Report and Accounts for Year End 30 September 2017
UK Oil & Gas Investments PLC
("UKOG" or the "Company")
Annual Report and Accounts for the year ended 30 September 2017
UK Oil & Gas Investments PLC (AIM: UKOG) the oil & gas investment company, announces that it has posted its Annual Report and Accounts for the year ended 30 September 2017 to shareholders along with the notice of its Annual General Meeting. Included below is the full text of the Annual Report and Accounts for the year ended 30 September 2017, which has been posted to shareholders and is available on our website at http://www.ukogplc.com/ul/UKOG%20Annual%20Report%202017.pdf
UK Oil & Gas Investments PLC
Annual Report and Accounts
For the year ended 30 September 2017
Forward-looking Statement
This annual report contains 'forward-looking information', which may include, but is not limited to, statements with respect to the future financial and operating performance of UK Oil & Gas Investments PLC, its subsidiaries, investment assets and affiliated companies, the estimation of oil reserves or resources, the realisation of resource estimates, costs of production, capital and exploration expenditures, costs and timing of the development of new assets, requirements for additional capital, governmental regulation of operations and exploration operations, timing and receipt of approvals, licenses, environmental risks, title disputes or claims.
Often, but not always, forward-looking statements can be identified by the use of words such as 'plans', 'expects', 'is expected', 'budget', 'scheduled', 'estimates', 'forecasts', 'intends', 'anticipates' or 'believes', or variations (including negative variations) of such words and phrases, or state that certain actions, events or results 'may', 'could', 'would', 'might' or 'will' be taken, occur or be achieved. Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of UK Oil & Gas Investments PLC and/or its subsidiaries, investment assets and/or its affiliated companies to be materially different from any future results, performance, or achievements expressed or implied by the forward-looking statements.
Such factors include, among others, general business, economic, competitive, political and social uncertainties; the actual results of current exploration activities; conclusions of economic evaluations and studies; fluctuations in the value of UK Pounds Sterling relative to the United States Dollar, and other foreign currencies; changes in project parameters as plans continue to be refined; future prices of products; possible variations recovery rates; failure of plant, equipment or processes to operate as anticipated; accidents, labour disputes and other risks of the oil and gas industry; political instability, adverse weather conditions, insurrection or war; delays in obtaining governmental approvals or financing or in the completion of development or construction activities.
Although UK Oil & Gas Investments PLC has attempted to identify important factors that could cause actual actions, events or results to differ materially from those described in forward-looking statements, there may well be other factors that cause actions, events or results to differ from those currently anticipated, estimated or intended.
Forward-looking statements contained herein are made as of the date of this annual report and UK Oil & Gas Investments PLC disclaims any obligation to update any forward-looking statements, whether as a result of new information, future events or results or otherwise. There can be no assurance that forward-looking statements will prove to be accurate, as actual results and future events could differ materially from those anticipated in such statements. Accordingly, readers should not place undue reliance on forward-looking statements due to the inherent uncertainty therein. Nothing in this annual report should be construed as a profit forecast.
STRATEGIC REPORT FOR THE YEAR ENDED 30 SEPTEMBER 2017
HIGHLIGHTS
· Broadford Bridge-1 step-out exploration well was spudded in May 2017 within UK Oil and Gas Investments PLC's ("UKOG's") 100% owned, 300 km2 PEDL234 Weald Basin licence. A successful sidetrack BB-1z was drilled within 6 days.
· Oil flowed continuously on pump from the Kimmeridge Limestone ("KL") 5 test zone together with the recovery of oil and gas to surface from multiple flow tests. Most extensive testing ever of an onshore exploration well conducted over 1000 plus feet of perforations.
· The oil discovery provides "proof of concept" for the Kimmeridge continuous oil deposit and proves further evidence to support a regionally extensive natural-fracture network capable of delivering oil to surface from the KL without reservoir stimulation.
· This financial year's (2018) imminent long-term Portland and KL flow testing and appraisal drilling programme at Horse Hill (operated by Horse Hill Developments Ltd) will follow up on the successful flow test results of early 2016, where an aggregate stabilised natural flow rate of 1,688 barrels of oil per day was achieved from three Portland and KL zones.
· The Horse Hill testing and subsequent drilling programme is geared towards delivering both conventional Portland oil production and the KL's first commercially viable stable oil production in 2019.
· UKOG's total gross attributable P50 Kimmeridge Clay Formation ("KCF") oil in place ("OIP") increased by 72% to 17.1 billion barrels in Weald Basin licence interests.
· Total UKOG net attributable KL OIP increased by 348% to 2.4 billion barrels via the 100% Broadford Bridge (PEDL234) acquisition.
· PEDL234 KCF P50 OIP was calculated by Nutech as 7.1 billion barrels, of which 1.7 billion barrels lie within the KL.
· HH-1 Portland oil discovery's OIP increased by 53% to 32 million barrels. Gross 2C contingent resources were estimated as 1.5 million barrels with further significant recoverable resource upside via early water re-injection.
For further information, please contact:
UK Oil & Gas Investments PLC
Stephen Sanderson / Kiran Morzaria Tel: 01483 243450
WH Ireland (Nominated Adviser and Broker)
James Joyce / James Sinclair-Ford Tel: 020 7220 1666
Cenkos Securities PLC (Joint Broker)
Joe Nally / Neil McDonald Tel: 0207 397 8919
Public Relations
Brian Alexander / David Bick Tel: 01483 243450
STATEMENT FROM THE CHAIRMAN
2017 has been a transformational year for UKOG. We have continued to build a spread of investments, focused on UK onshore oil assets centred upon our exciting and industry-leading position in the Weald Basin's Kimmeridge Limestone ("KL") oil play. These investments are underpinned by further discovered oil resources outside the KL play contained within five low-risk undeveloped oil and gas discoveries, which alone contain recoverable resources of over 14 million barrels net to the Company.
Our investment portfolio delivers a good balance of risk-reward between the KL's higher risk-higher reward growth potential and the lower risk-moderate reward of proven conventional oil discoveries.
PEDL 234 - Broadford Bridge
The potential and further understanding of the KL oil play has been our prime focus over the past year. The Broadford Bridge-1 and 1z ("BB-1/1z") oil discovery, located in the Weald's largest single licence, the 300 km² PEDL234, 100% UKOG owned and operated by Kimmeridge Oil and Gas Limited ("KOGL"), delivered on its technical objectives, namely: "proof of concept" for the existence of a continuous oil deposit within the Kimmeridge section, the determination of the deposit's lateral extent and supporting evidence for a regionally extensive natural fracture system within Kimmeridge Limestones. Importantly, the fracture system was shown to deliver oil to surface without the need for reservoir stimulation utilising massive hydraulic fracturing ("fracking").
The BB-1/1z exploration well, for which operations ceased in March 2018, was a bold 27 km step-out from HH-1, designed to provide proof of our geological concept that oil within the KL, as demonstrated at the Company's Horse Hill-1 discovery ("HH-1"), was part of a regionally extensive continuous oil deposit. Since the two prior Weald Basin wells which tested and recovered Kimmeridge oil to surface, HH-1 and Balcombe-1, were drilled within well-defined mapped conventional structural features, it was necessary to demonstrate that the BB-1/1z location, without any discernible conventional hydrocarbon trapping configuration (i.e. no structural or stratigraphic closure) contained moveable oil within the Kimmeridge.
Consequently, the multiple live, mobile oil shows seen in cuttings and drilling fluids, light oil seen in open fractures in cores, the recovery of oil and gas to surface from KL1 to KL4 flow tests, together with the light oil flowed continuously to surface from the KL5 test zone, presents further compelling evidence that the Upper Jurassic Kimmeridge of the central Weald Basin contains an extensive continuous oil accumulation. We believe that the data provided from BB-1/1z and analysed to date provides us proof of geological concept.
These live, mobile oil occurrences, together with corresponding rock and electric log data likely demonstrate a KL oil deposit of up to 1400 ft vertical extent exists at BB-1z. Geochemical analyses further support this proof of concept, as all oil samples from both BB-1z and HH-1 analysed to date are determined by Geomark Research to come from the same Upper Jurassic shale source, i.e. the oil lies within or immediately adjacent to the Upper Jurassic rocks where it was generated, one of the fundamental characteristics of a continuous oil accumulation.
The flow test campaign also contributed significantly to our understanding of the Kimmeridge play. Flow test inflows and pressure data, together with the specialist analysis of formation image log and core fractures, also demonstrated that the Kimmeridge contains both a local and regionally developed natural-fracture system, key to the future commercial viability of the KL deposit. These fractures are present in both limestones and shales.
Significantly, prior to the testing campaign these fracture-related data showed the key fracture sets to be open, i.e. likely able to transmit fluids under reservoir conditions. Consequently, neither the drilling fluid nor drilling and coring methodology appears to have "damaged" the reservoir (i.e. blocked or plugged fractures surrounding the well bore). As to whether these fractures remained fully or partly open during the necessary pressure draw-downs following acidisation used during testing is currently under investigation.
The ability of these fractures to deliver hydrocarbons to surface at BB-1z without stimulation (i.e. without "fracking") was demonstrated by both the KL5 test and by high initial instantaneous flow-back rates from the KL4 and KL3 test zones of 466 and 719 barrels of fluid per day respectively.
The finding of near identical reservoir geology and geochemistry between HH-1 and BB-1/1z also provided a valuable understanding that the Kimmeridge oil deposit stretches around 30 km across the Weald basin from the north-east at Horse Hill to the southern edge of our 100% PEDL234 Licence, with BB-1/1z likely lying on the deposit's southernmost boundary.
It is worth noting that since BB-1 lies in the extreme south of PEDL234, the well also demonstrates that most of the licence lies within the deposit's most prospective sweet spot. It is in this area where the Upper Jurassic shales are thickest, most deeply buried and have likely generated the most significant volumes of in-situ hydrocarbons.
Consequently, in the light of significant positive technical learnings and understanding of the wider KL deposit gained from BB-1/1z, the Company has accelerated its PEDL 234 drilling plans. We have now selected two further drilling sites in the central area of the licence, the first of which, subject to regulatory approval, should commence drilling in 2019. The required necessary planning application and Environment Agency ("EA") application are currently in preparation and are scheduled to be submitted by the summer.
Whilst the KL flow rates observed to date are likely sub-commercial, we are encouraged by the multiple occurrences of mobile oil observed in the well and their correlation with good calculated oil saturations in electric logs and core analyses. Consequently we are currently exploring new methods and technologies that might enable us to achieve higher sustainable oil rates and commercial viability from the 1400 vertical feet of oil-saturated KL reservoir rock interpreted at BB-1z.
With this in mind, serious consideration is being given to a possible future short sidetrack, BB-1y. The sidetrack's objective would include a selective re-test of the main KL units, likely utilising an alternate completion methodology, new completion fluids, the possible use of small-bore radial drilling and other reservoir stimulation techniques. Any future work at BB-1/1z would likely take place after a successful trial of such alternate methods and technologies in the next planned PEDL234 exploration well. Such future operations will require further in-depth study of the vast amount of data collected during drilling, coring, electric logging and testing before any conclusions can be finalised.
It is worth reflecting that, to date, the first two wells of UKOG's KL exploration programme, HH-1 and this year's BB-1/1z have produced Kimmeridge oil to the surface. This is no mean feat for a new play, particularly one involving both the first large-scale potential continuous oil deposit identified in the UK and one reliant on flowing oil to surface via naturally fractured reservoir rocks. Prior to these two wells, only one well (the 1986 Balcombe-1 well) within the Weald Basin's central thousand square mile area had tested the Kimmeridge reservoir, returning Kimmeridge oil to the surface.
PEDL137 - Horse Hill
This financial year's imminent long-term KL flow testing and appraisal drilling programme at Horse Hill (operated by Horse Hill Developments Ltd) will follow up on the successful flow test results of early 2016, where an aggregate stabilised natural flow rate of 1,688 barrels of oil per day was achieved from the Portland and two KL reservoir zones, KL3 and KL4.
The Horse Hill testing programme is solely geared towards determining the commerciality of both the conventional Portland oil accumulation and the continuous oil deposit within KL3 and KL4. The subsequent drilling phase, contingent upon a successful testing outcome will prepare the way for full time production at Horse Hill. If the programme is successful it is planned that Horse Hill will deliver stable oil production in 2019, subject to obtaining the necessary regulatory consents. Although the HH-1 well is not intended to be an immediate producer, any oil produced from the tests will, of course, be sold. Sales volumes are not incorporated into budgetary planning, but a successful testing outcome would generate further oil sales revenues for the Company.
Other Weald Basin and SE England Investments
The significant growth potential of the overall KL play in our portfolio is also solidly underpinned by oil within five other low-risk undeveloped oil discoveries. These discoveries contain third-party audited recoverable resources of over 14 million barrels net to UKOG (excludes discovered oil in the KL play and Godley Bridge Portland gas). Of these recoverable resources over half lie within the Horse Hill and Arreton (Isle of Wight) conventional Portland discoveries, both the subject of ongoing operational activities and investment. As stated above, first-oil from the Horse Hill Portland discovery is planned in 2019.
In the light of the "KL proof of concept" by BB-1/1z, UKOG's planned forward KL programme will now see a doubling of the Weald's drilled and tested Kimmeridge wells, with three more planned exploration step-out wells over the next 18 months, at Horse Hill, in PEDL234 (subject to regulatory approvals) and the Holmwood prospect (operated by Europa Oil & Gas).
Outlook
The key to maximising UKOG's growth remains a combination of the KL oil exploration play, which will continue to be our flagship for the foreseeable future, balanced by low-risk appraisal and development projects such as the Horse Hill Portland and Arreton Portland discoveries. The importance of our conventional assets should not be underestimated. Whilst the KL offers the potential of around 1,000 barrels per day per well if Horse Hill can be widely replicated, both Arreton and Horse Hill Portland potentially offer low-risk gross flow rates of several hundred barrels per day per well in the first year of production.
Our industry leading flagship KL programme's goal is to demonstrate that the play can generate economic returns and is repeatable over most of UKOG's 672 gross km² licence holding in the basin's "sweet spot". This is the largest KL licence holding of any company. Whilst the play is still developing, the goals of our investee companies are simple:
· Demonstrate commercial viability from one, possibly two, wells at Horse Hill in 2018. If this is successful and funding is forthcoming, move Horse Hill into long-term commercial production in 2019.
· Demonstrate that the KL sequence is commercially viable across three other locations in the Weald basin: Holmwood and two further wells in PEDL234. All of these will be subject to the relevant regulatory approvals and sufficient funding.
· Define and secure a batch of new drill sites, submit 'batch' planning consent applications to ensure a "hopper" of ready to drill locations.
· Consider submitting production planning applications immediately post-discovery and prior to commercial declaration. This will help deliver production from each well as early as regulatory permitting allows.
· Further consolidate our holdings in discoveries and developments, where possible, and acquire further prospective acreage and opportunities.
Planning permissions are in place for the full Horse Hill long-term testing and appraisal programme and Holmwood well. At the time of writing our investee companies are forecast to be able to asses commerciality in Q2 of 2018 and 2019 respectively.
For our non-KL discoveries, our focus will be firmly upon Horse Hill Portland and Arreton on the Isle of Wight. In a similar fashion to the KL strategy, we already have Horse Hill planning permission and EA permits in place to enable us to test the Portland in HH-1 and drill the necessary HH-2 well. At Arreton, a well site is being secured, and planning/permit application prepared. In the success case, production will be achieved as soon as the regulatory system allows, but it is envisaged that Arreton will be drilled in 2019.
We will continue to review, rank, prune and add to our investment portfolio to ensure our resources are employed only on the most technically and economically viable projects. This process was recently evidenced by the removal of the offshore Isle of Wight P1916 from the portfolio due to low technical prospectivity and the selected drill site's environmental sensitivity.
Corporate
During the financial year, UKOG raised gross proceeds of £7.46 million via the issue of equity which in addition to the £2.44 million in cash was used to fund £8.7 2 million of investment in exploration and evaluation assets, at the end of the year the Company had £1.74 million in cash and cash equivalents.
Cenkos Securities plc were appointed as UKOG's joint broker, and they were instrumental in the equity fund raise from a mix of institutional and retail investors which has partly funded Broadford Bridge. Subsequent to the year-end UKOG raised £10 million in convertible debt of which £5.25 million was outstanding at the date of the publication of this report.
