REG - Independent Oil &Gas - Final Results for the Year Ended 31 December 2019
26 March 2020
Independent Oil and Gas plc
Final Audited Results for the Year Ended 31 December 2019
Independent Oil and Gas plc ("IOG" or "the Company"), (AIM: IOG.L), the development and production company focused on becoming a substantial UK gas producer, is pleased to announce its final audited results for the Year Ended 31 December 2019.
2019 Highlights
Corporate and Operational
· Farm-out of 50% of Core Project to CalEnergy Resources Limited ("CER") with IOG retaining operatorship of all its assets
· Acquisition of the onshore Thames Reception Facilities ("TRF") at Bacton Gas Terminal
· Core Project Phase 1 Final Investment Decision (FID) taken in Q4 2019 with a view to first gas in Q3 2021
o Development works kicked off across all four key elements: platforms, subsea, drilling and onshore
· Harvey appraisal well, 48/24b-6, drilled safely in Q3 2019
o Initial analysis indicates c.40 Bcfe mid-case recoverable volumes at Harvey and c.100 Bcfe at Redwell
· Strengthening of board, management and operational team
· Alliance with CER for further Southern North Sea ("SNS") business development
o Number of licence applications in 32nd Offshore Licensing Round in alliance with CER
Financial
· £40 million Farm-out up-front payment received from CER
o £17.1 million used simultaneously to repay existing debt
· £125 million of development carry committed under Farm-out agreement
o £60 million for Phase 1 and £65 million for Phase 2
· €100m 5-year senior secured bond issue successfully raised from Nordic, European, UK and Asian institutional investors and subsequently listed on Oslo Børs
· Institutional equity fundraise, board/management subscription and Open Offer completed, raising combined gross proceeds of £18.9 million
· Cash balance at period end of £98.3 million (2018: £0.7 million), including restricted cash of £82.0 million
· Post tax profit for the year of £15.0 million (2018: Loss £5.6 million)
· Group net cash at year end £8.0 million
· Converted 8p convertible loan into Ordinary Shares at Farm-out completion
· Restructured 19p convertible loan into a long-term, unsecured, non-interest bearing convertible Loan Note Instrument
Board and Management
· Esa Ikaheimonen appointed as Non-Executive Director
· Neil Hawkings appointed as Non-Executive Director
· Rupert Newall appointed as Chief Financial Officer and Executive Director
Post Year End Developments
· Platform construction activities underway
· Competitive tender process commenced for jack-up drilling rig for Phase 1 drilling programme
· Established Well Management Company selected to support IOG's in-house drilling team in delivering best in class well execution
· Onshore TRF refurbishment activities ramping up; FEED studies being executed by Worley
· £60 million Phase 1 development carry and €100 million bond issue being utilised as planned
· Further seismic reprocessing underway to support plans for Harvey and Redwell licences as incremental developments beyond the Core Project
o Discussions ongoing as to potential CER participation in these licences following expiry of farm-in option in February 2020
· Core Project platforms estimated to have industry-leading average carbon intensity at just 0.2kg CO₂/boe, versus 21kg UK North Sea 2018 average
Andrew Hockey, CEO of IOG, commented:
"After a very successful 2019, and despite the unfolding Covid-19 pandemic, we at IOG are looking forwards from a position of fundamental strength to continuing our project execution throughout 2020. The two major financial highlights of last year, the £165 million farm-out to an exceptionally strong partner in CalEnergy Resources and the €100 million bond raise, enabled us to sanction Phase 1 of our substantial UK Southern North Sea Core Project. With funding in place we are firmly focused on cost-effective Phase 1 development execution as well as adding high-return incremental opportunities.
In 2019 we consolidated our competitive advantage in owning our infrastructure with the important acquisition of the Thames Reception Facilities at Bacton. We also safely drilled the Harvey appraisal well, demonstrating our operating capability and the potential to access additional resources and increased shareholder returns through our gas hub strategy.
The tangible progress made in 2019 reflects both our resilience in overcoming challenges and our drive to seize new opportunities. Such attributes will again prove crucial in this time of unprecedented upheaval. With a strengthened team and a robust low-cost portfolio benefitting from very low carbon intensity, we are well placed not just to survive but to thrive by investing through this cycle. With our balance sheet strength, commitment to the project and CER partnership, we are well positioned to reduce costs in the current low commodity price environment."
Certain information communicated in this announcement was, prior to its publication, inside information for the purposes of Article 7 of Regulation 596/2014.
Enquiries:
Independent Oil and Gas plc
Andrew Hockey (CEO)
Rupert Newall (CFO)
James Chance (Head of Corporate Finance & IR)
+44 (0) 20 7036 1400
finnCap Ltd
Christopher Raggett (Corporate Finance)
Simon Hicks (Corporate Finance)
Camille Gochez (Corporate Broking)
+44 (0) 20 7220 0500
Peel Hunt LLP
Richard Crichton
David McKeown
+44 (0) 20 7418 8900
Vigo Communications
Patrick d'Ancona
Chris McMahon
Simon Woods
+44 (0) 20 7390 0230
About IOG:
IOG owns and operates a 50% stake in substantial low risk, high value gas reserves in the UK Southern North Sea. The Company's Core Project targets a gross 2P peak production rate of 140 MMcfe/d (c. 24,000 Boe/d) from gross 2P gas Reserves of 302 Bcfe¹ + 2C gas Contingent Resources of 108 Bcfe², via an efficient hub strategy. In addition to the independently verified 2P reserves at Blythe, Elgood, Southwark, Nailsworth and Elland and 2C Contingent Resources at Goddard, IOG also has independently verified best estimate gross unrisked prospective gas resources of 73 Bcfe² at Goddard. Alongside this IOG has management estimated mid-case recoverable gas volumes of 40 Bcfe and 100 Bcfe at the Harvey and Redwell licences and continues to pursue value accretive acquisitions to generate significant shareholder returns.
1ERC Equipoise Competent Persons Report: October 2017, adjusted by Management to account for updated project timing and compression
2ERC Equipoise Competent Persons Report: October 2018
Competent Person's Statement
In accordance with the AIM Note for Mining and Oil and Gas Companies, IOG discloses that Andrew Hockey, IOG's CEO, is the qualified person that has reviewed the technical information contained in this document. Andrew Hockey has an MSc in Petroleum Geology and has been a member of the Petroleum Exploration Society of Great Britain since 1983. He has over 35 years' operating experience in the upstream oil and gas industry. Andrew Hockey consents to the inclusion of the information in the form and context in which it appears.
Chief Executive's Review
2019 Review
2019 proved to be a highly successful year for IOG in which we accomplished a series of transformational milestones against a turbulent backdrop. I am delighted to report that as a result of the year's activity we are fully funded to deliver first gas at our core development project ("Core Project") in the UK Southern North Sea ("SNS") in Q3 2021, having taken Final Investment Decision ("FID") in October 2019. The Core Project has always been a simple yet compelling proposition to deliver shareholder value: gas portfolio, pipeline, market. This proven core hub development approach provides clear competitive advantages enabling us to leverage our existing infrastructure to turn stranded or marginal assets into highly cost-efficient clusters. The reuse of pre-existing infrastructure also materially lowers the carbon footprint of our development, making our gas attractive from a sustainability perspective, an increasingly important element in both investment decisions and wider stakeholder engagement. The Company's successful financing, including our farmout to CalEnergy Resources Limited ("CER"), has laid firm foundations from which to deliver our Core Project and to pursue incremental development and production investment opportunities in the SNS. In everything we do, we endeavour to act with the highest regard to health, safety and sustainability as an operator and I look forward to another year of progress at our Core Project and across our SNS portfolio.
Following the restructuring of our debt and the successful defence of a hostile and opportunistic approach from one of our peers early in the year, the Company successfully raised aggregate gross proceeds of £18.9 million via an institutional equity placing, a Board/management subscription and a fully subscribed open offer. This critical step provided the financial strength and scope to deliver against our longer-term strategy for the benefit of our shareholders and new institutional investors. These proceeds funded the drilling of the Harvey appraisal well, 48/24b-6, and sustained overheads while progressing our farm-out process towards a successful conclusion.
The Harvey appraisal well presented the opportunity to add to the Company's resource base and was drilled safely in Q3 2019 using the Maersk Resilient jack-up rig, meeting the Initial Term commitment for Licence P2085 (IOG 100% Operator). While the results were different to pre-drill expectations, the well provided an invaluable data set to enhance our subsurface understanding of the Harvey-Redwell Area. Early indications from this work are encouraging, indicating the presence of a larger structure up-dip to the northeast of the 48/32-2 well, containing mid-case volumes of approximately 40 Bcfe, which would likely represent an attractive incremental investment opportunity. Integration of the Harvey well results into the seismic data spanning Redwell licence (P2441, IOG 100% Operator) also indicated that the Redwell discovery extends further to the northwest than previously estimated, incorporating both the Redwell discovery and Woodforde prospect into a single structure. The initial estimate of mid-case recoverable gas resource volumes on this structure is approximately 100 Bcfe.
In October 2019, we completed a Sale and Purchase Agreement ("SPA") with Perenco UK Ltd, Tullow Oil SK Ltd and Spirit Energy Resources for the acquisition of the onshore Thames Reception Facilities ("TRF") at Bacton Gas Terminal. Following FID, detailed planning and engineering work commenced to prepare for the refurbishment and recommissioning of the TRF gas and liquids processing equipment as part of the Core Project development plan.
The TRF and Thames Pipeline represent an important element of IOG's strategy as they provide the conduit to transport our own natural gas to the import-dependent UK market. In addition, the re-use of pre-existing infrastructure results in gross capex and transport tariff cost savings estimated to be in the order of £225 million over the lifecycle of the project. Furthermore, we also have ample capacity in the Thames Pipeline to accommodate additional IOG gas developments and to benefit from tariffs by offering a gas evacuation route to nearby gas producers. Equally important is the low-carbon footprint of our operations: post-period end we estimated the average carbon intensity of our platforms to be just 0.2 kg CO₂/boe, versus the 2018 UK North Sea average of 21kg. This is an integral element to our sustainability proposition and ensures the Company remains a relevant and attractive source of domestic gas for the UK throughout the energy transition.
After an extensive competitive process, we were delighted to announce in Q3 the signing of the £165 million farm-out of 50 per cent of the Core Project, excluding Harvey, to CER ("Farm-out"). In the same quarter we raised a €100 million 5-year senior secured bond ("Bond") from Nordic, continental European, UK and Asian institutional investors, which provided the balance of funding required to take FID on Phase 1 of the Core Project. This we did on 28 October 2019, on completion of the farm-out transaction with our new partner.
Under the Farm-out agreement, CER retained the option to acquire 50 per cent of the Harvey and Redwell licences for an additional payment of £20 million and certain royalty payments. Following the Harvey well and the additional technical work to be completed on the Harvey-Redwell Area, IOG extended the option's initial three-month deadline to 27 February 2020 for CER to finalise their own technical analysis. Post period end, our technical work and development planning for these licences has continued and, although the original option was not exercised, discussions continue around potential future CER participation.
Further to the Farm-out, IOG and CER signed an Area of Mutual Interest agreement which provides a framework for a 50:50 alliance on business development opportunities within a defined SNS area. As testament to IOG's technical and management competence, CER has agreed that IOG will maintain operatorship on such ventures.
Over the course of 2019 we strengthened our board, welcoming the high-calibre appointments of Esa Ikaheimonen and Neil Hawkings as Independent Non-Executive Directors. Since their respective arrivals, both Esa and Neil's invaluable upstream oil and gas expertise have made an immediate impact on the business and we are very grateful for their support. We also announced Rupert Newall's appointment as IOG's Chief Financial Officer and his subsequent appointment to the Board. The first half of the year also saw the resignation of LOG-appointees Martin Ruscoe and Charles Hendry from the Board.
2020 Outlook
With Core Project funding secured and development activities underway, 2020 was already set to be a very busy year for IOG, before the arrival of the Covid-19 global pandemic and associated extreme economic volatility. Whilst this unprecedented scenario presents severe challenges across the energy industry, IOG remains in a relatively robust position - being funded to deliver first gas in Q3 2021 as operator of an exceptionally strong joint venture partnership. Moreover, as we embark on a phase of key contracting, the precipitous fall in oil prices driven by the Covid-19 demand shock and the significant global oversupply situation also creates potential opportunities to drive down costs in the context of our efforts to deliver Phase 1 as cost-efficiently as possible. It is also worth noting that we have taken all due precautions to ensure optimal business continuity during the Covid-19 crisis, which continues to escalate at the time of writing.
Since FID, we have continued to work closely with the UK Oil and Gas Authority ("OGA") towards approval of our Phase 1 Field Development Plan ("FDP"), after which formal contract awards will be made both for our Normally Unmanned Platforms ("NUIs") and Subsea, Umbilicals, Risers and Flowlines ("SURF"). Until then, work on both fronts continues as planned under Letters of Limited Commitment.
Pipelay work is set to begin in mid 2020, with the laying of a 7-kilometre 24-inch pipeline connecting the Southwark field to the Thames Pipeline followed by laying of the longer 24-kilometre 12-inch line connecting Blythe to the Thames Pipeline and a 10-kilometre 6-inch line connecting Elgood to Blythe.
Southwark and Blythe NUI construction is underway, with installation scheduled for H1 2021. Given shallow water depths and the unmanned design, these platforms offer a low-cost and low-CO₂ operational model in line with our intent to be an environmentally conscious operator. TRF refurbishment activities at Bacton Terminal also continue to progress positively.
Preparation is also well underway for the five-well Phase 1 development drilling campaign which is due to commence in Q1 2021. Amid improving contracting conditions, IOG's in-house drilling team are ramping up detailed well design activities and technical and commercial evaluation of a jack-up drilling rig tender. Likewise, discussions with offshore drilling services providers are progressing with a view to contract awards later in H1 2020.
Alongside our primary focus of delivering first gas on time and on budget, the Board and management are also focused on further growth opportunities with a key requirement for cost-efficiency and value-accretion with a low CO₂ footprint, leveraging the benefits of the existing infrastructure. In that context, in November 2019, IOG along with CER jointly submitted applications under the AMI for a number of blocks in the 32nd Offshore Licensing Round. These applications focused on discoveries and prospects within tie-back range of the Thames Pipeline and IOG's existing assets. We expect the results of the 32nd Round applications to be announced in mid-Q2 2020.
I would like to take this opportunity to thank the team at IOG for their hard work and dedication to the Company over the course of the year. I would also like to thank our shareholders for their continued support in a challenging, yet
ultimately extremely positive year for the Company. A combination of hard work by the team and continued investor support has placed us in a strong position to achieve our ambitious goal of becoming a leading mid-cap UK SNS gas producer delivering significant shareholder value through high return investments.
Andrew Hockey
Chief Executive Officer
25 March 2020
Operational Update
Thames Pipeline and Thames Reception Facility
The 100% acquisition of the Thames Pipeline from Perenco UK Limited, Tullow Oil SK Limited and Spirit Energy Resources Limited completed in April 2018. With the farm down of the Core Assets to CalEnergy Resources Limited in October 2019, IOG now retains a 50% operated share in the pipeline. IOG Infrastructure Limited is the owner, user, holder and operator of the pipeline under the Pipeline Works Authority ('PWA').
On 25 October 2019 the acquisition of the Thames Reception Facility from Perenco UK Limited, Tullow Oil SK Limited and Spirit Energy Resources Limited completed. On completion £2.0 million of security was posted. With the farm down of the Core Assets to CalEnergy Resources Limited on 28 October 2019, IOG now retains a 50% operated share in the Thames Reception Facility. At completion the £0.5 million pipeline security paid to Perenco in April 2018 was transferred to a Law Debenture Trust account for our benefit. The total £2.5million security is now held 50:50 with CalEnergy Resources Limited.
The viability of this export route was confirmed by a 150 bar 24 hour hydrotest completed in September 2018. Work has continued during 2019 on the design definition of the reactivation of the Thames Pipeline and the tie into the Southwark platform as the new starting point of the line. This work has increased in intensity with the declaration of FID for the Phase 1 project at the end of October 2019 and at the time of writing plans are being finalized for the intelligent pigging of the pipeline in April 2020. Work has also continued on the definition of the refurbishment works required at the TRF for it to be ready to receive first gas in Q3 2021.
Core Project Phasing
During development engineering studies in 2018, it was decided to split the Core Project development into two Phases with Phase 1 comprising Blythe, Elgood and Southwark. In January 2019 it was decided to include Goddard in the Core Project. Phase 2 therefore includes Nailsworth, Elland and Goddard.
Core Project: Blythe
The Blythe gas discovery in the Rotliegend Leman Formation, straddles Blocks 48/22b and 48/23a in the SNS in licence P1736 in which IOGNSL has a 50% working interest and is operator. Blythe is planned to be developed with a single well tied back to the Thames Pipeline via an unmanned platform ('NUI').
The draft Phase 1 Field Development Plan comprising Blythe, Elgood and Southwark was submitted to the OGA in August 2018 and following bilateral meetings was resubmitted in late October 2018 taking account of OGA comments. Following the decision in early 2019 to farm down the IOG 100% interest in the Core Assets, progress toward FDP approval was necessarily limited until the farm-out process to CER completed and FID was declared at the end of October. At year end, EIA and FDP approval are expected to occur during Q2 2020 with first gas from Southwark planned for Q3 2021 and Blythe first gas in early Q4 2021.
