29 Jun 2018 07:00
FOR IMMEDIATE RELEASE
29 June 2018
SOLO OIL PLC
("Solo" or the "Company")
ANNUAL REPORT AND ACCOUNTS
FOR THE YEAR ENDED 31 DECEMBER 2017
Solo Oil plc (LSE AIM: SOLO) is pleased to announce that it has published its Annual Report and Accounts for the year ended 31 December 2017, extracts from which are set out below, and which are being posted to Shareholders and will be available on the website www.solooil.co.uk.
The Company's Notice of Annual General Meeting will be distributed shortly.
For further information:
Solo Oil plc Neil Ritson / Dan Maling | +44 (0) 20 7440 0642 |
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Beaumont Cornish Limited Nominated Adviser Roland Cornish / Rosalind Abrahams | +44 (0) 20 7628 3396 |
Shore Capital Broker Jerry Keen
Buchanan (PR) Ben Romney / Chris Judd / Henry Wilson |
+44 (0) 20 7408 4090
+44 (0) 20 7466 5000 |
Chairman's Statement incorporating the Strategic Report
Introduction
In 2017 the Company took significant strides towards the strategic commercialisation of certain investments in its portfolio. The Company has invested in long-term exploration onshore in Tanzania which has so far resulted in the discovery of a nationally significant gas field at Ntorya. That asset, which represents the bulk of Solo's net asset value ("NAV"), is now entering a period of maturity at which its monetisation can be realised. In the UK the Company's investment in the Horse Hill licences has resulted in the discovery of oil, which with further appraisal, could be of major significance. Other investments, notably the Company's early stage investment in helium exploration, continue to mature.
Investment Review
During the first half of 2017, successful appraisal drilling and testing at Ntorya-2 ("NT-2") in Tanzania led to an upgrade in the gross in place gas resources in the Ntorya gas discovery firstly to 1.34 trillion cubic feet ("tcf") and then with further work completed after the reporting period in February 2018 to 1.87 tcf. These resources have been independently certified by RPS Energy; who attribute 763 billion cubic feet ("bcf") to most likely gross contingent resources, a ten-fold increase from the prior independent resource assessment carried out in 2015. This step change in resources comes about largely as a direct result of the drilling of the NT-2 well. As a consequence of these substantial resource upgrades and an independent engineering study, conducted by io oil & gas consulting ("IO Consulting"), which demonstrated commerciality for the Ntorya gas discovery, a 25-year development licence was applied for in the third-quarter.
To further appraise the Ntorya gas field and to test a deeper, potentially oil bearing, zone the operator has proposed a further well, Chikumbi-1 ("CH-1"), to be drilled in 2018. The requested 25-year development licence, which envisages an early production scheme ("EPS") prior to full field development, continues to be reviewed by the Tanzanian authorities and the operator remains confident that the licence will be granted once ongoing discussions have been concluded.
Meanwhile in the UK; the drilling success in several analogous Weald Basin projects has further de-risked the Horse Hill-1 oil discovery where extended well production tests ("EWT") are now planned prior to a development plan being submitted. Planning permission was granted for these tests and also for the initial phases of any development which could include sidetracking the existing discovery well and the drilling of a new well.
Following the reporting period, Solo elected to acquire a further 5% interest in Horse Hill Development Limited; increasing its stake in the Horse Hill discovery from 7.5 to 9.75%. Resource estimates which include gross 62.5 million barrels oil in place ("OIIP") in the Portland Sandstone and significant gross most likely oil in place per square mile in the Kimmeridge Limestones will be updated in due course following the planned long-term tests. These in place volumes and the flow rates obtained on short-term test continue to encourage the Company to believe that commerciality will be declared and development will be an attractive opportunity with oil production possibly as early as 2019.
The period also saw the Company invest in a strategic helium exploration project in Tanzania, through Helium One Limited ("Helium One"), where technical studies have been ongoing and an independent report by Netherland, Sewell and Associates Inc. ("NSAI") issued in 2017 indicated approximately 100 bcf of gross prospective helium resources in prospects and leads that Helium One has under licence in the Rukwa Basin. Helium One's most mature project area in Tanzania is the Rukwa Basin and there, with technical services support from Solo, Helium One commenced the reprocessing of legacy seismic data in late 2017 with a view to completing a full reinterpretation in 2018, followed by drilling. Excellent prospects for subsurface accumulations of helium exist in the Helium One portfolio and the world market for helium continues to tighten with limited new supplies becoming available and demand continuing to rise. Through its contribution of technical services in 2017 and into 2018 Solo increased its stake in the project from 10 to 15%. Following a pre-IPO funding round in Helium One announced in June 2018 Solo now holds a 13.8% interest in the issued share capital of Helium One.
Gas sales at the Kiliwani North gas field in Tanzania remained strong until November, after which pressure decline led to a sharp drop in output from the Kiliwani North-1 ("KN-1") well. The operator has investigated both the causes for the loss of pressure as well as options for recovering production and further reserves from KN-1 and has proposed to recomplete the well in an additional productive zone and, in time, to add wellhead compression. That work is expected to be completed in 2018. A gross total of 6.4 bcf were produced from KN-1 in 2016 and 2017, equivalent to an average daily rate of 10 mmscf.
In November 2017 the Company signed a US$5 million financing facility with RiverFort Global Capital Limited ("RiverFort") to provide working capital and fund operations including the Horse Hill EWT and further appraisal at the Ntorya gas discovery. An initial drawdown of US$1.5 million was made to support cash calls from investee companies, notably at Ntorya, in late 2017 and early 2018.
At end-year the Company's technical director, Fergus Jenkins, stepped down as an executive director to pursue other interests. Mr Jenkins remained a director until May 2018 when a new non-executive director, Mr Jon Fitzpatrick, joined the Board. Mr Fitzpatrick is a qualified lawyer and an experienced energy sector practitioner with banking and deal structuring experience and his appointment brings skills which complement the existing Board. Following the departure of Mr Jenkins in late 2017 Mr Ritson assumed the role of technical director in addition to his existing duties. Mr Ritson's remuneration package however remained unchanged.
Closing remarks
Whilst considerable progress was made in 2017 with growing the underlying value and preparing assets within the portfolio for monetisation events; most notably at the Ntorya gas field in Tanzania, and further progress has been made in the first half of 2018, the pace of commercialisation has been slower than was expected. Being a non-operating investment company Solo is reliant on the operators of the assets and is not in control of many of the timelines. Nevertheless the executive management engages in a regular dialogue with the operators of its assets and investee companies with a view to facilitating the acceleration of monetisation and remains confident that substantial further progress will be made throughout 2018 as the Company's portfolio will undergo a high level of operational activity. At the AGM in early August the Board expects to set out its plans for the balance of 2018 and beyond.
Operational & Financial Review
Highlights for the period include:
Tanzania
• Ntorya-2 ("NT-2") appraisal well was drilled and successfully flow tested.
• A total 51 metres gross sandstone reservoir section was encountered at NT-2, 74 metres shallower than in Ntorya-1.
• A restricted test flowed 17 mmscfd ("million cubic feet per day") of gas (equivalent to approximately 2,830 barrels oil per day).
• Unrisked independently assessed gross resource estimates for the Ntorya appraisal area increased to 1.87 tcf Pmean gas in place ("GIIP").
• Solo has attributable net resources of approximately 468 bcf Pmean GIIP in the Ruvuma Basin, with 191 bcf (31.8 million barrels oil equivalent) of most likely contingent resources (2C) net to its 25% working interest.
• IO Consulting, a Baker Hughes (a GE Company) and McDermott joint venture, completed a gas commercialisation study that indicated that commercial development of the Ntorya field was achievable.
• A development plan for the Ntorya gas field and a request for a 25-year production licence as submitted to the Tanzania Petroleum Development Corporation ("TPDC") during September.
• Average production from Kiliwani North-1 ("KN-1") was approximately 10 mmscfd.
• Solo acquired an initial 10% interest in Helium One Limited during the period as an early entry opportunity into an estimated US$6 billion/year global helium market.
• Helium One's Rukwa Project in Tanzania is independently estimated by NSAI to contain unrisked most likely prospective recoverable helium volumes close to 100 bcf.
United Kingdom
• Surrey County Council approved the planning application submitted in late 2016 for the further development of Horse Hill, including long-term flow tests and further drilling and seismic data acquisition.
• UK Environment Agency has approved the proposed long-term testing of HH-1 and further work as envisaged under the planning application.
• Following the successful testing at Horse Hill-1 ("HH-1") in 2016 various operators have drilled additional wells in the Kimmeridge Limestone play in the Weald Basin and have demonstrated the widespread occurrence of the play, further supporting the regional significance of the naturally fractured oil bearing reservoir.
• At end-year 2017 plans were in place to commence a 150-day long-term test of the three proven reservoirs in HH-1.
Corporate & Financial
• Revenues from the sale of gas at Kiliwani totaled £0.6m for 2017, up from £0.5m in 2016.
• The Company issued £4.55 million in new equity during the period to pay for Ntorya-2 well testing costs and acquisition of 10% in Helium One.
• Shareholders approved a 20 for 1 consolidation of the Company's issued share capital.
• The Company signed a US$5 million finance facility arranged by RiverFort Global Capital Limited and made an initial drawdown of US$1.5 million.
• Mr Jenkins relinquished his duties as an executive director in December, remaining a non-executive director until May 2018.
Review of Investments by Country:
Tanzania
Many of Solo's investments are in Tanzania, a stable democratic republic in East Africa, where gas exploration efforts have been highly successful in recent years. Solo, and its operating partner Aminex plc ("Aminex"), currently produces gas in the Kiliwani North Development Licence on Songo Songo Island. That gas is sold to TPDC under a gas sales agreement signed in 2016 and is used domestically, contributing to the development of the local energy market in Tanzania.
Gas produced and used in Tanzania is largely unaffected by issues that have arisen with resources destined for export following changes in the legislation regarding hydrocarbon and mining law recently announced by the Tanzanian government. The nationally significant onshore Ntorya gas discovery made by Solo and Aminex is expected to be developed solely for local consumption and therefore is expected to continue to have TPDC's full support as Tanzania seeks to grow its indigenous energy provision.
In April 2018, the government of Tanzania established a new Mining Commission to regulate and implement the provisions of the Mining Act. The Commission is required to approve the grant of new licences and approve contracts. The establishment of the Commission and publishing of the new Mining Regulations is timely for Solo's Helium One investment with drilling expected to commence this year, and an application for a Mining Licence following drilling success. The industrial gas royalty remains at 3%, however, a 16% carry for the government and a 1% inspection fee are both now set in law.