Sadly, in November 2016, Jason Berry a director of the Company died suddenly following a short illness, Jason joined the Board in August 2014 and was instrumental in providing a firm financial footing for the early growth of the Company.
In March 2017, Allen Howard was appointed as Non-Executive Director of the Company. Allen has brought a wealth of technical expertise in well analysis and completions, huge experience and knowledge from the US onshore sector, plus a global network of industry and finance contacts. He is a hugely valuable addition to our team to help move our KL exploration and conventional assets into production.
The social licence obtained via our positive engagement process and good practices led to swift and unopposed grants of planning consent for BB-1/1z's flow testing extension and the extensive flow testing and appraisal programme at Horse Hill. My congratulations go to our entire team for the open, honest and professional way they have communicated with our neighbours and stakeholders.
Our operations and related technical analyses have also further demonstrated our commitment to fully understanding our assets. The extensive data acquisition programme of BB-1/1z has provided us with invaluable new insights into the key controls on the play and, consequently, represents a sound investment fundamental to our future success. We have continued to work with global experts, such as Chemostrat Inc., Geomark Research, Halliburton, Nutech, Premier Oil Field Laboratories, Schlumberger and Xodus Group, together with internationally recognised academic institutions such as Imperial College, London and the University of Utah's Exploration Geoscience International, to provide us with the best advice to help turn our ideas and oil discoveries into economic reality.
The progress made during 2017 would not have been possible without the efforts of UKOG's management team, consultants, supportive shareholders and other stakeholders. We would like to take this opportunity to thank all of them as we continue to deliver our strategy.
STRATEGY & BUSINESS MODEL
UKOG is an oil and gas investment company which specialises in investing in new geological ideas, concepts and methodologies to find and produce oil from previously unexplored rock formations within established oil-producing basins. Since relisting on London's AIM market ("AIM") at end-2013, driven initially by the successful Horse Hill Portland and Kimmeridge oil discoveries in 2014, our UK-focused asset acquisitions and successful investee drilling programme has made UKOG one of the most recognised and stand-out players in the entire UK onshore sector.
UKOG has a portfolio of direct and indirect interests in nine UK onshore exploration, appraisal, development and production assets, all situated within the Weald and Purbeck-Wight Basins of southern England. We are by far the largest acreage holder in the south of England, and the fourth largest in the overall UK onshore, with assets covering 942 gross km².
UKOG's portfolio includes five non-KL conventional oil discoveries together with a significant industry-leading position in the new flagship KL oil deposit or "play". This exciting new play has the potential for exceptional growth in the near and foreseeable future. UKOG, as the creator of the KL play, holds by far the largest acreage position within the play's most prospective area or "sweet spot", covering 672 gross km². Our sweet spot licences are independently calculated to contain a significant 21% of the play's total resource with a mean or average Kimmeridge oil in the ground within UKOG licences of 17 billion barrels.
We have built a portfolio that has the potential to generate significant returns for the Company and its shareholders. It includes a balanced portfolio of low-risk oil & gas production, appraisal and development assets as well as high upside exploration assets.
PRINCIPAL RISKS AND UNCERTAINTIES
UKOG continuously monitors its risk exposures and reports to the board of directors ("The Board") on a regular basis. The Board reviews these risks and focuses on ensuring effective systems of internal financial and non-financial controls are in place and maintained.
|
Risk |
Mitigation |
Magnitude & Likelihood |
|
Exploration Risk, UKOG's Investee companies, fail to locate and explore hydrocarbon bearing prospects that have the potential to deliver commercially, e.g. key wells are dry or less successful than anticipated |
Analysis of available technical information to determine work programme. Risk sharing arrangements entered into to reduce downside risk
|
Magnitude- High Likelihood - High |
|
Permitting Risk, planning, environmental, licensing and other permitting risks associated with our investees operations particularly with exploration drilling operations. |
UKOG's investee companies have to date been successful in obtaining the required permits to operate. Therefore, UKOG considers that such risks are partially mitigated through compliance with regulations, proactive engagement with regulators, communities and the expertise and experience of the management teams. |
Magnitude- High Likelihood - Medium |
|
Liquidity Risk, because of its investee's exploration and development activities |
The Board regularly reviews UKOG's cashflow forecast and the availability or adequacy of its current facilities to meet UKOG's cash flow requirements |
Magnitude- High Likelihood - Medium |
OPERATIONAL REVIEW AND OUTLOOK
KOG and its investments, it was a busy financial year and continued to be so post period end. Although during the year our investees were primarily focused on the Broadford Bridge exploratory well and associated flow testing, they were also preparing for a busy 2018.
In particular, it was important to secure the relevant regulatory approvals for the extended well or flow tests and, if successful, the drilling of two further wells at the Horse Hill oil discovery. These well tests are geared towards enabling the determination of commerciality to be made in Q2 of 2018, and subject to the necessary regulatory consents, stable long-term production from at least one well in 2019.
UKOG has been actively exploring other new opportunities and is acquiring further well sites, together with preparing planning applications for further exploration and appraisal drilling, notably in PEDL234 and onshore Isle of Wight (PEDL331).
The Company also made important decisions for two of our other investments: Markwells Wood and offshore Isle of Wight.
In the post reporting period, UKOG announced the decision that to focus upon appraising the onshore PEDL331 Arreton oil discovery and satellite exploration prospects, it had informed the Oil and Gas Authority ("OGA") that it will not seek any further extension to UKOG's only offshore licence P1916, which has now been relinquished.
In order to progress the acquisition of new site-specific hydrogeological data over and around the Markwells Wood well pad our investees temporarily withdrew their planning application to the South Downs National Park Authority ("SDNPA"). UKOG is considering whether to resubmit a revised planning application in 2018 after the completion of the planned data acquisition and upon the conclusions of ongoing technical conversations with EA. The Company acted in good faith that this position was understood and agreed by SDNPA and EA.
Subsequent to the year-end, UKOG received a breach of condition notice from SDNPA. UKOG and its investees do not consider the notice to be valid, and UKOG is considering its position on Markwells Wood in discussion with SDNPA and EA.
A more detailed review of each of UKOG's investments and the activities during the year is included below
PEDL234 - Broadford Bridge
During the previous financial year, UKOG acquired PEDL234 (300 km², net interest 100%), significantly increasing its acreage holding within the KL play's prime prospective area and making UKOG the largest player within both the Weald Basin and the KL play. The licence is operated by Kimmeridge Oil & Gas Limited ("KOGL"), a wholly-owned subsidiary of UKOG.
Onshore licence PEDL234 is one of the UK's largest, covering 300 km², three times the size of our Horse Hill licence PEDL137. The licence contains multiple look-alike geological features to the Horse Hill KL oil discoveries and an eastern extension of the Godley Bridge-1 conventional Portland gas discovery.
The licence straddles both the northern and southern flanks of the Weald Basin and, more crucially, the basin centre, where the Kimmeridge is thickest, most thermally mature and is consequently interpreted to contain the most significant volumes of in-situ generated KL oil. The results of the BB-1z and HH-1 wells now firmly puts the prime prospective are of the KL play , or sweet spot, firmly over the central and northern areas of the Nutech's calculated Kimmeridge P50 OIP figures of 7.1 billion barrels within PEDL234, of which 1.7 billion barrels lie within the limestones, gives comfort to this viewpoint.
Importantly, the licence acquisition included the existing Broadford Bridge well pad, planning permission and EA consent to drill the Broadford Bridge-1 ("BB-1") exploratory well.
The intent of the BB-1 exploratory well and flow tests was to demonstrate that moveable light oil in commercial quantities exists within the KL on the southern side of the Weald Basin, 27 km to the south-west of the Horse Hill Kimmeridge oil discovery. The BB-1 technical objectives were as follows; confirm that KL oil is contained within a resource or continuous oil deposit, determine the southerly extent of the deposit and provide supporting evidence for a regionally extensive natural fracture system within the KL.
To achieve these goals, the well was planned to acquire the most comprehensive data set gathered to date over the KL sequence. Data acquisition included an extensive conventional coring and electric logging programme aimed at characterising natural fracturing and other key reservoir and engineering parameters. Once drilled, cored and logged, the well would be completed to allow for flow testing of four KL zones.
We currently conclude that the most important technical goals of the drilling, coring and flow testing programme were achieved, namely: further proof of the KL "geological concept", the determination of the deposit's lateral extent and the presence of a regional scale open natural-fracture network capable of flowing oil to surface from the KL without reservoir stimulation.
The BB-1 well was deliberately designed as a deviated or "slant" well with a steady angle throughout the Kimmeridge so that it would penetrate an optimal number of near vertical natural fractures within the five naturally-fractured KL's (KL1-KL5). Drilling commenced on the BB-1 exploration well in May 2017 and was successfully drilled at an inclination of around 50 degrees to vertical to a depth of around 6,000 ft or 1,900 metres, terminating within the Jurassic Corallian sandstone.
The well's orientation was deliberately chosen to intersect the maximum number of potentially open fractures by drilling at approximately 90 degrees to the predicted open natural fracture orientation within the KL. The open natural fracture orientation was derived from analysis of the Weald's regional stress field and available wells with image logs. Drilling and coring of the BB-1 exploration well was completed in July 2017.
It should be noted that the KL's open natural fracture orientation recorded at the well was as predicted (within 5 degrees). Consequently the well's original design was validated. Subsequent specialist analysis of formation image log and core fractures, also demonstrated that the Kimmeridge contains both a local and regionally developed natural-fracture system, key to the future commercial viability of the KL deposit. These fractures were found to be present in both the Kimmeridge's limestones and shales and vertically throughout the entire Kimmeridge section.
An extensive coring programme was succesfully completed acquiring some 550 feet of 4-inch core. A continuous core totalling 520 feet was cut within the KL3 to KL5 section and a single 30 ft core within the deeper KL2 limestone. Specialist core analysis was undertaken on the cores by COREX in Aberdeen and Premier Oilfield Laboratories in Houston, Texas a specialist in the analysis of the shale and unconventional reservoirs of the USA. These cores represent the first significant coring of both Kimmeridge limestones and shales in the UK and provide the essential calibration for subsequent electric log analyses.
The coring programme provided the first evidence for the technical proof of KL geological concept. The cores retrieved from the KL5 section saw mobile, light oil recovered to surface. Oil in fact was seen at the site seeping from open natural fractures. The oil was sampled and analysed and was confirmed to have been generated by an Upper Jurassic shale source and of nearly identical geochemical composition and origin to the Horse Hill KL 3 and KL4 oils. Subsequent analysis of the KL5 limestone core also revealed that the matrix of the limestone itself was also oil saturated, occupying a significant 6% by weight of the actual rock. Further live oil traces were seen in cores throughout the coring process.
Following coring, the well was drilled ahead to total depth. Good mobile oil shows were seen in cuttings, and in the mud retort samples throughout the KL sequence together with elevated wet gas readings. Oil shows and elevated gas readings were found to coincide with fractures interpreted from image logs and appeared to be connected to several lost circulation zones (i.e. drilling fluid entering open fractures connected to the wellbore). Indirectly therefore, it appears that the lost circulation zones indicate that fractures were open and apparently well-connected and likely the source of the oil shows.
Significantly, prior to the testing campaign fracture-related data showed the key fracture sets to be open i.e. likely able to transmit fluids under reservoir conditions. Consequently, neither the drilling fluid nor drilling and coring methodology appears to have "damaged" the reservoir (i.e. blocked or plugged fractures surrounding the well bore). As to whether these fractures remained fully or partly open during the necessary pressure draw-downs following acidisation used during testing is currently under investigation.
After completion of the BB-1 exploration well it became apparent that the duration and difficulty of coring such highly-fractured rocks in an inclined well within the overall compressional stress regime of the Weald, together with the multiple pipe trips and significant electric logging runs likely exacerbated potential borehole breakouts creating ledges protruding into the borehole. These ledges prevented the final 7 inch casing from reaching the necessary depth in the inclined well. Caliper log data clarly showed that the well maintained an aceptable degree of rugosity with absolutely no evidence of any collapse.
The inability to case the well in the main reservoir section combined with potential plugging of near wellbore fractures with lost circulation material likely meant that future testing would be compromised. Therefore the decision was made to drill, log and case a mechanical sidetrack exploration well, BB-1z. This was drilled over a 6 day period in August 2017.
The BB-1z sidetrack was drilled from below the Purbeck Limestones and replicated the BB-1 exploration well some 200 ft to the south. The sidetrack delivered a fresh, near identical section of the KL, with minimal formation damage designed to be optimal for well completion and flow testing. Mobile oil traces were recovered from the drilling fluid throughout the Kimmeridge section and both oil and wet gas shows were at approximately the same level as that seen in the original BB-1 borehole.
In September 2017 the BB-1z exploration sidetrack was completed with an aggregate total of 1,064ft of perforations over eight naturally fractured zones, including within the new uppermost reservoir zone, KL5 and within a 500 foot section of the deepest KL0 section. Over the next six months, the Company embarked on an extended well test across the identified KL zones (KL0-KL5).
The first four tests were conducted over the original 4-zone production completion. Each test covered multiple peforated sections which included significant sections of interbeddedd fractured KL shales. Acidisation was therefore not selectively administered to any specific limestone horizon. Whilst the results of the tests showed inflows indicating some initial permeabilty together with natural gas blows, the results were disappointing. it was concluded that during the significant pressure draw-downs associated with the test's coiled tubing lifting methodology, the fractures within the predominantly shale test sections closed-up, reducing permeability effectively to zero. Consequently, any possibility of sustained flow rates from such shale dominated sections could likely only be obtained via reservoir stimulation beyond the scope of BB-1z's existing regulatory permissions.
It should also be noted that the KL0 section, comprising 500 ft thick fractured shale and interbedded thin limestones was tested within an uncemented section below a cement plug at the base of KL1, possibly further reducing the efectiveness of the acid wash. However some inflow and gas blow was recorded indicating at least an initial inflow of methane from the Kimmeridge. The KL0 zone was not subsequently selectively tested.
Given that traces of oil had been recovered to surface from each of the four tests, it was decided to abandon nitrogen lifting, open all four test zones and lift the well with a linear rod pump. This lift achieved oil to surface in measureable quantities but with no definition sa to which zone or zones may have contributed to flow. It is, however, interesting that the KL5 zone, which subsequently flowed oil to surface during the latter selective test campaign was not perforated, suggesting oil flow came from a deeper zone in the well. The recovered oil was sampled and analysed, showing it was geochemically identical to that found in the KL5 cores and HH-1 crudes.
In October 2017 management made the decision to proceed with a workover of the well and implement a revised selective testing programme. The revised testing methodology was similar to that undertaken at the Horse Hill oil discovery, utilisng a rod pump and nitrogen cylinders to provide initial lift to the well.
The decision to workover the BB1-z exploration well also followed an assessment by two independent consultants and the Company that the quality of the cement-bond between the well casing and the surrounding rock was not optimal, particularly over some of the secondary interbedded limestone and shale units in KL1 and KL2 and KL5. As a result the completion programme had in some places not effectively connected the BB-1z well to the best open natural fractures, therefore the testing up to that point had been unable to accurately assess the flow potential from the KL sequences.
The revised testing programme consisted of nine individual selective test zones throughout the KL each of around 50-100 ft of vertical extent. In November 2017 UKOG reported the results from KL1. Two short initial tests over secondary shale-dominated fractured secondary reservoir objectives within the KL1 were performed. The interbedded shale and limestone stringers returned gas to the flare and traces of oil to surface. The second KL1 test, recorded an inflow were returned to the well at an initial natural flow rate of over 370 barrels per day, accompanied by a wet gas blow and traces of oil to surface. The KL2 test, again in a secondary section of shales and interbedded limestones, showed an initial inflow of returned completion fluids of 99 barrels per day.
Although these KL1 and KL2 zones are interpreted on electric logs to be hydrocarbon bearing corresponding to the oil recovered to surface, the Company concluded that sustained commercial flow rates from the shale dominated KL1 could likely only be obtained via reservoir stimulation beyond the scope of its existing regulatory permissions. As with the original 4-zone test programme we believe that the acid wash likely entered the highly fractured shales, not the thinner, lesser fractured limestones and under the pressure draw-downs exterted by both nitrogen lifting and pummping closed up during testing
Oil and associated gas were recovered to surface from within three tests in the uppermost KL3 and KL4. High initial instantaneous flow-back rates were obtained from the KL4 and KL3 test zones of between 466 and 719 barrels of fluid per day respectively, but with no sustained flow. Due to the limited time remaining on the planning consent and the ongoing costs of testing, the decision was made to spend no further time on these zones and proceed ahead to the KL5 zone.