Following 2018 FEED studies to assess costs and schedule for the tie-in lines to the Thames Pipeline for the Phase 1 development including Blythe and 2018 offshore geotechnical surveys, FEED studies for the Blythe Platform continued in 2019 and work has progressed with the selected platform and pipeline and subsea installation contractors during Q4 2019.
In December 2019 the initial Term of Licence P1736 containing Blythe was extended to 30 June 2020 subject to the condition that an FDP be approved by the OGA by 30 June 2020.
Core Project: Elgood
IOGNSL has 50% working interest in and is operator of Licence P2260 (Block 48/22c), which was awarded in the 28th Licensing Round. The licence, which lies immediately to the north-west of the Blythe licence, contains the Elgood discovery in the Rotliegend Leman Sandstone.
Elgood is planned to be developed with a single well tied back subsea to the Thames Pipeline via a NUI at Blythe.
The Phase 1 Field Development Plan comprising Blythe, Elgood and Southwark was submitted to the OGA in August 2018 and following bilateral meetings was resubmitted in late October 2018 taking account of OGA comments. Following the decision in early 2019 to farm down the IOG 100% interest in the Core Assets, progress toward FDP approval was limited until the farm out process to CER completed and FID was declared at the end of October. At year end EIA and FDP approval are expected to occur during Q2 2020 with first gas at Southwark in Q3 2021 and Elgood first gas in Q4 2021.
Following 2018 FEED studies to assess costs and schedule for the tie-in lines to the Thames Pipeline for the Phase 1 development including Elgood, on declaration of Phase 1 FID, 2019 work has continued with the chosen pipeline and subsea installation contractor for the detailed design and planning for the installation during 2020 of the Elgood to Blythe pipeline and during 1H 2021 for the umbilical.
In January 2019 IOG received notification from the OGA that the drill or drop commitment for the initial Term of Elgood Licence P2260 had been waived and the Licence could proceed into the Second Term.
Core Project: Vulcan Satellites - Southwark, Elland and Nailsworth
The Vulcan Satellites are planned to be developed with NUIs at Southwark (three wells), Elland (two wells) and Nailsworth (three wells) via the Thames Pipeline. All three satellites have their reservoirs in the Rotliegend Leman Sandstone.
Following 2018 development studies it was decided to include Southwark as part of a Phase 1 development comprising Blythe, Elgood and Southwark.
The Phase 1 Field Development Plan comprising Blythe, Elgood and Southwark was submitted to the OGA in August 2018 and following bilateral meetings was resubmitted in late October 2018 taking account of OGA comments. Following the decision in early 2019 to farm down the IOG 100% interest in the Core Assets, progress toward FDP approval was limited until the farm out process to CER completed and FID was declared at the end of October. At year end EIA and FDP approval are expected to occur during Q2 2020 with first gas at Southwark in Q3 2021.
Following 2018 FEED studies to assess costs and schedule for the tie-in lines to the Thames Pipeline for the Phase 1 development including Southwark and offshore geotechnical surveys for the Southwark platform, FEED studies, detailed engineering and planning for the Southwark platform continued during 2019 with the chosen platform designer and fabricator. At the time of writing first platform steel has been cut for the platform.
Nailsworth and Elland, the other two Vulcan Satellites, will be part of Phase 2 of the development.
Given the development sequencing of both Nailsworth and Elland (Phase 2), most current year 2019 fixed asset additions have been attributable to the Southwark development area.
Further to the Vulcan East (Elland) suspended well 49/21-10A decommissioning paper, prepared by Acona in April 2015, IOGUKL has revisited the abandonment provision. Given drilling work is now envisaged to be occurring in the area of the suspended well during the Phase 2 development works, it is envisaged that the decommissioning can be completed at a cost of £2.4 million due to savings with synergies associated with this development drilling programme.
Core Project: Goddard
IOG NSL has a 50% working interest in and is operator of Licence P2438 which contains Goddard, an undeveloped gas discovery.
Licence P2438 formally commenced on 1 October 2018. Under the licence a firm commitment was made to the Oil and Gas Authority ("OGA") to reprocess 175 km2 of 3D seismic to PSDM and drill an appraisal well on Goddard to 3,140m
TD within three years. In the second half of 2018 access to 3D seismic data processed to PSDM level was secured from a previous operator, fulfilling the reprocessing commitment.
ERC Equipoise assess gross unrisked 1C/2C/3C Contingent Resources of 54.3/107.8/202.8 BCF at Goddard (net 27.4/53.9//101.4BCF) and Low/Best/High gross unrisked prospective gas resources are 41.8/73.0/121.4 BCF (net 20.9/36.9/60.8 BCF). The chance of development of Goddard is estimated by ERC Equipoise as being 75%. The CPR assesses the geological chance of success of the prospective gas resources at 48%.
In the light of the relative maturity of Goddard's Contingent Resources it was decided in early 2019 to commence Goddard FDP planning and to include Goddard in Phase 2 Core Project development planning.
Abbeydale
IOG NSL has a 50% working interest in and is operator of Licence P2442 which contains the Abbeydale undeveloped gas discovery. Licence P2442 formally commenced on 1 October 2018. Under the four-year Licence, a commitment was made to reprocess 150 km2 3D seismic data to PSDM and drill a well to 1,960m TD or drop the licence. 2019 work focused on securing prices for and planning 3D reprocessing.
Management estimates gross contingent resources on Abbeydale are 1C/2C/3C 5/11/24 BCF (net 2.5/5.5/12 BCF). The new 3D seismic reprocessing programme is expected to increase these estimates to more commercial levels with a view to tying into our Thames Pipeline as the export route.
Harvey and Redwell
IOGNSL has a 100% working interest in Licence P2085 to the east of Blythe (Blocks 48/23c & 48/24b), which was awarded in the 27th Licensing Round, and in Licence P2441, awarded in the 30th Licensing Round, which contains the Redwell (previously named Wherry) discovery.
Following the completion of seismic reprocessing in 2018, a new volumetric assessment of gross unrisked Prospective Resources (as estimated by management) was made at Harvey of 85-129-199BCF (Low-Mid-Best Estimate). Management's assessment of Geological Chance of Success at Harvey was 63%. Under the terms of licence P2085 a firm commitment was made to the Oil and Gas Authority ("OGA") to drill a well to 7,300ft TDVSS by 20 December 2019 or drop the Licence.
In Q3 2019 IOG drilled the Harvey appraisal well using the Maersk Resilient jack-up drilling unit. Halliburton were contracted to provide bundled well services and Fraser Well Management were retained as Well Operator.
Harvey appraisal well 48/24b-6 spud on the 3 August 2019. The well reached a total depth of 7,537 ft Measured Depth (MD) in the Permian Leman Sandstone reservoir, meeting the Initial Term work commitment for Licence P2085. The top of the Leman Sandstone was encountered at 7,086 ft MD. Two 90 ft cores were acquired in the reservoir along with a full suite of wireline logs, including pressure test and fluid samples, as well as Vertical Seismic Profiling (VSP). Initial analysis of the wireline data demonstrated the presence of a 49 ft gas column at the top of the reservoir, in contrast to pre-drill estimates of a 211 ft gas column.
Initial seismic remapping and technical assessment of gas volumes was completed in December. This remapping indicated that the Harvey structure as described on the pre-stack depth migration (PSDM) map prior to the well is likely to be compartmentalised into more than one structure. The 49ft gas column encountered at the well location appears to be a small independent pocket of gas. The updated mapping based on the well data also indicates the presence of a larger structure at Harvey up-dip to the northeast of the previous 48/23-2 well, i.e. the northern part of the pre-well PSDM Harvey structure. The size of this structure implies mid-case recoverable volumes of approximately 40 Bcfe, analogous to Blythe. Additional technical work is ongoing to provide further definition on the updated mapped volumes.
The well results have also been integrated into the seismic data covering the area of the Redwell discovery in IOG's P2441 licence, to the immediate east of the P2085 Harvey licence. This indicates that Redwell extends further to the northwest than previously estimated, incorporating both the Redwell discovery and Woodforde prospect into a single structure with management estimated mid-case recoverable resource volumes in the region of 100 Bcfe. The wells drilled at Redwell by previous operators prior to 2006 demonstrated a low-relief discovery of good reservoir quality. Further reservoir modelling work will now be undertaken to confirm estimates of gas in place (GIIP), potential resources and deliverability at Redwell. This will then inform whether there is scope for a future development in the Redwell-Harvey area (P2085 and P2441 licences), potentially benefitting from direct tie-in to the by-then operating Thames Pipeline export route or tie-back to Core Project infrastructure such as the Southwark or Blythe platforms.
Alongside the farmout transaction with its partner CER which completed in October 2019, IOG agreed an option for CER to acquire 50 per cent of the P2085 and P2441 licences within three months of completion of the Harvey appraisal well. Exercise of the option would entail a £20 million payment to IOG and a £0.95/MCF royalty on all of CER's life-of-field net gas production from Harvey. Given the time required to assess and integrate the Harvey well results, IOG agreed that CER would have until 27 February 2020 to finalise their own technical analysis and decide whether to exercise the option. Post period, CER allowed the option to lapse and we continue to discuss terms on which CER might enter the Harvey Licences.
Skipper
The Skipper licence, P1609, was formally relinquished on 11 February 2019, as determined by the OGA.
Asset Acquisitions
The Company continues to assess the potential for the acquisition of a number of assets, to support the wider development and growth of the business.
Key Performance Indicators
The Group's main business is the acquisition and exploitation of oil and gas acreage. Non-financial performance is tracked through the accumulation of licence interests followed by the successful discovery and exploitation of oil and gas reserves as indicated through prospective, contingent and proved reserves inventories. Financial performance is tracked through the raising of finance to fund proposed programmes and the control of costs against budgets. The Group has two main KPIs, the first of which is to cause no harm to people or the environment and the second of which was to sustain no Lost Time Incidents, both of which were met in 2019.
Principal Risks and Uncertainties
The Group operates in the oil and gas industry, an environment subject to a range of inherent risks and uncertainties. Key risks and associated mitigation are set out below.
Finance: Management seeks to generate shareholder returns through monetisation of a portfolio of proven offshore gas assets. This primarily entails construction and installation of production, transportation and processing infrastructure and drilling of production wells. These activities carry several key risks.
Risk
Mitigation
Investor support may be eroded, impacting the company's market value and potentially hindering fundraising activities
· Management has a clear strategy for value realisation and creation, which is regularly communicated to shareholders
· The Company's asset portfolio has robust inherent economics as well as substantial incremental value, as attested by third-party analyst reports
· The Company has fully funded its Phase 1 development and is therefore not anticipating raising additional capital in this regard
· CER's credit risk is low and kept under review
Volatility in macroeconomic conditions may hinder delivery of the Company's business plan
· The Company has fully funded its Phase 1 development and therefore has sufficient liquidity for its planned activities
· As a buyer of products and services, the Company faces both risks and opportunities from economic volatility
Each asset carries a range of potential values
· The Company has a healthily diversified portfolio of 6 proven gas fields in its Core Project, plus further assets which could potentially be added, therefore there is limited financial dependence on a single asset
The Company may not be able to raise funds to develop its assets
The Company successfully undertook equity, debt and farm-out funding from CER in 2019 which fully funded its Phase 1 activities, as detailed elsewhere in this report. With its current funding requirement met, the Company is anticipating production revenues from operations in H2 2021, which allows it then to begin to assess the funding requirements for the Phase 2, The Company will also have access to £65.0 million of funding carry from CER at that point
The Company faces the risk of a breach of its Bond terms
· The Company makes consist efforts to be fully aware of its responsibilities and obligations under the Bond terms
· The Company makes consistent efforts to manage the business within budget
· Management calibrates key project commitments against bond conditions and covenants to ensure avoidance of any breach
The administrators of London Oil and Gas Ltd ('LOG') may be obliged to divest its holding, creating downward pressure on the Company's market value
· The Company notes that the administrators of London Capital & Finance ("LCF"), with respect to LOG's holding in IOG, have stated publicly in December 2019 that they saw the market value of the Company at the time as a "significant discount to IOG's estimated net asset value". Management continues to have a positive engagement with the administrators and believe they intend to maximise the value of the LOG holding in IOG.
Operations: Operations may not go to plan, leading to damage, pollution, cost overruns and poor outcomes
Risk
Mitigation
Reservoir and subsurface uncertainty
· Thorough subsurface mapping and reservoir modelling
· High quality well design
· Lessons learned during early wells applied to subsequent wells
Departure from Schedule and Budget
· Ensure the project team is populated with sufficient competent personnel
· Award contracts to competent contractors
· Test schedule and budget - rigorous schedule and budget control
· Follow gate process, utilise peer reviews at appropriate project stages
Market conditions for rig and marine vessel procurement may harden.
· Contractual rates with existing platform and pipeline contracts have been fixed
· Issue advance ITTs to obtain prices for future services
· Where possible incentivise contracts in order to minimise delivered cost
Scope 'creep' in required works at the Bacton Terminal
· Develop a well-defined FEED during which the scope is stress tested
· Implement and maintain a Management of Change process
· Apply rigorous cost and schedule controls throughout Execution of works
Cyber Security
· Build an enhanced IT security plan and supporting procedures, including in particular:
· Improve access right to systems and protocols
· Enhance onboarding and leaving processes
Resource estimates may be misleading curtailing actual reserves recovered
· The Group deploys qualified personnel
· Regular third-party reports are commissioned
· A prudent range of possible outcomes are considered within the planning process
Regulatory and Legal: The Group may be unable to meet its licence and regulatory obligations
Risk
Mitigation
Delay in obtaining Offshore Field Development plan (FDP) consent, including Environmental consent for Phase 1
· Expedite submission of final revision of EIA to BEIS and then expedite BEIS to grant EIA approval.
· Liaison with OGA and other authorities to minimise delays in approvals
· Fully prepare all relevant applications for prompt submission.
Deficiency in Corporate Governance
· Develop, implement and maintain a suitable suite of corporate procedures (e.g. Financial Operating Procedures).
· All contracts must be authorised by Contracting and Procurement Function, General Counsel and Finance
Human Resources: The Company relies upon a pool of experienced and motivated personnel to identify and execute successful investment strategies
Risks
Mitigation
Key personnel may be lost to other companies
· The Remuneration Committee regularly evaluates incentivisation schemes to ensure they remain competitive
Difficulty in attracting the necessary talent as the Group moves into development of its projects
· The Group continues to review and adopt attractive packages for both staff and contractors
HSE and Sustainability
Risks
Mitigation
Personal harm to those that may be affected by our undertakings
· Compliance with the UK regulatory goal setting regime for safety is established, implemented and maintained through the company leadership HSE and Technical Committee, culture and management systems for safety
Adverse environmental effects of our activities including, in particular, contributing to Climate Change
· Strategic focus on natural gas as the preferential fossil fuel to provide a transition energy source to a renewables future
· Design and operation of low carbon footprint facilities, including re-use of existing infrastructure
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
Stakeholder mis-alignment
· Regular interfacing with key stakeholders
· Understand stakeholders' priorities and drivers
· Build and maintain relationships with stakeholders
Volatile commodity prices mean that the Company cannot be certain of the future sales value of its products
· Price mitigation strategies may be employed at the point of major capital commitment
· Gas may be sold under long-term contracts reducing exposure to short term fluctuations
· Oil and gas price hedging contracts may be utilised where viable
· Budget planning considers a range of commodity pricing
Gas price volatility
· Continue to take advice from gas market experts.
· Progress discussions for possible future hedging.
Brexit 'no-deal' at the end of 2020
· Major contracts for Phase 1 awarded or to be awarded in 2020.
· Maximise GBP content to minimise exposure to adverse FX rates
The Group may not be able to get access, at reasonable cost, to infrastructure and product markets when required
· A range of different off-take options are pursued wherever possible
COVID-19 Pandemic: Post period end the COVID-19 pandemic has created severe economic upheaval and unforeseeable disruptions to normal working practices around the world
Risks
Mitigation
COVID-19 Pandemic and associated economic volatility materially disrupts the Company's ability to deliver its key corporate objectives
· The Company has already secured funding to achieve first gas and free cash flow, and is not dependent on current cash flows to fund itself
· The Company has implemented logistical and organisational changes to underpin its resilience to severe economic disruption driven by COVID-19, with the key focus being protecting all personnel, minimising impact on critical workstreams and ensuring business continuity
S172 statement
Section 172 of the Companies Act 2006 requires Directors to take into consideration the interests of stakeholders and other matters in their decision making. The Directors continue to have regard to the interests of the Company's employees and other stakeholders, the impact of its activities on the community, the environment and the Company's reputation for good business conduct, when making decisions. In this context, acting in good faith and fairly, the Directors consider what is most likely to promote the success of the Company for its members in the long term. We explain in this annual report, and referenced below, how the Board engages with stakeholders.