A. Ruvuma Basin (25% interest)
In 2017 Solo held a 25% working interest in the Ruvuma Petroleum Sharing Agreement ("Ruvuma PSA") in the south-east of Tanzania covering an area of 3,447 square kilometres of which approximately 90% lies onshore and the balance offshore. The Ruvuma PSA is in a region of southern Tanzania where very substantial gas discoveries have been made offshore in recent years and where gas has also been discovered onshore and along the coastal islands at Ntorya, Mnazi Bay, Kiliwani North and Songo-Songo.
The Ruvuma PSA comprised two licence areas: the southern Mtwara Licence ("Mtwara") and the northern Lindi Licence ("Lindi"). The Ntorya Appraisal area and proposed Development Licence lies exclusively in the Mtwara Licence. As well as the Ntorya wells, several further prospects in the Ruvuma acreage have been identified from the 2014/2015 mapping, including potential prospects such as at Likonde and Namisange. Ministerial approval was obtained for an extension to Mtwara to December 2017 and the operator has also applied for a further two-year extension which is expected to be approved in 2018. In order to focus the Joint Ventures resources on the development of the Ntorya gas field and its surrounding area it has now been agreed that the Lindi Licence will be relinquished and will become the subject of a future application for a new PSA by TPDC with the option of Aminex and Solo participation once terms have been agreed. There are no penalties for the relinquishment of Lindi and the Company believes that this decision to focus on Ntorya represents the most effective means to deploy resources, as it limits further exploration spending in favour of the appraisal and development of proven resources.
The Ntorya gas-condensate discovery, made in 2012 and operated by Aminex, represents the most immediate commercialisation opportunity in the Ruvuma PSA. The Ntorya-1 ("NT-1") well was flowed over a 3.5-metre zone at the top of the gross 25-metre gas bearing interval at a maximum gross flow rate of 20.1 mmscfd and 139 bpd of 53 degree API condensate through a 1-inch choke. That well is suspended as a discovery for subsequent additional testing or production.
Based on an infill 2D seismic programme around NT-1 a re-estimation of the discovered and prospective resources in the Likonde-Ntorya area was made and subsequently audited by LR Senergy who issued a CPR in May 2015. LR Senergy estimated that Ntorya contained a gross 153 bcf of proven gas in place, of which they attributed a gross 70 bcf as best estimate contingent resources (2C).
In order to further appraise the Ntorya gas and condensate discovery made in the NT-1 well it was decided to drill an up-dip well, Ntorya-2 ("NT-2"), at a location approximately 1.5 kilometres east of the discovery well. The location was prepared in late 2016 and the Caroil-2 rig was moved onto the site in December and the well spudded on 21 December 2016.
During early 2017 drilling continued on prognosis with 17-inch casing set at 1,326 metres in early January and the well reached the anticipated reservoir section at a depth of 2,593 metres in early February 2017. A gross gas bearing sandstone reservoir interval of 51 metres thickness was encountered and the well was deepened to a final total depth of 2,795 metres, with a 7-inch liner set prior to testing. A 34-metre interval of the gross reservoir was perforated and flowed dry gas at a stabilised rate of 17 mmscfd through a 40/64-inch choke. Analysis of the well during testing and interpretation of electric logs strongly suggests that high mud weights, used to control gas influx during drilling, had caused a degree of formation damage around the well bore and these effects were reducing the test flows. Remedial operations prior to production could be undertaken to target higher flow rates.
As a result of the new data from NT-2 and a reassessment of all available data, including a new seismic interpretation, the gross most likely in place gas in the Ntorya discovery was increased in September 2017 by some 9-fold from 153 bcf in the LR Senergy report in May 2015 to 1,344 bcf. The Company being fully satisfied that such volumes, now discovered, are commercially exploitable. As a result the operator applied for a 25-year development licence covering the entire Ntorya field area in September 2017.
Further work in 2018 by RPS Energy Consultants Limited ("RPS"), on the resource estimates, and by IO Consulting, on the development engineering and economics, has led to a further upgrade of the resource estimates (Table 1) which now include independent 2C estimates of gross contingent resources of 763 bcf, of which 191 bcf would be net to Solo's working interest, equivalent to approximately 31.8 mmbbls oil equivalent.
Table 1: RPS Estimates of Contingent Resources in Ntorya
| Gas Contingent Resources (bcf) | |||||||||
Gross (100%) Licence Basis | Solo's Net 25% Working Interest Basis | Solo's Net Entitlement Basis | ||||||||
1C | 2C | 3C | 1C | 2C | 3C | 1C | 2C | 3C |
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Development Pending Category | 25.5 | 80.6 | 212.9 | 6.4 | 20.1 | 53.2 | 5.4 | 25.8 | 41.1 |
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Development Unclarified Category | 342.3 | 682.2 | 949.5 | 85.6 | 170.5 | 237.4 | 65.0 | 117.9 | 155.2 |
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Total Contingent Resources | 367.8 | 762.8 | 1162.4 | 92.0 | 190.6 | 290.6 | 70.4 | 143.7 | 196.3 |
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Source: RPS Energy
Once a development licence has been awarded, Solo and Aminex will carry out an approved work programme, yet to be agreed with the Tanzanian authorities, which may potentially include 3D seismic acquisition and further drilling. A well designed to further appraise the Ntorya gas field at the previously proposed Ntorya-3 location has been designated an exploration well as it will additionally test a deeper Jurassic age target to an estimated total depth of 3,400 metres. Due to the exploration target of the well it has been renamed Chikumbi-1 ("CH-1"). Rig tending was underway in April 2018 and it is hoped that the well can be spudded in 2018 once the Mtwara Licence has been extended for a further period as envisaged.
Under the terms of the Ruvuma PSA, after the approval of a development plan, TPDC may elect to contribute 15% of development costs in order to obtain a participating interest of 15% in production and revenues.
Solo is actively assessing its options with regards to its future participation in the project. Consideration is being given to options for further proportionate investment, project financing of an early production scheme, a possible farm-down, or sale of some or all of its 25% interest in the discovery in order to monetise its investment in the Ruvuma PSC and return funds to the Company to deploy elsewhere. A final decision on the future investment scenario will be taken when the terms of the 25-year development licence are known. The potential farm-down of the operator's interest, which is reported to be under discussion, will also impact on the timing and chosen route to Solo's monetisation.
B. Kiliwani North (7.55% interest)
In 2014, Solo agreed with Aminex to acquire up to a 13% working interest in the Kiliwani North Development Licence ("KNDL") on Songo-Songo Island. The Kiliwani North-1 ("KN-1") well was drilled by Aminex and its partners in 2008 and discovered gas in a 60-metre column in the Lower Cretaceous. Solo acquired an initial 6.5% interest in the KNDL project for US$3.5 million in 2015 and subsequently announced its intention to increase its stake to up to 10% through the acquisition of three additional tranches of project equity linked to project milestones at the Company's option.
The condition precedent for further acquisition of project equity by Solo was the signature of a gas sales agreement ("GSA"), which was achieved in January 2016. The subsequently agreed tranche milestones were the commencement of gas production, which was achieved in April 2016, the receipt of first cash revenue and the declaration of commercial (post-commissioning) gas production under the take-or-pay arrangements of the GSA. Once the first of these milestones was reached Solo increased its direct participation to 7.55%. Since production has continued in 2016 and 2017 under the commissioning terms of the Kiliwani North GSA further tranches of investment in the acquisition have not been made and Solo and Aminex have mutually agreed to the termination of their agreement. Solo continues to hold a 7.55% working interest in the KNDL, although TPDC has a back-in right to take up an interest in the KNDL which would reduce Solo's interest to 7.175%. To date TPDC have not taken up that option.
The GSA signed with TPDC for KNDL gas contains payment guarantees in US Dollars and is linked to a price escalation formula commencing at US$3.00 per million British Thermal Units ("mmBTU") and rising from January 2016. Following commissioning KN-1 was produced at a rate of roughly 15 mmscfd being the call on gas being made by TPDC. Overall gas market development continues to lag supply in Tanzania, however, this is expected to gradually change to a supply shortage in future years as new power projects and industrial usage increases. Due to a higher than specified calorific value for the gas and an advantageous effect of the sales contract's indexation allowance, gas has been sold during the reporting period at approximately US$3.27 per mcf.
Production from the KN-1 well declined sharply in late 2017 due to pressure loss and associated water influx to the wellbore. The operator has investigated options for recovering production and further reserves from KN-1 and has proposed to recomplete the well in an additional productive zone and in due course to add wellhead compression. An update from the Operator is expected pending further work on plant specifications and appropriate government approvals. A gross total of 6.4 bcf were produced from KN-1 in 2016 and 2017, equivalent to an average daily rate of 10 mmscf.
A resource report by LR Senergy, completed in May 2015, attributed approximately 28 bcf gross best estimate contingent resource to the Kiliwani North field. These estimates were revisited by RPS in 2018 following production over an 18 month period totaling approximately 6.4 bcf. A new Pmean GIIP of 30.8 bcf and a remaining reserve gross 2P reserves of 1.94 bcf. It is felt that with further intervention additional gas can be recovered from the KN-1 well and an additional 57 bcf prospective Pmean GIIP feature, Kiliwani South, has been identified in the licence that may merit future drilling after some additional work is undertaken.
C. Helium One (13.8% interest)
Solo entered into a sale and purchase agreement with Helium One Limited ("Helium One") to acquire an initial 10% stake in Helium One with an option to acquire a further 10% stake. Helium One owns exploration licences in a number of highly prospective, and extremely rare, helium properties in Tanzania. Netherland & Sewell Associates International ("NSAI") has independently assessed the most mature of the projects, in the Rukwa Basin of the East African Rift Valley, as having the gross potential for close to 100 bcf of helium in place.
With current world helium demand of approximately 6 bcf per annum the Rukwa project represents a potentially material contribution to future helium supply. World helium demand has been growing at a rate of about 3 per cent per annum over the last decade and is a vital component of many modern technologies, for example in Magnetic Resonance Imaging ("MRI") devices used in modern medicine. As a result of its unique properties as a super fluid, it plays a vital role in devices which use super conducting magnets; as in MRI machines. As an inert gas helium also plays a vital role in the production of many critical electronic components such as disk drives and fibre optics, and is additionally used for industrial testing, purging and leak detection. Helium, as a lifting gas in hybrid air vehicles (and other forms of airship), has also begun to have increased significance. Though relatively abundant in the earth's atmosphere, helium is lighter than air and is progressively being lost to space and on many applications is extremely difficult to recycle effectively.