In February 2018 the Company reported that oil had flowed to surface from the naturally fractured KL5 reservoir. Fluid returns to the surface, measured as half-hourly instantaneous pumped flow-rates over a 96-hour near-continuous period, ranged between 10 to 72 barrels per day. The fluid returns through the test equipment consisted of a mixture of oil plus returned spent-acid from an acid wash treatment, with no observed obvious formation water component. Associated oil-cut steadily increased to over 30%, with intermittent periods exceeding 50% by volume. The test continued to flow oil to surface at similar rates and oil-cuts as reported on 20 February. Although the continuous flow showed evidence of gradual cleaning and stabilisation over further days, due to planning permission time-constraints, the test was halted to test the deeper KL1 zone.
The KL1 test, over a newly perforated 40 ft naturally-fractured limestone section, showed encouraging initial fluid inflow rates of between 40-50 barrels per day post acidisation. However, no fluids were able to flow to surface due to a series of significant mechanical problems that could not be rectified within the remaining planning consent window. However, after the test halt, upon retrieving the uppermost packer and tubing, live mobile light oil was seen mixed with completion fluids.
Well test operations were completed in late March 2018 and the well was suspended for possible future re-entry and interventions.
As previously reported on 20 February, the presence of KL5 oil flowing to surface, oil returned to surface from KL1-KL4 flow tests, together with mobile oil in cores and drilling fluids, presents further compelling evidence that the Upper Jurassic Kimmeridge of the central Weald Basin contains an extensive continuous oil accumulation. These live, mobile oil occurrences, together with corresponding rock and electric log data likely demonstrate a deposit of up to 1400 ft vertical extent at BB-1/1z.
Geochemical analyses further support this conclusion, as all oil samples from both BB-1z and HH-1 analysed to date are determined by Geomark Research to come from the same Upper Jurassic shale source, i.e. the oil lies within or immediately adjacent to the Upper Jurassic rocks where it was generated, one of the key aspects of a continuous oil accumulation.
The near identical reservoir geology and geochemistry between HH-1 and BB-1/1z demonstrates that this continuous oil deposit has around a 30 km north-south extent, with BB-1/1z likely lying on the deposit's southernmost boundary. UKOG is the largest licence holder within the deposit's most prospective area or "sweet-spot", much of which resides in PEDL234.
Flow test inflows and pressure data, together with electric image log analyses, also demonstrate that the Kimmeridge contains both a local and regionally developed natural-fracture system, key to the future commercial viability of the KL deposit.
Whilst the KL flow rates observed are likely sub-commercial, given the multiple occurrences of mobile oil observed in the well and their correlation with good calculated oil saturations in electric logs and core analyses, we are exploring new methods and technologies that might enable us to achieve higher sustainable oil rates and commercial viability from the 1400 vertical feet of oil-saturated KL reservoir rock interpreted at BB-1z.
With this in mind, serious consideration is being given to a possible future short sidetrack, BB-1y. The sidetrack's objective would include a selective re-test of the main KL units, likely utilising an alternate completion methodology, new completion fluids, the possible use of small-bore radial drilling and other reservoir stimulation techniques. Any future work at BB-1/1z would likely take place after a successful trial of such alternate methods and technologies in the next PEDL234 exploration well.
PEDL234 - Future KL Exploration Plans
Due to the significant positive technical learnings and understanding of the wider KL play gained from BB-1/1z, the Company has accelerated its plans, to drill further wells within the PEDL234 licence. Two drilling sites have now been finalised, both located firmly within what the Company interprets to be the KL oil deposit's most prospective sweet-spot.
Both new locations lie within geological features in the central area of the 300 km² licence where the thickest, deepest buried and the most thermally mature (i.e. oil generative) KL section resides.
Lease terms on the first location have been agreed and a preliminary meeting with the Local Planning Authority is scheduled for this week. It is expected that a formal planning application will be submitted in Q3 2018, with drilling and testing in 2019 subject to obtaining necessary regulatory consents and funding.
PEDL234 - Godley Bridge
Godley Bridge also lies within onshore licence PEDL234. Godley Bridge-1 ("GB-1") was drilled in 1982/83 to a depth of 8,473 ft in the Lower Jurassic. Gas was discovered in the Upper Portland Sandstone and tested 1-1.5 mmscfd on test. In 1986 an appraisal well (GB-2) was drilled which came in very low to prognosis and well below any gas water contact seen in the first well. Subsequent investigations showed a major problem with the seismic static corrections in the area which had led to the appraisal well being badly positioned. Since the mid-1990's more modern processing has solved this problem and there is a high degree of confidence that a new well can be drilled up-dip of the original discovery to test a thicker section.
Although only the Portland D Sand Unit was proven to be gas bearing in the GB-1 well, it is possible that in a more crestal position the gas column extends down into the E1 Sand Unit below. Both of these reservoir units are well developed along the Godley Bridge anticlinal axis, the thick, clean sandstones with good reservoir properties extending to the east and west along the northern edge of the Weald Basin.
The Portland F Sand Unit, occurring at the base of the Portland interval in the Leigh-1 and Collingdean Farm-1 wells, could be a useful additional reservoir objective on the eastern extension of the anticlinal axis.
Technical studies by Xodus and UKOG show that the GB-1 Portland gas discovery likely extends into the north of PEDL234. More importantly, Nutech's petrophysical analysis of the GB-1 well also indicates that significant oil potential lies within the Kimmeridge underlying the Portland gas accumulation.
The Kimmeridge section encountered by the GB-1 well is thicker and more deeply buried than at Horse Hill, indicating the possibility for greater oil generation per unit volume of Kimmeridge shale than at Horse Hill. The Godley Bridge discovery also lies along a pronounced east-west faulted structural flexure, some 15 km in extent, and which is a prime candidate for the development of an associated significant fracture-network within both limestones and shales. Wet gas and oil shows were recorded throughout the Kimmeridge in GB-1 as is the case at the HH-1 discovery.
KOGL is finalising the selection of a well site and associated planning/permit applications. The well, subject to funding and the necessary planning consents, would both further appraise the Portland gas discovery and test the deeper KL in an optimised location.
PEDL 137 & PEDL 246 - Horse Hill
Onshore licences PEDL137 (99.3 km², net interest 32.435%) and PEDL246 (43.6 km², net interest 32.435%) contain the HH-1 conventional Portland oil discovery and the KL3 and KL4 discoveries within the KL continuous oil accumulation. These discoveries were flow tested in 2016 resulting in a combined aggregate initial flow rate of 1688 barrels of oil per day.
Planning permission for the forthcoming Horse Hill extended well or flow test and appraisal programme was received on 1 November 2017, and on 23 March 2018, all pre-commencement planning conditions were discharged by Surrey County Council. As at the date of the publication of this document licence operator Horse Hill Developments Ltd ("HHDL") has received the necessary permission to begin testing and drilling from EA and is now awaiting final approval from OGA. A programme of civil construction works in preparation for this programme is currently underway at the site. Long-term production testing is anticipated to commence in Q2 of 2018.
The planned production tests are specifically designed to prove that commercial volume of OIP. Consequently, we expect that HHDL will be to be able to make a determination of the commerciality for the Kimmeridge and Portland following these test results from Q2 of 2018.
HHDL has informed us that, subject to a successful test they plan to drill a new Portland appraisal well, HH-2, plus a further deviated KL wellbore, HH-1z, from the existing HH-1 wellbore. These wells are designed to be completed as future permanent oil producers, with first oil planned in 2019, subject to the necessary regulatory approvals and field development consent.
The HH-1 Portland oil discovery's importance was further boosted by Xodus' report in February 2017, which determined that the P50 OIP had increased to 32 million barrels, an increase of 53% from the 21 million barrels reported prior to 2016 flow testing. Gross Contingent Resources rose to 1.5 million barrels (0.5 million barrels net to UKOG) with a further 1.7-6.6 million barrels gross recoverable (0.5-2.1 million barrels net to UKOG) being possible via implementation of a water re-injection scheme.
Other Horse Hill-related Activity Highlights
· "Retention Areas" and related work programmes over the entirety of PEDL137 and PEDL246 were agreed with OGA, which extend both licences to 2021.
· UKOG acquired a further 1.9% interest in HHDL from Regency Mines plc.
Holmwood
Onshore licence PEDL143 (91.8 km², net interest 40%, operator Europa Oil & Gas (Holdings) plc) contains the Holmwood prospect, which is a look-alike feature to the HH-1 Portland and Kimmeridge oil discoveries, 8 km to the east. Planning permission is in place to drill the Holmwood-1 well to test the Portland and the Kimmeridge in 2018.
In September 2017 UKOG further increased its interest in the Holmwood PEDL143 licence and now holds a 40% stake, being the largest single participant in the joint venture.
The Holmwood-1 well is an important part of our Kimmeridge oil development strategy, designed to demonstrate that the results of Horse Hill can be replicated across the Weald and that the Kimmeridge contains a continuous oil deposit. The planned deviated well will also test a shallower Portland sandstone objective in a look-alike geological setting to the Horse Hill and Collendean Farm Portland discovery.
Isle of Wight
Onshore licence PEDL331 (200 km², net interest 65%) contains the Arreton-1 and Arreton-2 Portland oil discovery. The Isle of Wight onshore is an important element of our growth portfolio, with a focus upon fracture-enhanced conventional limestone and sandstone oil discoveries and look-alike explortaion prospects that have been missed by previous operators.
The PEDL331 licence was formally granted to UKOG by OGA in September 2016. Angus Energy assigned its 5% licence interest to Doriemus Plc and UKOG was formally appointed by OGA as the licence operator. The Joint Operating Agreement was executed with Doriemus and 30% partner Solo Oil Plc. UKOG is finalising the selection of the well site and preparing a planning application to drill the Arreton-3 appraisal well, again with a view to achieving early oil production in the event of success.
A volumetric and resource analysis by Xodus Group Ltd ("Xodus") of the Arreton-2 oil discovery ("Arreton Main") and the adjacent low-risk Arreton North and South Prospects ("Arreton Prospects") calculated a significant aggregate gross P50 OIP of 219 million barrels, with corresponsing net Company P50 Contingent Resources of 10.2 million barrels and 6.8 million barrels for the Arreton Main discovery and the Arreton South exploration prospect respectively.
Sites for the Arreton-3 appraisal well together with an Arreton-South exploration well have now been finalised. The Arreton-3 site is currently under negotiation and the plan is to submit a planning application by end of Summer 2018 for possible drilling towards the end of 2019.
Offshore licence P1916 (UKOG 100%) was relinquished due to low technical prospectivity, environmental sensitivity of the site and to focus upon the higher reward, technically robust, lower risk discovered oil of the onshore Isle of Wight.
Markwells Wood
Onshore licence PEDL126 (11.2 km², net interest 100%) contains the Markwells Wood-1 oil discovery.
In September 2016 UKOG submitted a planning application to the South Downs National Park Authority ("SDNPA") to further appraise and develop the Markwells Wood-1 oil discovery. The planned two-phase programme would see four horizontal wells drilled within the conventional Great Oolite limestone reservoir. The discovery is a geological look-alike to the neighbouring Horndean producing oil field (UKOG net interest 10%). However, this planning application was withdrawn in May 2017 to allow for further discussions with EA and to allow the gathering of site-specific information relating to groundwater and hydrogeology.
Subsequent to the year-end UKOG received a breach of condition notice from SDNPA. UKOG does not consider the Notice to be valid. Moreover, UKOG is of the opinion that the notice was misleading as it failed to recognise UKOG's extensive good faith discussions with the various regulatory authorities. Critically, the notice fails to mention that UKOG submitted a new Markwells Wood planning application to SDNPA dated 16 September 2016; the condition to rehabilitate within the specified timeframe was effectively suspended while SDNPA considered this new application.
UKOG, therefore, does not consider the Notice to be valid and is considering its position on Markwells Wood in discussion with SDNPA.
Baxters Copse
Onshore licence PEDL233 (89.6 km², net interest 50%, Operator IGas Energy plc) contains the Baxters Copse-1 oil discovery.
Horndean
Onshore licence PL211 (27.3 km², net interest 10%, operator IGas Energy plc). Horndean continued stable oil production throughout the period averaging around 140 gross bopd in 2017.
Avington
Onshore licence PL070 (18.3 km², net interest 5%, operator IGas Energy plc). Average Avington production in 2017 was around 35 bopd. Due to high operating costs and issues with one of the production wells, Avington production was temporarily shut down in early 2018.
Brockham and Lidsey
During the period, UKOG completed the sale of its shares in Angus Energy. Therefore, UKOG no longer has an indirect interest in the Brockham and Lidsey oil fields.
FINANCIAL REVIEW
Income Statement
In 2017, production continued from Horndean and Avington generating revenues of £0.21 million. The operating loss decreased in 2017 to £2.39 million from £2.89 million loss in 2016. This decrease is due to lower consultant and administrative cost. Loss for the year was £2.27 million an increase from the £1.97 million loss in 2016. This variance was due to the £1.03 million credit to the Income statement as a result of the negative goodwill associated with the acquisition of PEDL234.
Cash Flow / Financing
The group raised £7.12 million (net of costs) during the year, which along the cash and cash equivalents at the beginning of the period of £2.44 million was utilised to further our investees exploration and evaluation of the Weald basin (£8.72 million). We also disposed of our stake in Angus Energy which netted £0.57 million in cash.
Balance Sheet
During 2017, non-current assets increased by £8.53 million primarily as a result of the increased expenditure on exploration and evaluation assets, in particular, the drilling and coring of BB-1/1z which increased the exploration and evaluation assets from £6.19 million in 2016 to £15.11 million in 2017. The increase in expenditure on exploration and evaluation assets was also the primary driver for the increase in total assets to £27.25 million (2016: £18.52 million).
At the end of the period, the Group had £1.78 million (2016: £2.44 million) in cash and cash equivalents.
UKOG 's total liabilities increased to £4.08 million (2016: 0.59 million). This was driven by the increase in trade and other payables, associated with the increased operational activities at the Broadford Bridge.
Subsequent to the year-end UKOG) entered into a £10 million loan agreement ("Loan") with Cuart Investments PCC Ltd and YA II PN Ltd, an investment consortium arranged by Riverfort Global Capital Ltd. The first tranche of £7.5 million was drawn down by the Company in November, with the second tranche of £2.5 drawn down on 31 December 2017. The first and second tranches are repayable on 13 November 2019 and 31 December 2019, respectively.
The Loan attracts 0% interest and may, at the sole discretion of the Investors, be converted into new ordinary shares in the Company. The conversion price is the lower of either a share price of 8 pence, or 90% of the Company's lowest daily volume weighted average price during the five days prior to the conversion date. The Loan is convertible in tranches of not less than £250,000, with a limit of £3 million per quarter, unless otherwise agreed by the Company.
UKOG can repay the principal amount of the Loan at any time for cash, provided that the 5-day VWAP of the Company's equity is less than 8 pence and a prepayment fee equal to 10 percent of the principal amount of the Loan then outstanding is paid by the Company to the Investors.
At the date of the publication of this document, the outstanding amount due on this loan is £5.25 million.
Reserves, Resources and Oil in Place
In the past year, there has been a 72% increase in UKOG's total gross attributable P50 Kimmeridge oil in place ("OIP") to 17.1 billion barrels in its Weald Basin licence interests. There has been a 348% increase in total UKOG net attributable KL OIP to 2.4 billion barrels via the PEDL234 (Broadford Bridge) acquisition.
Nutech calculated PEDL234 Kimmeridge P50 OIP of 7.1 billion barrels, of which 1.7 billion barrels lie within the KL. The HH-1 Portland oil discovery's OIP increased by 53% to 32 million barrels.
UKOG has estimated net attributable P50 reserves of 98,200 barrels of oil (effective 31 December 2017, see Table 1 below). This figure is 19% lower than last year, due continuing production and the sale of UKOG's shares in Angus Energy, together with UKOG's net attributable interests in Brockham and Lidsey.