Likely consequence of any decision in the long term
The Chief Executive's Review at pages 2 and 3 in the Annual Report, Business Strategy at page 5 in the Annual Report and the QCA Statement on strategy at page 23 in the Annual Report set out the Company's long term rationale and strategy.
Interests of Employees
The Employee section of the Company's QCA Statement on page 25 of the Annual Report sets out the Company processes in place to safeguard the interests of employees.
Foster business relationships with suppliers, customers and others
The Company's policies and procedures relating to suppliers and all stakeholders are set out in the QCA Statement on page 23 of the Annual Report. The Company's approach to Shareholders is set out in the QCA Statement at page 21 of the Annual Report.
Community and Environment
The Company's approach to the community is set out in the QCA Statement at page 23 in the Annual Report and to the environment at page 5 in the Annual Report, and the QCA Statements at pages 26 and 27 in the Annual Report.
Maintain high standards of business conduct
The Corporate governance section of the Annual Report at pages 19 - 38 sets out the Board and Committee structures and extensive board and committee meetings held during 2019, together with the experience of executive management and the Board and the Company's policies and procedures.
Act fairly between shareholders
The Chief Executive's Review on pages 2 and 3 of the Annual Report and Highlights of 2019 on page 4 of the Annual Report summarise the institutional equity fundraise, Board/management subscription and open offer, LOG restructuring, bond issue and Farm-out to CER reconciling the Company's various stakeholder interests to preserve and enhance value.
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 2019 in view of the limited liquidity of longer dated UK gas futures and exposures carried during the year. As the Company's capital investment programmes increase, the Company will consider the use of appropriate hedging, seeking to retain 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 risks arising from the Group's use of financial instruments can be found in Note 20 to the financial statements.
Insurance
The Group insures the risks it considers appropriate for the Group's needs and circumstances. However, the Group may elect not to have insurance for certain risks, due to the high premium costs associated with insuring those risks or for various other reasons, including an assessment that the risks are remote.
Finance Review
From a financial perspective 2019 was a transformational year for the company with over £250 million of committed capital raised across a number of transactions, culminating in FID being taken on Phase 1 of the Core Project.
Financial highlights for the year primarily included the successful Farm-out to CER, which entailed a £40 million consideration paid on completion plus development carries of £60 million and £65 million for Phase 1 and Phase 2 respectively. Alongside this came the successful €100 million 5-year senior secured bond issue which settled in September 2019 and was subsequently listed on the Oslo Børs.
The farm-out consideration enabled the repayment of £17.1m in debt, alongside which the full £10.9m of the 2016 8p convertible loan principal and accrued interest was converted into 135,464,155 new Ordinary Shares. In addition, the full £11.6m of 2018 19p convertible loan principal and accrued interest was restructured into a long-term, unsecured, non-interest-bearing Loan Note Instrument, convertible at 19p into 60,872,631 Ordinary Shares.
The other significant funding event of the year was the institutional equity Placing, as announced on 3 April 2019, which raised gross proceeds of £16.6 million, alongside which a fully subscribed Open Offer raised £2 million and a Board & management Subscription raised a further £0.275 million. This combined equity fundraise funded corporate and operational activities during the year.
The Company ended the year with £16.2 million of cash and £82.1 million of restricted cash relating to the Bond issue and remaining Phase 1 development carry of £55.5 million.
Income Statement
The Group made a gain for the year of £15.0 million (2018: £5.6 million loss), driven by a £24.3 million profit on disposal of 50% of the Core Project assets.
There was no impairment made against oil and gas properties during the year. This compares with the £184k impairment charged in 2018 relating to post-well drilling expenses.
The Income Statement includes a charge of £4.0 million (2018: £0.9 million) reflecting the expenses incurred for pre-licence activity, business development ("BD") and other corporate project activity and expenses.
Net administration expenses of £2.6 million (2018: £1. 0 million) relate to the underlying costs of running the Group's corporate operations and have increased as a result of the business and increase in the headcount now required.
There was no gain/loss on settlement of liabilities of in the period. The 2018 loss of £106k reflected both realised and unrealised movements on the settlement of liabilities via the issue of shares.
The foreign exchange gain of £0.2 million (2018: loss £0.3 million) reflects foreign exchange movements on non-GBP denominated loans, provisions and trade creditors and loans.
A gain of £5.0 million was recognised on the restructuring of the February 2018 convertible loan from LOG. The replacement convertible loan note improved terms such as attaching a zero interest rate and provided an extended maturity date and was subordination to other Group debt. See note 7 for full details.
Finance expense of £7.9 million (2018: 3.1 million) includes accrued interest payable on loans (net of capitalised interest of £1.5 million (2018: £0.8 million), discount accretion and both current and amortised finance expenses. These expenses relate to fees and interest incurred on both loan finance facilities and those trade creditors subject to deferred payment and equity conversion terms.
Balance Sheet
PPE oil and gas assets have decreased to £28.9 million (2018: £41.5 million) during the year, representing capital expenditure activities on the Core Project assets, and the impact of the Farm-out which entailed 50% disposal of these assets.
The Harvey, Goddard and Abbeydale exploration and evaluation ('E&E') assets represent the E&E portfolio at 31 December 2019, with a net book value of £13.1 million (2018: £2.4 million) to the Group at that date.
Current assets have increased to £103.4 million (2018: £1.4 million) mainly resulting from adding the Bond proceeds, increasing the cash resources to £98.3 million (2018: £0.70 million) of which £82.1 million is restricted.
Total liabilities have increased to £106.0 million (2018: £51.1 million) mainly resulting from accounting for the Bond, creating an increase in long-term loans of £66.4 million. Liabilities also include trade creditors £3.9 million (2018: £5.9 million), other creditors £1.4 million (2018: £1.8 million), deferred consideration in relation to acquisitions of £3.1 million (2018: £6.2 million). Decommissioning provisions of £7.2 million, including Vulcan East suspended well abandonment provision of £1.2 million (2018: £3.6 million), the Thames Pipeline decommissioning provision of £1.0 million (2018:
£2.0 million) and the Thames Reception Facility at Bacton of £5.0 million. Accruals of £1.3 million (2017: £3.5 million). There are no short-term loans (2018: £6.9 million).
The Group ended the period with a net cash position of £8.0 million
Cash Flow
Net cash outflows of £10.3 million (2018: £3.0 million) from operations, £83.3 million (2018: £14.8 million) from investing activities and £109.0 million (2018: £0.4 million) from financing activities. Loan repayments of £17.1 million (2018: £nil) were funded from proceeds from the Farm-out to CER of the issue of equity instruments in the Company totalling £18.9 million (2018: £18.8 million). At the end of the period £82.0 million of funds were held as restricted cash in escrow accounts relating to monies received from the Bond issue
The Directors do not recommend payment of a dividend.
€100 million Bond
In September 2019, the Group issued a €100 million 5-year senior secured Bond in the name of Independent Oil and Gas plc to a range of institutional investors across the Nordic region, Europe, UK and Asia. It has a bullet repayment structure, with a maturity date of 20 September 2024, and an interest rate, payable quarterly, of 9.5 per cent per annum over the three-month EURIBOR rate (with a floor of zero when this rate is negative, as it is at the time of writing). The first eight quarterly payments were set aside at settlement in a Debt Service Reserve Account. The Bond has a senior secured position over the Group's licences and infrastructure assets, as well as any further licence in which the Group takes an ownership interest during the tenure of the Bond.
The Bond is callable 3 years after issuance with an initial call premium of 50% of the coupon (i.e. repayable at a cost of €104.75 million if 3m EURIBOR is at zero or lower), declining by 10% every six months thereafter.
Proceeds of the Bond are to be used to fund capital expenditure on IOG's gas development project in the UK Southern North Sea ("Core Project"), financing costs and general corporate purposes.
In December 2019 the Bond was listed on the Oslo Børs with the ISIN NO0010863236.
The Company has the option, subject to conditions and investor commitments, to issue additional amounts up to a maximum aggregate of €30 million ("Tap Issues"). Tap Issues carry identical terms to the initial €100 million issue, but may be issued at different prices.
Funding & Liquidity
The Board has reviewed the Group's cash flow forecasts having regard to its current financial position and operational objectives.
The Consolidated Statement of Financial Position at 31 December 2019 details a net cash position of the Group of £8.0 million. The Board is satisfied that the Group will have sufficient financial resources available to meet its commitments based on meeting the requirements of the funding commitments in place. In particular, the completion of the Bond and Farm-out transactions, as announced on 9 September 2019 and 28 October 2019 respectively, provide the funding required to finance the Group's activities. Accordingly, the Board continue to adopt the going concern basis for the preparation of these financial statements.
The Strategic Report on pages 4 to 18 has been issued and signed on behalf of the Board.
Rupert Newall
Chief Financial Officer
25 March 2020
Consolidated Statement of Comprehensive Income
Notes
2019
2018
£000
£000
Administration expenses
(2,622)
(974)
Impairment of oil and gas properties
9
-
(184)
Project, pre-licence and exploration expenses
(4,027)
(922)
Net loss on settlement of liabilities
-
(106)
Profit on farm-down of assets
6
24,340
-
Foreign exchange gain/(loss)
238
(334)
_________
_________
Operating profit/(loss)
3
17,929
(2,520)
Finance expense
5
(7,939)
(3,124)
Finance income
34
-
Gain on loan modification
7
5,005
-
_________
_________
Profit/(loss) for the year before taxation
15,029
(5,644)
Taxation
8
-
-
_________
_________
Profit/(loss) and total comprehensive profit/(loss) for the year attributable to equity holders of the parent
9
15,029
(5,644)
_________
_________
Profit/(loss) for the year per ordinary share - basic
9
5.1p
(4.6p)
Profit/(loss) for the year per ordinary share - diluted
9
3.7p
(4.6p)
The profit of for the year £15.0 million (2018: loss £5.6 million) arose from continuing operations.
Consolidated and Company Statements of Changes in Equity
Share capital
Share premium
Share-based payment reserve
Accumulated losses
Total equity
Group:
£000
£000
£000
£000
£000
At 1 January 2018
1,203
22,337
3,099
(31,405)
(4,766)
Loss for the year
-
-
-
(5,644)
(5,644)
_____
________
________
________
_______
Total comprehensive loss attributable to owners of the parent
-
-
-
(5,644)
(5,644)
Issue of warrants
-
-
4,190
-
4,190
Issue of share options
-
-
378
-
378
Exercise of share options
66
-
(1,359)
1,359
66
_____
________
________
________
_______
At 31 December 2018
1,269
22,337
6,308
(35,690)
(5,776)
Profit for the year
-
-
-
15,029
15,029
_____
________
________
________
_______
Total comprehensive profit attributable to owners of the parent
-
-
-
15,029
15,029
Issue of share capital
3,483
27,086
-
-
30,569
Lapse of warrants
-
-
(31)
31
-
Issue of share options
-
-
676
-
676
Exercise of share options
50
-
(601)
601
50
_____
______
________
________
_______
At 31 December 2019
4,802
49,423
6,352
(20,029)
40,548
_____
________
_______
________
_______
Company:
At 1 January 2018
1,203
22,337
3,099
(3,912)
22,727
Loss for the year
-
-
-
(2,604)
(2,604)
_____
________
________
________
_______
Total comprehensive profit attributable to owners of the parent
-
-
-
(2,604)
(2,604)
Issue of warrants
-
-
4,190
-
4,190
Issue of share options
-
-
378
-
378
Exercise of share options
66
-
(1,359)
1,359
66
_____
________
________
________
_______
At 31 December 2018
1,269
22,337
6,308
(5,157)
24,757
Loss for the year
-
-
-
(7,010)
(7,010)
_____
________
________
________
_______
Total comprehensive loss attributable to owners of the parent
-
-
-
(7,010)
(7,010)
Issue of share capital
3,483
27,086
-
-
30,569
Lapse of warrants
-
-
(31)
31
-
Issue of share options
-
-
676
-
676
Exercise of share options
50
-
(601)
601
50
_____
________
_______
_______
_______
At 31 December 2019
4,802
49,423
6,352
(11,535)
49,042
______
________
_______
________
_______
Share capital - Amounts subscribed for share capital at nominal value.
Share premium - Amounts received on the issue of shares, in excess of the nominal value of the shares.
Share-based payment reserve - Amounts reflecting fair value of options and warrants issued.
Accumulated losses - Cumulative net losses recognised in the Statement of Comprehensive Income net of amounts recognised directly in equity.
Consolidated Statement of Financial Position
Notes
2019
2018
£000
£000
Non-current assets
Intangible assets: exploration & evaluation
10
13,099
2,352
Intangible assets: other
10
80
3
Property, plant and equipment: development & production
11
28,921
41,527
Property, plant and equipment: other
11
1,071
41
Restricted Cash
19
49,230
-
_________
_________
92,401
43,923
_________
_________
Current assets
Other receivables and prepayments
14
5,092
672
Restricted cash
19
32,836
-
Cash and cash equivalents
19
16,197
702
_________
_________
54,125
1,374
_________
_________
Total assets
146,526
45,297
Current liabilities
Loans
16
-
(6,934)
Trade and other payables
16
(7,231)
(11,137)
_________
_________
(7,231)
(18,071)
_________
_________
Non-current liabilities
Loans
17,19
(89,243)
(22,884)
Provisions
17
(9,504)
(10,118)
_________
_________
(98,747)
(33,002)
_________
_________
Total liabilities
(105,978)
(51,073)
_________
_________
NET ASSET / (LIABILITIES)
40,548
(5,776)
_________
_________
Capital and reserves
Share capital
18
4,802
1,269
Share premium
18
49,423
22,337
Share-based payment reserve
6,352
6,308
Accumulated losses
(20,029)
(35,690)
_________
_________
40,548
(5,776)
_________
_________
The financial statements were approved and authorised for issue by the Board of Directors on 25 March 2020 and were signed on its behalf by:
Rupert Newall
Chief Financial Officer
25 March 2020
Company Statement of Financial Position
Company Number: 07434350
Notes
2019
2018
£000
£000
Non-current assets
Intangible assets
10
80
3
Property, plant and equipment
11
1,071
41
Investments
13
15,486
17,197
Amounts due from subsidiaries
13
28,710
29,526
Restricted Cash
19
49,230
-
_________
_________
94,577
46,767
_________
_________
Current assets
Other receivables and prepayments
15
2,513
672
Restricted cash
19
31,586
-
Cash and cash equivalents
19
16,197
702
_________
_________
50,296
1,374
_________
_________
Total assets
144,873
48,141
Current liabilities
Trade and other payables
16
(5,944)
(8,071)
Non-current liabilities
Loans
17
(89,243)
(14,054)
Provisions
17
(644)
(1,259)
_________
_________
(89,887)
(15,313)
_________
_________
Total liabilities
(95,831)
(23,384)
_________
_________
NET ASSETS
49,042
24,757
_________
_________
Capital and reserves
Share capital
18
4,802
1,269
Share premium
18
49,423
22,337
Share-based payment reserve
6,352
6,308
Accumulated losses
(11,535)
(5,157)
_________
_________
49,042
24,757
_________
_________
The Company has taken advantage of the exemption allowed under Section 408 of the Companies Act 2006 and has not presented its own Statement of Comprehensive Income in these financial statements.
The Company loss for the year was £7.0 million (2018: loss £2.6 million).
The financial statements were approved and authorised for issue by the Board of Directors on 25 March 2020 and were signed on its behalf by: -
Rupert Newall
Chief Financial Officer
25 March 2020
Consolidated Cash Flow Statement
Notes
2019
2018
£000
£000
Profit/(loss) for the year
7
15,029
(5,644)
Depreciation, depletion and amortisation
244
9
Exploration asset write off
-
184
Loss on settlement of liabilities
-
106
Share based payments
675
187
Movement in trade and other receivables
(4,420)
(812)
Movement in trade and other payables
(620)
(415)
Profit on disposal of fixed assets
6
(24,340)
-
Interest received
(35)
(2)
Gain on loan modification
(5,005)
-
Finance fees
7,939
3,206
Foreign exchange differences
238
142
_________
_________
Net cash used in operating activities
(10,295)
(3,039)
Investing activities
Purchase of intangible and tangible assets
(17,048)
(14,327)
Movement in restricted cash
(87,646)
-
Interest received
35
2
Farm out proceeds received [1]
22,389
-
Acquisitions [2]
10
-
-
Initial Thames Reception Facility ("TRF") decommissioning security
(2,000)
-
Farm out proceeds received in respect of ("TRF") decommissioning security
1,000
-
Initial Thames Pipeline decommissioning security
250
(500)
Lease liability payments
(236)
-
_________
_________
Net cash used in investing activities
(83,256)
(14,825)
Financing activities
Proceeds from issue of equity instruments of the Group
18,675
67
Issue costs in relation to issue of equity
(1,288)
-
Proceeds from issue of Norwegian Bond
90,439
-
Cash received from loans
25
3,925
18,787
Finance fees paid
(2,705)
(433)
_________
_________
Net cash generated from financing activities
109,046
18,421
Net increase in cash and cash equivalents
15,495
557
Cash and cash equivalents at the beginning of the year
702
145
_________
_________
Cash and cash equivalents at end of year
19
16,197
702
_________
_________
[1] Proceeds from the farm out were received net of funds which were settled to LOG for loans and interest totalling £17,139k and legal fees £472k
[2] The Thames Reception Facility at Bacton was acquired for £1.00
Company Cash Flow Statement
Notes
2019
2018
£000
£000
Loss for the year
18
(7,010)
(2,604)
Depreciation charges
244
8
Loss on settlement of liabilities
3
-
106
Share based payments
675
138
Movement in trade and other receivables
(1,841)
(312)
Movement in trade and other payables
(2,205)
(415)
Inter-company service charge uplift
(165)
(206)
Interest received
(35)
(2)
Finance fees
6,596
1,322
Gain on loan modification
(5,005)
-
Foreign exchange differences
289
142
_________
_________
Net cash used in operating activities
(8,457)
(1,823)
Investing activities
Purchase of intangible and tangible assets
(297)
(573)
Movement in restricted cash
(87,646)
-
Loans to subsidiary undertakings
(19,339)
(15,470)
Proceeds from subsidiary undertakings
22,389
-
Interest received
35
2
Lease liability payments
(236)
_________
_________
Net cash used in investing activities
(85,094)
(16,041)
Financing activities
Proceeds from issue of equity instruments of the Company
18,675
67
Issue costs in relation to issue of equity
(1,288)
Proceeds from issue of Norwegian Bond (net of costs)
90,439
-
Cash received from loans
23
3,925
18,787
Finance fees paid
(2,705)
(433)
_________
_________
Net cash generated from financing activities
109,046
18,421
Net (decrease) / increase in cash and cash equivalents
15,495
557
Cash and cash equivalents at the beginning of the year
702
145
_________
_________
Cash and cash equivalents at end of year
17
16,197
702
_________
_________
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 2019 were authorised for issue by the Board of Directors on 25 March 2020 and the balance sheets were signed on the Board's behalf by the CFO, Rupert Newall.
