPS was anti-dilutive and therefore the potential ordinary shares were ignored for the purposes of calculating diluted EPS. The impact of options and warrants subsequently issued on 1 March 2017 has been to increase the weighted average number of ordinary shares on a diluted basis to 135,305,802.
8 Intangible assets
Group
Exploration Company Total Exploration
& evaluation & IT software & evaluation
assets assets assets
2016 2016 2016 2015
GBP000 GBP000 GBP000 GBP000
At cost
At beginning of the
year 16,903 - 16,903 15,767
Additions 11,331 3 11,334 1,136
Blythe asset acquisition
(note 10) 1,662 - 1,662 -
Vulcan satellites asset
acquisition (note 10) 5,533 - 5,533 -
Reclassified as Development
& Production assets (7,506) - (7,506) -
_________ _________ ________ _________
At end of the year 27,923 3 27,926 16,903
_________ _________ ________ _________
Impairments and write-downs
At beginning of the
year (2,085) - (2,085) (8,254)
DD&A - (1) (1) -
Impairment reversal/(impairment) (20,013) - (20,013) 6,169
_________ _________ ________ _________
At end of the year (22,098) (1) (22,099) (2,085)
_________ _________ ________ _________
Net book value
At 31 December 5,825 2 5,827 14,818
_________ _________ _________ _________
At 1 January 14,818 - 14,818 7,513
_________ _________ ________ _________
In 2015, following a revised valuation of both the Skipper and Blythe assets, the Skipper impairment of GBP6,169,000, charged in 2014, was reversed and the gain was taken to the Statement of Comprehensive Income.
The 2016 impairment of GBP22,098,000 reflects the decision that the Skipper field is no longer commercial.
Exploration & evaluation assets at 31 December 2016 mainly comprise the Group's interest in the Vulcan Satellites, Elgood and Harvey.
Following submission of the Blythe FDP in December 2016, as per the Group's accounting policy, the Blythe asset has been re-categorised as property, plant and equipment. In accordance with IFRS6 and the Group's accounting policy, Blythe has been assessed at the point of transfer and it was determined that based on the project economics; the impairment on Blythe of GBP2,085,000 originally charged in 2014 should be reversed.
9 Property, plant and equipment
Group Development Company & administration Total Total
& production assets
assets
2016 2016 2016 2015
GBP000 GBP000 GBP000 GBP000
At cost
At beginning of - - - -
the year
Additions - 30 30 -
Reclassified from
E&E assets (see
Note 8) 7,506 - 7,506 -
_________ _________ _________ _________
At end of the year 7,506 30 7,536 -
_________ _________ _________ _________
Accumulated depreciation
At beginning of - - - -
the year
DD&A - (6) (6) -
_________ _________ _________ _________
At end of the year - (6) (6) -
_________ _________ _________ _________
Net book value
At 31 December 7,506 24 7,530 -
_________ _________ _________ _________
At 1 January - - - -
_________ _________ _________ _________
10 Asset Acquisitions
During the year, the Group had the following significant asset acquisition transactions.
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 GBP1 million, plus interim cash adjustments, initial consideration upon completion, with a further GBP0.75 million payable nine months thereafter. Further payments of GBP3.25 million are payable upon achievement of certain further milestones which remain contingent and uncertain.
Given the GBP3.25m is dependent on achievement of future milestones and the transaction is considered an asset acquisition, these amounts have not been recognised in the financial statements. The total assets are recognised at cost which is based on the respective fair values at the acquisition date. The below assets and liabilities were acquired on 28 October 2016.
GBP000
Exploration and evaluation
assets 5,533
Less:
Current assets less current
liabilities (13)
Decommissioning provision (3,598)
_____
Net assets acquired 1,922
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 GBP1.5 million, plus interim cash adjustments, payable at completion with deferred consideration of a further USD 5.0 million to be paid at first gas. Given the USD 5.0 million is dependent on achievement of future milestones and the transaction is considered an asset acquisition, these amounts have not been recognised in the financial statements.