At the time of writing, UKOG also has 22.6 million barrels ("MMbbl") of net attributable P50 Contingent and Prospective Resources, 14.4 million barrels of this is in four non-KL discoveries (see Table 2 below). Table 2 includes net Contingent Resources for the Horse Hill Portland reservoir. However, Table 2 does not include net Contingent Resources for the PEDL234 Godley Bridge Portland gas discovery.
Gross unrisked oil in place ("OIP") for UKOG's licence interests are shown in Table 3. These OIP volumes are dominated by the Kimmeridge OIP estimated for the Horse Hill and Broadford Bridge/Godley Bridge licences.
Table 1: UKOG's Producing Fields, Gross and Net Reserves (at 31 December 2017)
|
Asset
|
UKOG Interest
|
Gross Reserves (barrels)
|
Net Reserves (barrels)
|
Source, Date
|
||||
|
P90
|
P50
|
P10
|
P90
|
P50
|
P10
|
|||
|
Horndean1
|
10%
|
713,000
|
982,000
|
1,219,000
|
71,300
|
98,200
|
121,900
|
IGas, Dec 2017
|
|
Avington1
|
5%
|
-
|
-
|
-
|
-
|
-
|
-
|
IGas, Dec 2017
|
|
TOTALS
|
|
|
|
|
71,300
|
98,200
|
121,900
|
|
Note:
IGas's internal reserves estimates for Horndean and Avington: proven ("1P"), proven + probable ("2P"), proven + probable + possible ("3P") are deterministic, not probabilistic.
Table 2: UKOG's Unrisked Gross and Net Resources
|
Asset
|
Licence
|
UKOG's Interest
|
Gross Resources (MMbbl)
|
Net Resources (MMbbl) 1
|
Source, Date
|
||||
|
P90
|
P50
|
P10
|
P90
|
P50
|
P10
|
||||
|
Horndean 2,5
|
PEDL126
|
10%
|
N/A
|
0.82
|
N/A
|
N/A
|
0.08
|
N/A
|
IGas, Dec 2017
|
|
Avington 2,5
|
PEDL070
|
5%
|
N/A
|
0.74
|
N/A
|
N/A
|
0.04
|
N/A
|
IGas, Dec 2017
|
|
Markwells Wood 2
|
PEDL126
|
100%
|
0.6
|
1.3
|
2.7
|
0.6
|
1.3
|
2.7
|
Xodus, September 2015
|
|
Holmwood 3
|
PEDL143
|
40%
|
0.8
|
3.4
|
12.5
|
0.3
|
1.4
|
5.0
|
Europa/ERCE, June 2012
|
|
Baxters Copse 2,4
|
PEDL233
|
50%
|
2.7
|
4.6
|
6.7
|
1.3
|
2.3
|
3.4
|
IGas/DeGMcN, July 2016
|
|
Horse Hill Portland 2
|
PEDL137
|
32.4%
|
0.6
|
1.5
|
3.6
|
0.2
|
0.5
|
1.2
|
Xodus, January 2017
|
|
Arreton Main 2
|
PEDL331
|
65%
|
9.9
|
15.7
|
24.1
|
6.4
|
10.2
|
15.7
|
Xodus, January 2016
|
|
Arreton Prospects 3
|
PEDL331
|
65%
|
4.0
|
10.5
|
21.6
|
2.6
|
6.8
|
14.0
|
Xodus, January 2016
|
|
TOTALS
|
|
|
|
|
|
11.4
|
22.6
|
42.0
|
|
Notes:
1. UKOG net share.
2. Contingent Resources.
3. Prospective Resources.
4. Contingent Resources are in barrels of oil equivalent, as they include gas.
5. IGas's internal reserves estimates for Horndean and Avington: proven ("1P"), proven + probable ("2P"), proven + probable + possible ("3P") are deterministic, not probabilistic.
Table 3: UKOG Unrisked Gross OIP
|
Asset
|
Licence
|
UKOG's Interest
|
OIP (MMbbl) or GIIP (bcf)
|
Source & Date
|
||
|
Low P90
|
Best P50
|
High P10
|
||||
|
Onshore Isle of Wight
|
PEDL331
|
65%
|
144
|
219
|
322
|
Xodus, January 2016
|
|
Markwells Wood
|
PEDL126
|
100%
|
34
|
47
|
63
|
Xodus, September 2015
|
|
Holmwood
|
PEDL143
|
30%
|
4
|
15
|
55
|
Europa/ERCE, June 2012
|
|
Horndean
|
PL211
|
10%
|
27
|
56
|
110
|
Northern/RPS, Feb 2010
|
|
Avington
|
PEDL070
|
5%
|
25
|
59
|
110
|
IGas/Senergy, July 2014
|
|
Baxters Copse
|
PEDL233
|
50%
|
N/A
|
52
|
N/A
|
IGas/Senergy, July 2014
|
|
Horse Hill Portland
|
PEDL137
|
31.2%
|
22
|
32
|
47
|
Xodus, January 2017
|
|
Horse Hill Oil
|
PEDL137/246
|
31.2%
|
3,131
|
9,245
|
17,519
|
Nutech, June 2015
|
|
Horse Hill Oil
|
PEDL137/246
|
31.2%
|
N/A
|
10,993
|
N/A
|
Schlumberger, August 2015
|
|
Broadford Bridge/ Godley Bridge Oil
|
PEDL234
|
100.0%
|
3,158
|
7,120
|
13,717
|
Nutech, December 2016
|
SAFETY AND THE ENVIRONMENT
The United Kingdom has one of the most stringent regulatory regimes in the world. There are multiple standards and guidelines that our investee companies are required to conform to prior to and during operations.
Prior to the start of drilling the wells our investee companies must have multiple permits and consents. These include a license from the Oil and Gas Authority to commence operations, planning permissions from the local planning agencies, local landowner consents, environmental permits for the EA and permits from the Health and Safety Executive. Our Investee's operations are also subject to regular inspections to ensure that they are always fully compliant.
Environmental Initiatives
To further enhance the environmental credentials of our investee companies, they agreed on a long-term alliance with a British-based company to use its natural, biodegradable drilling fluid. UKOG will insist that this zero-hazard drilling fluid (or "mud") will be used in all of UKOG's investee oil exploration and development drilling activities across the Weald Basin. The use of this mud will ensure that there can be zero contamination of any groundwater via the drilling process.
The drilling fluid, also used by water well drilling companies in the UK, is registered with the Centre for Environment, Fisheries and Aquaculture Science (Cefas). It is also the only drilling fluid to be formally approved by the Department for the Environment, Food and Rural Affairs for use in the public water supply.
HHDL is also commissioning a company to construct and operate an enclosed flare for its upcoming appraisal and well testing programme. The enclosed flare, commonly used at landfill sites, is clean burning, without odour and produces low emissions. The enclosed flare will be a first in the UK onshore industry.
Community Engagement
As part and parcel of any of our investee's exploration and development, there runs alongside this a comprehensive community engagement plan.
It is vital that our investee companies engage, listen and communicate effectively with local communities, particularly when they begin the process of planning new developments.
Throughout this year's operations, UKOG is proud that its investee companies have embarked on a proactive community engagement campaign. For the first time in the onshore industry in the UK, a viewing platform was built at Broadford Bridge to accommodate residents, local politicians, media and investors to observe the working of the well pad and engage with the management and operators. Up to 300 people visited the BB-1 site, and it is our goal that this feature should be part of all our investee community engagement programmes going forward.
The Company actively engaged and had meetings with the two Members of Parliament in the area, Nick Herbert (Arundel & South Downs) and Jeremy Quin (Horsham). Both were given access to the site.
Elsewhere, our investees kept in contact with community group representatives in both the Horse Hill and Markwells Wood areas, holding occasional Community Engagement Group meetings. At the time of writing, over 200 letters are being delivered to residents of Horse Hill and they will be invited to visit the site as soon as the viewing platform has been erected. This follows various meetings with the local group Norwood Hill Residents, together with representatives from the parish councils of Charlwood and Salford & Sidlow.
Oil Price Environment
Brent crude oil price ended 2017 at $65/barrel ("b"), the highest end-of-year price since 2013. West Texas Intermediate (WTI) crude oil prices averaged $51/b in 2017, up $7/b from the 2016 average, and ended the year $6/b higher than at the end of 2016. Brent prices have moved up $10/b since the end of 2016 and ended the year at $65/b, widening the Brent-WTI spread to $5/b at the end of the year, the largest difference since 2013.
Despite relatively high U.S. crude oil production, curtailments in production by members of the Organization of the Petroleum Exporting Countries (OPEC) and robust global demand supported crude oil price increases in 2017. The OPEC agreement to curtail crude oil production in 2017 and subsequent extension of that agreement through 2018 tightened crude oil supplies, which put upward pressure on crude oil prices.
The price spread between Brent and WTI was significantly greater in 2017 than in 2016. Lower domestic crude oil prices made U.S. crude oil more competitive in international markets and supported record U.S. crude oil exports. Domestic demand was also higher: U.S. product supplied for crude oil and petroleum products was the highest level since 2007.
DIRECTORS
Stephen Sanderson, Executive Chairman and Chief Executive Officer
Stephen Sanderson joined UK Oil & Gas Investments PLC in September 2014 and was appointed Executive Chairman and Chief Executive in July 2015. A highly-experienced petroleum geologist, oil industry veteran and upstream energy business leader, with over 30 years operating experience, Stephen is a proven oil finder and has been instrumental in the discovery of more than 12 commercial conventional fields, including the Norwegian Smorbuk-Midgaard field complex. Stephen held a variety of senior management roles for ARCO (which was acquired by BP in 2000), Wintershall AG (a subsidiary of German chemical giant BASF) and three junior start-ups. He created and ran successful new exploration businesses in Africa, Europe and South America. He has significant technical and commercial expertise in the petroleum systems of Africa, the North Sea, Norway, onshore UK & Europe, South America, the South Atlantic, Middle East, Asia, India, Australia and the USA. He is a graduate and Associate of the Royal School of Mines, Imperial College, London, a Fellow of the Geological Society of London and a member of the American Association of Petroleum Geologists. He served for four years in the British Army and TAVR as a platoon commander, serving in the UK and Berlin.
Kiran Morzaria, Finance Director (appointed 23 October 2015)
Mr Morzaria holds a Bachelor of Engineering (Industrial Geology) from the Camborne School of Mines and an MBA (Finance) from CASS Business School. He has extensive experience in the mineral resource industry working in both operational and management roles. Mr Morzaria spent the first four years of his career in exploration, mining and civil engineering. He then obtained his MBA and became the Finance Director of Vatukoula Gold Mines Plc for seven years. He has served as a director of a number of public companies in both an executive and non-executive capacity; he is a non-executive director of European Metals Holdings Ltd and the Chief Executive Officer for Rare Earth Minerals Plc.
Allen D Howard, Non-Executive Director (appointed 1 March 2017)
Mr Howard was Senior Vice President of Houston-based Premier Oilfield Laboratories, having been Chief Operating Officer of well analysis experts Nutech. Allen also held senior positions with Schlumberger. He holds a degree in Chemical Engineering from Texas Tech University and an MBA from Mays Business School in Texas.
REPORT OF THE DIRECTORS
The Directors present their annual report together with the audited consolidated financial statements of the Group for the Year Ended 30 September 2017.
Principal Activity and Business Review
The principal activity of the Group and the Company is that of an investment holding company to acquire a diverse portfolio of direct and indirect interests in exploration, development and production oil and gas assets which are based in the UK.
Results and Dividends
Loss on ordinary activities of the Group after taxation amounted to £2,268,000 (2016: Loss £1,972,000). The Directors do not recommend the payment of a dividend (2016: £nil). The Company has no plans to adopt a dividend policy in the immediate future.
Principal Risks and Uncertainties
The principal risks and uncertainties facing the Group involve the ability to secure funding in order to finance the acquisition and exploitation of oil and gas assets and fluctuating commodity prices.
In addition, the amount and quality of the Group's oil and gas resources and the related costs of extraction and production represent a significant risk to the Group.
Financial Risk Management Objectives and Policies
The Group's principal financial instruments are available for sale assets, trade receivables, trade payables and cash at bank, and borrowings. The main purpose of these financial instruments is to fund the Group's operations.
It is, and has been throughout the period under review, the Group's policy that no trading in financial instruments shall be undertaken. The main risk arising from the Group's financial instruments is liquidity risk. The Board reviews and agrees policies for managing this risk and this is summarised below.
Liquidity Risk
The Group's objective is to maintain a balance between continuity of funding and flexibility through the use of equity and its cash resources. Further details of this are provided in the principal accounting policies, headed 'going concern'.
Key Performance Indicators
Due to the current status of the Group, the Board has not identified any performance indicators as key.
Future Developments
Future developments are outlined in the Chairman's Statement and Strategic Report.
Going Concern
The Directors note the substantial losses that the Group has made for the year ended 30 September 2017. The Directors have prepared cash flow forecasts for the period ending 31 March 2019 which take account of the current cost and operational structure of the Group.
The cost structure of the Group 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 Group to operate within its available funding.
These forecasts demonstrate that the Group has sufficient cash funds 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.
Events After the Reporting Period
Events after the Reporting Period are outlined in Note 23 to the Financial Statements.
Corporate Governance
Audit and Remuneration Committees have been established and, in each case, comprises Directors Allen D Howard and Kiran Morzaria, with Allen D Howard as Chairman.
The role of the Remuneration Committee is to review the performance of the executive Directors and to set the scale and structure of their remuneration, including bonus arrangements. The Remuneration Committee also administers and establishes performance targets for the Group's employee share schemes and executive incentive schemes for key management. In exercising this role, the terms of reference of the Remuneration Committee require it to comply with the Code of Best Practice published in the Combined Code.
The Audit Committee is responsible for making recommendations to the Board on the appointment of the auditors and the audit fee and receives and reviews reports from management and the Company's auditors on the internal control systems in use throughout the Group and its accounting policies.
Suppliers' Payment Policy
The Group's policy is to agree terms and conditions with suppliers in advance; payment is then made in accordance with the agreement provided the supplier has met the terms and conditions. Suppliers are typically paid within 30 days of issue of invoice.
Charitable Contributions
During the year the Group made charitable donations amounting to £Nil (2016 - £Nil).
Substantial Shareholdings
As at 23 March 2017, the Company had been notified of the following substantial shareholdings in the ordinary share capital:
|
Shareholder |
Number of Ordinary Shares |
Holding % |
|
Interactive Investor Services Nominees Limited |
421,839,126 |
11.27% |
|
Hargreaves Lansdown (Nominees) Limited |
410,897,345 |
10.98% |
|
Barclays Direct Investing Nominees Limited |
335,123,598 |
8.96% |
|
Hargreaves Lansdown (Nominees) Limited |
265,625,006 |
7.10% |
|
Hargreaves Lansdown (Nominees) Limited |
250,827,819 |
6.70% |
|
Interactive Investor Services Nominees Limited |
222,659,495 |
5.95% |
|
HSDL Nominees Limited |
215,696,083 |
5.76% |
|
HSDL Nominees Limited |
183,730,054 |
4.91% |
|
HSBC Client Holdings Nominee (UK) Limited |
145,213,074 |
3.88% |
Directors
The Directors who held office during the year and up to the date of this report are given below:
Current Board
Stephen Sanderson (Executive Chairman & CEO)
Kiran Morzaria (Finance Director)
Allen D Howard (Non-Executive Director) (appointed 1 March 2017)
Previous Directors
Jason Berry (ceased 16 November 2016)
The total options held by directors is 115,000,000. Stephen Sanderson holds fully vested options over 85,000,000 which are exercisable at 0.4p, 1.15p and 1.82p each up until 31 December 2017, 28 September 2019 and 24 May 2022 respectively (The 0.4p options that were due to expire on the 31 December 2017, were extended in December 2017, until Stephen Sanderson entered into a open period, as permitted under the option agreement). Kiran Morzaria holds 20,000,000 options and Allen Howard holds 10,000,000 options all exercisable at 1.15p up until 24 May 2022.
Auditor
A resolution to reappoint Chapman Davis LLP as auditor will be proposed at the forthcoming Annual General Meeting ("AGM").
Annual General Meeting
Notice of the forthcoming Annual General Meeting will be enclosed separately.
Statement of Directors' Responsibilities
The Directors are responsible for preparing the annual report and financial statements in accordance with applicable law and regulations.