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 within this Note 1 on pages 61 and 62.
The consolidated financial statements have been prepared on a historical cost basis.
Going concern
The Board has reviewed the Group's cash flow forecasts up until September 2021 having regard to its current financial position and operational objectives and has concluded that the Group is able to continue as a going concern.
During 2019 the Group announced it had successfully completed a number of financial transactions to provide not only the required liquidity to sustain its ongoing overhead costs but to also enable it to progress and approve the Phase 1 development programme, delivering production and sales of gas from its SNS Core Project Phase 1 assets (Blythe, Elgood & Southwark) utilising its previously acquired Thames pipeline and newly acquired Thames Reception Facilities at Bacton.
In April 2019 the Group successfully restructured its debt from LOG with equity and raised additional funds of £18.9 million by way of a placing, subscription and open offer, enabling the Group to fund the Harvey well and progress its business and Core Project through to farm-out completion. In September 2019 IOG raised €100 million(£90.4 million), before fees, via a Senior Secured Bond listed on the Oslo Børs thereby completing its financial capability to deliver its Phase 1 project. Finally, in October 2019, the Group completed the 50% farm-out of its assets (excluding the Harvey licences) to CalEnergy Resources Limited, providing an additional £40 million of proceeds upon completion, of which £17.1 million was used to repay LOG debt. Following the farm-out the Board and CER took the Final Investment Decision for Phase 1 of the Core Project.
The Group is primarily now in a development phase of operations with a number of related projects to complete and it is the Board's opinion that the Group has the skills and financial resources to deliver Phase 1 of the Core Project.
In the current business climate, the Directors acknowledge the COVID-19 pandemic and have implemented logistical and organisational changes to underpin the organisation's resilience to COVID-19, with the key focus being protecting all personnel, minimising impact on critical workstreams and ensuring business continuity. The Company's funding over the next period is from cash balances, drawdown of the remaining Phase 1 Development Carry from CER and drawings from the funds raised in the €100 million bond. The Phase 1 Development Carry continues to be drawn down and is guaranteed by CER's parent company which provides the Directors significant comfort. The undrawn proceeds from the €100 million bond are held in escrow with DNB Bank ASA. As we embark on a phase of key contracting, the precipitous fall in oil prices driven by the COVID-19 demand shock and the significant global oversupply situation also creates potential opportunities to drive down costs in the context of our efforts to deliver Phase 1 as cost-efficiently as possible and the Directors see this as part of its strategy to mitigate impacts from the COVID-19 pandemic.
New and revised accounting standards
(i) New and amended standards adopted by the Group:
The accounting policies adopted are consistent with those of the previous financial year. New or amended financial standards or interpretations adopted during the year and that have a significant impact upon the financial statements are detailed below.
(ii) The following standards, amendments and interpretations, which are effective for reporting periods beginning after the date of these financial statements, have not been adopted early: -
Standard
Description
Effective date
IFRS 3
Definition of a Business (Amendments to IFRS 3)
1 January 2020
IAS1, IAS8
Definition of Material (amendments to IAS1 and IAS 8)
1 January 2020
n/a
Amendments to References to the Conceptual Framework in IFRS Standards
1 January 2020
IFRS 17
Insurance Contracts
1 January 2021
In reviewing the above standards, the Company does not believe that there will be a material impact on the financial statements.
IFRS 16 'Leases'
IOG adopted IFRS 16 Leases ('IFRS 16') with effect from 1 January 2019. IFRS 16 was issued in January 2016 to replace IAS 17 Leases.
IFRS 16 sets out the principles for the recognition, measurement, presentation and disclosure of leases and requires lessees to account for all leases, with limited exceptions, under a single on-balance sheet model similar to the accounting for finance leases under IAS 17. Under IFRS 16, at the commencement date of a lease, a lessee is required to recognise a liability to make lease payments ('lease liability') and an asset representing the right to use the underlying asset during the lease term ('right-of-use asset'). Lease liabilities are measured at the present value of future lease payments over the reasonably certain lease term. Variable lease payments that do not depend on an index or a rate are not included in the lease liability. Such payments are expensed as incurred throughout the lease term.
In applying IFRS 16 for the first time the Group has applied the short-term lease practical expedient by not recognising lease liabilities in respect to lease arrangements with a remaining lease term of less than 12 months as at 1 January 2019. The Group adopted the modified retrospective approach to adoption on 1 January 2019, measuring right-of use assets at an amount based on their respective lease liability on adoption, with the cumulative effect of adopting the standard recognised at the date of initial application without restatement of comparative information.
Lessees are required to separately recognise the interest expense associated with the unwinding of the lease liability and the depreciation expense on the right-of-use asset. These costs replace amounts previously recognised as operating expenditure in respect of operating leases in accordance with IAS 17.
Basis of consolidation
Where the Company has control over an investee, it is classified as a subsidiary. The Company controls an investee if all three of the following elements are present: power over the investee, exposure to variable returns from the investee, and the ability of the investor to use its power to affect those variable returns. Control is reassessed whenever facts and circumstances indicate that there may be a change in any of these elements of control.
The consolidated financial statements present the results of the Company and its subsidiaries as if they formed a single entity. Inter-company transactions and balances between Group companies are therefore eliminated in full. The financial statements of subsidiaries are included in the Group's financial statements from the date that control commences until the date that control ceases.
Asset Acquisition
In the event of an asset acquisition, the cost of the acquisition is assigned to the individual assets and liabilities based on their relative fair values. All directly attributable costs are capitalised. Contingent consideration is accrued for when these amounts are considered probable and are discounted to present value based on the expected timing of payment.
Oil and gas exploration, development and producing assets
The Group adopts the following accounting policies for oil and gas asset expenditure, based on the stage of development of the assets:
1) Pre-Licence
Expenditure incurred prior to the acquisition and/or award of a licence interest is expensed to the Statement of Comprehensive Income as 'Exploration Expenses'.
2) Exploration and evaluation ('E&E')
Capitalisation
Costs incurred after rights to explore have been obtained, such as geological and geophysical surveys, drilling and commercial appraisal costs, and other directly attributable costs of exploration and appraisal including technical and administrative overheads, are capitalised as intangible exploration and evaluation ('E&E') assets. The assessment of what constitutes an individual E&E asset is based on technical criteria but essentially either a single licence area or contiguous licence areas with consistent geological features are designated as individual E&E assets. Costs relating to the exploration and evaluation of oil and gas interests are carried forward until the existence, or otherwise, of commercial reserves have been determined.
E&E costs are not amortised prior to the conclusion of appraisal activities. Once active exploration is completed the asset is assessed for impairment. If commercial reserves are discovered then the carrying value of the E&E asset is reclassified as a development and production ('D&P') asset, within property, plant and equipment ('PPE'), following development sanction by the Board, but only after the carrying value is assessed for impairment at point of transfer and, where appropriate, its carrying value adjusted. Following development sanction by the Board, a Field Development Plan ('FDP') may be submitted. If it is subsequently assessed that commercial reserves have not been discovered, the E&E asset is written off to the Statement of Comprehensive Income. The Group's definition of commercial reserves for such purpose is proven and probable ('2P') reserves on an entitlement basis.
Intangible E&E assets that relate to E&E activities that are not yet determined to have resulted in the discovery of commercial reserves remain capitalised as intangible E&E assets at cost, subject to impairment assessments as set out below.
Borrowing costs
Borrowing costs directly attributable to the construction of qualifying assets, which are assets that necessarily take a substantial period of time to prepare for their intended use, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use. All other borrowing costs are recognised as interest payable in the statement of comprehensive income in accordance with the effective interest method.
Impairment
The Group's oil and gas assets are analysed into cash generating units ('CGU') for impairment reporting purposes, with E&E asset impairment testing being performed at an individual asset level. E&E assets are reviewed for impairment when circumstances arise which indicate that the carrying value of an E&E asset exceeds the recoverable amount. Such indicators would include but not limited to:
(i) adequate and sufficient data exists that render the resource uneconomic and unlikely to be developed;
(ii) title to the asset is compromised;
(iii) budgeted or planned expenditure is not expected in the foreseeable future; and
(iv) insufficient discovery of commercially viable resources leading to the discontinuation of activities.
Oil and gas exploration, development and producing assets (continued)
The recoverable amount of the individual asset is determined as the higher of its fair value less costs to sell and value in use. Impairment losses resulting from an impairment review are separately recognised and written off to the Statement of Comprehensive Income.
Impaired assets are reviewed annually to determine whether any substantial change to their fair value amounts previously impaired would require reversal.
A previously recognised impairment loss is reversed if the recoverable amount increases because of a change in the estimates used to determine the recoverable amount, but not to an amount higher than the carrying amount that would have been determined (net of depletion or amortisation) had no impairment loss been recognised in prior periods. Reversal of impairments and impairment charges are credited/(charged) to a separate line item within the Statement of Comprehensive Income.
3) Development and production ('D&P')
Capitalisation
Costs of bringing a field into production, including the cost of facilities, wells and sub-sea equipment together with E&E assets reclassified in accordance with the above policy, are capitalised as a D&P asset within PPE. Normally each individual field development will form an individual D&P asset but there may be cases, such as phased developments, or multiple fields around a single production facility when fields are grouped together to form a single D&P asset. The cost of development and production assets also include the cost of acquisitions and purchases of such assets, directly attributable overheads, applicable borrowing costs and the cost of recognising provisions for future consideration payments - see Note 9 and Note 10. The discounted cost for future decommissioning is also added to the D&P asset.
Depreciation and depletion
All costs relating to a development are accumulated and not depreciated/depleted until the commencement of production. Depletion is calculated on a UOP basis based on the 2P reserves of the asset. Any re-assessment of reserves affects the depletion rate prospectively. Significant items of plant and equipment will normally be fully depreciated over the life of the field; however, these items are assessed to consider if their useful lives differ from the expected life of the D&P asset and should this occur a different depreciation rate may be charged. The key areas of estimation regarding depletion and the associated unit of production calculation for oil and gas assets are recoverable reserves and future capital expenditures.
Impairment
A review is carried out for any indication that the carrying value of the Group's D&P assets may be impaired. If any indicators are identified, a review of D&P assets is carried out on an asset by asset basis and involves comparing the carrying value with the recoverable value of an asset. The recoverable amount of an asset is determined as the higher of its fair value less costs to sell and value in use. The value in use is determined from estimated future net cash flows, being the present value of the future cash flows expected to be derived from production of commercial reserves. Impairment resulting from the impairment testing is charged to a separate line item within the Statement of Comprehensive Income.
The pre-tax future cash flows are adjusted for risks specific to the CGU and are discounted using a pre-tax discount rate. The discount rate is derived from the Group's post-tax weighted average cost of capital and is adjusted where applicable to consider any specific risks relating to the country where the CGU is located, although other rates may be used if appropriate to the specific circumstances. The discount rates applied in assessments of impairment are reassessed each year. The Company uses a risk adjusted discount rate of 10%, unless otherwise stated.
The CGU basis is generally the field, however, oil and gas assets, including infrastructure assets may be accounted for on an aggregated basis where such assets are economically inter-dependent.
Oil and gas exploration, development and producing assets (continued)
4) Offshore Pipelines
Capitalisation
Costs of commissioning an offshore pipeline to transport hydrocarbons, including the cost of related onshore facilities and subsea equipment are capitalised as a tangible asset within PPE. Each contiguous pipeline will form an exclusive individual asset but there may be cases, such as phased developments, when pipelines are grouped together to form a single tangible pipeline asset. The cost of offshore pipeline assets also includes the cost of acquisitions and purchases of such assets, directly attributable overheads, applicable borrowing costs and the discounted cost of future decommissioning.
Depreciation
All costs relating to pipeline commissioning are not depreciated until the commencement of transportation of hydrocarbons. Depreciation is calculated on a straight-line basis over the period in which transportation is likely to take place. Any re-assessment of this timeline will impact on the depreciation rate prospectively. The key areas of estimation regarding depreciation are future capital expenditures and recoverable reserves for those fields where such pipelines are utilised for the transportation of oil and gas production.
Impairment
A review is carried out for any indication that the carrying value of the pipeline asset may be impaired. If any indicators are identified, such as the pipeline's inability to continue to operate safely and effectively in its current environment, a review of the pipeline asset is carried out. Impairment resulting from the impairment review is charged to a separate line item within the Statement of Comprehensive Income.
Assets other than oil and gas interests
Assets other than oil and gas interests are stated at cost, less accumulated depreciation and any provision for impairment. Depreciation is provided at rates estimated to write off the cost, less estimated residual value, of each asset over its expected useful life as follows: -
· Computer and office equipment: 33% straight line, with one full year's depreciation in year of acquisition; and
· Tenants improvements: 20% straight line, with one full year's depreciation in year of acquisition.
Provisions
Provisions are recognised when:
· the Group has a present legal or constructive obligation resulting from past events;
· it is more likely than not that an outflow of resources will be required to settle the obligation; and
· the amount can be reliably estimated.
Decommissioning
Provisions for decommissioning costs are recognised in accordance with IAS 37 Provisions, Contingent Liabilities and Contingent Assets. Provisions are recorded at the present value of the expenditures expected to be required to settle the Group's future obligations.
Provisions are reviewed at each reporting date to reflect the current best estimate of the cost at present value. Any change in the date on which provisions fall due will change the present value of the provision. These changes are treated as an administration expense. The unwinding of the discount is reflected as a finance expense.
In the case of a D&P and/or pipeline asset, since the future cost of decommissioning is regarded as part of the total investment to gain access to future economic benefits, this is included as part of the cost of the relevant D&P and/or pipeline asset.
Disposals
Net proceeds from any disposal of an E&E, D&P or pipeline asset are initially credited against the previously capitalised costs of that asset and any surplus or shortfall proceeds are credited or debited to the Statement of Comprehensive Income.
For the Farm down of an E&E, D&P or pipeline asset, proceeds from the farm-down are credited against the previously capitalised costs of the asset and any surplus or shortfall proceeds above or below the representative percentage of the carrying value of the asset or assets being farmed down are credited or debited to the Statement of Comprehensive Income accordingly.
Foreign currencies
The Group's presentational currency is GBP Sterling and has been selected based on the currency of the primary economic environment in which the Group operates. The Group's primary product is generally traded by reference to its pricing in GBP Sterling. The functional currency of all companies in the Group is also considered to be GBP Sterling. Transactions in currencies other than the functional currency of a company are recorded at a rate of exchange approximating to that prevailing at the date of the transaction. At each balance sheet date, monetary assets and liabilities that are denominated in currencies other than the functional currency are translated at the amounts prevailing at the balance sheet date and any gains or losses arising are recognised in the Consolidated Statement of Comprehensive Income.
Taxation
Current Tax
Tax is payable based upon taxable profit for the year. Taxable profit differs from net profit as reported in the Statement of Comprehensive Income because it excludes items of income or expense that are taxable or deductible on other years and it further excludes items that are never taxable or deductible. Any Group liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the reporting date.
Deferred Tax
Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised.
Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries, except where the Group can control the reversal of the temporary differences and it is probable that the temporary difference will not reverse in the foreseeable future.
The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.
Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled, or the asset is realised. Deferred tax is charged or credited in the Statement of Comprehensive Income, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also dealt with in equity. Deferred tax assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current tax liabilities and when they relate to income taxes levied by the same taxation authority and the Group intends to settle its current tax assets and liabilities on a net basis.