The current global supply of helium comes from several large deposits in the USA and as an impurity removed from hydrocarbon gas in a number of major liquefied natural gas ("LNG") projects such as in Qatar and Algeria. However, the US government has been selling its strategic reserve and will close the facility for international sales no later than September 2021, after which there is projected to be a significant shortage of helium available on world markets. In June 2017, several countries abruptly cut diplomatic relations with Qatar and imposed trade and travel bans. The ramifications for global helium supply were significant, with both Qatari plants being turned off for a period, as exports of helium were unable to pass the trade barriers imposed on Qatar. While only a temporary situation, it did highlight the fragility of the helium supply chain, and reliance on Qatari supplies. It should also be noted that helium output from LNG plants can only be increased if LNG demand also increases and as a result much of the global helium supply is highly illiquid. Helium One holds one of the only known large, high-volume, standalone helium resource projects being developed globally and, if successful, could provide much needed stability to global helium supply. Helium One's projects are not associated with hydrocarbon gases and therefore, if commercial volumes are discovered, could be produced as a major swing producer to global markets.
The Helium One Tanzania projects have excellent supply economics and, once liquefied close to production well sites, the helium could be transported to world markets via the deep-water port at Dar es Salaam. Given the competitive demand for crude helium on world markets Solo and Helium One would expect to sell helium at the wellhead through an off-take agreement with a large industrial gas company who would liquefy and transport the helium to market. With weak supply-demand fundamentals helium prices, which are currently in the range US$200-260 per million cubic feet (for pure liquid helium), have been rising in 2017/2018 and are expected to continue to rise until significant new supplies are commercialized.
Originally identified by means of helium macro-seeps the prospects under investigation by Helium One have been mapped using soil geochemistry anomalies, airborne geophysical tools and on legacy 2D seismic data acquired previously during failed hydrocarbon exploration in the 1980s. The identified macro-seepage indicates high concentrations of helium (up to in excess of 10% by volume) in association with nitrogen that may be trapped in the subsurface. In late 2017, with technical support and backing from Solo, Helium One commenced a seismic reprocessing project on the 2D legacy seismic intended to lead to a full reinterpretation and prior to the selection and drilling of the initial exploration wells.
Helium One announced in June 2018 that the reinterpretation was nearing completion and that it confirmed previous estimated of helium resources in the Rukwa Basin. Prospects ready for drilling have been identified and Helium One have indicated they are in negotiations for the provision of a drilling rig and services. The drilling of initial test wells is anticipated to occur in late 2018 or early 2019 depending on the availability of rigs and finance.
Solo completed its acquisition of an initial 10% interest in Helium One on 22 March 2017 through the payment of £1.2 million in cash and the issue to Helium One of 236,842,105 (pre-consolidation) shares at an issue price of 0.54p in Solo Oil plc (10.8p post consolidation). As initial market reaction to the proposed projects was muted the decision was taken not to exercise the option to increase Solo's investment to 20% and the option granted in the March sale and purchase agreement was allowed to lapse.
Since Solo's initial investment, Helium One have been focusing on evolving its subsurface technical data set and preparing its prospect database ready for possible drilling in 2018. Subsequent to period end Helium One have also been made to start to reprocess the existing legacy 2D seismic data with Solo's technical assistance. In return for the technical assistance provided, especially in regard to seismic reprocessing, Helium One has issued additional equity to Solo in 2018 up to a 15% stake in Helium One. In June 2018 Helium One closed a US$2.0 million pre-IPO funding round providing the necessary funding of the Rukwa project up to drilling. As a consequence of the issue of new shares Solo's interest in Helium One is now 13.8%; which at the pre-IPO valuation is worth £2.84 million, an 11% increase over the purchase price in 2017.
United Kingdom
Solo's principal investments to date in the UK have been in the Weald Basin, south of London, where the Horse Hill-1 well ("HH-1") was drilled and identified a thick section of oil bearing naturally fractured Kimmeridge Limestones in addition to an oil bearing Portland Sandstone section. A well drilled recently at Broadford Bridge ("BB-1") and a subsequent side-track, BB-1z, some 30 kilometres to the southwest of HH-1, has revealed the continuation of similar naturally fractured and oil saturated Kimmeridgian age limestones and shales as were seen at HH-1. Similar Kimmeridge lithologies have also been reported at Brockham and Balcombe in the Weald Basin suggesting the play is regionally extensive. Logs and cores from the BB-1/1z well, as reported by the operator, show extensive natural fracturing throughout the entire Kimmeridge section, including a previously unidentified potential oil bearing fracture-zone below the previously seen oldest Kimmeridge Limestone, KL1, now designated KL0. These results indicate a possible gross vertical thickness of the Kimmeridge continuous oil deposit of up to around 1,200 feet. Solo remains confident that with additional drilling a regionally significant new oil play will be realised.
A. Horse Hill, Weald Basin (9.75% interest)
In 2014, the Company acquired a 10% interest in a special purpose company, Horse Hill Developments Limited ("HHDL"), which became the operator and 65% interest holder in two Petroleum Exploration and Development Licences, PEDL 137 and 246, in the northern Weald Basin between Gatwick Airport and London. PEDL 137 covers 99.29 square kilometres (24,525 acres) to the north of Gatwick Airport in Surrey. PEDL 246 covers an area of 43.58 square kilometres (10,769 acres) and lies immediately adjacent and to the east of PEDL 137.
The HH-1 well commenced drilling operations in September 2014 and reached total depth at 8,870 feet MD in November 2014. Evaluation of electric logs and other data collected from the well resulted in the announcement on 24 October 2014 of a conventional Upper Portlandian Sandstone oil discovery. Subsequent analysis of the Kimmeridge, Oxfordian and Liassic sections in the well indicated that there was also substantial in place oil in the naturally fractured Kimmeridge Limestones and associated mudstones.
Approval for the testing of all three oil bearing zones was granted in late 2015 and the tests commenced in early February 2016. Tests lead to naturally flowing oil rates of the Kimmeridge Limestones at a gross rate of 460 bopd from the Lower (KL3) interval and 900 bopd from the upper (KL4) interval. The Portland Sandstone was placed on pump to stimulate flow and achieved a maximum gross stable rate in excess of 320 bopd. These flow rates substantially exceeded the expectations for the well and rank alongside some of the highest rates ever achieved on test for any UK onshore well.
Following the testing of the Portland Sandstone, where higher productivity and a lower than expected water cut were observed, further analysis on the electric logs has led to a 3-fold increase in the anticipated gross oil in place at this stratigraphic level. Previous estimates of oil in place within the Portland Sandstone were 7.7 mmbbls per square mile and were increased to 22.9 mmbbls per square mile. Based on estimates by Xodus in 2017 this would increase the overall gross oil in place within the Horse Hill Portlandian discovery to approximately 32 million barrels of oil ("mmbbls").
The relevant licences have been extended to permit further work and HHDL has been granted planning consent by Surrey County Council ("SCC") for an extended well test ("EWT") and additional appraisal work that includes 3D seismic and further drilling. In September 2017 the Environment Agency granted the necessary permits to HHDL to carry out extended well tests, drill a side-track well from the existing HH-1 and drill and test a new borehole at the HH-1 site.
In December 2017 HHDL announced its plans for a 150-day EWT program aimed at confirming commerciality of the Portland and Kimmeridge discoveries and, if successful, to commence a further well in late 2018 with a view to commencing permanent oil production in 2019. Equipment for the proposed EWT was procured and testing is anticipated to commence after receipt of all relevant consents, including the Oil & Gas Authority ("OGA"). Each of the three zones; Portland, KL3 and KL4, would be tested for a duration of 30 to 40 days consisting of a series of stabilised steady state flow and shut-in periods designed to establish the oil in place in contact with the wellbore.
In 2018 Solo acquired a further 5% interest in HHDL in a sale and purchase agreement with Primorus Investments plc, increasing its working interest in the Horse Hill licences to 9.75%. Solo paid the equivalent of £200,000 per percent for the additional HHDL interest paid partly in cash and partly in Solo shares.
The OGA granted final approval for the EWT in mid-June 2018 and HHDL indicated that test operations were underway on the 27 June 2018.
B. Isle of Wight, PEDL 331 (30% interest)
An application was made jointly with UK Oil and Gas Investments plc ("UKOG") for a 200 square kilometre onshore block in the south and central portion of the Isle of Wight in the UK 14th Landward Licensing Round. Solo holds a 30% working interest in the joint venture and in the licence, PEDL 331.
Based on work by UKOG, and confirmed by independent work by Solo, Arreton-2, originally drilled in 1974 by the Gas Council, but never tested, is now considered to be an oil discovery on the Arreton Main Field. When taken together with the adjacent prospects Xodus has calculated a P50 gross oil in place estimate of 219 mmbbls in conventional reservoirs within the Purbeck, Portland and Inferior Oolite limestone reservoirs at Arreton. Arreton Main is considered by Xodus to contain most likely (P50) contingent resource net to Solo's interest in PEDL 331 of 4.7 mmbbls.
UKOG has become operator of PEDL 331 and has commenced discussions with the local planning authorities and land owners and expects to seek regulatory consents to appraise the Arreton Main oil discovery in the coming years.
Other investments
The Company holds several other investments that remain under active review, but have had only minimal expenditure in the reporting period.
A. Burj Africa, Nigeria, West Africa (20% interest)
Between 2013 and 2015 Solo made an investment into various ventures aimed at accessing known reserves in fields in Nigeria. These have resulted in a 20% interest in Burj Petroleum Africa Limited ("Burj Africa") a company which had applied for various undeveloped fields in the 2014 Nigerian Marginal Fields Bid Round ("Marginal Fields Round") along with joint venture partners Global Oil and Gas and Truvent Consulting.
Recent developments in the world oil markets and specific to Nigeria have significantly delayed the issue of new licences under the envisaged Marginal Fields Round. The Company continues to monitor developments in Nigeria and looks forward to further news in due course.
B. Ontario, Canada (28.56% interest)
Solo holds an interest in 23,500 acres of petroleum leases in southern Ontario, which contain a number of Ordovician reefal structures that contain variously oil, gas and condensate. The operator, Reef Resources Inc., ("Reef") has been unable to fund the continued development of the Ausable gas condensate field and no alternative has so far been found to unlock the known potential.
Solo's management continues to seek ways to advance or monetize the investment made in the Ausable and the adjacent Airport fields. Discussions have continued with Reef with a view to locating a new investment partner to re-invigorate the planned work program at Ausable. To date a commercially viable forward program has not emerged.
Financial & Corporate Review
Full year 2017 provided the second consecutive year of revenue generation for Solo with £0.6m of net sales from the Company's 7.55% interest in the Kiliwani North gas field. Through the issue of £4.5m in new share capital Solo also funded the successful test of Ntorya-2 and acquisition of 10% in Helium One during the period, at an effective average share price of 10.6p (post consolidation).
Increases in general and administrative expenditure for the year were primarily attributable to executive Director salaries (£0.4m:2017; £0.2m:2016), associated non-cash share based payment expenses (£0.2m in 2017) and operational joint venture expenditures associated with a full year of gas revenues from Kiliwani North (£0.1m in 2017). The executive management team has now been reduced to two directors following the resignation of Fergus Jenkins in December 2017 with ongoing measures to reduce overheads being actively managed by the board in 2018.