Company law requires the directors to prepare consolidated financial statements for each financial year. The Directors have prepared the consolidated accounts in accordance with International Financial Reporting Standards as adopted by the EU ("adopted IFRS"). The consolidated financial statements are required by law to give a true and fair view of the state of affairs of the Group and Company and of the profit or loss for that period. In preparing these financial statements, the Directors are required to:
· Select suitable accounting policies and then apply them consistently;
· Make judgements and estimates that are reasonable and prudent;
· State whether applicable IFRS's have been followed, subject to any material departures disclosed and explained in the financial statements; and
· Prepare the consolidated financial statements on the going concern basis unless it is inappropriate to presume that the Group will continue in business.
The Directors are responsible for keeping adequate accounting records, which disclose with reasonable accuracy at any time the financial position of the Group and to enable them to ensure that the consolidated financial statements comply with the Companies Act 2006. They are also responsible for safeguarding the assets of the Group and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities.
The Directors are responsible for the maintenance and integrity of the corporate and financial information included on the Company's website. The Company's website is maintained in accordance with AIM Rule 26.
Legislation in the United Kingdom governing the preparation and dissemination of consolidated financial statements may differ from legislation in other jurisdictions.
Statement as to Disclosure of Information to the Auditor
As at the date of this report the serving directors confirm that:
· So far as each director is aware, there is no relevant audit information of which the Group's auditors are unaware, and
· they have taken all the steps that they ought to have taken as directors' in order to make themselves aware of any relevant audit information and to establish that the Group's auditor are aware of that information.
REPORT OF THE INDEPENDENT AUDITOR TO THE MEMBERS OF UK OIL & GAS INVESTMENTS PLC
OPINION
We have audited the financial statements of UK Oil & Gas Investments Plc (the 'Parent Company') and its subsidiaries (the 'Group') for the year ended 30 September 2017 which comprise the consolidated statement of comprehensive income, the consolidated and company statements of financial position, the consolidated and company's statements of changes in equity, the consolidated and company's statements of cash flows and notes to the financial statements, including a summary of significant accounting policies.
The financial reporting framework that has been applied in the preparation of the group and parent company financial statements is applicable law and International Financial Reporting Standards (IFRSs) as adopted by the European Union.
In our opinion:
• the financial statements give a true and fair view of the state of the Group's and of the Parent Company's affairs as at 30 September 2017 and of the Group's losses for the year then ended;
• the Group and Parent Company financial statements have been properly prepared in accordance with IFRSs as adopted by the European Union;
• the Parent Company financial statements have been properly prepared in accordance with IFRS as adopted by the European Union and as applied in accordance with the provisions of the Companies Act 2006; and
• the financial statements have been prepared in accordance with the requirements of the Companies Act 2006.
SEPARATE OPINION IN RELATION TO IFRSS AS ISSUED BY THE IASB
As explained in note 1 to the Group financial statements, the Group in addition applying IFRSs as adopted by the European Union, has also applied IFRSs as issued by the International Accounting Standards Board (IASB). Our opinion is extended to this financial framework.
BASIS FOR OPINION
We conducted our audit in accordance with International Standards on Auditing (UK) (ISAs (UK)) and applicable law. Our responsibilities under those standards are further described in the Auditor's responsibilities for the audit of the financial statements section of our report. We are independent of the Group in accordance with the ethical requirements that are relevant to our audit of the financial statements in the UK, including the FRC's Ethical Standard as applied to listed entities, and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
CONCLUSIONS RELATING TO GOING CONCERN
We have nothing to report in respect of the following matters in relation to which the ISAs (UK) require us to report to you where:
• the directors' use of the going concern basis of accounting in the preparation of the financial statements is not appropriate; or
• the directors have not disclosed in the financial statements any identified material uncertainties that may cast significant doubt about the company's ability to continue to adopt the going concern basis of accounting for a period of at least twelve months from the date when the financial statements are authorised for issue.
KEY AUDIT MATTERS
Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial report of the current period. These matters were addressed in the context of our audit of the financial report as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters. We have determined the matters described below to be the key audit matters to be communicated in our report.
CARRYING VALUE OF INTANGIBLE EXPLORATION AND EVALUATION ASSETS
The Group's intangible exploration and evaluation assets ('E&E assets') represent the most significant asset on its statement of financial position totalling £15.1m as at 30 September 2017.
Management and the Board are required to ensure that only costs which meet the IFRS criteria of an asset and accord with the Group's accounting policy are capitalised within the E&E asset. In addition in accordance with the requirements of IFRS 6 'Exploration for and Evaluation of Mineral Resources' ('IFRS 6') Management and the Board are required to assess whether there is any indication whether there are any indicators of impairment of the E&E assets.
Given the significance of the E&E assets on the Group's statement of financial position and the significant management judgement involved in the determination of the capitalisation of costs and the assessment of the carrying values of the E&E asset there is an increased risk of material misstatement.
How the Matter was addressed in the Audit
The procedures included, but were not limited to, assessing and evaluating management's assessment of whether any impairment indicators in accordance with IFRS 6 have been identified across the Group's exploration projects, the indicators being:
• Expiring, or imminently expiring, licence and/or exploration rights
• A lack of budgeted or planned exploration and evaluation spend on the licence areas
• Discontinuation of, or a plan to discontinue, exploration activities in the licence areas
• Sufficient data exists to suggest carrying value of exploration and evaluation assets is unlikely be recovered in full through successful development or sale.
In addition, we obtained the expenditure budget for the 2018/19 year(s) and assessed that there is reasonable forecasted expenditure to confirm continued exploration spend into the projects indicating that Management are committed to the projects. We also reviewed AIM announcements and Board meeting minutes for the year and subsequent to year end for exploration activity to identify any indicators of impairment.
We also assessed the disclosures included in the financial statements.
OTHER INFORMATION
The Directors are responsible for the other information. The other information comprises the information included in the annual report, other than the financial statements and our auditor's report thereon. Our opinion on the financial statements does not cover the other information and, except to the extent otherwise explicitly stated in our report, we do not express any form of assurance conclusion thereon.
In connection with our audit of the financial statements, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the financial statements or our knowledge obtained in the audit or otherwise appears to be materially misstated. If we identify such material inconsistencies or apparent material misstatements, we are required to determine whether there is a material misstatement in the financial statements or a material misstatement of the other information. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.
OPINIONS ON OTHER MATTERS PRESCRIBED BY THE COMPANIES ACT 2006
In our opinion, based on the work undertaken in the course of the audit:
• the information given in the Strategic Report and the Directors' report for the financial year for which the financial statements are prepared is consistent with the financial statements; and
• the Strategic Report and the Directors' report have been prepared in accordance with applicable legal requirements.
MATTERS ON WHICH WE ARE REQUIRED TO REPORT BY EXCEPTION
In the light of the knowledge and understanding of the Group and the Parent Company and its environment obtained in the course of the audit, we have not identified material misstatements in the Strategic report or the Directors' report.
We have nothing to report in respect of the following matters in relation to which the Companies Act 2006 requires us to report to you if, in our opinion:
• adequate accounting records have not been kept by the Parent Company, or returns adequate for our audit have not been received from branches not visited by us; or
• the Parent Company financial statements are not in agreement with the accounting records and returns; or
• certain disclosures of Directors' remuneration specified by law are not made; or
• we have not received all the information and explanations we require for our audit.
RESPONSIBILITIES OF DIRECTORS
As explained more fully in the Directors' responsibilities statement, the Directors are responsible for the preparation of the financial statements and for being satisfied that they give a true and fair view, and for such internal control as the Directors determine is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the financial statements, the Directors are responsible for assessing the Group's and the Parent Company's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the Directors either intend to liquidate the Group or the Parent Company or to cease operations, or have no realistic alternative but to do so.
AUDITOR'S RESPONSIBILITIES FOR THE AUDIT OF THE FINANCIAL STATEMENTS
This report is made solely to the Company's members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work has been undertaken so that we might state to the Company's members those matters we are required to state to them in an auditor's report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company and the Company's members as a body, for our audit work, for this report, or for the opinions we have formed.
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with ISAs (UK) or ISA IAASB will always detect a material misstatement when it exists.
Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these financial statements.
A further description of our responsibilities for the audit of the financial statements is located on the Financial Reporting Council's website at: www.frc.org.uk/auditorsresponsibilities. This description forms part of our auditor's report.
FINANCIAL STATEMENTS
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR YEAR ENDED 30 SEPTEMBER 2017
|
|
Notes |
30 Sep 2017 |
30 Sep 2016 |
|
|
|
£'000 |
£'000 |
|
|
|
|
|
|
Revenue |
3 |
207 |
151 |
|
Cost of sales |
|
(254) |
(204) |
|
|
|
|
|
|
|
|
|
|
|
Gross (loss) |
|
(47) |
(53) |
|
|
|
|
|
|
Operating expenses |
|
|
|
|
Administrative expenses |
|
(1,785) |
(2,062) |
|
Foreign exchange losses |
|
(15) |
(20) |
|
Depletion & impairment expense |
9 |
(74) |
(78) |
|
Share based payments expense |
19 |
(474) |
(682) |
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) |
|
(2,395) |
(2,895) |
|
|
|
|
|
|
Gain on settlements of financial instruments |
|
204 |
- |
|
Share of associate loss |
11 |
(77) |
(106) |
|
Negative Goodwill |
2 |
- |
1,029 |
|
|
|
|
|
|
|
|
|
|
|
(Loss) before taxation |
4 |
(2,268) |
(1,972) |
|
|
|
|
|
|
Taxation |
6 |
- |
- |
|
|
|
|
|
|
(Loss) for the year attributable to equity holders of the parent |
|
(2,268) |
(1,972) |
|
|
|
|
|
|
Other comprehensive income |
|
|
|
|
Transfer to income statement |
|
- |
- |
|
|
|
|
|
|
Other comprehensive income net of taxation |
|
- |
- |
|
|
|
|
|
|
Total comprehensive loss attributable to equity holders of the |
|
|
|
|
Parent |
|
(2,268) |
(1,972) |
|
|
|
|
|
|
(Loss) per share |
|
|
|
|
|
|
Pence |
Pence |
|
|
|
|
|
|
Basic and diluted |
7 |
(0.08) |
(0.09) |
The accompanying accounting policies and notes form an integral part of these financial statements.
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
AS AT 30 SEPTEMBER 2017
|
|
Notes |
2017 |
2016 |
|
|
|
£'000 |
£'000 |
|
|
|
|
|
|
Assets |
|
|
|
|
Non-current assets |
|
|
|
|
Exploration & evaluation assets |
8 |
15,110 |
6,187 |
|
Oil & Gas properties |
9 |
1,428 |
1,500 |
|
Property, Plant & Equipment |
9 |
170 |
370 |
|
Investment in associate |
11 |
5,003 |
4,757 |
|
Available for sale investments |
12 |
- |
368 |
|
|
|
|
|
|
Total non-current assets |
|
21,711 |
13,182 |
|
|
|
|
|
|
Current assets |
|
|
|
|
Inventory |
13 |
4 |
3 |
|
Trade and other receivables |
14 |
3,787 |
2,890 |
|
Cash and cash equivalents |
15 |
1,748 |
2,444 |
|
|
|
|
|
|
Total current assets |
|
5,539 |
5,337 |
|
|
|
|
|
|
Total Assets |
|
27,250 |
18,519 |
|
|
|
|
|
|
Current liabilities |
|
|
|
|
Trade and other payables |
16 |
(3,725) |
(591) |
|
|
|
|
|
|
Total current liabilities |
|
(3,725) |
(591) |
|
|
|
|
|
|
Non-current Liabilities |
|
|
|
|
Provisions |
17 |
(359) |
(359) |
|
|
|
|
|
|
Total non-current liabilities |
|
(359) |
(359) |
|
|
|
|
|
|
Total liabilities |
|
(4,084) |
(950) |
|
|
|
|
|
|
Net Assets |
|
23,166 |
17,569 |
|
|
|
|
|
|
Shareholders' Equity |
|
|
|
|
Share capital |
18 |
11,938 |
11,842 |
|
Share premium account |
|
46,939 |
39,644 |
|
Share based payment reserve |
|
1,172 |
1,224 |
|
Accumulated losses |
|
(36,883) |
(35,141) |
|
|
|
|
|
|
Total shareholders' equity |
|
23,166 |
17,569 |
COMPANY STATEMENT OF FINANCIAL POSITION
AS AT 30 SEPTEMBER 2017
|
|
Notes |
2017 |
2016 |
|
|
|
£'000 |
£'000 |
|
|
|
|
|
|
Assets |
|
|
|
|
Non-current assets |
|
|
|
|
Exploration & evaluation assets |
8 |
1,318 |
742 |
|
Investment in subsidiary companies |
10 |
5,019 |
5,019 |
|
Investment in associate |
11 |
5,003 |
4,757 |
|
Available for sale investments |
12 |
- |
368 |
|
|
|
|
|
|
Total non-current assets |
|
11,340 |
10,886 |
|
|
|
|
|
|
Current assets |
|
|
|
|
Trade and other receivables |
14 |
9,735 |
3,672 |
|
Cash and cash equivalents |
15 |
1,714 |
2,371 |
|
|
|
|
|
|
Total current assets |
|
11,449 |
6,043 |
|
|
|
|
|
|
Total Assets |
|
22,789 |
16,929 |
|
|
|
|
|
|
Current liabilities |
|
|
|
|
Trade and other payables |
16 |
(364) |
(299) |
|
|
|
|
|
|
Total Current Liabilities |
|
(364) |
(299) |
|
|
|
|
|
|
Total liabilities |
|
(364) |
(299) |
|
|
|
|
|
|
Net Assets |
|
22,425 |
16,630 |
|
|
|
|
|
|
Shareholders' Equity |
|
|
|
|
Share capital |
18 |
11,938 |
11,842 |
|
Share premium account |
|
46,939 |
39,644 |
|
Share Based Payment Reserve |
|
1,172 |
1,224 |
|
Accumulated losses |
|
(37,624) |
(36,080) |
|
|
|
|
|
|
Total shareholders' equity |
|
22,425 |
16,630 |
These financial statements were approved by the Board of Directors on 28 March 2018
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEAR ENDED 30 SEPTEMBER 2017
|
|
Share capital |
Share premium |
Share based payment reserve |
Accumulated losses |
Total |
|
|
£'000 |
£'000 |
£'000 |
£'000 |
£'000 |
|
Balance at 1 October 2015 |
11,787 |
31,622 |
659 |
(33,286) |
10,782 |
|
Loss for the year |
- |
- |
- |
(1,972) |
(1,972) |
|
Total comprehensive income |
- |
- |
- |
(1,972) |
(1,972) |
|
Issue of shares |
55 |
8,262 |
- |
- |
8,317 |
|
Cost of share issue |
- |
(240) |
- |
- |
(240) |
|
Share option expired |
- |
- |
(117) |
117 |
- |
|
Share based payments |
- |
- |
682 |
- |
682 |
|
Balance at 30 September 2016 |
11,842 |
39,644 |
1,224 |
(35,141) |
17,569 |
|
Loss for the year |
- |
- |
- |
(2,268) |
(2,268) |
|
Total comprehensive income |
- |
- |
- |
(2,268) |
(2,268) |
|
Issue of shares |
96 |
7,631 |
- |
- |
7,727 |
|
Cost of share issue |
- |
(336) |
- |
- |
(336) |
|
Share option exercised |
- |
- |
(316) |
316 |
- |
|
Share option expired |
|
|
(210) |
210 |
- |
|
Share based payments |
- |
- |
474 |
- |
474 |
|
Balance at 30 September 2017 |
11,938 |
46,939 |
1,172 |
(36,883) |
23,166 |
COMPANY STATEMENT OF CHANGES IN EQUITY
FOR THE YEAR ENDED 30 SEPTEMBER 2017
|
|
Share capital |
Share premium |
Share based payment reserve |
Accumulated losses |
Total |
|
|
£'000 |
£'000 |
£'000 |
£'000 |
£'000 |
|
Balance at 1 October 2015 |
11,787 |
31,622 |
659 |
(33,286) |
10,782 |
|
Loss for the year |
- |
- |
- |
(2,911) |
(2,911) |
|
Total comprehensive income |
- |
- |
- |
(2,911) |
(2,911) |
|
Issue of shares |
55 |
8,262 |
- |
- |
8,317 |
|
Cost of share issue |
- |
(240) |
- |
- |
(240) |
|
Share option exercised |
- |
- |
(117) |
117 |
- |
|
Share based payments |
- |
- |
682 |
- |
682 |
|
Balance at 30 September 2016 |
11,842 |
39,644 |
1,224 |
(36,080) |
16,630 |
|
Loss for the year |
- |
- |
- |
(2,070) |
(2,070) |
|
Total comprehensive income |
- |
- |
- |
(2,070) |
(2,070) |
|
Issue of shares |
96 |
7,631 |
- |
- |
7,727 |
|
Cost of share issue |
- |
(336) |
- |
- |
(336) |
|
Share option exercised |
- |
- |
(316) |
316 |
- |
|
Share option expired |
- |
- |
(210) |
210 |
- |
|
Share based payments |
- |
- |
474 |
- |
474 |
|
Balance at 30 September 2017 |
11,938 |
46,939 |
1,172 |
(37,624) |
22,425 |
CONSOLIDATED STATEMENT OF CASH FLOW
FOR THE YEAR ENDED 30 SEPTEMBER 2017
|
|
|
2017 |
2016 |
|
|
|
£'000 |
£'000 |
|
|
|
|
|
|
Cash flows from operating activities |
|
|
|
|
Loss from operations |
|
(2,395) |
(2,895) |
|
Foreign currency losses |
|
- |
20 |
|
Other non-cash income & expenses |
|
- |
(19) |
|
Depletion & impairment |
|
74 |
78 |
|
Share based payment charge |
|
474 |
682 |
|
Increase in inventories |
|
(1) |
(1) |
|
(Increase) / decrease in trade & other receivables |
|
(897) |
9 |
|
Increase in trade & other payables |
|
3,134 |
262 |
|
Net cash (outflow) from operating activities |
|
389 |
(1,864) |
|
|
|
|
|
|
Cash flows from investing activities |
|
|
|
|
Expenditures on exploration & evaluation assets |
|
(8,723) |
(458) |
|
Expenditures on oil & gas properties |
|
(2) |
(266) |
|
Payments for acquisition of associate |
|
(55) |
(1,150) |
|
Loans advanced to investee companies |
|
- |
(1,216) |
|