The amount of the asset or liability is determined using tax rates that have been enacted or substantively enacted by the reporting date and are expected to apply when the deferred tax liabilities/(assets) are settled/(recovered). Deferred tax balances are not discounted.
Investments & Loans (Company)
Non-current investments in subsidiary undertakings are shown in the Company's Statement of Financial Position at cost less any provision for permanent diminution of value.
Loans to subsidiary undertakings are stated at amortised cost and recognised in accordance with IFRS9. The loans have no maturity date and are not repayable until the respective subsidiary entity has sufficient cash to repay the loan, however they are technically due on demand
Leases
In January 2016, the IASB issued IFRS 16 "Leases" ("IFRS 16"), which requires entities to recognise right-of-use ("ROU") assets and lease obligations on the statement of financial position.
The Group adopted IFRS 16 on 1 January 2019 using the modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information, instead recognising the cumulative effect as an adjustment to the opening retained earnings and the Group applied the standard prospectively.
The Group has applied the standard while using the following optional expedients permitted under the standard:
• Short-term leases - those with terms of 12 months or less at date of adoption
• Low-value leases - those with a value less than £5,000
On 1 January 2019, the Group recognised a cumulative increase to ROU assets of £1.1 million for leases previously classified as operating leases, directly offset to the lease obligations. The weighted average incremental borrowing rate used to determine the lease obligation at adoption was approximately 11.5%. The assets and lease obligations related to the adoption of IFRS 16, relate to office leases and the Thames Pipeline permission to cross the foreshore.
The Company depreciates the ROU assets on a straight-line basis over the length of the lease unless management determines this is not representative of the useful life, in which case, management will estimate the useful life of the asset to be used.
Financial Instruments
Financial instruments are recognised when the Group becomes a party to the contractual provisions of the instrument and are subsequently measured at amortised cost.
Classification and measurement of financial assets
The initial classification of a financial asset depends upon the Group's business model for managing its financial assets and the contractual terms of the cash flows. The Group's financial assets are measured at amortised cost and are held within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest.
The Group's cash and cash equivalents and other receivables are measured at amortised cost. Other receivables are initially measured at fair value. The Group holds other receivables with the objective to collect the contractual cash flows and therefore measures them subsequently at amortised cost.
The Group has no financial assets measured at FVOCI (Fair Value Through Other Comprehensive Income) or FVTPL (Fair Value Through the Statement of Profit or Loss)
Restricted cash
Restricted cash includes cash balances that are subject to access restrictions or have conditions attached to their drawdown. Included in this are monies raised from its Norwegian bond placing held in escrow and subject to defined drawdown conditions. Also included are balances held as collateralised security in the Group's name for future expenditures such as Decommissioning.
Cash and cash equivalents
Cash includes cash on hand and demand deposits with any bank or other financial institution. Cash equivalents are short-term, highly liquid investments that are readily convertible to known amounts of cash which are subject to an insignificant risk of changes in value.
Impairment of financial assets
The Group recognises loss allowances for expected credit losses ('ECL's) on its financial assets measured at amortised cost. Due to the nature of its financial assets, the Group measures loss allowances at an amount equal to the lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses. The company has carried out an analysis of the balances outstanding at the end of the period and assessed the likelihood of repayment from its subsidiaries. It believes that there is no significant increase in credit risk from the prior year and, if anything, the position is strengthened with the sanction of the phase 1 project resulting in future cashflows for its subsidiaries.
Classification and measurement of financial liabilities
A financial liability is initially classified as measured at amortised cost or FVTPL. A financial liability is classified as measured at FVTPL if it is held-for-trading, a derivative or designated as FVTPL on initial recognition.
The Group's accounts payable, accrued liabilities and long-term debt are measured at amortised cost.
Accounts payable and accrued liabilities are initially measured at fair value and subsequently measured at amortised cost. Accounts payable and accrued liabilities are presented as current liabilities unless payment is not due within 12 months after the reporting period.
Long-term debt is initially measured at fair value, net of transaction costs incurred. The contractual cash flows of the long-term debt are made up of solely principal and interest, therefore long-term debt is subsequently measured at amortised cost. Long-term debt is classified as current when payment is due within 12 months after the reporting period.
Where warrants are issued in lieu of arrangement fees on debt facilities, the fair value of the warrants are measured at the date of grant as determined through the use of the Black‑Scholes technique. The fair value determined at the grant date of the warrants is recognised in the Group's warrant reserve and is amortised as a finance cost over the life of the facility.
The Group has no financial liabilities measured at FVTPL.
The outstanding LOG loans are unsecured against any assets or Company of the Group.
Convertible loan notes
Upon issue, convertible notes are assessed as to whether it is necessary to separate the loan into an equity and liability component at the date of issue. If the bifurcation is considered material the liability component is recognised initially at its fair value. Subsequent to initial recognition, it is carried at amortised carrying value using the effective interest method until the liability is extinguished on conversion or redemption of the notes. The equity component is the residual amount of the convertible note after deducting the fair value of the liability component. This is recognised and included in equity and is not subsequently re-measured.
During the year, the Company re-negotiated the terms of is February 2018 convertible loan. The loan was considered to have been redeemed under the provisions of IFRS 9 and the resulting improvement in terms created a £5.0 million gain on loan redemption. The loan redemption gain was assessed by reference to the fair value of the remaining cashflows of the 2018 convertible loan note. The gain reflects the improvement in terms between the 2018 and the replacement 2019 loan due to the zero coupon rate attached to the 2019 loan and the extended maturity date to redemption.
Equity
Equity instruments issued by the Company are recorded at the proceeds received, net of direct issue costs, allocated between share capital and share premium.
Share issue expenses and share premium account
The costs of issuing new share capital are written off against the share premium account arising out of the proceeds of the new issue.
Share-based payments
The Company and Group have applied the requirements of IFRS 2 Share-based payments. The Company issues equity share options, to certain employees and contractors, as direct compensation for both salary and fees sacrificed in lieu of such share options. Other Long-Term Incentive Plan ('LTIP') and Company Share Ownership Plan ('CSOP') share options may be awarded to incentivise and reward successful corporate and individual performance. The fair value of these awards has been determined at the date of the grant of the award allowing for the effect of any market-based performance conditions.
The fair value of share options awarded, in lieu of salary sacrifice, is expensed on the effective date of grant, with no vesting conditions applied. The fair value is deemed to be the actual salary sacrificed.
For LTIP and CSOP share option awards, based upon incentive and performance, the fair value, adjusted by the estimate of the number of awards that will eventually vest because of non-market conditions, is expensed uniformly over the vesting period and is charged to the Statement of Comprehensive Income, together with an increase in equity reserves, over a similar period. The fair values are calculated using an option pricing model with suitable modifications to allow for early exercise. The inputs to the model include: the share price at the date of grant; exercise price; expected volatility; expected dividends; risk-free rate of interest; and patterns of exercise of the plan participants. Where the terms and conditions of options are modified before they vest, the increase in the fair value of the options, measured immediately before and after the modification, is also charged to the Statement of Comprehensive Income over the remaining vesting period. No expense is recognised for options that do not ultimately vest except where vesting is only conditional upon a market condition.
The fair value of warrants issued to third parties is calculated by reference to the service provided, or if this is not considered possible, calculated in the same way as for LTIP share options as detailed above. Typically, these amounts have related to debt issues and are included in the effective interest rate calculation of borrowings.
Profit or Loss earnings per share
Profit or 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.
The following are the critical judgements that management has made in the process of applying the entity's accounting policies and that have the most significant effect on the amounts recognised in financial statements.
Impairment of assets
Management is required to assess oil and gas assets for indicators of impairment and has considered the economic value of individual E&E and D&P assets. The carrying value of oil and gas assets is disclosed in Notes 11 and 12. The carrying value of related investments in the Company Statement of Financial Position is disclosed on page 46. E&E assets are subject to a separate review for indicators of impairment, by reference to the impairment indicators set out in IFRS 6, which is inherently judgmental.
Key estimates used in the assessment of value in use and fair value less costs to sell assessments
As noted in the accounting policy the carrying value of the assets is assessed against the higher of a value-in-use calculation and a fair value less costs to sell assessment.
The calculation of value-in-use for oil and gas assets under development or in production is most sensitive to the following assumptions:
· Commercial reserves
· production volumes;
· commodity prices;
· fixed and variable operating costs;
· capital expenditure; and
· discount rates
The fair value less costs to see assessment considered the proceeds arising from the Group's farm-down of its assets to CalEnergy and the indicative value derived from the transaction.
Commercial Reserves
Commercial reserves are proven and probable ('2P') oil and gas reserves, calculated on an entitlement basis. Estimates of commercial reserves underpin the calculation of depletion and amortisation on a UOP basis. Estimates of commercial reserves include estimates of the amount of oil and gas in place, assumptions about reservoir performance over the life of the field and assumptions about commercial factors which, in turn, will be affected by the future oil and gas price.
Production volumes/recoverable reserves
Annual estimates of oil and gas reserves are generated internally by the Group with external input from operator profiles and/or a Competent Person. These are reported annually by the Board. The self-certified estimated future production profiles are used in the life of the fields which in turn are used as a basis in the value-in-use calculation.
Commodity prices
An average of published forward prices and the long-term assumption for natural UKNBP gas and Brent oil are used for future cash flows in accordance with the Group's corporate assumptions. Field specific discounts and prices are used where applicable.
Fixed and variable operating costs
Typical examples of variable operating costs are pipeline tariffs, treatment charges and freight costs. Commercial agreements are in place for most of these costs and the assumptions used in the value-in-use calculation are sourced from these where available. Examples of fixed operating costs are platform costs and operator overheads. Fixed operating costs are based on operator and/or third-party duty holder budgets.
Capital expenditure
Field development is capital intensive and future capital expenditure has a significant bearing on the value of an oil and gas development asset. In addition, capital expenditure may be required for producing fields to increase production and/or extend the life of the field. Cost assumptions are based on operator and/or service contractor cost estimates or specific contracts where available.
Critical accounting judgements and key sources of estimation uncertainty (continued)
Discount rates
Discount rates reflect the current market assessment of the risks specific to the oil and gas sector and are based on the weighted average cost of capital for the Group. Where appropriate, the rates are adjusted to reflect the market assessment of any risk specific to the field for which future estimated cash flows have not been adjusted. The Group has applied a risk adjusted discount rate of 10% for the current year (2018: 10%).
Sensitivity to changes in assumptions
A potential change in any of the above assumptions may cause the estimated recoverable value to be lower than the carrying value, resulting in an impairment loss. The assumptions which would have the greatest impact on the recoverable amounts of the fields are production volumes (linked to recoverable reserves) and commodity prices.
Farm-in date
The assumed farm-in date of a disposal transaction can vary the carrying value of assets and in turn, effect the profit or loss on disposal amount that is recognised in the statement of comprehensive income. Where appropriate the Group has applied judgement to the cut-off date of the farm-down to CER to ensure that the numbers represented the fundamentals of the transaction.
Investments (Company)
If circumstances indicate that impairment may exist, investments in and the value of any loans to 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 or loan amount due, an impairment charge is recorded in the Company. Evaluation of impairments on such investments involves significant management judgement and may differ from actual results.
Decommissioning
At 31 December 2019, the Group has obligations in respect of decommissioning a suspended well on the Vulcan Satellites D&P asset, together with the offshore Thames Pipeline and the acquired Thames Reception Facility at Bacton.
The extent to which a provision is recognised depends on the legal requirements at the date of decommissioning, regulatory activity required to ensure such infrastructure meets safety and environmental requirements, the estimated costs and timing of the work and the discount rate applied.
A full decommissioning estimate for the Vulcan Satellites asset remains uncertain until all development infrastructure has been installed and production volumes and time to abandonment has been considered. Prior to full development infrastructure and commissioning, the Group will utilise technical reports, and advice from the UK Oil & Gas Authority, to estimate costs of abandonment.
On acquisition of the Thames Pipeline, the Group assumed the decommissioning liability for the pipeline, which is based upon a regulatory framework determined by the OGA. A discounted cost estimate provision has been made in the financial statements as at 31 December 2019 and this provision will continue to be reviewed on an annual basis, given the regulatory framework is subject to constant change and is inherently uncertain over future years.
On acquisition of the Thames Reception Facility at Bacton, the Group assumed the initial decommissioning liability for the asset which was cash collateralised, which is based upon a contractual obligation with Perenco. A provision has been made in the financial statements as at 31 December 2019. This provision will be reviewed on an annual basis and reassessed once the development has been completed.
The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised, if the revision only affects that period, or, in the period of revision and future periods, if the revision affects both current and future periods.
Fair value of share options and warrants
The fair value of options and warrants is calculated using appropriate estimates of expected volatility, risk free rates of return, expected life of the options/warrants, the dividend growth rate, the number of options expected to vest and the impact of any attached conditions of exercise. See above for further details of these assumptions.
2 Segmental information
The Group complies with IFRS 8, Operating Segments, which requires operating segments to be identified based upon internal reports about components of the Group that are regularly reviewed by the directors to allocate resources to the segments and to assess their performance. In the opinion of the directors, the operations of the Group comprise one class of business, being the exploration and development of oil and gas opportunities in the UK Southern North Sea.
3 Operating Costs
The Groups operating profit (2018: loss) is stated after charging/(crediting) the following:
2019
2018
£000
£000
Fees payable to the Company's auditor:
- for the audit of the Group's financial statements
80
58
Of which:
for the audit of the Company's financial statements1
50
58
For the audit of the Subsidiaries financial statements1
30
-
Depreciation, depletion and amortisation
244
9
Project, pre-licence and exploration expenses
Impairment of oil and gas properties
4,027
-
922
184
Profit on farm-down of assets
(24,340)
-
Personnel costs - direct expenses
2,060
847
Personnel costs - share-based payments
675
378
Net loss on settlement of liabilities
-
106
Foreign exchange (gain)/loss
(238)
334
1 2018 audit fees were paid and borne by the parent company and noted in each subsidiaries accounts.
4 Personnel costs and directors' remuneration
During the year, the average number of personnel, including contract personnel, for both the Company and Group was:
2019
2018
Number
Number
Management / technical / operations
26
18
of which: Directors
6
5
Personnel costs Group and Company
£000
£000
Wages, salaries, fees and other direct costs
2,440
1,882
Social security costs
344
232
Pension costs
3
1
Share-based payments
675
378
________
________
3,462
2,493
________
________
Note that project contract personnel, capitalised directly to project cost centres, are excluded from the above personnel cost figures.
Key management personnel are deemed to be Directors, Chief Financial Officer, General Counsel and the Head of Corporate Finance.
On 11 December 2019 the Chief Financial Officer was appointed a Director; until that date, neither the Chief Financial Officer nor the Head of Corporate Finance were Directors.
4 Personnel costs and directors' remuneration (continued)
Directors' remuneration
Salary/Fees
Salary/Fees Sacrificed
Bonus
Share-based payment
2019
Total
Salary
Share-based payment
2018
Total
£000
£000
£000
£000
£000
£000
£000
£000
Fiona MacAulay
125
-
-
-
125
17
-
17
Esa Ikaheimonen3
-
34
-
-
34
-
-
-
Neil Hawkings4
25
4
-
-
29
-
-
-
Andrew Hockey
211
57
266
94
628
179
118
297
Rupert Newall5
13
-
-
-
13
-
-
-
Mark Hughes
144
39
181
31
395
90
52
142
Mark Routh6
-
-
-
159
159
141
52
193
Martin Ruscoe1
-
13
-
-
13
15
15
30
Andrew Hay
-
-
-
-
11
8
19
Charles Hendry2
5
12
-
-
17
15
15
30
_______
_______
_____
_______
_______
_____
_______
________
523
159
447
284
1,413
468
260
728
_______
_______
_____
_______
_______
_____
_______
________
Other key management personnel
691
80
363
12
1,146
143
79
222
Total key management personnel
1,214
239
810
296
2,559
611
339
950
1 Martin Ruscoe resigned on 23 April 2019;
2 Charles Hendry resigned on 23 April 2019;
3 Esa Ikaheimonen was appointed on 14 March 2019;
4 Neil Hawkings was appointed on 24 May 2019;
5 Rupert Newall was appointed on 11 December 2019, prior to that his remuneration is captured in 'other key management personnel'.
6 Mark Routh resigned on 31 December 2018. The share-based payment represents the exercise of his options granted prior to his resignation.
The salary amounts are those cash amounts paid to directors and key management personnel during the year. The share-based payment amounts represent the fair value of options issued and/or expensed in the year, for LTIP's CSOP's and those in lieu of cash salary and/or director fees paid. In addition to the above, an amount of £1,188 (2018: £470) was paid in employer pension contributions for Mark Hughes.
Social security costs for the year for key management personnel were £240k (2018 - £134k).
For the current directors at 31 December 2019, the service agreements provide that the full contractual amount will be paid in cash. In addition, there is the option to voluntary elect to sacrifice up to 25% cash and receive the equivalent amount in share options. The salary sacrifice option was removed for all Directors with effect from October 2019, except for Esa Ikaheimonen who has sacrificed all his fees for share options since joining the Company.