11 Investments
Shares Loans
in Group to Group
Company companies companies Total
GBP000 GBP000 GBP000
At cost
At 1 January 2015 12,592 3,467 16,059
Additions - 1,311 1,311
_________ _________ _________
At 31 December 2015 12,592 4,778 17,370
Additions 1,922 7,217 9,139
_________ _________ _________
At 31 December 2016 14,514 11,995 26,509
Impairment
At 1 January 2015 (8,254) (1,870) (10,124)
Impairment reversal 6,169 - 6,169
_________ _________ _________
At 31 December 2015 (2,085) (1,870) (3,955)
Impairment reversal 2,085 - 2,085
_________ _________ _________
At 31 December 2016 - (1,870) (1,870)
Net book value
At 1 January 2016 10,507 2,908 13,415
At 31 December 2016 14,514 10,125 24,639
_________ _________ _________
The Company has undertaken not to seek repayment of loans from other Group subsidiary companies until each subsidiary has sufficient funds to make such payments.
In recognition of the 2015 impairment reversal against the carrying value of the Group's exploration and evaluation assets in 2015 described in Note 8 above, an equivalent impairment reversal of GBP6,169,000 against the carrying value of the Company's investment in its subsidiaries was credited to the Company's Statement of Comprehensive Income.
In the current year, the Directors have reconsidered the economics of the underlying projects held by the subsidiaries including the potential of the exploration projects and consider it appropriate to reverse an impairment of GBP2,085,000.
The Company's subsidiaries, all registered at 60 Gracechurch Street, London EC3V 0HR, are as follows: -
Country Area of
of
Directly held incorporation operation %
IOG Infrastructure Limited United Kingdom United Kingdom 100
IOG North Sea Limited United Kingdom United Kingdom 100
IOG UK Limited United Kingdom United Kingdom 100
All three subsidiaries were incorporated in the United Kingdom and are 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 Group UK Offshore Production Licences are held 100% by either IOG North Sea Limited or IOG UK Limited.
13 Receivables and prepayments
2016 2015
GBP000 GBP000
Group
VAT recoverable 22 139
Warrants and prepaid costs associated
with new loan facilities (Note 16) - 1,354
Prepayments 43 -
Debtors 20 -
Decommissioning guarantees 200 -
_________ _________
285 1,493
_________ _________
Company
VAT recoverable 22 139
Warrants and prepaid costs associated
with new loan facilities (Note 16) - 1,354
Prepayments 38 -
Debtors 20 -
_________ _________
80 1,493
_________ _________
14 Current liabilities
2016 2015
GBP000 GBP000
Group
Loans 4,076 1,460
Trade payables 5,577 847
Amounts due to joint operation partners - 63
Accruals 205 195
_________ _________
9,858 2,565
_________ _________
Company
Trade payables 5,577 847
Amounts due to joint operation partners - 63
Accruals 149 176
_________ _________
5,726 1,086
_________ _________
Of the Group's loans, GBP1.99 million was due to Weatherford Technical Services Limited (2015: GBP1.46 million) and GBP2.08 million was due to GE Oil & Gas UK Limited (2015: GBPnil). Following Amendment, No. 6, to the loan agreement, the loan repayable to Weatherford Technical Services Limited was discharged in full on 24 May 2017. The loan due to GE Oil & Gas UK Limited is payable by 31 December 2017.
The interest rate on the Weatherford loan was 12% effective 1 January 2017.
The interest rate on the GE loan is LIBOR + 9%.
15 Non-current liabilities
2016 2015
GBP000 GBP000
Group
Long term loans 4,733 -
Trade creditors - 293
Decommissioning provision 3,598 -
_________ _________
8,331 293
_________ _________
Company
Trade creditors - 24
_________ _________
Trade creditors' book value stated at 31 December 2016 equates to fair value.
The balance on both the Group's and the Company's non-current liabilities at 31 December 2015 were written off in 2016 following management's commercial decision to impair in full, the Skipper P1609 licence and field.
On 7 December 2015, loan facilities were announced for GBP2.75 million and GBP2.0 million arranged with London Oil and Gas Limited ('LOG') and GE Oil and Gas UK Limited respectively. On 11 December 2015, a further loan was announced for GBP0.8 million arranged with LOG.