Proceeds from sale of Available for Sale Financial Assets |
|
572 |
- |
|
Acquisition of subsidiaries, net of cash acquired |
|
- |
(1,257) |
|
Net cash (outflow) from investing activities |
|
(8,208) |
(4,347) |
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
Proceeds from issue of share capital |
|
7,459 |
4,416 |
|
Share issue costs |
|
(336) |
(240) |
|
Repayments of loan & borrowings |
|
- |
(111) |
|
Net cash inflow from financing activities |
|
7,123 |
4,065 |
|
|
|
|
|
|
Net change in cash and cash equivalents |
|
(696) |
(2,146) |
|
|
|
|
|
|
Cash and cash equivalents at beginning of the period |
|
2,444 |
4,590 |
|
|
|
|
|
|
Cash and cash equivalents at end of the period |
|
1,748 |
2,444 |
COMPANY STATEMENT OF CASH FLOW
FOR THE YEAR ENDED 30 SEPTEMBER 2017
|
|
|
2017 |
2016 |
|
|
|
£'000 |
£'000 |
|
|
|
|
|
|
Cash flows from operating activities |
|
|
|
|
(Loss) from operations |
|
(2,197) |
(2,785) |
|
Foreign currency losses |
|
- |
1 |
|
Share based payment charge |
|
474 |
682 |
|
Gain/(loss) on settlements of financial instruments |
|
- |
|
|
Decrease in trade & other receivables |
|
128 |
76 |
|
Increase / (decrease) in trade & other payables |
|
65 |
(14) |
|
Net cash (outflow) from operating activities |
|
(1,530) |
(2,040) |
|
|
|
|
|
|
Cash flows from investing activities |
|
|
|
|
Expenditures on exploration & evaluation assets |
|
(576) |
(80) |
|
Loan advanced to subsidiary |
|
(6,191) |
(412) |
|
Payments for acquisition of associate |
|
(55) |
(1,150) |
|
Loans advanced to investee companies |
|
- |
(1,216) |
|
Proceeds from sale of Available for Sale Financial Instrument |
|
572 |
- |
|
Acquisition of subsidiaries, net of cash acquired |
|
- |
(1,257) |
|
Net cash (outflow) from investing activities |
|
(6,250) |
(4,115) |
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
Proceeds from issue of share capital |
|
7,459 |
4,416 |
|
Share issue costs |
|
(336) |
(240) |
|
Repayments of loan & borrowings |
|
- |
(111) |
|
Finance costs paid |
|
- |
- |
|
Net cash inflow from financing activities |
|
7,123 |
4,065 |
|
|
|
|
|
|
Net change in cash and cash equivalents |
|
(657) |
(2,090) |
|
|
|
|
|
|
Cash and cash equivalents at beginning of the period |
|
2,371 |
4,461 |
|
|
|
|
|
|
Cash and cash equivalents at end of the period |
|
1,714 |
2,371 |
NOTES TO THE FINANCIAL STATEMENTS
1. Principal Accounting Policies
Basis of Preparation
UK Oil and Gas Investments PLC is a company incorporated in the United Kingdom. The Company's shares are listed on the AIM market of the London Stock Exchange.
The Consolidated Financial Statements are for the year ended 30 September 2017 and have been prepared under the historical cost convention and in accordance with International Financial Reporting Standards as adopted by the EU ("adopted IFRS"). These Consolidated Financial Statements (the "Financial Statements") have been prepared and approved by the Directors on 28 March 2018 and signed on their behalf by Stephen Sanderson and Kiran Morzaria.
The accounting policies have been applied consistently throughout the preparation of these Financial Statements, and the financial report is presented in Pound Sterling (£) and all values are rounded to the nearest thousand pounds (£ '000) unless otherwise stated.
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 Group and/or Company, as standards, amendments and interpretations which are effective for the financial year beginning on 1 October 2016 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 IFRSs, IASs and Interpretations were in issue but not yet effective. Their adoption is not expected to have a material effect on the financial statements unless otherwise indicated:
· IFRS 9 Financial Instruments (effective date 1 January 2018);
· IFRS 15 Revenue from Contracts with Customers (effective date 1 January 2018);
· IFRS 16 Leases (effective date 1 January 2019);
· IFRS 17 Insurance Contracts (effective date 1 January 2021).
Basis of consolidation
The consolidated financial information incorporates the financial statements of the Company and its subsidiaries (the "Group"). Control is achieved where the Group is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee.
Inter-company transactions, balances and unrealised gains on transactions between Group companies are eliminated; unrealised losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred.
Where necessary, adjustments are made to the financial statements of subsidiaries to bring the accounting policies used in line with those used by the Group.
Business combinations
Business combinations are accounted for using the acquisition method. The consideration for acquisition is measured at the fair values of assets given, liabilities incurred or assumed, and equity instruments issued by the Company in order to obtain control of the acquiree (at the date of exchange). Costs incurred in connection with the acquisition are recognised in profit or loss as incurred. Where a business combination is achieved in stages, previously held interests in the acquiree are re-measured to fair value at the acquisition date (date the Group obtains control) and the resulting gain or loss, is recognised in profit or loss. Adjustments are made to fair values to bring the accounting policies of acquired businesses into alignment with those of the group. The costs of integrating and reorganising acquired businesses are charged to the post acquisition profit or loss where applicable.
Revenue
Revenue is measured by reference to the fair value of consideration received or receivable by the Group for services provided, excluding VAT and trade discounts. Revenue is credited to the Income Statement in the period it is deemed to be earned.
Revenue from the sale of oil and petroleum products is recognised when the significant risks and rewards of ownership have been transferred, which is considered to occur when title passes to the customer. This generally occurs when the product is physically transferred into a vessel, pipe or other delivery mechanism.
Revenue from the production of oil, in which the Group has an interest with other producers, is recognised based on the Group's working interest and the terms of the relevant production sharing contracts. Differences between oil lifted and sold and the Group's share of production are not significant.
Finance Income and Costs
Finance income and costs are reported on an accruals basis.
Oil & Gas properties ("OGP"), Exploration & Evaluation assets
Oil and natural gas exploration, evaluation and development expenditure is accounted for using the successful efforts method of accounting.
(i) Pre-licence costs
Pre-licence costs are expensed in the period in which they are incurred.
(ii) Licence and property acquisition costs
Exploration licence and leasehold property acquisition costs are capitalised in intangible assets. Licence costs paid in connection with a right to explore in an existing exploration area are capitalised and amortised over the term of the permit.
Licence and property acquisition costs are reviewed at each reporting date to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration drilling is still under way or firmly planned, or that it has been determined, or work is under way to determine that the discovery is economically viable based on a range of technical and commercial considerations and that sufficient progress is being made on establishing development plans and timing.
If no future activity is planned or the licence has been relinquished or has expired, the carrying value of the licence and property acquisition costs are written off through the statement of profit or loss and other comprehensive income. Upon recognition of proved reserves and internal approval for development, the relevant expenditure is transferred to oil and gas properties.
(iii) Exploration and evaluation costs
Exploration and evaluation activity involves the search for hydrocarbon resources, the determination of technical feasibility and the assessment of commercial viability of an identified resource.
Once the legal right to explore has been acquired, costs directly associated with an exploration well are capitalised as exploration and evaluation intangible assets until the drilling of the well is complete and the results have been evaluated. These costs include directly attributable employee remuneration, materials and fuel used, rig costs and payments made to contractors.
If no potentially commercial hydrocarbons are discovered, the exploration asset is written off through the statement of profit or loss and other comprehensive income as a dry hole. If extractable hydrocarbons are found and, subject to further appraisal activity (e.g., the drilling of additional wells), it is probable that they can be commercially developed, the costs continue to be carried as an intangible asset while sufficient/continued progress is made in assessing the commerciality of the hydrocarbons. Costs directly associated with appraisal activity undertaken to determine the size, characteristics and commercial potential of a reservoir following the initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially capitalised as an intangible asset.
All such capitalised costs are subject to technical, commercial and management review, as well as review for indicators of impairment at least once a year. This is to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are written off through the statement of profit or loss and other comprehensive income.
When proved reserves of oil and natural gas are identified and development is sanctioned by management, the relevant capitalised expenditure is first assessed for impairment and (if required) any impairment loss is recognised, then the remaining balance is transferred to oil and gas properties. Other than licence costs, no amortisation is charged during the exploration and evaluation phase.
(iv) Development costs
Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalised within oil and gas properties.
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. Other property, plant and equipment are generally depreciated on a straight-line basis over their estimated useful lives, which is generally 20 years for refineries, and major inspection costs are amortised over three to five years, which represents the estimated period before the next planned major inspection. Property, plant and equipment held under finance leases are depreciated over the shorter of lease term and estimated useful life. 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 Group, 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 Group 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.
If the change in estimate results in an increase in the decommissioning liability and, therefore, an addition to the carrying value of the asset, the Group considers whether this is an indication of impairment of the asset as a whole, and if so, tests for impairment. If, for mature fields, the estimate for the revised value of oil and gas assets net of decommissioning provisions exceeds the recoverable value, that portion of the increase is charged directly to expense. Over time, the discounted liability is increased for the change in present value based on the discount rate that reflects current market assessments and the risks specific to the liability. The periodic unwinding of the discount is recognised in the statement of profit or loss and other comprehensive income as a finance cost. The Company recognises neither the deferred tax asset in respect of the temporary difference on the decommissioning liability nor the corresponding deferred tax liability in respect of the temporary difference on a decommissioning asset.
Taxation
Current tax is the tax currently payable based on taxable profit for the year.
Deferred income taxes are calculated using the liability method on temporary differences. Deferred tax is generally provided on the difference between the carrying amounts of assets and liabilities and their tax bases. However, deferred tax is not provided on the initial recognition of goodwill, nor on the initial recognition of an asset or liability unless the related transaction is a business combination or affects tax or accounting profit. Deferred tax on temporary differences associated with shares in subsidiaries and joint ventures is not provided if reversal of these temporary differences can be controlled by the Company and it is probable that reversal will not occur in the foreseeable future. In addition, tax losses available to be carried forward as well as other income tax credits to the Company are assessed for recognition as deferred tax assets.
Deferred tax liabilities are provided in full, with no discounting. Deferred tax assets are recognised to the extent that it is probable that the underlying deductible temporary differences will be able to be offset against future taxable income. Current and deferred tax assets and liabilities are calculated at tax rates that are expected to apply to their respective period of realisation, provided they are enacted or substantively enacted at the balance sheet date.
Changes in deferred tax assets or liabilities are recognised as a component of tax expense in the income statement, except where they relate to items that are charged or credited directly to equity in which case the related deferred tax is also charged or credited directly to equity.
Financial Assets
Financial assets are divided into the following categories: loans and receivables and available-for-sale financial assets. Financial assets are assigned to the different categories by management on initial recognition, depending on the purpose for which they were acquired, and are recognised when the Group becomes party to contractual arrangements. Both loans and receivables and available for sale financial assets are initially recorded at fair value.
Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. Trade, most other receivables and cash and cash equivalents fall into this category of financial assets. Loans and receivables are measured subsequent to initial recognition at amortised cost using the effective interest method, less provision for impairment. Any change in their value through impairment or reversal of impairment is recognised in the income statement.
Provision against trade receivables is made when there is objective evidence that the Group will not be able to collect all amounts due to it in accordance with the original terms of those receivables. The amount of the write-down is determined as the difference between the asset's carrying amount and the present value of estimated future cash flows.
A financial asset is derecognised only where the contractual rights to the cash flows from the asset expire or the financial asset is transferred, and that transfer qualifies for derecognition. A financial asset is transferred if the contractual rights to receive the cash flows of the asset have been transferred or the Group retains the contractual rights to receive the cash flows of the asset but assumes a contractual obligation to pay the cash flows to one or more recipients. A financial asset that is transferred qualifies for derecognition if the Group transfers substantially all the risks and rewards of ownership of the asset, or if the Group neither retains nor transfers substantially all the risks and rewards of ownership but does transfer control of that asset.
Derivative instruments are recorded at cost and adjust for their market value as applicable. They are assessed for any equity and debt component which is subsequently accounted for in accordance with IFRS's.
Financial Liabilities
Financial liabilities are obligations to pay cash or other financial assets and are recognised when the Group becomes a party to the contractual provisions of the instrument.
All financial liabilities initially recognised at fair value less transaction costs and thereafter carried at amortised cost using the effective interest method, with interest-related charges recognised as an expense in finance cost in the income statement. A financial liability is derecognised only when the obligation is extinguished, that is, when the obligation is discharged or cancelled or expires.
Inventories
Inventories are stated at the lower of cost and net realisable value. The cost of materials is the purchase cost, determined on first-in, first-out basis. The cost of crude oil and refined products is the purchase cost, the cost of refining, including the appropriate proportion of depreciation, depletion and amortisation and overheads based on normal operating capacity, determined on a weighted average basis. The net realisable value of crude oil and refined products is based on the estimated selling price in the ordinary course of business, less the estimated costs of completion and the estimated costs necessary to make the sale.
Cash and Cash Equivalents
Cash and cash equivalents comprise cash on hand and demand deposits, together with other short-term, highly liquid investments that are readily convertible into known amounts of cash and which are subject to an insignificant risk of changes in value.
Share-Based Payments
The Group operates a number of equity-settled, share-based compensation plans, under which the entity receives services from employees as consideration for equity instruments (options) of the Company. The fair value of the employee services received in exchange for the grant of the options is recognised as an expense. The total amount to be expensed is determined by reference to the fair value of the options granted:
· Including any market performance conditions;
· Excluding the impact of any service and non-market performance vesting conditions (for example, profitability or sales growth targets, or remaining an employee of the entity over a specified time period; and
· Including the impact of any non-vesting conditions (for example, the requirement for employees to save).
Non-market vesting conditions are included in assumptions about the number of options that are expected to vest. The total expense is recognised over the vesting period, which is the period over which all of the specified vesting conditions are to be satisfied.
In addition, in some circumstances, employees may provide services in advance of the grant date, and therefore the grant-date fair value is estimated for the purposes of recognising the expense during the period between service commencement period and grant date.
At the end of each reporting period, the entity revises its estimates of the number of options that are expected to vest based on the non-market vesting conditions. It recognises the impact of the revision to original estimates, if any, in profit or loss, with a corresponding adjustment to equity.
When the options are exercised, the Company issues new shares. The proceeds received, net of any directly attributable transaction costs, are credited to share capital (nominal value) and share premium.