Following a review of carrying values at 31 December 2017 the board decided to fully impair the capitalised Ausable reef expenditures (£0.3m) and Burg Petroleum Africa Limited available for sale investment amounts (£0.6m).
Shareholders approved a share consolidation of every 20 existing ordinary shares into one new ordinary share at the Company's AGM. The Board believes this restructure is in the best interests of the Company's long term development as a public quoted company in having a more manageable number of issued ordinary shares and to a level which is more in line with other comparable AIM-traded companies.
In November 2017 the Company signed a US$5 million finance facility arranged by RiverFort and made an initial drawdown of US$1.5 million. The facility has up to an eighteen-month term and, after an initial repayment holiday, is repayable in monthly installments via cash or conversion into ordinary shares.
Following the period end the Company raised £2m by the issue of 57.1 million shares at 3.5p to fund the acquisition of a further 5% in HHDL and ongoing working capital for its core investments.
Immediate Outlook
Solo has made some significant advances in its investments in Tanzania in 2017, especially in the Ntorya gas- condensate discovery which has been successfully further appraised by the Ntorya-2 well with a resultant 11-fold increase in the estimated in place gas resources. A 25-year development licence for Ntorya has been applied for and will allow the finalisation of plans to commercialise Ntorya; which in Solo's case may involve continued project investment, or a full or partial sale, or farmout, of the Company's equity position depending on negotiating advantageous commercial terms with a third-party. The drilling of a third appraisal well, with an additional deeper exploration target, named Chikumbi-1, is being planned for later in 2018, and represents a significant catalyst for Solo's investment story. The board has previously commented that an open offer to shareholders would be made to fund any commitment due to further drilling at Ruvuma.
The Horse Hill discovery made in 2016 yielded exceptionally high flow rates at all three productive levels on test and is expected to receive further longer-term testing in order to help design a commercial development. Solo has reviewed the recent encouraging drilling and testing by other operators in the Weald Basin and as a consequence seized the opportunity to increase the Company's investment in Horse Hill from 6.5% to 9.75% ahead of the longer-term testing activities. The EWT of the three productive intervals in HH-1 is expected to commence imminently.
The Company has made some initial investments in a natural helium exploration opportunity in Tanzania, through purchase and the contribution of technical services, with Helium One Limited and sees the Rukwa Basin as a potentially world class helium opportunity with very compelling economics and market dynamics. Further technical work will be completed in 2018, and subject to the availability of drilling capacity and financing in Helium One, it is expected that initial drilling on these helium prospects can commence in late 2018 or early 2019.
Through a planned reduction in executive management the Company has actively reduced it's G&A costs in the light of reduced revenue in late 2017 from the Kiliwani North Gas Field and pending the monetisation of some of its mature investments. It is anticipated that further savings to cash G&A expenditures will be made in 2018 through the issue of shares in lieu of fees to some directors and key advisers, as well as active cost cutting measures by the Board. In the interim some director fees are being accrued in anticipation of monetisation events in the second half of 2018. In summary, the near-term outlook can be defined as a period of high activity across the portfolio with a number of important operational and corporate events that will, in the success case, enable Solo to realise the value of its portfolio and monetise key assets for the benefit if its shareholders.
Qualified Person's statement:
The information contained in this document has been reviewed and approved by Neil Ritson, Chairman for Solo Oil Plc. Mr Ritson is a member of the Society of Petroleum Engineers, a Fellow of the Geological Society, an Active Member of the American Association of Petroleum Geologists and has over 40 years relevant experience in the oil industry.
Glossary and Notes
2D seismic | seismic data collected using the two-dimensional common depth point method |
3D | three-dimensional |
AIM | London Stock Exchange Alternative Investment Market |
API | American Petroleum Institute |
barrel or bbl | 45 US gallons |
bbls | barrels of oil |
bcf | billion cubic feet |
best estimate or P50 | the most likely estimate of a parameter based on all available data, also often termed the P50 (or the value of a probability distribution of outcomes at the 50% confidence level) |
billion | 10 to the power 9 |
bopd | barrels of oil per day |
CNG | condensed natural gas |
contingent resources | those quantities of petroleum estimated, at a given date, to be potentially recoverable from known accumulations, but the associated projects are not yet considered mature enough for commercial development due to one or more contingencies |
CPR | Competent Persons Report |
discovery | a petroleum accumulation for which one or several exploratory wells have established through testing, sampling and/or logging the existence of a significant quantity of potentially moveable hydrocarbons |
electric logs | tools used within the wellbore to measure the rock and fluid properties of the surrounding formations |
GIIP | gas initially in place |
GSA | gas sales agreement |
HH-1 | Horse Hill-1 well |
HHDL | Horse Hill Developments Limited |
KN-1 | Kiliwani North-1 well |
KNDL | Kiliwani North Development Licence |
m | thousand (ten to the power 3) |
mm | million (ten to the power 6) |
mmbbls | million barrels of oil |
mmscf | million standard cubic feet of gas |
mmscfd | million standard cubic feet of gas per day |
OGA | UK Oil and Gas Authority (formally the Department of Energy and Climate Change) |
oil in place or STOIIP | stock tank oil initially in place, those quantities of oil that are estimated to be in known reservoirs prior to production commencing |
pay | reservoir or portion of a reservoir formation that contains economically producible hydrocarbons. The overall interval in which pay sections occur is the gross pay; the portion of the gross pay that meets specific criteria such as minimum porosity, permeability and hydrocarbon saturation are termed net pay |
PEDL | Petroleum Exploration and Development Licence |
permeability | the capability of a porous rock or sediment to permit the flow of fluids through the pore space |
petrophysics | the study of the physical and chemical properties of rock formations and their interactions with fluids |
play | a set of known or postulated oil or gas accumulations sharing similar geologic properties |
porosity | the percentage of void space in a rock formation |
prospective resources | those quantities of petroleum which are estimated, at a given date, to be potentially recovered from undiscovered accumulations |
proven reserves | those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable (1P), from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations |
probable reserves | those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P) |
possible reserves | those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P) Reserves, which is equivalent to the high estimate scenario |
PSA | petroleum sharing agreement |
PRMS | Petroleum Resources Management System |
reserves | those quantities of petroleum anticipated to be commercially recovered by application of development projects to known accumulations from a given date forward under defined conditions |
reservoir | a subsurface rock formation containing an individual natural accumulation of moveable petroleum |
SPE | Society of Petroleum Engineers |
tcf | trillion cubic feet |
trillion | 10 to the power 12 |
unconventional reservoir | widely accepted to mean those hydrocarbon reservoirs that are tight; that is have low permeability |
The estimates provided in this statement are based on the Petroleum Resources Management System ("PRMS") published by the ("SPE") and are reported consistent with the SPE's 2011 guidelines. All definitions used in the announcement have the meaning given to them in the PRMS.
Financial Statements
Statement of Comprehensive Income for the year ended 31 December 2017
|
| Year ended | Year ended |
| Notes | 31 December 2017 | 31 December 2016 |
|
| £000's | £000's |
Revenue |
| 614 | 501 |
|
|
|
|
Operating expenses |
| (87) | - |
Administrative expenses |
| (1,261) | (721) |
Loss from operations | 3 | (734) | (220) |
Impairment charge | 8, 10 | (300) | - |
Amortisation charge | 9 | (484) | (275) |
Finance costs | 6(a) | (126) | (29) |
Finance income | 6(b) | 66 | - |
Exchange losses |
| (81) | - |
Provision for losses on financial instrument | 13 | - | - |
|
|
|
|
Loss before taxation |
| (1,659) | (524) |
Income tax | 5 | - | - |
Loss for the year |
| (1,659) | (524) |
|
|
|
|
Other comprehensive income |
|
|
|
Decrease in value of Available for sale assets |
| (577) | (34) |
Other comprehensive income for the year net of taxation |
| (577) | (34) |
|
|
|
|
Total comprehensive income for the year attributable to equity holders of the parent |
| (2,236) | (558) |
|
|
|
|
Loss per share (pence) |
|
|
|
Basic and diluted (2016: restated due to share consolidation) | 7 | (0.43) | (0.17) |
|
|
|
|
Statement of Financial Position as at 31 December 2017
| Notes | 31 December 2017 | 31 December 2016 |
|
| £000's | £000's |
Assets
Non- current assets |
|
|
|
Intangible asset | 8 | 13,816 | 12,036 |
Oil & gas properties | 9 | 194 | 678 |
Available for sale assets | 10 | 3,226 | 1,181 |
Total non-current assets |
| 17,236 | 13,895 |
Current assets |
|
|
|
Trade and other receivables | 12 | 1,395 | 1,336 |
Cash and cash equivalents |
| 396 | 600 |
Total current assets |
| 1,791 | 1,936 |
Total assets |
| 19,027 | 15,831 |
|
|
|
|
Liabilities
Current liabilities |
|
|
|
Trade and other payables | 14 | (324) | (444) |
Derivative financial instrument | 13 | - | - |
Borrowings | 15 | (1,080) | - |
Total liabilities |
| (1,404) | (444) |
|
|
|
|
Net assets |
| 17,623 | 15,387 |
|
|
|
|
|
|
|
|
Equity |
|
|
|
Share capital | 16 | 785 | 699 |
Deferred share capital | 16 | 1,831 | 1,831 |
Share premium |
| 31,749 | 27,559 |
Share-based payment reserve |
| 1,129 | 933 |
AFS reserve |
| (693) | (116) |
Retained loss |
| (17,178) | (15,519) |
|
| 17,623 | 15,387 |
|
|
|
|
Statement of Cash Flows for the year ended 31 December 2017
|
| Year ended | Year ended |
|
| 31 December 2017 | 31 December 2016 |
|
| £000's | £000's |
Cash outflow from operating activities |
|
|
|
Operating loss |
| (734) | (220) |
Adjustments for: |
|
|
|
Share-based payments |
| 196 | 49 |
(Increase) in receivables |
| (55) | (813) |
(Decrease)/increase in payables |
| (120) | 210 |
Foreign exchange loss |
| (81) | 93 |
Net cash outflow from operating activities |
| (794) | (681) |
|
|
|
|
Cash flows from investing activities |
|
|
|
Interest received |
| 66 | - |
Payments to acquire intangible assets |
| (2,080) | (1,597) |
Net payments on settlements of derivative financial instruments |
| - | (450) |
Payments to acquire Available for sale investments |
| (1,276) | - |
Net cash outflow from investing activities |
| (3,290) | (2,047) |
|
|
|
|
Cash flows from financing activities |
|
|
|
Proceeds from borrowings |
| 1,080 | - |
Repayments of borrowings |
| - | (119) |
Finance costs |
| (126) | (2) |
Proceeds on issuing of ordinary shares |
| 3,200 | 2,800 |
Cost of issue of ordinary shares |
| (274) | (175) |
Net cash inflow from financing activities |
| 3,880 | 2,504 |
|
|
|
|
Net decrease in cash and cash equivalents |
| (204) | (224) |
|
|
|
|
Cash and cash equivalents at beginning of the year |
| 600 | 824 |
Cash and cash equivalents at end of the year |
| 396 | 600 |
The above Cash Flow should be read in conjunction with the accompanying notes.