The amounts drawn at 31 December 2016 (excluding accrued interest) were as follows: -
Loan Facility Amount Drawn
------------------ ----------------
LOG GBP2.75 GBP2.01 million
million facility
------------------ ----------------
LOG GBP0.80 GBP0.8 million
million facility
------------------ ----------------
GE GBP2.0 million GBP2.0 million
facility
------------------ ----------------
There were warrants issued to LOG and GE Oil and Gas UK Limited in respect of the above 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.
On 5 February 2016, a further loan was announced arranged with LOG and provided for GBP10.0 million of secured convertible debt funding. The 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 of completion and converted into ordinary shares in the Company within 36 months after each drawing.
The balance on the Group's long term loans at 31 December 2016 is represented by drawings of GBP5,542,000 plus accrued interest of GBP208,000 on the LOG facilities, less the non-amortised value GBP1,017,000 of loan finance (which includes the non-amortised amount of warrants as detailed above).
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 GBP10.0 million convertible loan.
The Company has obligations in respect of decommissioning the Vulcan Satellites' E&E asset. 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 is based upon a recent technical valuation.
16 Equity share capital
Share Share
capital premium Total
Number GBP000 GBP000 GBP000
Allotted, issued
and fully paid
At 1 January 2015
- Ordinary shares
of 1 pence each 69,247,764 692 17,163 17,855
Equity issued 609,500 6 139 145
Equity issued 210,174 2 48 50
Loan settlement via
issue of shares 6,507,399 65 181 246
Equity issued 2,142,858 22 128 150
Placing fees - - (10) (10)
_________ _________ _________ _________
At 31 December 2015
- Ordinary shares
of 1 pence each 78,717,695 787 17,649 18,436
2016
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
_________ _________ _________ _________
On 25 June 2015, the Company issued 609,500 ordinary shares and on 2 July 2015, the Company issued a further 210,174 ordinary shares at a subscription prices of 23.79 pence each to raise total proceeds of GBP145,000 and GBP50,000 respectively.
On 13 October 2015, the Company issued 6,507,399 ordinary shares at a subscription price of 3.777 pence each in satisfaction of the total debt of GBP246,000. The conversion price reflected 85% of the average quoted market price for IOG's ordinary shares over the three lowest average prices over the preceding 10-day trading period.
On 21 October 2015, the Company issued 2,142,858 ordinary shares at a subscription price of 7 pence each to raise total proceeds of GBP150,000.
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.
Share options and warrants
During the year, the Company granted share options under its share option plan as follows:
Number Price Date of Expiry
Grant
1 January
2015 12,178,512 13.82p various various
Staff options 230,029 1p 1 Mar 2015 30 Sep 2018
Staff options 41,757 1p 1 Mar 2015 28 Feb 2019
Staff options 131,856 1p 1 Mar 2015 31 Aug 2019
Staff options 1,352,071 1p 1 Mar 2015 28 Feb 2020
31 Aug
Staff options 1,531,778 1p 2015 31 Aug 2020
31 December
2015 15,466,003 11.09p
Staff options 2,888,561 1p 1 Mar 2016 28 Feb 2021
29 Jul
Staff options 103,462 1p 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
All LTIP options, 4,500,000 outstanding at 31 December 2015, expired on 30 September 2016. Accordingly, the fair value of these awards has been transferred from the Share-based Payment Reserve to Accumulated Loss. 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.
The remaining staff options, 11,029,143, outstanding at 31 December 2016 have been issued to directors and other personnel under (i) an AIM bonus scheme upon listing of the Company's shares on 30 September 2013 (5,203,946 options) and (ii) as salary sacrifice options issued periodically in lieu of salary (5,825,197 options). Further details for directors are provided in Note 4. All options were issued at an exercise price of 1p per share and carry no additional performance conditions.
The remaining average contractual life of the 11,029,143 share options outstanding at 31 December 2016 (2015 - 15,466,003) was 2.81 years at that date (2015 - 4.56). All such share options were exercisable at 31 December 2016.