The average proportions of monthly salaries paid in cash and share options in 2019 for all directors is as follows:
Cash
Shares
Fiona MacAulay
100%
0%
Andrew Hockey
79%
21%
Mark Hughes
79%
21%
Rupert Newall1
100%
0%
Esa Ikaheimonen
0%
100%
Neil Hawkings
81%
19%
1. Rupert Newall sacrificed an average of 23% of his 2019 salary before being appointed as a Director on 11 December 2019.
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.
4 Personnel costs and directors' remuneration (continued)
Amounts of salary and/or fees outstanding at 31 December 2019 to which these terms relate totalled £34k (31 December 2018 - £76k) for directors and key management personnel and £17k (2018 - £11k) for other personnel. These share options are yet to be issued.
Directors' interests in options on 1p ordinary shares of the Company at 31 December 2019 were as follows:
Granted
Type
Total
31 Dec 2018
Awarded in 2019
(Exercised) in 2019
Total
31 Dec 2019
Exercise price
Expiry date
Andrew Hockey
1 Sep 2017
Salary Sacrifice
110,800
-
(110,800)
-
1p
31 Aug 2022
1 Mar 2018
Salary Sacrifice
102,537
-
(102,537)
-
1p
28 Feb 2023
1 Mar 2018
LTIP
1,600,000
-
-
1,600,000
20p
28 Feb 2028
1 Sep 2018
Salary Sacrifice
128,700
-
(128,700)
-
1p
31 Aug 2023
28 Feb 2019
Salary Sacrifice
-
146,730
(146,730)
-
1p
28 Feb 2024
1 May 2019
CSOP
-
1,600,000
-
1,600,000
12.75p
30 Apr 2029
31 Aug 2019
Salary Sacrifice
-
267,740
-
267,740
1p
31 Aug 2024
1,942,037
2,014,470
(488,767)
3,467,740
Mark Hughes
27 Jul 2018
LTIP
-
1,000,000
1,000,000
35p
27 July 2028
1 Sep 2018
Salary Sacrifice
-
62,417
(62,417)
-
1p
31 Aug 2023
28 Feb 2019
Salary Sacrifice
-
99,776
(99,776)
-
1p
28 Feb 2024
1 May 2019
CSOP
-
1,000,000
-
1,000,000
12.75p
30 Apr 2029
31 Aug 2019
Salary Sacrifice
-
186,063
-
183,063
1p
31 Aug 2024
-
2,348,256
(162,193)
2,183,063
Rupert Newall
28 Feb 2019
Salary Sacrifice
-
94,911
(94,911)
-
1p
28 Feb 2024
1 May 2019
CSOP
-
1,200,000
-
1,200,000
12.75p
30 Apr 2029
31 Aug 2019
Salary Sacrifice
-
240,966
-
240,966
1p
31 Aug 2024
-
1,535,877
(94,911)
1,440,966
Esa Ikaheimonen
1 May 2019
LTIP
-
600,000
-
600,000
12.75p
30 Apr 2029
31 Aug 2019
Salary Sacrifice
-
136,606
-
136,606
1p
31 Aug 2024
-
736,606
-
736,606
Fiona MacAulay
1 May 2019
LTIP
-
1,000,000
-
1,000,000
12.75p
30 Apr 2029
-
1,000,000
-
1,000,000
Neil Hawkings
24 May 2019
LTIP
-
600,000
-
600,000
13.5p
28 Feb 2024
31 Aug 2019
Salary Sacrifice
-
18,061
-
18,061
1p
31 Aug 2024
-
618,061
-
618,061
Martin Ruscoe1
1 Sep 2017
Salary Sacrifice
44,699
-
(44,699)
-
1p
31 Aug 2022
1 Mar 2018
Salary Sacrifice
34,179
-
(34,179)
-
1p
28 Feb 2023
1 Sep 2018
Salary Sacrifice
30,888
-
(30,888)
-
1p
31 Aug 2023
28 Feb 2019
Salary Sacrifice
46,954
(46,954)
-
1p
28 Feb 2024
31 Aug 2019
Salary Sacrifice
72,481
(72,481)
-
1p
31 Aug 2024
109,766
119,435
(229,201)
-
Charles Hendry
1 Sep 2017
Salary Sacrifice
39,745
-
-
39,745
1p
31 Aug 2022
1 Mar 2018
Salary Sacrifice
34,179
-
-
34,179
1p
28 Feb 2023
1 Sep 2018
Salary Sacrifice
30,888
-
-
30,888
1p
31 Aug 2023
28 Feb 2019
Salary Sacrifice
-
35,215
-
35,215
1p
28 Feb 2024
31 Aug 2019
Salary Sacrifice
-
67,708
-
67,708
1p
31 Aug 2024
104,812
102,923
-
207,735
Mark Routh
19 Nov 2014
Salary Sacrifice
218,672
-
(218,672)
-
1p
31 Aug 2019
1 Mar 2015
Salary Sacrifice
638,361
-
(638,361)
-
1p
28 Feb 2020
31 Aug 2015
Salary Sacrifice
611,601
-
(611,601)
-
1p
31 Aug 2020
1 Mar 2016
Salary Sacrifice
888,494
-
(888,494)
-
1p
28 Feb 2021
31 Aug 2016
Salary Sacrifice
365,550
-
(365,550)
-
1p
31 Aug 2021
1 Mar 2017
Salary Sacrifice
298,628
-
(298,628)
-
1p
28 Feb 2022
31 Aug 2017
Salary Sacrifice
147,507
-
(147,507)
-
1p
31 Aug 2022
28 Feb 2018
Salary Sacrifice
112,791
-
(112,791)
-
1p
28 Feb 2023
31 Aug 2018
Salary Sacrifice
110,553
-
(110,553)
-
1p
31 Aug 2023
28 Feb 2019
Salary Sacrifice
-
42,876
(42,876)
-
1p
28 Feb 2024
3,392,157
42,876
(3,435,033)
-
1 Options granted to South Riding Consultancy Limited, a company in which Martin Ruscoe is a majority shareholder and a director.
5 Finance expense
2019
2018
£000
£000
Interest on loans
1,928
1,493
Interest on deferred payment creditors
140
373
Amortisation of loan finance charges
4,357
617
Current year loan finance charges
566
49
Current year finance charges on deferred payment creditors
54
-
Unwinding of discount on convertible loan
258
-
Unwinding of deferred consideration provisions
636
592
________
________
7,939
3,124
________
_________
6 Profit on Farm-down of assets
2019
2018
£000
£000
Proceeds
40,000
-
Disposals:
Intangible Assets
(150)
-
Property, plant & equipment
(15,510)
-
________
________
Profit on Farm-down of assets
24,340
-
________
_________
7 Gain on loan modification
In October 2019, the Company completed a restructuring of its remaining debt with London Oil and Gas Limited. The convertible debt and interest (£11.6 million) pertaining to the £10.0 million facility dated 21 February 2018 was restructured into a new convertible loan which allows for the conversion of the loan into 60,872,631 shares at a strike price of 19 pence at maturity. The new loan has an extended maturity date of 23 September 2024, is unsecured, subordinated to other debt the Group holds and incurs interest at the rate of zero percent. The Company calculated the gain reflecting the improvement in terms between the 2018 and 2019 loan under the provisions of IFRS 9 to be £5.0 million, using an effective interest rate of 11.5%, and has recognised this gain in the Statement of Comprehensive Income.
8 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:
2019
2018
£000
£000
Profit / (Loss) for the year
15,029
(5,644)
Income tax expense
-
-
_________
_________
Profit / (Loss) before income taxes
15,029
(5,644)
Expected tax expense/(credit) based on the standard rate of United Kingdom corporation tax at the domestic rate of 40% (2018: 40%)
6,012
(2,258)
Difference in tax rates
1,892
826
Expenses / (income) not deductible for tax purposes
1,552
137
Income not taxable/allowable
(4,199)
(2,617)
Disposal
(22,722)
-
Unrecognised taxable losses carried forward
17,465
3,912
_________
_________
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 £124.70 million (2018:£80.72 million). There are also accelerated capital allowances of £33.4m (2018:£32.6m)
The Group has not recognised a deferred tax asset at 31 December 2019 on the basis that the Group would expect the point of recognition to be when the Group has some level of production history showing that the Group is making profits in line with the underlying economic model which would support the recognition."
9 Profit/(loss) per share
2019
2018
£000
£000
Profit /(loss) for the year attributable to shareholders (Numerator)
15,029
(5,644)
___________
___________
Weighted average number of ordinary shares: basic (Denominator)
297,560,956
123,581,926
Add potentially dilutive shares:
LOG convertible share
-
205,265,850
Convertible loan notes
60,872,631
-
Salary/Fee sacrifice options
3,511,871
6,628,423
LTIP/CSOP
10,900,000
3,600,000
Warrants
33,277,310
33,777,310
diluted
406,122,768
372,853,509
___________
___________
Profit/(loss) per share in pence: basic
5.1p
(4.6p)
diluted
3.7p
(4.6p)
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, convertible loan notes and warrants into ordinary shares.
As the result for 2018 was a loss, the options and warrants outstanding would be anti-dilutive. Therefore, the dilutive loss per share is considered as the same as the basic loss per share.
There were no anti-dilutive instruments that were not included in the calculations that would have a material impact on the basic earnings per share.
There are no significant ordinary share issues post the balance sheet date, save for those disclosed in note 26 that would materially affect this calculation.
10 Intangible assets
Group
Exploration & evaluation assets
Company & IT software assets
Total
Exploration & evaluation assets
Company & IT software assets
Total
2019
2019
2019
2018
2018
2018
£000
£000
£000
£000
£000
£000
At cost
At beginning of the year
24,719
7
24,726
22,402
3
22,405
Additions
10,897
113
11,010
2,351
4
2,355
Disposals
(150)
-
(150)
(34)
-
(34)
_________
_________
________
________
________
________
At end of the year
35,466
120
35,586
24,719
7
24,726
_________
_________
________
________
________
________
Impairments and write-downs
At beginning of the year
(22,367)
(4)
(22,371)
(22,217)
(2)
(22,219)
Amortisation
-
(36)
(36)
-
(2)
(2)
Impairment
-
-
-
(184)
-
(184)
Disposals
-
-
-
34
-
34
________
________
________
________
________
________
At end of the year
(22,367)
(40)
(22,407)
(22,367)
(4)
(22,371)
_________
_________
________
________
________
________
Net book value
At 31 December 2019
13,099
80
13,179
At 1 January 2019
2,352
3
2,355
At 1 January 2018
185
1
186
Exploration and evaluation assets at 31 December 2019 comprise the Group's interest in the Harvey and Abbeydale appraisal prospects and the Goddard pre-development prospect.
An impairment charge of £184k was recognised during 2018 reflecting those post 2016 drilling expenses and licence administration costs incurred on the previously impaired Skipper asset, Licence P1609 which was relinquished during 2019.
11 Property, plant and equipment
Group
D&P assets
Phase 1
D&P assets Phase 2
Pipeline assets
Right of use assets
Company & admin assets
Total
D&P assets Phase 1
D&P assets Phase 2
Pipeline assets
Company & admin assets
Total
2019
2019
2019
2019
2019
2019
2018
2018
2018
2018
2018
£000
£000
£000
£000
£000
£000
£000
£000
£000
£000
£000
At cost
At beginning of the year
22,444
8,136
10,947
-
74
41,601
11,873
9,443
-
34
21,350
On transition
-
-
-
703
-
703
-
-
-
-
-
Additions
3,521
869
668
351
184
5,593
10,963
(1,287)
10,447
40
20,163
Change in estimate of decommissioning asset (note 17)
-
(1,198)
-
-
-
(1,198)
Decommissioning asset (note 17)
-
-
10,000
-
-
10,000
Disposals
(12,118)
(3,745)
(10,353)
-
-
(26,216)
-
-
-
-
-
Reclassified from current assets
-
-
-
-
-
-
-
200
-
-
200
Thames Pipeline decommissioning security
-
-
(250)
-
-
(250)
-
-
500
-
500
Blythe asset acquisition (Note 12)
-
-
-
-
-
-
(392)
-
-
-
(392)
Vulcan Satellites asset acquisition (Note 12)
-
-
-
-
-
-
-
(220)
-
-
(220)
______
______
______
______
______
_____
______
______
______
______
_____
At end of the year
13,847
4,062
11,012
1,054
258
30,233
22,464
8,136
10,947
74
41,601
______
______
______
______
______
_____
______
______
______
______
_____
Accumulated depreciation
At beginning of the year
-
-
-
-
(33)
(33)
-
-
-
(14)
(14)
DD&A
-
-
-
(145)
(63)
(208)
-
-
-
(19)
(19)
______
______
______
______
______
_____
______
______
______
______
_____
At end of the year
-
-
-
(145)
(96)
(241)
-
-
-
(33)
(33)
______
______
______
______
______
_____
______
______
______
_____
_____
Net book value
At 31 December 2019
13,847
4,062
11,012
909
162
29,992
At 1 January 2019
22,444
8,136
10,947
-
41
41,568
At 1 January 2018
11,873
9,443
-
-
20
21,336
Phase 1 development and production assets received Final Investment Decision in October 2019 and are awaiting approval of the final Field Development Plan from the OGA, expected by 30 April 2020
Phase 2 development and production assets are currently scheduled for Final Investment Decision in Q3 2021.
Amounts paid as decommissioning security guarantees in respect of both the Elland P039 Licence suspended well, £200k and the Initial Thames Pipeline Decommissioning Security were classified as fixed assets at 31 December 2018. In 2019, a further £2.0 million was paid upon acquisition as security against the Thames Reception Facility Decommissioning Security.
Following the farm-down to CER, the above amounts we reduced by 50% resulting in £100k held against the Elland P039 licence, £250k against the Thames Pipeline, and £1.0 million against the Thames Reception Facility. At the year end, £1.25 million for the Thames Pipeline and Thames Reception Facility classified as Restricted cash on the balance sheet.
12 Restructuring and Farm-out
Debt Restructuring of Loans and Convertible Loans
At the beginning of the year, the following loans were outstanding.
Loan Facility
Entity
Effective Date
Principal
£000
Accumulated interest
£000
31 December 2018 £000
£2.75 million facility
IOG North Sea Limited
7 December 2015
2,750
654
3,404
£0.80 million facility
IOG North Sea Limited
11 December 2015
800
192
992
£10.00 million facility
IOG North Sea Limited
5 February 2016
10,000
1,671
11,671
£10.00 million facility
IOG plc
21 February 2018
10,000
672
10,672
£15.00 million facility
IOG plc
13 September 2018
7,150
142
7,292
Capitalised fees
(4,213)
29,818
In April 2019 the Group restructured its debt with the Company's main creditor London Oil and Gas Limited ("LOG") with a Debt Repayment and Discharge Agreement ('DRDA') to defer each 2019 maturity by 12 months.
LOG also converted £1.6 million of the outstanding balance of the February 2016 loan in to 20,497,204 ordinary shares.
On 28 October 2019, at the completion of the Farm-out, £17.1 million of cash proceeds were used to repay in full all non-convertible loans and £79,000 of the February 2016 convertible loan, with the balance of the latter loan being converted into 135,464,155 new Ordinary Shares.
The 2018 secured convertible loan which accrued interest at 9% above LIBOR was restructured into a £11.6 million Convertible Loan Note Instrument. This instrument is unsecured, subordinated to other Group debt, accrues no interest, has a maturity date of 23 September 2024 and is convertible at 19p into 60,872,361 Ordinary Shares.
The table below sets out the opening, movement and closing position of the LOG loans in 2019.
Loan Facility
B/fwd Balance
2019 Drawdown
2019 Interest
Cash Settlement
Converted to ordinary shares
Gain on loan modification3
Other
Carrying Value at 31 December 2019
£000
£000
£000
£000
£000
£000
£000
£000
£2.75 million facility
3,404
-
252
(3,656)
-
-
-
-
£0.80 million facility
992
-
82
(1,074)
-
-
-
-
£10.00 million facility
11,671
-
885
(79)
(12,477)
-
-
-
£10.00 million facility
10,672
-
894
-
-
(5,005)
2581
6,819
£15.00 million facility
7,292
3,925
1,113
(12,330)
-
-
-
-
Capitalised Fees
(4,213)
-
-
-
-
-
4,2132
-
29,818
3,925
3,226
(17,139)
(12,477)
(5,005)
4,471
6,819
1 2019 unwinding discount of the convertible loan
2 Fees expensed to Statement of Comprehensive Income in 2019
3 See note 7
Share Placing, Open Offer and Subscription
In April 2019, the Group raised gross proceeds of £18.9 million through the issue of ordinary shares at 10 pence. The three components of shares were issued:
Ordinary Shares
£000
Placement
165,795,050
16,580
Subscription
3,250,000
325
Open Offer
20,141,129
2,014
189,186,179
18,919
Farm-out and Phase 1 FID
On 28 October 2019 the Company announced that it completed the farm-out of 50 per cent of its SNS Assets (excluding Harvey) to CalEnergy Resources Limited ("CER"). IOG and CER took Phase 1 FID and submitted confirmation of full funding to the OGA in support of the Phase 1 FDP approval.