Statement of Changes in Equity for the year ended 31 December 2017
|
| Deferred |
| Share | AFS |
|
|
| Share | share | Share | based | reserve | Accumulated | Total |
| capital | capital | premium | payments |
| losses | equity |
| £000's | £000's | £000's | £000's | £000's | £000's | £000's |
|
|
|
|
|
|
|
|
Balance at 31 December 2015 | 556 | 1,831 | 25,077 | 884 | (82) | (14,995) | 13,271 |
|
|
|
|
|
|
|
|
Loss for the year | - | - | - | - | - | (524) | (524) |
Decrease in value of Available for sale assets | - | - | - | - | (34) | - | (34) |
Total comprehensive income | - | - | - | - | (34) | (524) | (558) |
Share issue | 143 | - | 2,657 | - | - | - | 2,800 |
Cost of share issue | - | - | (175) | - | - | - | (175) |
Share-based payment charge | - | - | - | 49 | - | - | 49 |
Total contributions by and distributions to owners of the Company | 143 | - | 2,482 | 49 | - | - | 2,674 |
|
|
|
|
|
|
|
|
Balance at 31 December 2016 | 699 | 1,831 | 27,559 | 933 | (116) | (15,519) | 15,387 |
|
|
|
|
|
|
|
|
Loss for the year |
|
|
|
|
| (1,659) | (1,659) |
Decrease in value of Available for sale assets |
|
|
|
| (577) |
| (577) |
Total comprehensive income | - | - | - | - | (577) | (1,659) | (2,236) |
Share issue | 86 | - | 4,464 | - | - | - | 4,550 |
Cost of share issue | - | - | (274) | - | - | - | (274) |
Share-based payment charge | - | - | - | 196 | - | - | 196 |
Total contributions by and distributions to owners of the Company | 86 | - | 4,190 | 196 | - | - | 4,472 |
|
|
|
|
|
|
|
|
Balance at 31 December 2017 | 785 | 1,831 | 31,749 | 1,129 | (693) | (17,178) | 17,623 |
Notes to the financial statements for the year ended 31 December 2017
1 | Summary of significant accounting policies |
|
|
General information and authorisation of financial statements
|
|
| Solo Oil plc is a public limited company incorporated in England & Wales. The address of its registered office is Suite 3B, Princes House, 38 Jermyn Street, London SW1Y 6DN. The Company's ordinary shares are traded on the AIM Market operated by the London Stock Exchange. The financial statements of Solo Oil plc for the year ended 31 December 2017 were authorised for issue by the Board on 28 June 2018 and the balance sheet signed on the Board's behalf by Mr Daniel Maling and Mr Neil Ritson.
|
|
| Investing policy Solo's Investing Policy is to acquire a diverse portfolio of direct and indirect interests in exploration, development and production oil and gas assets, and any other subsurface gas assets of potential commercial significance, located worldwide but predominantly in the Americas, Europe or Africa.
The Company (Solo) may invest by way of outright acquisition or by the acquisition of assets, including the intellectual property, of a relevant business, partnerships or joint venture arrangements. Such investments may result in the Company acquiring the whole or part of a company or project (which in the case of an investment in a company may be private or listed on a stock exchange, and which may be pre-revenue), may constitute a minority stake in the company or project in question and may take the form of equity, joint venture debt, convertible instruments, licence rights, or other financial instruments as the Directors deem appropriate.
Solo intends to be a long-term investor and the Directors will place no minimum or maximum limit on the length of time that any investment may be held.
There is no limit on the number of projects into which the Company may invest, nor the proportion of the Company's gross assets that any investment may represent at any time and the Company will consider possible opportunities anywhere in the world.
All of the Solo's assets will be held in its own name, or through wholly owned subsidiaries.
|
|
| Statement of compliance with IFRS |
|
| The financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union and as applied in accordance with the provisions of the Companies Act 2006. The principal accounting policies adopted by the Company are set out below.
|
|
| New standards, amendments and interpretations adopted by the Company
No new and/or revised Standards and Interpretations have been required to be adopted, and/or are applicable in the current year by/to the Company, as standards, amendments and interpretations which are effective for the financial year beginning on 1 January 2017 are not material to the Company.
New standards, amendments and interpretations not yet adopted
At the date of authorisation of these financial statements, the following Standards and Interpretations which have not been applied in these financial statements, were in issue but not yet effective for the year presented:
- IFRS 9 in respect of Financial Instruments which will be effective for the accounting periods beginning on or after 1 January 2018.
- IFRS 15 in respect of Revenue from Contracts with Customers which will be effective for accounting periods beginning on or after 1 January 2018.
- IFRS 16 in respect of Leases which will be effective for accounting periods beginning on or after 1 January 2019.
- IFRS 17 Insurance Contracts (effective date 1 January 2021).
There are no other IFRSs or IFRIC interpretations that are not yet effective that would be expected to have a material impact on the Company.
|
|
| Basis of preparation | |
| The financial statements have been prepared on the historical cost basis, except for the measurement to fair value of assets and financial instruments as described in the accounting policies below, and on a going concern basis. | |
|
The financial report is presented in Pound Sterling (£) and all values are rounded to the nearest thousand pounds (£'000) unless otherwise stated. | |
|
| |
|
| |
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| |
|
|
|
|
| Available for sale financial assets |
| Available-for-sale financial assets are non-derivative financial assets that are either designated to this category or do not qualify for inclusion in any of the other categories of financial assets. The Group's available-for-sale financial assets include unlisted securities. These available-for-sale financial assets are measured at fair value. Gains and losses are recognised in other comprehensive income and reported within the available-for-sale reserve within equity, except for impairment losses and foreign exchange differences, which are recognised in profit or loss. When the asset is disposed of or is determined to be impaired, the cumulative gain or loss recognised in other comprehensive income is reclassified from the equity reserve to profit or loss and presented as a reclassification adjustment within other comprehensive income. Interest calculated using the effective interest method and dividends are recognised in profit or loss within finance income |
|
Revenue recognition |
| Revenue is recognised to the extent that the right to consideration is obtained in exchange for performance. Payment received in advance of performance is deferred on the balance sheet as a liability and released as services are performed or products are exchanged as per the agreement with the customer.
Revenue is generated from one main source of income currently. In the current year, revenue is being generated from the Company's Farm-in interests, on an accrued monthly basis, along with the associated costs.
Revenue from the production of gas, in which the Company has an interest with other producers, is recognised based on the Company's working interest and the terms of the relevant production sharing contracts. Differences between gas lifted and sold and the Company's share of production are not significant. |
|
|
| Foreign currencies |
| Transactions in currencies other than Sterling are recorded at the rates of exchange prevailing on the dates of the transactions. At each balance sheet date, monetary assets and liabilities that are denominated in foreign currencies are retranslated at the rates prevailing on the balance sheet date. Gains and losses arising on retranslation are included in the income statement for the period.
|
|
Taxation |
| The tax expense represents the sum of the current tax and deferred tax. |
|
The current tax is based on taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it excludes items of income or expense that are taxable or deductible in other periods and it further excludes items that are never taxable or deductible. The liability for current tax is calculated by using tax rates that have been enacted or substantively enacted by the balance sheet date. |
|
Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amount of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the balance sheet liability method. Deferred tax liabilities are 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. Such assets and liabilities are not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction which affects neither the tax profit nor the accounting profit. |
|
|
| Intangible assets |
| Externally acquired intangible assets comprising deferred exploration and evaluation expenditure are initially recognised at cost in compliance with IFRS 6 "Exploration for and evaluation of mineral resources". |
|
The Company follows the successful efforts method of accounting for exploration and evaluation expenditure. All licence, acquisition, exploration and evaluation costs are capitalised in cost centres by area of interest pending determination of the commercial viability of the relevant prospect. |
|
|
|
|
|
|
| Impairment of tangible and intangible assets |
| At each balance sheet date the Group reviews the carrying amounts of its tangible and intangible assets to determine whether there is any indication that those assets have suffered an impairment loss. If there is such indication then an estimate of the asset's recoverable amount is performed and compared to the carrying amount. |
|
Recoverable amount is the higher of fair value less costs to sell and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value. Where the asset does not generate cash flows that are independent from other assets, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs. |
|
If the recoverable amount of an asset is estimated to be less that its carrying amount, the carrying amount of the asset is reduced to its recoverable amount. An impairment loss is recognised as an expense immediately, unless the relevant asset is carried at a re-valued amount, in which case the impairment loss is treated as a revaluation decrease. |
|
Where an impairment loss subsequently reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset in prior periods. A reversal of an impairment loss is recognised as income immediately, unless the relevant asset is carried at a re-valued amount, in which case the reversal of the impairment loss is treated as a revaluation increase.
|
| Oil and gas properties and other property, plant and equipment
(i) Initial recognition Oil and gas properties and other property, plant and equipment are stated at cost, less accumulated depreciation and accumulated impairment losses.
The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligation and, for qualifying assets (where relevant), borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. The capitalised value of a finance lease is also included within property, plant and equipment.
When a development project moves into the production stage, the capitalisation of certain construction/development costs ceases, and costs are either regarded as part of the cost of inventory or expensed, except for costs which qualify for capitalisation relating to oil and gas property asset additions, improvements or new developments.
(ii) Depreciation/amortisation Oil and gas properties are depreciated/amortised on a unit-of-production basis over the total proved developed and undeveloped reserves of the field concerned, except in the case of assets whose useful life is shorter than the lifetime of the field, in which case the straight-line method is applied. Rights and concessions are depleted on the unit-of-production basis over the total proved developed and undeveloped reserves of the relevant area.
The unit-of-production rate calculation for the depreciation/amortisation of field development costs takes into account expenditures incurred to date, together with sanctioned future development expenditure. An item of property, plant and equipment and any significant part initially recognised is derecognised upon disposal or when no future economic benefits are expected from its use or disposal. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is included in the statement of profit or loss and other comprehensive income when the asset is derecognised.
The asset's residual values, useful lives and methods of depreciation/amortisation are reviewed at each reporting period and adjusted prospectively, if appropriate.
(ii) Major maintenance, inspection and repairs Expenditure on major maintenance refits, inspections or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset, or part of an asset that was separately depreciated and is now written off is replaced and it is probable that future economic benefits associated with the item will flow to the Company, the expenditure is capitalised. Where part of the asset replaced was not separately considered as a component and therefore not depreciated separately, the replacement value is used to estimate the carrying amount of the replaced asset(s) and is immediately written off. Inspection costs associated with major maintenance programmes are capitalised and amortised over the period to the next inspection. All other day-to-day repairs and maintenance costs are expensed as incurred.
|
| Provision for rehabilitation / Decommissioning Liability The Company recognises a decommissioning liability where it has a present legal or constructive obligation as a result of past events, and it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of obligation can be made.