Equity
Equity comprises the following:
"Share capital" representing the nominal value of equity shares.
"Share premium" representing the excess over nominal value of the fair value of consideration received for equity shares, net of expenses of the share issue.
"Share based payment reserve" represents the value of equity benefits provided to employees and directors as part of their remuneration and provided to consultants and advisors hired by the Group from time to time as part of the consideration paid.
"Retained earnings" represents retained profits and (losses).
Foreign Currencies
Transactions in foreign currencies are translated at the exchange rate ruling at the date of the transaction. Monetary assets and liabilities in foreign currencies are translated at the rates of exchange ruling at the balance sheet date. Non-monetary items that are measured at historical cost in a foreign currency are translated at the exchange rate at the date of the transaction. Non-monetary items that are measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined. Any exchange differences arising on the settlement of monetary items or on translating monetary items at rates different from those at which they were initially recorded are recognised in the profit or loss in the period in which they arise. Exchange differences on non-monetary items are recognised in other comprehensive income to the extent that they relate to a gain or loss on that non-monetary item taken to other comprehensive income, otherwise such gains and losses are recognised in the income statement.
The Group and Company's functional currency and presentational currency is Sterling.
Significant accounting judgements, estimates and assumptions
The preparation of the Group's consolidated financial statements requires management to make judgements, estimates and assumptions that affect the reported amounts of revenues, expenses, assets and liabilities, and the accompanying disclosures, and the disclosure of contingent liabilities at the date of the consolidated financial statements. Estimates and assumptions are continuously evaluated and are based on management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to the carrying amount of assets or liabilities affected in future periods.
In particular, the Group has identified the following areas where significant judgements, estimates and assumptions are required. Further information on each of these areas and how they impact the various accounting policies are described below and also in the relevant notes to the financial statements.
Changes in estimates are accounted for prospectively.
(i) Judgements
In the process of applying the Group's accounting policies, management has made the following judgements, which have the most significant effect on the amounts recognised in the consolidated financial statements:
(a) Contingencies
Contingent liabilities may arise from the ordinary course of business in relation to claims against the Group, including legal, contractor, land access and other claims. By their nature, contingencies will be resolved only when one or more uncertain future events occur or fail to occur. The assessment of the existence, and potential quantum, of contingencies inherently involves the exercise of significant judgement and the use of estimates regarding the outcome of future events.
(ii) Estimates and assumptions
The key assumptions concerning the future and other key sources of estimation uncertainty at the reporting date that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are described below. The Group based its assumptions and estimates on parameters available when the consolidated financial statements were prepared. Existing circumstances and assumptions about future developments, however, may change due to market change or circumstances arising beyond the control of the Group. Such changes are reflected in the assumptions when they occur.
Significant accounting judgements, estimates and assumptions (continued)
(a) Hydrocarbon reserve and resource estimates
Hydrocarbon reserves are estimates of the amount of hydrocarbons that can be economically and legally extracted from the Group's oil and gas properties. The Group 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 Brent oil price assumption used in the estimation of commercial reserves is US$80/bbl. The carrying amount of oil and gas development and production assets at 30 September 2017 is shown in Note 9.
The Group 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 Group's reported financial position and results, which include:
· The carrying value of exploration and evaluation assets; oil and gas properties; property, plant and equipment; and goodwill may be affected due to changes in estimated future cash flows
· Depreciation and amortisation charges in the statement of profit or loss and other comprehensive income 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
· The recognition and carrying value of deferred tax assets may change due to changes in the judgements regarding the existence of such assets and in estimates of the likely recovery of such assets
(b) Exploration and evaluation expenditures
The application of the Group's accounting policy for exploration and evaluation expenditure requires judgement to determine whether future economic benefits are likely, from future either 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 Group 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 statement of profit or loss and other comprehensive income in the period when the new information becomes available.
(c) 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 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
(d) Recoverability of oil and gas assets
The Group assesses each asset or cash generating unit (CGU) (excluding goodwill, which is assessed annually regardless of indicators) 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.
Information on how fair value is determined by the Group follows.
(e) Decommissioning costs
Decommissioning costs will be incurred by the Group at the end of the operating life of some of the Group's facilities and properties. The Group assesses its decommissioning provision at each reporting date. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing, extent and amount of expenditure may also change - for example, in response to changes in reserves or changes in laws and regulations or their interpretation.
Therefore, significant estimates and assumptions are made in determining the provision for decommissioning.
As a result, there could be significant adjustments to the provisions established which would affect future financial results.
External valuers may be used to assist with the assessment of future decommissioning costs. The involvement of external valuers is determined on a case by case basis, taking into account factors such as the expected gross cost or timing of abandonment, and is approved by the Company's Audit Committee. Selection criteria include market knowledge, reputation, independence and whether professional standards are maintained. The provision at reporting date represents management's best estimate of the present value of the future decommissioning costs required
(f) Fair value measurement
The Group measures financial instruments, such as derivatives, at fair value at each balance sheet date. From time to time, the fair values of non-financial assets and liabilities are required to be determined, e.g., when the entity acquires a business, or where an entity measures the recoverable amount of an asset or cash-generating unit (CGU) at FVLCD.
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest.
A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use.
The Group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, maximising the use of relevant observable inputs and minimising the use of unobservable inputs. From time to time external valuers are used to assess FVLCD of the groups non-financial assets. Involvement of external valuers is decided upon by the valuation committee after discussion with and approval by the Company's Audit Committee. Selection criteria include market knowledge, reputation, independence and whether professional standards are maintained. Valuers are normally rotated every three years. The valuation committee decides, after discussions with the Group's external valuers, which valuation techniques and inputs to use for each case.
Changes in estimates and assumptions about these inputs could affect the reported fair value.
Going Concern
The Directors noted the losses that the Group has made for the Year Ended 30 September 2017. The Directors have prepared cash flow forecasts for the period ending 31 March 2019 which take account of the current cost and operational structure of the Group.
The cost structure of the Group 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 Group to operate within its available funding.
These forecasts demonstrate that the Group has sufficient cash funds 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 Group remains a going concern. At 30 September 2017 the Company had cash and cash equivalents of £1,748,000 and borrowings of £nil. 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.
1. Business Combinations
Acquisition of Celtique Energie Weald Limited
On 13 June 2016 through UK Oil and Gas Investments Plc, the Group announced the acquisition of 100 per cent of the entire issued share capital of Celtique Energie Weald Limited. The company was re-named Kimmeridge Oil & Gas Limited.
The total consideration of £3.5million, comprised £1.25million in cash and £2.5million in the form of 142,648,831 UKOG ordinary shares. The acquisition was completed, and shares issued on 5 August 2016.
Through the business combination the Group acquired the following assets:
· Weald Basin licence, PEDL234, a 300 sq. km area, more than doubling the Group's net acreage holdings in the prime Kimmeridge Limestone Oil province.
The assets and liabilities arising on the day of the acquisition are as follows:
|
|
Celtique Energie |
|
|
|
|
Weald Limited Fair Value |
Fair Value Adjustments |
Total Fair Value |
|
|
£'000 |
£'000 |
£'000 |
|
|
|
|
|
|
Intangible Assets: Exploration Costs |
4,536 |
- |
4,536 |
|
|
|
|
|
|
Net identifiable assets acquired at fair value |
4,536 |
- |
4,536 |
|
|
- |
- |
- |
|
Total consideration |
3,507 |
- |
3,507 |
|
Negative goodwill on purchase |
|
|
1,029 |
|
|
|
|
|
|
Total cash outflow on the acquisition is as follows: |
|
|
|
|
Cash paid |
|
|
1,257 |
|
Net cash acquired with the subsidiaries |
|
|
- |
|
Net consolidated cash flow |
|
|
1,257 |
|
|
|
|
|
2. Segment Reporting
All of the Group's assets and operations are located in the United Kingdom. For management purposes, the Group is organised into business units based on the main types of activities and has three reportable segments, as follows:
· Oil exploration and production segment: includes producing business activities
· Oil exploration and evaluation: includes non-producing activities.
· Head Office, corporate and administrative, including parent company activities.
The Board of Directors monitors the operating results of its business units separately for the purpose of making decisions about resource allocation and performance assessment. Segment performance is evaluated based on operating profit or loss and is measured consistently with operating profit or loss in the consolidated financial statements. However, the Group's financing (including finance costs and finance income) and income taxes are managed on a group basis and are not allocated to operating segments.
The accounting policies used by the Group in reporting segments internally are the same as those used in the financial statements.
Subject to further acquisitions and/or disposals, the Group expects to further review its segmental information during the forthcoming financial year, as it begins to see the full impact of its acquisitions and/or disposals.
|
Group |
Oil production & exploration |
Oil exploration & evaluation |
Corporate & Administrative |
Consolidated |
|
Year ended 30 September 2017 |
£'000 |
£'000 |
£'000 |
£'000 |
|
Revenue |
|
|
|
|
|
External Customers |
207 |
- |
- |
207 |
|
Total revenue |
207 |
- |
- |
207 |
|
Results |
|
|
|
|
|
Depletion & impairment |
(74) |
- |
- |
(74) |
|
Share of associates loss |
- |
(77) |
- |
(77) |
|
Profit/(loss) before& after taxation |
(66) |
(209) |
(1,993) |
(2,268) |
|
|
|
|
|
|
|
Segment assets |
2,162 |
21,193 |
4,395 |
27,750 |
|
|
|
|
|
|
|
Segment liabilities |
(306) |
(3,415) |
(363) |
(4,084) |
|
|
|
|
|
|
|
Other disclosures: |
|
|
|
|
|
Investment in associate |
- |
323 |
- |
323 |
|
Capital expenditure (1) |
2 |
8,723 |
- |
8,725 |
(1) Capital expenditure consists of capitalised exploration expenditure, development expenditure, additions to oil & gas properties and to other intangible assets including expenditure on assets from the acquisition of subsidiaries.
|
Group |
Oil production & exploration |
Oil exploration & evaluation |
Corporate & Administrative |
Consolidated |
|
Year ended 30 September 2016 |
£'000 |
£'000 |
£'000 |
£'000 |
|
Revenue |
|
|
|
|
|
External Customers |
151 |
- |
- |
151 |
|
Total revenue |
151 |
- |
- |
151 |
|
Results |
|
|
|
|
|
Depletion & impairment |
(78) |
- |
- |
(78) |
|
Share of associates loss |
- |
(106) |
- |
(106) |
|
(Loss) before & after taxation |
(53) |
(106) |
(1,831) |
(1,972) |
|
|
|
|
|
|
|
Segment assets |
2,162 |
10,052 |
6,305 |
18,519 |
|
|
|
|
|
|
|
Segment liabilities |
(310) |
(341) |
(299) |
(950) |
|
|
|
|
|
|
|
Other disclosures: |
|
|
|
|
|
Investment in associate |
- |
2,800 |
- |
2,800 |
|
Capital expenditure (1) |
320 |
4,940 |
- |
5,260 |
(1) Capital expenditure consists of capitalised exploration expenditure, development expenditure, additions to oil & gas properties and to other intangible assets including expenditure on assets from the acquisition of subsidiaries.
3. Operating Loss
|
|
|
|
|
2017 |
|
2016 |
|
Group |
|
|
|
£'000 |
|
£'000 |
|
|
|
|
|
|
|
|
|
Operating (loss) is stated after charging: |
|
|
|
|
|
|
|
- Directors remuneration - fees & salaries |
|
|
|
428 |
|
489 |
|
- Employee Benefit Trust charge |
|
|
|
5 |
|
- |
|
- Auditors' remuneration |
|
|
|
|
|
|
|
Audit-related assurance services |
|
|
|
32 |
|
20 |
|
Other compliance services |
|
|
|
- |
|
- |
|
Tax compliance |
|
|
|
- |
|
- |
|
- Depletion & impairment of oil & gas properties |
|
|
|
74 |
|
78 |
4. Directors and Employees
The Company employed the services of 4 Employees (2016: 3). Remuneration in respect of these employees of which 3 were executive and non-executive Directors was:
|
|
|
|
2017 |
|
2016 |
|
Group |
|
|
£'000 |
|
£'000 |
|
|
|
|
|
|
|
|
Employment costs, including Directors, during the year: |
|
|
|
|
|
|
Wages and salaries |
|
|
453 |
|
413 |
|
Consultancy fees |
|
|
- |
|
76 |
|
Share based payments |
|
|
217 |
|
577 |
|
|
|
|
670 |
|
1,066 |
|
|
|
|
|
|
|
|
Average number of persons, including executive Directors employed |
No. |
|
No. |
||
|
Administration |
|
|
4 |
|
3 |
|
|
|
|
4 |
|
3 |
|
|
|
|
|
|
|
|
Directors' remuneration |
|
|
£'000 |
|
£'000 |
|
Emoluments |
|
|
645 |
|
1,066 |
|
|
|
|
|
|
|
|
The amounts set out above include remuneration in respect of the directors' are as follows: |
|||||
|
|
|
|
2017 |
|
2016 |
|
|
|
|
£'000 |
|
£'000 |
|
|
|
|
|
|
|
|
Donald Strang |
|
|
- |
|
1 |
|
Jason Berry (resigned 16 November 2016) |
|
|
65 |
|
366 |
|
Stephen Sanderson |
|
|
339 |
|
607 |
|
Kiran Morzaria |
|
|
179 |
|
92 |
|
Allen Howard (appointed 1 March 2017) |
|
|
62 |
|
- |
|
Total Directors Emoluments |
|
|
645 |
|
1,066 |
|
|
Fees and salaries |
Share based |
Total |
|
2017 |
£'000 |
£'000 |
£'000 |
|
S Sanderson |
240 |
99 |
339 |
|
K Morzaria |
100 |
79 |
179 |
|
A Howard (*) |
23 |
39 |
62 |
|
J Berry (**) |
65 |
- |
65 |
|
|
428 |
217 |
645 |
|
|
|
|
|
|
|
Fees and salaries |
Share based |
Total |
|
2016 |
£'000 |
£'000 |
£'000 |
|
S Sanderson |
240 |
367 |
607 |
|
K Morzaria |
92 |
- |
92 |
|
J Berry |
156 |
210 |
366 |
|
D Strang (***) |
1 |
- |
1 |
|
|
489 |
577 |
1,066 |
|
|
|
|
|
|
* Appointed 1 March 2017. ** Resigned 16 November 2016. *** Resigned 23 October 2015. **** Share based payments are non-cash remuneration by way of the issue of share options in the company. No pension contributions were made on behalf of Directors during the year. |
|||
5. Income Tax
There is no tax credit on the loss for the current or prior year. The tax assessed for the year differs from the standard rate of corporation tax in the UK as follows:
|
|
|
|
|
2017 |
|
2016 |
|
|
|
|
|
£'000 |
|
£'000 |
|
|
|
|
|
|
|
|
|
Loss for the year before tax |
|
|
|
(2,268) |
|
(1,972) |
|
Tax rate |
|
|
|
19/20% |
|
20% |
|
Expected tax credit |
|
|
|
(442) |
|
(394) |
|
|
|
|
|
|
|
|
|
Differences between capital allowances and depreciation |
|
|
|
- |
|
- |
|
Expenses not deductible for tax purposes |
|
|
|
107 |
|
136 |
|
Future income tax benefit not brought to account |
|
|
|
335 |
|
258 |
|
|
|
|
|
|
|
|
|
Actual tax expense |
|
|
|
- |
|
- |
|
|
|
|
|
|
|
|
|
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. Loss per Share
The calculation of the basic loss per share is calculated by dividing the consolidated loss attributable to the equity holders of the Company by the weighted average number of ordinary shares in issue during the year.
|
|
|
2017 |
|
2016 |
|
Group |
|
£'000 |
|
£'000 |
|
(Loss) attributable to ordinary shareholders |
|
(2,268) |
|
(1,972) |
|
|
|
|
|
|
|
|
|
Number |
|
Number |
|
|
|
|
|
|
|
Weighted average number of ordinary shares for |
2,905,392,699 |
|
2,177,913,909 |
|
|
|
|
|
|
|
|
|
|
Pence |
|
Pence |
|
|
|
|
|
|
|
Basic and diluted loss per share |
|
(0.08) |
|
(0.09) |
As inclusion of the potential ordinary shares would result in a decrease in the earnings per share they are considered to be anti-dilutive, as such, a diluted earnings per share is not included.