The weighted average exercise price of the options remaining was 1.00 pence at 31 December 2016 (2015 - 11.09 pence). No further options have been exercised as at 25 May 2017.
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 2016, both received and receivable, is calculated as GBP358,000 (2015 - GBP321,000) and this has been fully charged to the Statement of Comprehensive Income. The exercise price was determined as 1p (2015 - 1p).
During 2016, LTIPS awarded to both Mark Routh and Peter Young in September 2013, expired. Accordingly, the fair value of these awards has been transferred from the Share-based Payment Reserve to Accumulated Loss.
During the year, the Company granted warrants as follows:
Number Price Date of Expiry
Grant
1 January 2015 956,087 31.36p various various
Issued to GE Oil and 7 Dec 30 Dec
Gas UK Ltd 4,989,122 11.9p 2015 2016
Issued to GE Oil and 29 Dec 30 Dec
Gas UK Ltd 788,188 11.9p 2015 2016
Issued to London Oil 29 Dec 30 Dec
and Gas Ltd 5,777,310 11.9p 2015 2016
Issued to London Oil 29 Dec 31 Dec
and Gas Ltd 7,500,000 8p 2015 2016
31 December 2015 20,010,707 11.37p
Issued to Weatherford
Technical Services 29 Mar 31 Mar
Limited 500,000 8p 2016 2019
Lapsed - Charles Stanley
Securities (630,000)
Exercised by GE Oil
& Gas UK Ltd (5,777,310)
31 December 2016 14,103,397 11.29p
The fair value of warrants granted in 2015 was calculated as GBP1,272,000 all of which was recognised and included within the total of deferred/prepaid financing costs and taken to the Share-based Payment Reserve
All 2015 warrants granted to GE Oil & Gas UK Limited were exercised prior to 31 December 2016.
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 warrants granted in 2016 is calculated as GBP31,000 (2015 - GBP1,272,000) all of which has been recognised as a current financing cost. The average exercise price was determined as 8 pence (2015 - 10.36 pence).
During 2016, 630,000 warrants awarded to Charles Stanley Securities in September 2013, expired. Accordingly, the fair value of these awards has been transferred from the Share-based Payment Reserve to Accumulated Loss.
The following assumptions were applied in the above calculations
2016 warrants
Risk free interest
rate 1.46%
Dividend yield nil
Weighted average 3 years
life expectancy
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 31 December 2016.
17 Cash and cash equivalents
2016 2015
Group and Company GBP000 GBP000
Cash at bank 247 23
_________ _________
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 GBP1,784,000 (2015: GBP5,667,000).
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 -- Derivative financial instruments -- Trade and other payables
Liquidity risk
The Group's 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 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. The Board have identified that further funds will be required within the next 12 months and are implementing various courses of action as detailed in the Finance Review to ensure that adequate funding is available.
Greater Greater Total
than
6 months 6 months, than undiscounted Carrying
less
or less than 12 12 months amount
months
2016 Group GBP000 GBP000 GBP000 GBP000 GBP000
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
________ _________ ________ _________ ________
2015 Group
Current financial
assets
Cash and cash
equivalents 23 - - 23 23
________ _________ ________ _________ ________
23 - - 23 23
________ _________ ________ _________ ________
Current financial
liabilities
Loans - 1,430 - 1,430 1,430
Trade and
other payables 1,232 - - 1,232 1,232
Non-current financial liabilities
Trade and
other payables - - 293 293 293
________ _________ ________ _________ ________
1,232 1,430 293 2,955 2,955
________ _________ ________ _________ ________
Greater Greater Total
than
6 months 6 months, than undiscounted Carrying
less
or less than 12 12 months amount
months
2016 Company GBP000 GBP000 GBP000 GBP000 GBP000
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
Non-current financial liabilities
Trade and - - - - -
other payables
________ _________ ________ _________ ________
639 5,087 - 5,726 5,726
________ _________ ________ _________ ________
2015 Company
Current financial
assets
Cash and cash
equivalents 23 - - 23 23
________ _________ ________ _________ ________
23 - - 23 23
________ _________ ________ _________ ________
Current financial
liabilities
Trade and
other payables 1,086 - - 1,086 1,086
Non-current financial liabilities
Trade and
other payables - - 24 24 24
________ _________ ________ _________ ________
1,086 - 24 1,110 1,110
________ _________ ________ _________ ________
Credit risk
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.