The obligation generally arises when the asset is installed or the ground/environment is disturbed at the field location. When the liability is initially recognised, the present value of the estimated costs is capitalised by increasing the carrying amount of the related oil and gas assets to the extent that it was incurred by the development/construction of the field. Any decommissioning obligations that arise through the production of inventory are expensed when the inventory item is recognised in cost of goods sold.
Changes in the estimated timing or cost of decommissioning are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to oil and gas assets. Any reduction in the decommissioning liability and, therefore, any deduction from the asset to which it relates, may not exceed the carrying amount of that asset. If it does, any excess over the carrying value is taken immediately to the statement of profit or loss and other comprehensive income.
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| Borrowings |
| Borrowings are recognised initially at fair value, net of any applicable transaction costs incurred. Borrowings are subsequently carried at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the income statement over the period of the borrowings using the effective interest method (if applicable).
Interest on borrowings is accrued as applicable to that class of borrowing. |
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| Provisions |
| Provisions are recognised for liabilities of uncertain timing or amounts that have arisen as a result of past transactions and are discounted at a pre-tax rate reflecting current market assessments of the time value of money and the risks specific to the liability. |
|
Financial instruments |
| Financial assets and financial liabilities are recognised on the balance sheet when the Company has become a party to the contractual provisions of the instrument |
|
Cash and cash equivalents |
| Cash and cash equivalents comprise cash in hand, cash at bank and short term deposits with banks and similar financial institutions. |
|
Trade and other receivables |
| Trade and other receivables do not carry any interest and are stated at their nominal value as reduced by appropriate allowances for estimated irrecoverable amounts. |
|
|
| Financial liability and equity |
| Financial liabilities and equity instruments are classified according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the assets of the Company after deducting all of its liabilities. |
|
|
| Trade and other payables |
| Trade and other payables are non interest bearing and are stated at their nominal value. |
|
Equity instruments |
| Equity instruments issued by the Company are recorded at the proceeds received, net of direct issue costs. |
|
|
| Share-based payments |
| Where share options are awarded to employees, the fair value of the options at the date of grant is charged to the income statement over the vesting period. Non-market vesting conditions are taken into account by adjusting the number of equity instruments expected to vest at each balance sheet date so that, ultimately, the cumulative amount recognised over the vesting period is based on the number of options that eventually vest. Market vesting conditions are factored into the fair value of the options granted. As long as all other vesting conditions are satisfied, a charge is made irrespective of whether the market vesting conditions are satisfied. The cumulative expense is not adjusted for failure to achieve a market vesting condition. |
|
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 income statement over the remaining vesting period. |
| Where equity instruments are granted to persons other than employees, the income statement is charged with the fair value of goods and services received. Equity-settled share-based payments are measured at fair value at the date of grant except if the value of the service can be reliably established. The fair value determined at the grant date of equity-settled share-based payments is expensed on a straight-line basis over the vesting period, based on the Company's estimate of shares that will eventually vest. |
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|
| Critical accounting estimates and judgements |
|
The Company makes estimates and assumptions regarding the future. Estimates and judgements are continually evaluated based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. In the future, actual experience may differ from these estimates and assumptions. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below. |
|
|
| Useful lives of intangible assets and property, plant and equipment |
| Intangible assets and property, plant and equipment are amortised or depreciated over their useful lives. Useful lives are based on the management's estimates of the period that the assets will generate revenue, which are based on judgement and experience and periodically reviewed for continued appropriateness. Changes to estimates can result in significant variations in the carrying value and amounts charged to the income statement in specific periods. |
|
|
| Share-based payments |
| The Company utilised an equity-settled share-based remuneration scheme for employees. Employee services received, and the corresponding increase in equity, are measured by reference to the fair value of the equity instruments at the date of grant, excluding the impact of any non-market vesting conditions. The fair value of share options are estimated by using Black-Scholes valuation method as at the date of grant. The assumptions used in the valuation are described in Note 17 and include, among others, the expected volatility, expected life of the options and number of options expected to vest. |
|
|
| Deferred taxation |
| Deferred tax assets are recognised when it is judged more likely than not that they will be recovered. |
|
|
| Hydrocarbon reserve and resource estimates Hydrocarbon reserves are estimates of the amount of hydrocarbons that can be economically and legally extracted from the Company's oil and gas properties. The Company estimates its commercial reserves and resources based on information compiled by appropriately qualified persons relating to the geological and technical data on the size, depth, shape and grade of the hydrocarbon body and suitable production techniques and recovery rates. Commercial reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of recoverable reserves and the proportion of the gross reserves which are attributable to the host government under the terms of the Production-Sharing Agreements. Future development costs are estimated using assumptions as to the number of wells required to produce the commercial reserves, the cost of such wells and associated production facilities, and other capital costs. The current long-term gas price assumption used in the estimation of commercial reserves currently held by the Company is US$3/MMTBU. The carrying amount of oil and gas development and production assets at 31 December 2017 is shown in Note 9.
The Company estimates and reports hydrocarbon reserves in line with the principles contained in the SPE Petroleum Resources Management Reporting System (PRMS) framework. As the economic assumptions used may change and as additional geological information is obtained during the operation of a field, estimates of recoverable reserves may change. Such changes may impact the Company's reported financial position and results, which include: · The carrying value of exploration and evaluation assets; oil and gas properties; property and plant and equipment may be affected due to changes in estimated future cash flows · Depreciation and amortisation charges in the income statement may change where such charges are determined using the Units of Production (UOP) method, or where the useful life of the related assets change · Provisions for decommissioning may require revision - where changes to the reserve estimates affect expectations about when such activities will occur and the associated cost of these activities |
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|
| Exploration and evaluation expenditures The application of the Company's accounting policy for exploration and evaluation expenditure requires judgement to determine whether future economic benefits are likely, from either future exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves. The determination of reserves and resources is itself an estimation process that involves varying degrees of uncertainty depending on how the resources are classified. These estimates directly impact when the Company defers exploration and evaluation expenditure. The deferral policy requires management to make certain estimates and assumptions about future events and circumstances, in particular, whether an economically viable extraction operation can be established. Any such estimates and assumptions may change as new information becomes available. If, after expenditure is capitalised, information becomes available suggesting that the recovery of the expenditure is unlikely, the relevant capitalised amount is written off in the income statement and in the period when the new information becomes available. |
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|
| Units of production (UOP) depreciation of oil and gas assets Oil and gas properties are depreciated using the UOP method over total proved developed and undeveloped hydrocarbon reserves. This results in a depreciation/amortisation charge proportional to the depletion of the anticipated remaining production from the field.
The life of each item, which is assessed at least annually, has regard to both its physical life limitations and present assessments of economically recoverable reserves of the field at which the asset is located. These calculations require the use of estimates and assumptions, including the amount of recoverable reserves and estimates of future capital expenditure. The calculation of the UOP rate of depreciation/amortisation will be impacted to the extent that actual production in the future is different from current forecast production based on total proved reserves, or future capital expenditure estimates change. Changes to the proved reserves could arise due to changes in the factors or assumptions used in estimating reserves, including: · The effect on proved reserves of differences between actual commodity prices and commodity price assumptions · Unforeseen operational issues |
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|
| Recoverability of oil and gas assets The Company assesses each asset or cash generating unit (CGU) each reporting period to determine whether any indication of impairment exists. Where an indicator of impairment exists, a formal estimate of the recoverable amount is made, which is considered to be the higher of the fair value less costs of disposal (FVLCD) and value in use (VIU). The assessments require the use of estimates and assumptions such as long-term oil prices (considering current and historical prices, price trends and related factors), discount rates, operating costs, future capital requirements, decommissioning costs, exploration potential, reserves (see (a) Hydrocarbon reserves and resource estimates above) and operating performance (which includes production and sales volumes). These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may impact the recoverable amount of assets and/or CGUs. |
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|
| Equity reserves |
| Share capital is determined using the nominal value of shares that have been issued.
The share premium account represents premiums received on the initial issuing of the share capital. Any transaction costs associated with the issuing of shares are deducted from share premium, net of any related income tax benefits.
The share based payment reserve represents the cumulative amount which has been expensed in the income statement in connection with share based payments, less any amounts transferred to retained earnings on the exercise of share options.
Available For Sale Financial Asset reserve represents the market value movement of AFS investments.
Retained earnings include all current and prior period results as disclosed in the income statement |
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| |
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| |
| Going Concern | |
| The Directors noted the losses that the Company has made for the Year Ended 31 December 2017. The Directors have prepared cash flow forecasts for the period ending 30 June 2019 which take account of the current cost and operational structure of the Company.
The cost structure of the Company comprises a high proportion of discretionary spend and therefore in the event that cash flows become constrained, costs can be quickly reduced to enable the Company to operate within its available funding.
These forecasts demonstrate that the Company has sufficient cash resources available to allow it to continue in business for a period of at least twelve months from the date of approval of these financial statements. Accordingly, the financial statements have been prepared on a going concern basis.
It is the prime responsibility of the Board to ensure the Company remains a going concern. At 31 December 2017 the Company had cash and cash equivalents of £378,000 and borrowings of £1,080,000. The Company has minimal contractual expenditure commitments and the Board considers the present funds sufficient to maintain the working capital of the Company for a period of at least 12 months from the date of signing the Annual Report and Financial Statements. For these reasons the Directors adopt the going concern basis in the preparation of the Financial Statements. | |
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| |
2 | Turnover and segmental analysis | |
| An operating segment is a distinguishable component of the Company that engages in business activities from which it may earn revenues and incur expenses, whose operating results are regularly reviewed by the Company's chief operating decision maker to make decisions about the allocation of resources and assessment of performance and about which discrete financial information is available. The chief operating decision maker has defined that the Company's only reportable operating segment during the period is that of oil & gas exploration & production.
The Company's current revenue is all generated in Tanzania from oil & gas production in accordance with its farm-in/profit sharing agreements, within Tanzania. However with this segment only in its second period of production, and with the only major related transactions being the carrying value of the oil & gas properties assets as described in Note 9, no further segmental analysis is deemed useful to disclose currently. This years revenue from this segment was £613,000 (2016: £501,000).
Subject to further acquisitions, the Company expects to further review its segmental information during the forthcoming financial year and update accordingly.