CER paid the initial cash consideration of £40m to IOG under the terms of the farm-out. CER will also pay for up to £125m of IOG's development costs, usable against 80 per cent of IOG's 50 per cent share of Core Project costs, up to caps of £60m for Phase 1 and £65m for Phase 2. IOG will pay CER a royalty of 20.2 per cent of its net revenues from the Phase 1 fields only (i.e. 10.1 per cent of gross Phase 1 revenues, net of National Transmission System entry charges and applicable marketing fees), up to a cap of £91m over field life.
In addition, IOG will receive an effective royalty interest equating to £0.50/MCF on CER's 50 per cent share of production from certain sections of the Goddard Field after 70 BCF gross has been produced from the field, up to a maximum royalty of £9.75m. With its experienced SNS development team, IOG has retained Operatorship of the Core Project.
CER also had the option to acquire 50 per cent of the Harvey licences within three months of completion of the Harvey appraisal well 48/24b-6. Subsequent to the year end, the Company announced that this option expired on 27 February 2020.
Upon completion of the Farm-out, the company settled all but one of its outstanding LOG loans including interest with £17.1 million of the £40 million proceeds received.
13 Investments
Shares
Loans
in Group
to Group
Company
companies
companies
Total
£000
£000
£000
At cost
At 1 January 2018
17,416
12,280
29,696
Additions
(219)
17,246
17,027
_________
_________
_________
At 31 December 2018
17,197
29,526
46,723
Disposals
(1,711)
(816)
(4,757)
_________
_________
_________
At 31 December 2019
15,486
28,710
41,966
Net book value
At 31 December 20191
15,486
28,710
41,966
At 1 January 2019
17,197
29,526
46,723
At 1 January 2018
17,416
12,280
29,696
1 There were no impairments in the 2019 period.
The Company has undertaken not to seek repayment of loans from other Group subsidiary companies until each subsidiary has sufficient funds to make such payments, however they are technically due on demand. These loans are non-interest bearing.
The Company's subsidiaries, all registered at 60 Gracechurch Street, London EC3V 0HR, are as follows:
Country of
Area of
Directly held
incorporation
operation
%
IOG Infrastructure Limited
United Kingdom
United Kingdom
100
IOG North Sea Limited
United Kingdom
United Kingdom
100
IOG UK Ltd
United Kingdom
United Kingdom
100
Avalonia Energy Limited (dormant)
United Kingdom
United Kingdom
100
Avalonia Goddard Limited (dormant)
United Kingdom
United Kingdom
100
Avalonia Abbeydale Limited (dormant)
United Kingdom
United Kingdom
100
IOG Infrastructure Limited completed the Thames Pipeline acquisition on 16 April 2018 and became an active subsidiary at that time. All three active subsidiaries are now engaged in the business of oil and gas appraisal, development and/or operations in the UK North Sea.
The three dormant companies were incorporated in 2018 and have been made available to support any potential Group restructure following refinancing of the Group.
The financial reporting periods for each subsidiary entity are consistent with the Company and end on 31 December.
14 Interests in production licences
At 31 December 2019, all ten Group UK Offshore Production Licences, apart from Harvey and Redwell (100%), were owned 50% by either IOG North Sea Limited or IOG UK Ltd. The Thames Pipeline P370 and Bacton Gas Terminal assets are owned 50% by IOG Infrastructure Limited. The Skipper Licence 100% interest was relinquished 11 February 2019.
15 Other receivables and prepayments
2019
2018
£000
£000
Group
VAT recoverable
759
311
Prepayments
257
361
Operator advance accounts
2,579
-
Debtors
1,497
-
_________
_________
5,092
672
_________
_________
Company
VAT recoverable
759
311
Prepayments
257
361
Debtors
1,497
-
_________
_________
2,513
672
_________
_________
The 2019 prepayments relate to rent and general administration. Included in 2019 Prepayments (both Group and Company) were financing costs of £nil (2018: £291k) incurred at 31 December 2019, these were expensed to the Statement of Comprehensive Income during the period.
The debtors balance of £1.4 million represents an amount paid to ABG Sundal Collier Holding ASA to buy back Norwegian bonds that it held. At the year end these bonds had not been transferred in title to the Company and remained as a receivable.
The Company has considered the carrying value of Debtors in the context of IFRS 9 and has assessed the debtors ability to repay the amount due. In assessing the expected credit loss ('ECL') of the receivables, the Company considered future cash flows from the entities and concluded there is no material ECL provision required.
16 Current liabilities
2019
2018
£000
£000
Group
Loans
-
6,934
Trade payables
3,856
5,961
Lease liabilities
939
-
Accruals
1,588
3,467
Contingent consideration payable (see Note 15)
848
1,709
_________
_________
7,231
18,071
_________
_________
Company
Trade payables
3,856
5,961
Lease liabilities
939
-
Accruals
301
401
Contingent consideration payable (see Note 15)
848
1,709
_________
_________
5,944
8,071
_________
_________
17 Non-current liabilities
2019
2018
£000
£000
Group
Long-term loans
89,243
22,884
Contingent consideration payable
2,267
4,478
Decommissioning provision
7,237
5,640
_________
_________
98,747
33,002
_________
_________
Company
Long-term loans
89,243
14,054
Contingent consideration payable
644
1,259
_________
_________
89,887
15,313
_________
_________
Long-term loans:
Norwegian bonds issued in September 2019 represent £82.4 million of the long-term loans balance. See note 20 for further details
The amounts drawn on LOG loans at 31 December 2019 were as follows:
Loan Facility
Entity
Effective Date
Maturity Date
Principal
Interest
£11.6 million convertible loan, 5 year facility
IOG plc
28 September 2019
23 September 2024
£11.6 million
Nil
See note 12 for information relating to the outstanding LOG loan.
17 Non-current liabilities (continued)
Contingent consideration payable:
The Group is required under the terms of the 2016 acquisition of the additional 50% of Blythe, the 2016 acquisition of Vulcan Satellites, to make further amounts payable on both the FDP approval (Vulcans), being a current liability expected by 30 April 2020, and first gas (Blythe and Vulcans) being non-current liabilities, see below.
As disclosed in the 2018 financial statements, these milestone events triggering deferred consideration payments are now considered to be more certain than not and a non-current amount of £2.3 million is recognised. These amounts have been provided for and the payments discounted to the point where the Board expect the milestones to be achieved based on the current development programme. Timings for these non-current payments, pursuant to first gas, have been adjusted during 2019 and are now anticipated to be Q4 for Blythe.
The movements in the year are as follows:
2019
2018
£000
£000
At 1 January
6,187
6,013
Disposal to CER
(3,092)
-
Prospective adjustment for change in payment dates
(493)
(612)
Foreign exchange
30
194
Unwinding of discount
482
592
At 31 December
3,114
6,187
Given the timing of the expected payments, the total balance is split between current and non-current as below:
2019
2018
£000
£000
Current contingent consideration payable (FDP approval)
847
1,709
Non-Current contingent consideration payable (first gas)
2,267
4,478
3,114
6,187
17 Non-current liabilities (continued)
Decommissioning provision:
2019
2018
£000
£000
at 1 January
5,640
3,598
Revision in estimates
(1,162)
Additions
10,000
2,042
Disposals
(7,239)
-
At 31 December
7,239
5,640
The Group has regulatory and financial obligations in respect of decommissioning a suspended well on the Elland Licence P039 - Gross £2.4 million (2018: £3.6 million), net to the Company £1.2m and decommissioning the Thames Pipeline - £2.0 million (2018: £2.0 million). During the year through the acquisition of the Thames Reception Facility at Bacton the company also took on further decommissioning liabilities totalling £5.0 million
A full decommissioning estimate for the Elland suspended well remains uncertain until an appropriate drilling programme has been reviewed and considered for the Elland development, which may include the abandonment of that particular well. The timing and thus payment of this decommissioning program remains inherently uncertain, but the company reassessed the costs in 2019 and revised the cost down to £2.4 million (gross) of which it will be liable for 50% share. As per Note 1, the current estimate of £2.4 million is based upon a recent technical valuation and by its nature is subject to market conditions at the time of contracting a rig to carry out the work.
The £1.0 million provision for the Thames Pipeline decommissioning obligation has been calculated on a discounted cash flow basis, whereby the present value of the regulatory marine surveys has been inflated at 2% and then discounted at the risk-free discount rate of 1.8%. It has been estimated that the Thames Pipeline has a useful life over the next 25 years; however, the judgements made on this and other variables, currently provided by the OGA, are inherently uncertain.
The initial £10.0 million provision for the Thames Reception Facility decommissioning obligation has been recognised on the basis of the SPA, then reduced to reflect the Farm-out to CER (£5.0 million net). Resulting in a net £5.0 million liability. An initial payment of £2.0 million was made by the Company as security for the liability on completion of the Thames Reception Facility transaction which was then reduced for CER's 50% share to £1m. The Group is due to pay a further eight quarterly payments of £0.5 million as security six months after the start of gas production. The Group has chosen to recognise the full amount of the liability represented in the SPA as there is no material difference of discounting the payments back to the balance sheet date.
18 Share capital
Share
Share
capital
premium
Total
Number
£000
£000
£000
Authorised, allotted, issued and fully paid
At 1 January 2018
- Ordinary shares of 1p each
120,209,629
1,203
22,337
23,540
Equity issued
6,658,527
66
-
66
_________
_________
_________
_________
At 31 December 2018
- Ordinary shares of 1p each
126,868,156
1,269
22,337
23,606
Equity issued:
- April 2019, Ordinary shares of 1p - Placing, open offer, subscription and LOG conversion
209,670,834
2,097
17,173
19,270
- October 2019, Ordinary shares of 1p - London Oil & Gas Ltd debt conversion
135,464,155
1,355
9,482
10,837
- October 2019, Ordinary shares of 1p - Edimis Energy Limited settlement1
3,147,139
31
431
462
Equity issued2
5,022,961
50
-
50
_________
_________
_________
_________
At 31 December 2019
- Ordinary shares of 1p each
480,173,245
4,802
49,423
54,225
_________
_________
_________
_________
1 For further details, see related party transactions note 27
2 During 2019, the Company issued 5,022,961 (2018: 6,658,527) ordinary shares at a subscription price of 1p from the exercise of management and other personnel share options.
Share options and warrants
During the current and prior year, the Company granted share options under its share option plans as follows:
Number
Price
Date of Grant
Expiry
1 January 2018
12,323,666
1p
Salary/fee sacrifice options
483,166
1p
1 Mar 2018
28 Feb 2023
LTIP options
2,600,000
20p
1 Mar 2018
28 Feb 2028
LTIP options
1,000,000
35p
27 Jul 2018
26 Jul 2028
Salary/fee sacrifice options
534,420
1p
1 Sep 2018
31 Aug 2023
Options exercised
(6,658,527)
31 December 2018
10,282,725
9.11p
Salary/fee sacrifice options
628,496
1p
28 Feb 2019
28 Feb 2024
LTIP options
600,000
13.25p
24 May 2019
23 May 2029
LTIP options
1,600,000
12.75p
1 May 2019
30 Apr 2029
CSOP options
5,100,000
12.75p
1 May 2019
30 Apr 2029
Salary/fee sacrifice options
1,223,611
1p
31 Aug 2019
31 Aug 2024
Options exercised
(5,022,961)
31 December 2019
14,111,871
13.03p
For details of LTIP and CSOP valuations see Note 4.
18 Share capital (continued)
Of the remaining personnel options, 12,323,666, outstanding at 1 January 2018, 6,652,747 were exercised during 2018. Of those personnel options granted during 2018, 5,810 were exercised during 2018. Total personnel options exercised in 2018 is thus 6,658,527.
Of the remaining staff options, 10,282,725, outstanding at 31 December 2018, 4,519,233 were exercised during 2019. Of those staff options granted during 2019, 503,728 were exercised during 2019. Total personnel options exercised in 2019 is thus 5,022,961.
The fair value of these options exercised was transferred from the Share-based Payment Reserve to Accumulated Loss.
All salary/fee sacrifice options outstanding at 31 December 2019 were issued at an exercise price of 1p per share and carry no additional performance conditions. These shares were issued at a volume calculated by taking the amount owing and dividing by the volume weighted average price for period to which the salary sacrifice pertains.
CSOP Valuation
The valuation model for CSOP options is a Black Scholes option pricing model which calculates the fair value of a European style option. The valuation model assumes:
- Share price of 12.75p
- Exercise price of 12.75
- Option life of 10 years
- The risk-free rate and volatility of the underlying are known and constant (0.74%, 3 year UK government bond at grant date)
- Returns on the underlying option are normally distributed.
LTIP Valuation
The LTIP valuation is based on a Log-normal Monte-Carlo stochastic model.
The valuation incorporates a forecast employee turnover to establish the number of options expected to vest, the charge requires recalculation each year to take account of any revised estimates regarding employee turnover and any new grants of share options.
- Efficient markets (i.e., market movements cannot be predicted)
- No commissions
- 10,000 iteration
- The risk-free rate and volatility of the underlying are known and constant (0.62%, 3 year UK government bond at grant date)
- Share price volatility is 84.19%
All LTIP and CSOP options outstanding at 31 December 2019 were issued to option holders with, other than the target price, several performance criteria including the delivery, measurement, control and management of an appropriate HSE statement and policy together with a Group-wide HSE focussed culture.
The remaining average contractual life of the 14,111,871 options outstanding at 31 December 2019 (2018 - 10,282,725) was 7.7 years at that date (2018: 4.9 years) of which 1,062,893 were exercisable at 31 December 2019 (2018: 6,682,725).
The weighted average exercise price of the options remaining was 13.03p at 31 December 2019 (2018 - 9.11p).
A further 403,104 options are due to be issued in 2020 relating to 2019 salary/fee sacrifice; however, these have not been issued as at the date of this report.
The Company calculates the value of personnel salary/fee sacrificed share-based compensation as the actual value of the sacrificed amount. This is deemed to be the fair value of such awards. The fair value of sacrificed salary/fee share options granted in 2019 is calculated as £299k (2018: £236k) and this has been charged to the Statement of Comprehensive Income. The exercise price of such awards was determined as 1p (2018: 1p).
The Company calculates the fair value of LTIP share-based compensation using a Black-Scholes options pricing model. The fair value of LTIP options granted in 2019 is calculated as £750k (2018: £633k), of which £166k (2018: £141k) has been charged to the Statement of Comprehensive Income, being the amortised amount over the vesting period attributable to the current year. The exercise price of these options has been determined as 20p for those issued on 1 March 2018 and 35p for those issued on 27 July 2018. On 1 May 2019 the Company announced that it had cancelled the future awards under the 2018 LTIP options scheme.
18 Share capital (continued)
Further details for directors are provided in Note 4.
The Company did not grant any warrants in the current year. Warrants for 500,000 lapsed during the year and are shown as follows:
Number
Price
Date of Grant
Expiry
1 January 2018
13,777,310
9.64p
London Oil & Gas Ltd
20,000,000
32.18p
13 Sep 2018
12 Sep 2023
31 December 2018
33,777,310
22.98p
Lapsed warrant
(500,000)
8p
29 Mar 2016
31 Mar 2019
31 December 2019
33,277,310
23.21p
The Company calculates the value of share-based compensation using the Black-Scholes option pricing model to estimate the fair value of warrants at the date of grant.
The fair value of 20,000,000 warrants granted to London Oil & Gas Limited on 13 September 2018 was calculated as £4.19 million, all of which was recognised as an issue cost of the £15 million LOG loan facility, held at amortised cost using the effective interest method. The exercise price of these warrants was determined as 32.18p.
The following assumptions were applied in the LOG warrant award calculation:
Risk free interest rate
1.50%
Dividend yield
nil
Weighted average life expectancy
4 years
Volatility factor
96.45%
A volatility of 96.45% has been applied based upon the Company's share price over the period from the Company's listing on AIM on 30 September 2013 until 13 September 2018.
During the year 500,000 warrants granted to a services contractor lapsed.
The remaining average contractual life of the 33,277,310 warrants outstanding at 31 December 2019 (2018 - 33,777,310) was 2.23 years at that date (2018 - 3.18 years). All such warrants were exercisable at 31 December 2019.
The weighted average exercise price of the warrants remaining was 23.21p at 31 December 2019 (2018 - 22.98p). No further warrants have been issued or exercised as at 25 March 2020.
19 Restricted cash, Cash and cash equivalents
2019
2018
Group
£000
£000
Restricted cash
82,066
-
Cash at bank
16,197
702
Company
Restricted cash
80,816
-
Cash at bank
16,197
702
Restricted cash at 31 December 2019 include £82.0 million (2018: £nil) of restricted deposits in Euro escrow and Debt Service Reserve Accounts following the Norwegian Bond issue and a £1.3 million deposit secured against decommissioning provisions of its infrastructure assets. Of the total restricted cash balances for £32.8 million for the Group and £31.6 million for the Company is available within 1 year.
Cash and cash equivalents comprise cash in hand, deposits and other short-term money market deposit accounts that are readily convertible into known amounts of cash. The fair value of cash and cash equivalents is £16.2 million (2018: £0.7 million).