Carrying Maximum
value exposure
Group and Company: GBP000 GBP000
Cash and cash equivalents 247 247
________ ________
The Group made investments and advances into subsidiary companies during the year, recovery of which is dependent on future income generation of those subsidiaries.
The Group's and Company's external trade and other receivables comprise UK HMRC VAT and 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 trade and other receivables as they relate to third parties with no default history.
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 2016, 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 2,951,000 (GBP2,392,000) of current liabilities held by the Company and USD 2,457,000 (GBP1,992,000) of current liabilities held by the Group in one of its subsidiaries. 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 GBP399,000 gain or loss in the Group's Statement of Comprehensive Income and a GBP217,000 gain or loss in the Company's Statement of Comprehensive Income.
The Group has no current revenues. The Group and the Company's cash balances are maintained in GBP Sterling which is the functional and reporting currency of each Group company. Consequently, no formal policies have been put in place to hedge the Group and Company's activities to the exposure to currency risk. It is the Group's policy to ensure that individual Group entities enter transactions in their functional currency wherever possible. The Group considers this minimises any foreign exchange exposure.
Management regularly monitor the currency profile and obtain informal advice to ensure that the cash balances are held in currencies which minimise the impact on the results and position of the Group and the Company from foreign exchange movements.
Capital management
The primary objective of the Group's capital management is to maintain appropriate levels of funding to meet the commitments of its forward programme of 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, the Group made drawings of GBP7,542,000 against its London Oil & Gas Limited and GE Oil & Gas UK Limited loan facilities.
Borrowing facilities
The Group and Company had GBP9,825,000 borrowings outstanding at 31 December 2016 (2015 - GBP1,460,000) including accrued interest. It had in place further undrawn debt on the London Oil & Gas Limited facilities of a total GBP8,009,000, 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 to capital expenditure in the current period as part of the exploration and development work programme for the licences in which it participates:
2016 2015
GBP000 GBP000
Authorised but not contracted - 7,180
Contracted 408 734
_________ _________
408 7,914
_________ _________
All 2016 capital commitments relate to UKCS Licence and associated fees derived from the Group's participation in its UK North Sea operations.
Blythe Asset Acquisition
As announced on 19 April 2016 and subsequent deal completion on 21 June 2016, further to the initial GBP1.5 million consideration payable at completion, together with interim period adjustments, a further consideration payment of USD 5.0 million is to be paid contingent on first gas.
Vulcan Satellites Acquisition
As announced on 13 June 2016 and subsequent deal completion on 28 October 2016, further to the initial GBP1.0 million consideration payable at completion, together with interim period adjustments, and the initial deferred consideration of GBP0.75 million payable on 28 July 2017, further consideration payments of GBP1.75 million and GBP1.5 million are to be paid contingent on the approval of a Field Development Plan and on production of first gas respectively.
21 Related party transactions
Details of directors' remuneration are provided in Note 4.
Mark Routh acquired no additional shares during the year (2015 - nil). He held 4,303,010 shares at 31 December 2016 (2015 - 4,303,010) shares being 3.94% of the total issued share capital.
Peter Young subscribed for no additional shares during the year (2015 - acquired 105,087 for GBP25,000) bringing his total holding to 13,831,725 (2015 - 13,831,725) being 12.66% of the total issued share capital.
22 Subsequent events
The key events after 31 December 2016 are as follows:
Weatherford Technical Services Limited
On 8 March 2017, the Company, on behalf of its Group subsidiary, IOG North Sea Limited, signed a further amendment to alter the schedule and loan repayment amounts through to final redemption of the outstanding loan.
The terms of the amendment allowed for the Company to make monthly periodic payments through to 24 May 2017, at which time the loan has now been fully discharged.
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR EAASSAEXXEAF
(END) Dow Jones Newswires
May 26, 2017 02:01 ET (06:01 GMT)
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