In respect of the total assets, £1,566,000 (2016: £2,541,000) arise in the UK, and £nil (2016: £300,000) arise in Canada, £17,156,000 arise in Tanzania (2016: £12,689,000), and £nil arise in Nigeria (2016: £576,000). | |
3 | Operating loss | Year ended 31 December 2017 £000's | Year ended 31 December 2016 £000's |
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|
|
| Loss from operations has been arrived at after charging: |
|
|
| Directors remuneration | 537 | 267 |
| Directors pension contribution | 12 | - |
| Salaries and national insurance | 101 | 77 |
| Audit fees | 15 | 13 |
| Share-based payments | 196 | 49 |
|
|
|
|
| Amounts payable to auditors and their associates in respect of both audit and non-audit services: |
|
|
| Audit services - statutory audit - Chapman Davis LLP | 15 | 13 |
|
| 15 | 13 |
4 | Employee information and directors emoluments |
|
|
|
| Year ended 31 December 2017 £000's | Year ended 31 December 2016 £000's |
| Staff information |
|
|
| The average number of employees (excluding executive directors) was : | 1 | 1 |
|
|
|
|
| Their aggregate remuneration comprised : |
| £000's |
| Wages and salaries | 40 | 40 |
| Total | 40 | 40 |
|
|
|
|
| Directors' remuneration |
|
|
| Total | 641 | 314 |
| Year ended 31 December 2017 | Salary and fees £000's | Share-based payments £000's | Pension contributions £000's | Total £000's |
| Neil Ritson | 125 | 46 | - | 171 |
| Don Strang | 19 | 38 | - | 57 |
| Dan Maling | 180 | 60 | - | 240 |
| Fergus Jenkins (including termination provision) | 213 | 46 | 12 | 271 |
|
| 537 | 190 | 12 | 739 |
| Year ended 31 December 2016 | Salary and fees £000's | Share-based payments £000's | Total £000's |
| Neil Ritson | 125 | 12 | 137 |
| Don Strang | 58 | 9 | 67 |
| Dan Maling (appointed 10 August 2016) | 24 | 15 | 39 |
| Fergus Jenkins | 40 | 11 | 51 |
| Sandy Barblett (resigned 10 August 2016) | 20 | - | 20 |
|
| 267 | 47 | 314 |
5 | Taxation | Year ended 31 December 2017 £000's | Year ended 31 December 2016 £000's |
| Current tax expense |
|
|
| UK corporation tax profits for the year | - | - |
| Total income tax expense | - | - |
| The reasons for the difference between the actual tax charge for the year and the standard rate of corporation tax in the UK applied to profits for the year are as follows: |
|
|
|
|
|
|
| Loss for the year | (1,659) | (524) |
| Standard rate of corporation tax in the UK | 19% | 20% |
| Loss on ordinary activities multiplied by the standard rate of corporation tax | (315) | (105) |
| Expenses not deductible for tax purposes | 94 | 70 |
| Future income tax benefit not brought to account | 221 | 35 |
| Current tax charge for year | - | - |
|
|
|
|
| No deferred tax asset has been recognised because there is uncertainty of the timing of suitable future profits against which they can be recovered. | ||
6(a) | Finance costs | Year ended 31 December 2017 £000's | Year ended 31 December 2016 £000's |
| Loan Interest | 12 | 2 |
| Finance fees | 114 | - |
| Losses on settled equity swap payments | - | 27 |
| Share-based payments | - | - |
| Total | 126 | 29 |
|
|
|
|
6(b) | Finance Income |
|
|
|
|
|
|
| Finance income of £66,000 represents interest receivable on the loan to Horse Hill Developments Ltd. |
|
|
|
|
|
|
7 | Loss per share | Year ended 31 December 2017 £000's | Year ended 31 December 2016 £000's |
|
|
|
|
| The calculation of loss per share is based on the loss after taxation divided by the weighted average number of shares in issue during the year with the comparative disclosure being restated to reflect the 1 for 20 share consolidation in July 2017. |
|
|
|
Net loss after taxation (£000's) | (1,659) | (524) |
| Number of shares |
|
|
|
|
|
|
| Weighted average number of ordinary shares for the purposes of basic loss per share (millions) | 384.7 | 304.6 |
| Basic and diluted loss per share (expressed in pence) | (0.43) | (0.17) |
|
As inclusion of the potential ordinary shares would result in a decrease in the loss per share they are considered to be anti-dilutive, as such, a diluted loss per share is not included. | ||
8 | Intangible assets - Deferred exploration and evaluation expenditure |
|
|
|
|
| Total £000's |
| Cost |
|
|
| As at 31 December 2015 |
| 13,750 |
|
|
|
|
| Additions |
| 1,597 |
| Transfer to Oil & Gas Properties - restated |
| (953) |
| As at 31 December 2016 - restated |
| 14,394 |
|
|
|
|
| Additions |
| 2,080 |
| As at 31 December 2017 |
| 16,474 |
|
|
|
|
| Accumulated amortisation and impairment |
|
|
| Balance at 31 December 2015 |
| 2,358 |
|
|
|
|
| Impairment charge |
| - |
| Balance at 31 December 2016 |
| 2,358 |
|
|
|
|
| Impairment charge |
| 300 |
| Balance at 31 December 2017 |
| 2,658 |
|
Net book value As at 31 December 2017 |
| 13,816 |
| As at 31 December 2016 - restated |
| 12,036 |
| Impairment Review
The additions to deferred exploration and evaluation expenditure during the period relate mainly to the completion of drilling operations for the Ntorya-2 appraisal and subsequent testing of the well.
The issue of an updated reserves and resource report by RPS Energy in February 2018 identified a new structure, Kiliwani South, in the Kiliwani North Development Licence block. Kiliwani South is reported as having a Pmean gross gas in place resource (GIIP) of 57 bcf in addition to the Kiliwani North structure of 30.8 bcf GIIP. The directors have assessed the impact of the new RPS Energy report and believe it is appropriate to reclassify past costs of £0.95 million previously recorded as Oil & Gas properties to exploration and evaluation expenditure.
Following a review of the carrying value and future prospects for Solo's Ausable Reef intangible it has been fully impaired at 31 December 2017. The resulting impairment charge is £0.30 million. |
9 | Oil & Gas properties |
|
|
|
|
| Total £000's |
| Cost |
|
|
| As at 31 December 2015 |
| - |
|
|
|
|
| Transfer from intangible assets - restated |
| 953 |
| As at 31 December 2016 - restated |
| 953 |
|
|
|
|
| Additions |
| - |
| As at 31 December 2017 |
| 953 |
|
|
|
|
| Accumulated amortisation and impairment |
|
|
| Balance at 31 December 2015 |
| - |
|
|
|
|
| Depreciation charge |
| 275 |
| As at 31 December 2016 |
| 275 |
|
|
|
|
| Depreciation charge |
| 484 |
| Balance at 31 December 2017 |
| 759 |
|
Net book value As at 31 December 2017 |
| 194 |
| As at 31 December 2016 - restated |
| 678 |
| The Oil & Gas properties comprise the 7.55% participating interest in the Kiliwani North Development Licence, in Tanzania.
As described in Note 8, the Directors have reclassified £0.95 million of previously capitalised expenditure relating to the Kiliwani North Development Licence to Intangibles. Accumulated amortisation has been calculated based on the February 2018 RPS Energy report which details 6.3 bcf of production to date and a remaining 2P reserve of 2 bcf currently accessible from the Kiliwani North-1 production well.
Impairment Review The Directors have carried out an impairment review as at 31 December 2017, and determined that an impairment charge is not currently required. The Directors based this assessment on continuing operational work schedules that are ongoing to improve operational efficiencies and production.
|
10 | Available for sale financial assets |
|
| ||
|
|
|
| 31 December 2017 | 31 December 2016 |
| Investment in listed and unlisted securities |
|
| £000's | £000's |
| Valuation at beginning of the year |
|
| 1,181 | 1,192 |
| Additions at cost |
|
| 2,626 | - |
| Disposal |
|
| (4) | - |
| Decrease in value of investments - Burj Africa |
|
| (577) | (11) |
| Valuation at the end of the year |
|
| 3,226 | 1,181 |
|
|
|
|
|
|
| The available for sale investments splits are as below: |
|
|
|
|
| Non-current assets - listed |
|
| - | 5 |
| Non-current assets - unlisted |
|
| 3,226 | 1,176 |
|
|
|
| 3,226 | 1,181 |
| Available-for-sale investments comprise investments in unlisted securities and are held by the Company as a mix of strategic and short term investments. |
Solo completed its acquisition of an initial 10% interest in Helium One on 22 March 2017 through the payment of £1.2 million in cash and the issue to Helium One of 236,842,105 (pre-consolidation) shares at an issue price of 0.54p in Solo Oil plc (10.8p post consolidation). Helium One owns exploration licences in a number of highly prospective, and extremely rare, helium properties in Tanzania.
Following a review of the carrying value and future prospects for Solo's Burj Africa has been fully impaired at 31 December 2017. The resulting impairment charge is £0.58 million.
11 | Subsidiary company |
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| The only subsidiary of Solo Oil Plc is Solo Oil International Limited a wholly-owned, UK incorporated micro-entity, which is dormant, and has been since incorporation with an issued share capital of £1. | ||
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|
|
12 | Trade and other receivables |
|
| ||
|
|
|
| 31 December 2017 | 31 December 2016 |
| Current trade and other receivables |
|
| £000's | £000's |
| Trade receivables |
|
| 336 | 583 |
| Loan to Horse Hill Developments Ltd |
|
| 749 | 658 |
| Prepayments |
|
| 28 | 14 |
| Other debtors |
|
| 282 | 81 |
|
|
|
| 1,395 | 1,336 |
|
|
|
|
|
|
| The directors consider that the carrying amount of trade and other receivables approximates to their fair value. | ||||
13 | Derivative financial instrument |
|
| ||
|
|
|
| 31 December 2017 | 31 December 2016 |
| Equity Swap |
|
| £000's | £000's |
| Fair value at 1 January |
|
| - | (314) |
| Settlements during the year |
|
| - | 450 |
| (Losses) on settlements |
|
| - | (136) |
| Provision at 31 December |
|
| - | - |
| Fair value at 31 December |
|
| - | - |
|
|
|
|
|
|
|
During the year ended 31 December 2016, the Company settled the swap for a total of £450,000 paid to YAGM, no further Swap arrangements have been entered into by the Company.
| ||||
14 | Trade and other payables |
|
| ||
|
|
|
| 31 December 2017 | 31 December 2016 |
| Current trade and other payables |
|
| £000's | £000's |
| Trade payables |
|
| 162 | 404 |
| Other payables |
|
| 34 | 18 |
| Accruals |
|
| 128 | 22 |
|
|
|
| 324 | 444 |
|
|
|
|
|
|
| The directors consider that the carrying amount of trade payables approximates to their fair value. | ||||
15 | Borrowings |
|
| |||||
|
|
|
| 31 December 2017 | 31 December 2016 | |||
| Convertible Loan Note |
|
| £000's | £000's | |||
| First tranche drawn down of US $1.5m |
|
| 1,080 | - | |||
|
|
|
| 1,080 | - | |||
|
|
|
|
|
| |||
| The repayment terms of the convertible loan from Riverfort Global Ltd are:
Each tranche carries an 18 month term with each tranche having a 3 month repayment holiday followed by repayment of 10% of the gross amount of principal per month such that 30% of the gross principal remains outstanding at the end of 12 months.