20 Bonds payable
On 20 September 2019, the Company issued an up to €130 million Norwegian Bond on the Oslo Børs, of which €100 million was drawn down to fund the Phase 1 development program.
2019
2018
£000
£000
Balance at the beginning of the year
-
-
Bonds Issued (€100m)
90,439
-
Transaction fees
(2,793)
Interest charged
2,545
-
Interest Paid
(2,545)
-
Currency revaluation
(5,223)
-
_________
_________
82,423
-
_________
_________
The secured callable bonds were issued on 20 September 2019 by IOG plc at an issue price of par. The bonds have a term of five years and will be repaid in full at maturity. The bonds carry a coupon of 9.5% plus 3 month EURIBOR with a EURIBOR floor of 0% and were issued at par.
The Bond is callable 3 years after issuance with an initial call premium of 50% of the coupon (i.e. repayable at a cost of €104.75 million if 3m EURIBOR is at zero or lower), declining by 10% every six months thereafter.
21 Leases
Lease liabilities
2019
£000
At 1 January
1,054
Interest expenses
121
Lease payments
(236)
At 31 December
939
Lease payments
Group
Company
2019
2018
2019
2018
£000
£000
£000
£000
Within one year
346
-
346
-
In the second to fifth year inclusive
552
-
552
-
Greater than five years
667
-
667
-
Finance leases payments represent the Group and Company's share of office lease rental payments at 10 Arthur Street, London and Endeavour House, 189 Shaftesbury Avenue, London, together with the Crown Estate lease for the rights for the Thames Pipeline to cross the foreshore at Bacton.
22 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
• Restricted cash
• Loans
• Other receivables
• Trade and other payables
• Convertible loan notes
• Bonds
22 Financial instruments (continued)
Liquidity risk
The Group and Company's policy is to ensure that it will always have sufficient cash to allow it to meet its liabilities when they become due. To achieve this aim, it seeks to maintain readily available cash balances supplemented by borrowing facilities sufficient to meet expected requirements for a period of at least twelve to eighteen months for personnel costs, overheads, working capital and as commitments dictate for capital spend.
Rolling cash forecasts, which are essentially the current budgeting and reforecasting process, identifying the liquidity requirements of the Group and Company, are produced frequently. These are reviewed and approved regularly by management and the Board to ensure that sufficient financial resources are made available. The Group's oil and gas exploration and development activities are currently funded through the Company with existing cash balances, Bond proceeds in escrow and joint venture partner carry receipts from CER.
Greater than
Greater
Total
6 months
6 months, less
than
undiscounted
Carrying
or less
than 12 months
12 months
amount
2019 Group
£000
£000
£000
£000
£000
Current financial liabilities
Trade and other payables
3,856
-
-
3,856
3,856
Obligations under finance leases
939
939
939
Deferred consideration
848
-
-
848
848
Accruals
1,588
-
-
1,588
1,588
Loans
-
-
-
-
-
Non-current financial liabilities
Deferred Consideration
-
-
2,267
2,267
2,267
Loans
-
-
11,566
11,566
11,566
Bonds
4,108
4,108
113,179
121,395
121,395
________
_________
________
_________
________
11,339
4,108
127,012
142,549
142,549
________
_________
________
_________
________
2018 Group
Current financial assets
Cash and cash equivalents
702
-
-
702
702
________
_________
________
_________
________
702
-
-
702
702
________
_________
________
_________
________
Current financial liabilities
Trade and other payables
6,017
-
-
6,017
5,961
Deferred consideration
1,750
-
-
1,750
1,709
Accruals
3,467
-
-
3,467
3,467
Loans
3,138
4,213
-
7,351
6,934
Non-current financial liabilities
Deferred Consideration
-
-
5,426
5,426
4,478
Loans
-
-
34,118
34,118
22,884
Decommissioning Provisions
-
-
6,291
6,291
4,331
________
_________
________
_________
________
14,372
4,213
45,835
64,420
49,764
________
_________
________
_________
________
22 Financial instruments (continued)
Greater than
Greater
Total
6 months
6 months, less
than
undiscounted
Carrying
or less
than 12 months
12 months
amount
2019 Company
£000
£000
£000
£000
£000
Current financial liabilities
Trade and other payables
3,856
-
-
3,856
3,856
Deferred Consideration
848
-
-
848
848
Accruals
1,240
-
-
1,240
1,240
Non-current financial liabilities
Deferred Consideration
-
-
644
644
644
Loans
-
-
11,566
11,566
11,566
Bonds
4,108
4,108
113,179
121,395
121,395
________
_________
________
_________
________
10,052
4,108
125,389
139,549
139,549
________
_________
________
_________
________
2018 Company
Current financial assets
Cash and cash equivalents
702
-
-
702
702
Loans to Group companies
-
-
29,526
29,526
29,526
________
_________
________
_________
________
702
-
29,526
30,228
30,228
________
_________
________
_________
________
Current financial liabilities
Trade and other payables
6,017
-
-
6,017
5,961
Deferred Consideration
1,750
-
-
1,750
1,709
Accruals
402
-
-
402
402
Non-current financial liabilities
Deferred Consideration
-
-
1,500
1,500
1,259
Loans
-
-
23,543
23,543
14,054
________
_________
________
_________
________
8,169
-
25,043
33,212
23,385
________
_________
________
_________
________
22 Financial instruments (continued)
Credit risk
Credit risk arises principally from the Group's and Company's other receivables, restricted cash, cash and cash equivalents, and loans to subsidiaries (Company). It is the risk that the counterparty fails to discharge its obligation in respect of the instrument. The credit risk on liquid funds is limited because the counterparties are banks with credit ratings assigned by international credit rating agencies. The Group places funds only with selected organisations with ratings of 'A' or above as ranked by Standard & Poor's for both long and short-term debt. Funds are currently placed with the National Westminster Bank plc and DNB Bank ASA for the EUR Escrow and DSRA funds. Under IFRS 9 there is no material impact for both the Group and Company when assessing expected credit losses of its receivables.
The Group made investments and advances into subsidiary undertakings during the year and these mostly relate to the funding of the SNS Hub Development Projects, and the Company expects to recover these loans when these Projects start to generate positive cash flows. Loans to subsidiary undertakings are recognised at amortised cost in accordance with IFRS 9. The loans have no maturity date and are not repayable until the respective subsidiary entity has sufficient cash to repay the loan. The Board has accordingly assessed the expected repayment dates based on the strategic forecasts approved by the Board.
As at the Balance Sheet date, the Group and Company had £1.5 million external receivables (2018: £nil).
IFRS 9 introduced a new impairment model that requires the recognition of ECLs on financial assets at amortised cost. The ECL computation considers forward looking information to recognise impairment allowances earlier. Intercompany exposures, where appropriate, are also in scope under IFRS 9. The Company assesses the loans made to subsidiary undertakings on the basis of the relevant subsidiaries' long-term strategic forecasts and alongside the Board's commercial rationale for providing the specific loan. The loans are not repayable on demand and are expected to be repaid once the underlying assets progress into the production phase when cash inflows are generated. Based on the methodology set out by the standard, the Board has for each intercompany loan, assessed the probability of the default, the loss given default and the expected exposure to compute the ECLs. The Board has incorporated relevant medium and long-term macroeconomic forecasts in their assessment which is included as a principle consideration in the entity's strategic forecasts. Such factors include oil price sensitivities, funding requirements, reserve and resource estimates. The Board has concluded that any ECLs to be recognised are not material to these financial statements and that there has been no significant increase in credit risk that would warrant the recognition of a material provision. Accordingly, the Company has not recognised any expected credit loss for the balances owed by subsidiary undertakings recognised on the Balance Sheet at amortised cost. The Group and Company do not hold any collateral as security for any external financial instruments, or otherwise.
The maximum exposure to credit risk is the same as the carrying value of these items in the financial statements as shown below.
Group
Company
2019
2018
2019
2018
£000
£000
£000
£000
Other receivables
1,497
-
1,497
-
Loans to subsidiaries
-
-
28,710
29,526
Restricted cash
82,066
-
80,816
-
Cash and cash equivalents
16,197
702
16,197
702
22 Financial instruments (continued)
Cash flow interest rate risk
Save for restricted EUR denominated cash held in escrow and DSRA accounts which attract a nominal negative cost to hold, cash is essentially non-interest bearing. Loans and trade creditors are subject only to fixed interest rates; accordingly, commercial interest rates would have no significant impact upon the Group's and Company's result for the year ended 31 December 2019 (nor 31 December 2018).
In relation to the EUR denominated cash held in escrow, which currently attracts a nominal negative cost to hold, a 10% fluctuation in the cost to hold rate (currently 0.612%) would increase/reduce the charge by £52k per annum.
Foreign exchange risk
At 31 December 2019, 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.
The Company holds significant balances (€95.0 million) in EUR from proceeds of the Bond issue, held in escrow. The remaining balances are held in GBP £16.2 million. 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 EUR would give rise to a £6.0 million gain or £7.4 million loss in the Group and Company's Statement of Comprehensive Income
The Group has no current revenues. The Group and the Company's cash balances are maintained in GBP Sterling which is the functional and reporting currency of each Group company and EUR for the Bond deposits. No formal policies have been put in place to hedge the Group and Company's activities to the exposure to currency risk. It is the Group's policy to ensure that individual Group entities enter transactions in their functional currency wherever possible. The Group considers this minimises any foreign exchange exposure.
Management regularly monitor the currency profile and obtain informal advice to ensure that the cash balances are held in currencies which minimise the impact on the results and position of the Group and the Company from foreign exchange movements.
Capital management
The primary objective of the Group's capital management is to maintain appropriate levels of funding to meet the commitments of its forward programme of appraisal and development expenditure, and to safeguard the entity's ability to continue as a going concern and create shareholder value. The Director's consider capital to include equity as described in the Statement of Changes in Equity, and loan notes, as disclosed in Notes 12 and 18. The Group raised an additional £18.9 million of equity by way of a placement, open offer and subscription in 2019
Borrowing facilities
The Group had £85.0 million of borrowings outstanding at 31 December 2019 (2018 - £34.0 million).
Hedges
The Group did not hold any hedge instruments at the reporting date.
23 Financial commitments and contingent liabilities
The Group has contracted capital expenditure in the current period as part of the phase 1 development work program for the licences in which it participates:
2019
2018
£000
£000
Authorised but not contracted
30,066
-
Contracted
1,250
1,287
_________
_________
31,316
1,287
_________
_________
All 2019 contracted amounts relate to contracted UKCS Licence Fee and associated OGA Levy payments (estimate) together with contracted service awards to suppliers procured for the development of the Group's phase 1 project assets (Blythe, Southwark, Elgood, Thames Reception Facility and Thames Pipeline).
Thames Pipeline:
Security in the sum of £0.50 million, the Initial Thames Decommissioning Pipeline Security Amount, was provided on completion of the Thames Pipeline SPA in April 2018. In October 2019, following the completion of the farm-out to CalEnergy Resources Limited, this amount was reduced to £0.25 million.
Further security in the sum of £1.25 million, the Thames Decommissioning Pipeline Security Amount, is to be provided on the earlier of:
· one month after the variation issued by the OGA to the Pipeline Works Authorisation to allow for the tie-in of one or more of the Group's fields; or
· at the date of sale or alternative use of the Thames Pipeline
Thames Reception Facility ("TRF"):
Security in the sum of £2.0 million, the Initial Thames Reception Facility Decommissioning Security Amount, was provided on completion of the TRF SPA in October 2019. Following the completion of the farm-out to CalEnergy Resources Limited, this amount was reduced to £1.0 million.
Further security in the sum of £4.0 million, the TRF Decommissioning Security Amount, is to be provided 2.5 years following the announcement of 'first gas'. This additional amount is payable in 8 quarterly instalments of £0.5 million with the first instalment payable 6 months after the declaration of 'first gas'.
Cross-Guarantees:
The Company acts as guarantor to its subsidiary IOG North Sea Limited and its facilities with LOG. These cross guarantees are considered insurance contracts in accordance with IFRS4.
24 Related party transactions
Details of directors' and key management personnel remuneration are provided in Note 4.
Andrew Hockey, CEO, acquired 710,729 ordinary shares of 1p each in the capital of the Company and is the current holder of these shares at 31 December 2019. Andrew is also the current holder of 3,467,740 share options at 31 December 2019 and is also entitled to 62,460 share options through salary sacrifice at 31 December 2019, which at the date of this report have not yet been granted.
Rupert Newall, CFO, and persons closely associated, acquired 3,667,050 ordinary shares of 1p each in the capital of the Company and are the current holders of these shares at 31 December 2019. Of those shares acquired, 3,147,139 were issued to Edimis Energy Limited, a company which Rupert is a Director, in lieu of payment for fees for advisory services to the Company. Rupert is also the current holder of 1,440,966 share options at 31 December 2019 and is also entitled to 56,214 share options through salary sacrifice at 31 December 2019, which at the date of this report have not yet been granted.
During 2019, Mark Hughes, COO, acquired a further 415,770 ordinary shares of 1p each in the capital of the Company and is the current holder of 597,770 shares at 31 December 2019. Mark is also the current holder of 2,183,063 share options at 31 December 2019 and is also entitled to 42,473 share options through salary sacrifice at 31 December 2019, which at the date of this report have not yet been granted.
Fiona MacAulay, Chair, acquired 200,000 ordinary shares of 1p each in the capital of the Company and is the current holder of these shares at 31 December 2019. Fiona is also the current holder of 1,000,000 share options at 31 December 2019.
Esa Ikaheimonen, Non-Executive Director, acquired 500,000 ordinary shares of 1p each in the capital of the Company and is the current holder of these shares at 31 December 2019. Esa is also the current holder of 736,606 share options at 31 December 2019 and is also entitled to 97,050 share options through salary sacrifice at 31 December 2019, which at the date of this report have not yet been granted.
Neil Hawkings, Non-Executive Director, is the current holder of 628,055 share options at 31 December 2019. Neil is also entitled to 9,994 share options through salary sacrifice at 31 December 2019, which at the date of this report have not yet been granted.
Details of loans and interest charged by LOG are detailed in Notes 12 and 17. The relevant loans outstanding at the end of the year related to the Company.
25 Notes supporting statements of cash flows (continued)
Details of significant non-cash transactions
2019
2018
£000
£000
Equity consideration for settlement of liabilities
624
-
Group - Loans and borrowings
Current
loans and borrowings
£000Non-current
loans and borrowings
£000Total
loans and borrowings
£000At 1 January 2018
-
12,394
12,394
Drawdowns (Repayments)
-
18,787
18,787
Debt converted into current liability
6,934
(6,934)
-
Issue of warrants and finance fees
-
(4,225)
(4,225)
Amortisation of finance fees
-
617
617
Interest accruing in period
-
2,245
2,245
At 31 December 2018
6,934
22,884
29,818
Of the interest accruing in the period, £22k was capitalised to D&P assets, leaving £1.09 million expensed to the Statement of Comprehensive Income (Note 5).
25 Notes supporting statements of cash flows (continued)
Group - Loans and borrowings
Current
loans and borrowings
£000Non-current
loans and borrowings
£000Total
loans and borrowings
£000At 1 January 2019
6,934
22,884
29,818
Drawdowns (Repayments)
-
3,925
3,925
Lease liability on transition
1,054
-
1,054
Amortisation of finance fees
-
4,213
4,213
Interest accruing in period
528
2,698
3,226
Debt converted into ordinary shares
(3,644)
(8,833)
(12,477)
Repayments
(4,054)
(13,321)
(17,375)
Gain on modification of convertible loan
-
(5,005)
(5,005)
Unwinding of discount
121
259
380
At 31 December 2019
939
6,820
7,759
Company - Loans and borrowings
Current
loans and borrowings
£000Non-current
loans and borrowings
£000Total
loans and borrowings
£000At 1 January 2018
-
-
-
Drawdowns (Repayments)
-
17,150
17,150
Issue of warrants and finance fees
-
(4,224)
(4,224)
Amortisation of finance fees
-
314
314
Interest accruing in period
-
814
814
At 31 December 2018
-
14,054
14,054
Drawdowns (Repayments)
-
3,925
3,925
Lease liability on transition
1,054
-
1,054
Amortisation of finance fees
-
3,910
3,910
Gain on modification of convertible loan
-
(5,005)
(5,005)
Unwinding of discount
121
259
380
Repayments
(236)
(12,330)
(12,566)
Interest accruing in period
-
2,007
2,007
At 31 December 2019
939
6,820
7,759
26 Subsequent events
The key events after 31 December 2019 are as follows:
Since January 2020 the Company has awarded 9,278,019 ordinary shares at 1p to Executive Directors and staff under its Company Share Ownership Plan.
On 14 February 2020 the Company, following a move to its new offices at Endeavour House, 189 Shaftesbury Lane, London, sublet both floors of its 10 Arthur Street, London, lease.
On 28 February 2020 the Company announced confirmation that the option held by its Core Project partner, CalEnergy Resources Limited ("CER"), to acquire 50 per cent of the Harvey and Redwell licences has now expired. However, discussions remain ongoing as to potential CER participation in these licences.
On 6 March 2020, the Company drew down €11.7 million from the escrow funds account after completing the first milestone event of the terms of the bond.
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