The convertible loan has an interest rate charge of 8% per annum of gross amount provided and is unsecured.
The first tranche of gross US $1.5m was drawn down in November 2017. On 18 June 2018 an exercise for conversion of US $116,168 into equity was received with a resulting allotment of 3,394,747 new ordinary shares at a conversion price of 2.56p per share. | |||||||
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| |||||
| 16 | Share capital |
| |||||
|
|
| Number of shares | Nominal value | ||||
|
|
|
| £000's | ||||
|
| a) Called up, allotted, issued and fully paid: Ordinary shares of 0.01p each |
|
| ||||
|
| As at 31 December 2015 | 5,556,580,571 | 556 | ||||
|
|
|
|
| ||||
|
| 7 April 2016 - Placing for cash at 0.25p | 320,000,000 | 32 | ||||
|
| 23 September 2016 - Placing for cash at 0.18p | 1,111,111,111 | 111 | ||||
|
| As at 31 December 2016 | 6,987,691,682 | 699 | ||||
|
|
| ||||||
|
| 16 February 2017 - Placing for cash at 0.5p | 400,000,000 | 40 | ||||
|
| 22 March 2017 - Placing for cash at 0.54p | 222,222,222 | 22 | ||||
|
| 22 March 2017 - Part acquisition of investments in Helium One Ltd at 0.57p | 236,842,105 | 24 | ||||
|
|
|
|
| ||||
|
| As at 30 June 2017 | 7,846,756,009 | 785 | ||||
|
|
| ||||||
|
| In July 2017 the ordinary shares of 0.01p each were the subject of a 1 for 20 share consolidation via the creation of new ordinary shares of 0.2p each. There were no further issue of shares in the period to 31 December 2017 so the called up, allotted, issued and fully paid new ordinary shares of 0.2p each totalled:- | ||||||
|
|
| ||||||
|
| As at 31 December 2017 392,337,801 785 | ||||||
|
|
| ||||||
|
| b) Deferred shares | ||||||
|
| Deferred shares of 0.69 pence each (2016: 265,324,634) | 265,324,634 | 1,831 | ||||
|
|
| ||||||
| c) Total Share options in issue |
|
| |||
| During the year no options were granted (2016: 212,500,000 pre-consolidation). As at 31 December 2017 the unexercised options in issue were restated as: |
|
|
| ||
Exercise Price (original) | Amended | Expiry Date | Amended | Original Options in Issue 31 December 2017 |
1.54p | 30.8p | 30 April 2018 | 350,000 | 7,000,000 |
0.5p | 10p | 31 December 2020 | 10,200,000 | 204,000,000 |
0.5p | 10p | 31 December 2020 | 3,425,000 | 68,500,000 |
0.3p | 6p | 31 December 2020 | 5,000,000 | 100,000,000 |
0.35p | 7p | 31 October 2021 | 10,625,000 | 212,500,000 |
|
|
| 29,600,000 | 592,000,000 |
|
|
|
|
|
| d) Total warrants in issue |
|
|
| No warrants lapsed or were cancelled or exercised during the year (2016: nil). As at 31 December 2016 the 31,952,777 warrants at 1.2p & 0.69p per share were outstanding and these warrants at their restated amounts were 1,597,638 at 24p & 13.8p. During the year the Company issued no options but did issue 3,500,000 warrants in relation to loan draw-down financing, however, no related finance charge has been incurred as a result of the warrants granted as the fixed conversion price is 7.25p over the 3 year term. | ||
17 | Share based payment | |||||||
|
| |||||||
| The Company used the Black-Scholes model to determine the value of the options and the inputs were as follows: | |||||||
|
|
| Issue 1/11/2016 |
| ||||
| Share price at grant (pence) |
| 0.21 |
|
|
| ||
| Fair Value price at grant (pence) |
| 0.12 |
|
|
| ||
| Expected volatility (%) |
| 82.2% |
|
|
| ||
| Expected life (years) |
| 5 years |
|
|
| ||
| Risk free rate (%) |
| 0.61% |
|
|
| ||
| Expected dividends (pence) |
| nil |
|
|
| ||
|
|
|
|
|
|
| ||
| Expected volatility was determined by using the Company's share price for the preceding 12 months. | |||||||
|
|
|
|
|
|
| ||
| The total share-based payment expense in the year for the Company was £196,000 expense in relation to options (2016: £49,000) and £nil finance charges in relation to warrants (2016: nil). | |||||||
|
| |||||||
| Employee Benefit Trust | |||||||
| The Company established on 7 December 2012, an employee benefit trust called the Solo Oil Employee Benefit Trust ("EBT") to implement the use of the Company's existing share incentive plan over 5% of the Company's issued share capital from time to time in as efficient a manner as possible for the beneficiaries of that plan. The EBT is a discretionary trust for the benefit of directors and employees of the Company and its subsidiaries.
No further subscriptions for shares in the Company has been made by the EBT during the years ended 31 December 2017 and 2016. | |||||||
18 | Financial instruments |
| The Company is exposed through its operations to one or more of the following financial risks: |
| · Fair value or cash flow interest rate risk |
| · Foreign currency risk |
| · Liquidity risk |
| · Credit risk |
| · Market risk |
|
Policy for managing these risks is set by the Board. The policy for each of the above risks is described in more detail below. |
|
Fair value and cash flow interest rate risk |
| The Company currently has a convertible loan facility which incurs interest at 8% per annum. Generally the Company has a policy of holding debt at a floating rate. The directors will revisit the appropriateness of this policy should the Company's operations change in size or nature. Operations are not permitted to borrow long-term from external sources locally. |
|
Foreign currency risk |
| Foreign exchange risk arises because the Company has operations located in various parts of the world whose functional currency is not the same as the functional currency in which the company's investments are operating. The Company's net assets are exposed to currency risk giving rise to gains or losses on retranslation into sterling. Only in exceptional circumstances will the Company consider hedging its net investments in overseas operations as generally it does not consider that the reduction in volatility in consolidated net assets warrants the cash flow risk created from such hedging techniques. |
|
Liquidity risk |
| The liquidity risk of each entity is managed centrally by the treasury function. Each operation has a facility with treasury, the amount of the facility being based on budgets. The budgets are set locally and agreed by the board annually in advance, enabling the cash requirements to be anticipated. Where facilities of entities need to be increased, approval must be sought from the finance director. Where the amount of the facility is above a certain level agreement of the board is needed. |
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All surplus cash is held centrally to maximise the returns on deposits through economies of scale. The type of cash instrument used and its maturity date will depend on the forecast cash requirements. |
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Credit risk |
| The Company is mainly exposed to credit risk from credit sales. It is Company policy, implemented locally, to assess the credit risk of new customers before entering contracts. Such credit ratings are taken into account by local business practices.
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| The Company does not enter into complex derivatives to manage credit risk, although in certain isolated cases may take steps to mitigate such risks if it is sufficiently concentrated. |
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Market risk |
| As the company is now investing in listed companies, the market risk will be that of finding suitable investments for the company to invest in and the returns that those investments will return given the markets that in which investments are made. |
19 | Related party transactions | ||||||||
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The Company had the following amounts outstanding from its investee companies (Note 10) at 31 December:
The above loan outstanding is included within trade and other receivables, Note 12. The loan to Horse Hill has been made in accordance with the terms of the investment agreement whereby it accrues interest daily at the Bank of England base rate and is repayable out of future cash flows.
There were no transactions between the parent and its dormant subsidiary, which are related parties, during the year. Details of director's remuneration, being key personnel, are given in Note 4.
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| Remuneration of Key Management Personnel
The remuneration of the directors, and other key management personnel of the Company, is set out below in aggregate for each of the categories specified in IAS24 Related party Disclosures. | ||||||||
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| Year ended | Year ended | ||||||
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| 31 December 2017 | 31 December 2016 | ||||||
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| £'000s
| £'000s
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| Short-term employee benefits | 479 | 317 | ||||||
| Share-based payments | 190 | 47 | ||||||
| Termination provision | 98 | - | ||||||
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| 767 | 364 | ||||||
20 | Ultimate controlling party |
| In the opinion of the directors there is no controlling party. |
21 | Retirement benefit scheme |
| The Company does not operate either a defined contribution or defined benefit retirement scheme. |
22 | Commitments |
| As at 31 December 2017, the Company had no material commitments. |
23 | Post balance sheet event |
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During February 2018 the Company raised £2 million before expenses by the issue of 57,142,857 new ordinary shares of 0.2p each at a price of 3.5p per Placing share. The net proceeds from the Fundraising will be used to fund the Company's acquisition of an additional 5% equity interest in Horse Hill Developments Limited ("HHDL"), as well as working capital for work programmes within the Company's existing investments and optional capital to invest during 2018 in new high value-low entry cost ventures that complement and expand the Company's portfolio.
On 27 February 2018, Solo acquired an additional 5% of HHDL from Primorus Investments Plc for an aggregate consideration of £1 million; made up of £650,000 in cash and 9,973,011 new ordinary Solo shares. Solo now holds a 15% interest in HHDL and an effective 9.75% interest in the Horse Hill licences PEDL137 and PEDL246.
On 2 May 2018, Mr Jon Fitzpatrick was appointed to the board as a non-executive director.
On 18 June 2018, the Company announced that, in relation to the US$5m Convertible Loan facility previously announced on 14 November 2017 and the US$1.5m advance drawn at that time, it has now received a notice of exercise from YA II PN Ltd and Cuart Investments PCC Ltd (the "Investors") to convert a small portion of the Loan, with an aggregate par value of US$116,168, into equity equating to a conversion price of 2.56p per share. The Company, therefore, allotted 3,394,747 new ordinary shares to the Investors ("Investor Shares"). The Investor Shares will rank pari passu in all respects with the existing ordinary shares. After the conversion and previous repayments, the Par Value outstanding on the Loan is US$1.15 million.
On 21 June 2018, the Company announced an update on its Helium One available for sale investment. Following Helium One's pre-IPO funding round of US$2m Solo now holds 18.7 million shares in Helium One Limited equivalent to a 13.8% interest. On the basis of the pre-IPO funding round pricing of US$0.20 per share Solo's interest is now valued at £2.84 million; in excess of the £2.55 million acquisition cost paid in March 2017.
Note to the announcement: The financial information set out above does not constitute the Company's statutory accounts for the years ended 31 December 2017 or 2016. The financial information for the year ended 31 December 2016 is derived from the statutory accounts for that year. The audit of statutory accounts for the year ended 31 December 2017 is complete.
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