7. Exploration & evaluation assets
|
|
|
Group |
|
Company |
|
|
|
£'000 |
|
£'000 |
|
|
|
|
|
|
|
Cost & Net Book Value |
|
|
|
|
|
As at 1 October 2015 |
|
1,309 |
|
662 |
|
Acquired through Business Combinations |
|
4,420 |
|
- |
|
Additions |
|
458 |
|
80 |
|
As at 30 September 2016 |
|
6,187 |
|
742 |
|
|
|
|
|
|
|
Acquired through Business Combinations |
|
- |
|
- |
|
Reclassifications |
|
200 |
|
- |
|
Additions |
|
8,723 |
|
576 |
|
As at 30 September 2017 |
|
15,110 |
|
1,318 |
During the year, there has been no impairment charged, or considered there required to be. The Directors have assessed the fair value of the exploration & evaluation assets as at 30 September 2017 and have concluded at this time there is no requirement to impair and reduce the carrying value whilst they continue to explore and assess these licence areas, further to the detail below.
Exploration and evaluation activity involves the search for hydrocarbon resources, the determination of technical feasibility and the assessment of commercial viability of an identified resource. The additions during the year reflect the associated exploration and evaluation activities. As this point the Company is still assessing the potential of these assets and will continue to develop and evaluate these assets in the coming year. Since the acquisition date there has been no material changes to the Licence areas. The directors therefore consider that no impairment is required at 30 September 2017.
8. Oil & gas properties
|
|
Oil & gas |
Property, |
Total |
Oil & gas |
|
|
2017 |
2017 |
2017 |
2016 |
|
Group |
£'000 |
£'000 |
£'000 |
£'000 |
|
Cost |
|
|
|
|
|
As at 1 October |
1,660 |
370 |
2,030 |
1,648 |
|
Acquired through Business Combinations |
- |
- |
- |
116 |
|
Reclassifications |
- |
(200) |
(200) |
- |
|
Additions |
2 |
- |
2 |
266 |
|
As at 30 September |
1,662 |
170 |
1,832 |
2,030 |
|
|
|
|
|
|
|
Depletion & impairment |
|
|
|
|
|
As at 1 October |
(160) |
- |
(160) |
(82) |
|
Depletion charge |
(74) |
- |
(74) |
(78) |
|
As at 30 September |
(234) |
- |
(234) |
(160) |
|
|
|
|
|
|
|
Carrying value |
|
|
|
|
|
As at 30 September |
1,428 |
170 |
1,598 |
1,870 |
Impairment review
The Directors have carried out an impairment review as at 30 September 2017 and determined that an impairment charge is not currently required. The Directors based this assessment ongoing production from Hordean and in the case of Avingdon the operational optimisation that is ongoing to improve operational efficiencies.
9. Investment in Subsidiaries
|
Company |
|
|
|
|
2017 |
|
2016 |
|
|
|
|
|
|
£'000 |
|
£'000 |
|
Cost and net book amount |
|
|
|
|
|
|
|
|
At 1 October |
|
|
|
|
5,019 |
|
1,512 |
|
Additions in the year |
|
|
|
|
- |
|
3,507 |
|
At 30 September |
|
|
|
|
5,019 |
|
5,019 |
The Company holds more than 50 per cent of the share capital of the following companies as at 30 September 2017:
|
Company |
Country of Registration |
Proportion held |
Functional Currency |
Nature of business |
|
UKOG (GB) Limited |
UK |
100% |
GB£ |
Oil production |
|
UKOG Solent Limited |
UK |
100% |
GB£ |
Oil exploration |
|
UKOG Weald Limited |
UK |
100% |
GB£ |
Oil exploration |
|
Kimmeridge Oil & Gas Limited |
UK |
100% |
GB£ |
Oil exploration |
All subsidiary undertakings are included in the consolidation. The proportion of the voting rights in the subsidiary undertaking held directly by the parent company do not differ from the proportion of the ordinary shares held. The following companies are taking an exception from the audit of the financial statements as per S479A of the Companies Act; UKOG (GB) Ltd (04050227), UKOG Solent Ltd (05000092), UKOG Weald Ltd (04991234), Kimmeridge Oil & Gas Ltd (07055133).
10. Investment in Associate
|
Group & Company |
|
2017 |
|
2016 |
|
|
|
£'000 |
|
£'000 |
|
Carrying Value as at 1 October |
|
4,757 |
|
2,063 |
|
Re-classification from available for sale investments |
|
- |
|
- |
|
Equity additions at cost |
|
323 |
|
2,800 |
|
Share of associates loss for the year |
|
(77) |
|
(106) |
|
Carrying Value as at 30 September |
|
5,003 |
|
4,757 |
On 6 March 2015, the Company acquired a further 8% interest in Horse Hill Development Ltd. ("Horse Hill") for a cash consideration of £580,000, thus increasing the Company's holding to 28%. At this point the interest was deemed to qualify as that of an associate company and the investment re-classified from this date. A further 2% holding was acquired on 12 March 2016, for £352,000 payable by the issue of 44million Ordinary Shares in UK Oil & Gas Investments Plc, at a price of 0.8pence per share. This acquisition took the Company's interest in Horse Hill to a 30% shareholding.
On 15 April 2016, the Company acquired a further 12% interest in Horse Hill for a total consideration of £1,800,000, payable as £1,000,000 in cash and £800,000 by the issue of 43,886,116 Ordinary Shares in UK Oil & Gas Investments Plc, at a price of 1.82p per share. A further 8% interest was acquired on 21 July 2016, for total consideration of £1,000,000, payable as £150,000 in cash and £850,000 by the issue of 50,981,799 Ordinary Shares in UK Oil & Gas Investments Plc at a price of 1.57pence per share. These acquisitions to the Company's interest in Horse Hill to a 48% shareholding at 30 September 2017.
On 24 August 2017 the Company acquired a further 1.9% shareholding in Horse Hill total consideration of £323,000, payable as £54,498 in cash and £268,502 by the issue of 17,361,862 Ordinary Shares in UK Oil & Gas Investments Plc, at a price of 1.55p per share, thus increasing the Company's holding to 49.9%.
|
Details of the Group & Company's associate at 30 September 2017 are as follows: |
||||||||||
|
Name |
Place of Incorporation |
Proportion held |
Date associate interest acquired |
Reporting Date of associate |
Principal activities |
|||||
|
Horse Hill Developments Ltd |
UK |
49.9% |
06/03/15 |
31/12/16 |
Oil exploration |
|||||
|
|
||||||||||
|
Summarised financial information for the Group & Company's associate, where made publicly available, as at 30 September 2017 is given below: |
||||||||||
|
|
For the 9 months ended 30 September 2017 |
As at 30 September 2017 |
||||||||
|
|
Revenue £'000 |
(Loss) £'000 |
Total other comprehensive income £'000 |
Assets £'000 |
Liabilities £'000 |
|||||
|
Horse Hill Developments Ltd |
- |
(123) |
- |
9,598 |
(6,963) |
|||||
11. Available for Sale Investments
|
|
|
2017 |
|
2016 |
|
Group & Company |
|
£'000 |
|
£'000 |
|
Investment in unlisted securities |
|
|
|
|
|
Valuation at 1 October |
|
368 |
|
368 |
|
Additions at cost |
|
- |
|
- |
|
Disposals |
|
(368) |
|
- |
|
Valuation at 30 September |
|
- |
|
368 |
On 16 May 2014, the Company completed the acquisition of a strategic 6% shareholding in Angus Energy Plc, a company incorporated in Scotland and resident in the UK, for a consideration of £368,000, payable by the issue of 46million shares in the Company.
Angus Energy Plc completed a listing on the AIM Market on 14 November 2016. The Company disposed of its entire shareholding in Angus Energy Plc for £572,000 in early 2017 resulting in a gain on disposal of £204,000.
12. Inventory
|
|
|
2017 |
|
2016 |
|
Group |
|
£'000 |
|
£'000 |
|
|
|
|
|
|
|
Inventories - Crude Oil |
|
4 |
|
3 |
|
Total |
|
4 |
|
3 |
13. Trade and Other Receivables
|
|
Group |
Company |
||||
|
|
2017 |
|
2016 |
2017 |
|
2016 |
|
|
£'000 |
|
£'000 |
£'000 |
|
£'000 |
|
Trade debtors |
164 |
|
160 |
145 |
|
145 |
|
Other debtors |
1,488 |
|
594 |
418 |
|
546 |
|
Loans to related parties (see Note 24) |
2,117 |
|
2,117 |
2,117 |
|
2,117 |
|
Loans to subsidiary companies |
- |
|
- |
7,055 |
|
864 |
|
Prepayments and accrued income |
16 |
|
19 |
- |
|
- |
|
Total |
3,785 |
|
2,890 |
9,735 |
|
3,672 |
The directors consider that the carrying amount of trade and other receivables approximates to their fair value.
14. Cash and Cash Equivalents
|
|
Group |
Company |
||||
|
|
2017 |
|
2016 |
2017 |
|
2016 |
|
|
£'000 |
|
£'000 |
£'000 |
|
£'000 |
|
|
|
|
|
|
|
|
|
Cash at bank and in hand |
1,748 |
|
2,444 |
1,714 |
|
2,371 |
|
Total |
1,748 |
|
2,444 |
1,714 |
|
2,371 |
15. Trade and Other Payables
|
|
Group |
Company |
||||
|
|
2017 |
|
2016 |
2017 |
|
2016 |
|
Current trade and other payables |
£'000 |
|
£'000 |
£'000 |
|
£'000 |
|
Trade creditors |
2,656 |
|
536 |
283 |
|
244 |
|
Accruals and deferred income |
1,069 |
|
55 |
81 |
|
55 |
|
Total |
3,725 |
|
591 |
364 |
|
299 |
The directors consider that the carrying amount of trade and other payables approximates to their fair value.
16. Provisions - Decommissioning
|
|
|
2017 |
|
2016 |
|
Group |
|
£'000 |
|
£'000 |
|
As at 1 October |
|
359 |
|
359 |
|
Acquired on acquisition of subsidiaries |
|
- |
|
- |
|
Additions |
|
- |
|
- |
|
As at 30 September |
|
359 |
|
359 |
The amount provided at 30 September 2017 represents the Group's share of decommissioning liabilities in respect of the producing Horndean and Avington fields, and the Markwell's Wood and Havant drilling sites.
The Company makes full provision for the future cost of decommissioning oil production facilities and pipelines on a discounted basis on the installation of those facilities. The decommissioning provision represents the present value of decommissioning costs relating to oil and gas properties. At this point in time it is uncertain as to when some of these decommissioning costs will occur given current plans by the Company which may change when operations cease. Therefore, the Directors have taken a conservative approach and not discounted these values. These provisions have been created based on the Company's internal estimates. Assumptions based on the current economic environment have been made, which management believes are a reasonable basis upon which to estimate the future liability. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required that will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This, in turn, will depend upon future oil and gas prices, which are inherently uncertain.
17. Share Capital
|
Ordinary Shares |
Number of |
|
|
|
|
ordinary shares |
Nominal Value |
Total Value |
|
|
|
£ |
£'000 |
|
Issued at 30 September 2015 |
2,030,284,020 |
0.0001 |
203 |
|
On 01 March 16, for warrants exercised at 2.25p per share |
10,666,666 |
0.0001 |
1 |
|
On 10 March 16, for warrants exercised at 2.25p per share |
2,500,000 |
0.0001 |
- |
|
On 15 April 16, for acquisition at 1.82p per share |
43,886,116 |
0.0001 |
5 |
|
On 25 May 16, placing for cash at 1.5p per share |
266,666,667 |
0.0001 |
27 |
|
On 05 August 16, for acquisition at 1.58p per share |
142,648,831 |
0.0001 |
14 |
|
On 11 September 16, for acquisition at 1.67p per share |
50,981,799 |
0.0001 |
5 |
|
On 22 September 16, for options exercised at 0.4p per share |
30,000,000 |
0.0001 |
3 |
|
Issued at 30 September 2016 |
2,577,634,099 |
0.0001 |
258 |
|
|
|
|
|
|
On 08 December 16, for options exercised at 0.4p per share |
20,000,000 |
0.0001 |
2 |
|
On 24 May 17, placing for cash at 0.8p per share |
812,500,000 |
0.0001 |
81 |
|
On 16 June 17, for warrants exercised at 0.4p per share |
15,000,000 |
0.0001 |
1 |
|
On 19 July 17, for options/warrants exercised at 0.4p/2.25p per share |
55,000,001 |
0.0001 |
6 |
|
On 28 July 17, for warrants exercised at 0.8p per share |
40,625,000 |
0.0001 |
4 |
|
On 24 August 17, for acquisition at 1.55p per share |
17,361,862 |
0.0001 |
2 |
|
On 04 September 17, for options exercised at 0.4p per share |
2,000,000 |
0.0001 |
- |
|
Issued at 30 September 2017 |
3,540,120,962 |
0.0001 |
354 |
Deferred shares
The Company has in existence at 30 September 2016 and at 30 September 2017, 1,158,385,229 deferred shares of 0.001p. These deferred shares do not carry voting rights.
Total Ordinary and Deferred Shares
The issued share capital as at 30 September 2017 is as follows:
|
|
Number of shares |
Nominal Value £ |
Total Value £'000 |
|
|
|
|
|
|
Ordinary shares |
3,540,120,962 |
0.0001 |
354 |
|
Deferred shares |
1,158,385,352,229 |
0.00001 |
11,584 |
|
|
|
|
11,938 |
Share Options
During the year 120 million options were granted (2016: 65 million).
|
As at 30 September 2017 the options in issue were: |
|
|
|
Exercise price |
Expiry date |
Options in issue |
|
|
|
30 September 2016 |
|
|
|
|
|
0.4p |
31 December 2017 |
44,000,000 |
|
1.15p |
24 May 2022 |
120,000,000 |
|
1.82p |
26 September 2019 |
45,000,000 |
|
|
|
209,000,000 |
78.5 million options were exercised, and no options were cancelled during the year (2016: 30 million exercised).
20 million options lapsed during the year (2016: nil).
Warrants
As at 30 September 2017, no warrants were in issue (2016: 13,500,001).
40,625,000 warrants were issued during the year (2016: 13,500,001). No warrants lapsed during the year (2016: nil). 54,125,001 warrants were exercised during the year (2016: 13,166,666 exercised).
Employee Benefit Trust
The Company established on 29 September 2014, an employee benefit trust called the UK Oil & Gas Employee Benefit Trust ("EBT") to implement the use of the Company's existing share incentive plan over 10% 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, employees and consultants of the Company.
Accordingly, the trustees of the EBT subscribed for 129,000,000 new ordinary shares of 0.01p each in the Company, at par value per share at an aggregate cost to the Company of £12,900, such shares representing 9.07% of the existing issued share capital of the Company (at that date). The shares held in the EBT are intended to be used to satisfy future awards made by the Company's Remuneration Committee under the share incentive scheme.
No further issue of ordinary shares was made to the EBT during the year ended 30 September 2017.
18. Share-Based Payments
Details of share options and warrants granted during the year to Directors & consultants over the ordinary shares are as follows:
|
|
At 1 October 2016 |
Issued during the year |
lapsed /exercised during the year |
At 30 September 2017 |
Exercise price |
Date from which exercisable |
Expiry date |
|
|
No. |
No. |
No. |
No. |
£ |
|
|
|
Share options |
millions |
million |
millions |
millions |
|
|
|
|
|
|
|
|
|
|
|
|
|
Allen Howard |
- |
10 |
- |
10 |
0.0115 |
25/05/2017 |
24/05/2022 |
|
Donald Strang |
10 |
- |
(10) |
- |
0.0040 |
28/11/2013 |
28/11/2020 |
|
David Lenigas |
10 |
- |
(10) |
- |
0.0040 |
28/11/2013 |
28/11/2020 |
|
Jason Berry |
10 |
- |
(2) |
8 |
0.0115 |
22/08/2014 |
22/08/2019 |
|
Jason Berry |
20 |
- |
(20) |
- |
0.0182 |
28/09/2016 |
28/09/2016 |
|
Kiran Morzaria |
- |
20 |
- |
20 |
0.0115 |
25/05/2017 |
24/05/2022 |
|
Stephen Sanderson |
25 |
- |
- |
25 |
0.0040 |
21/01/2015 |
31/12/2017 |
|
Stephen Sanderson |
35 |
- |
- |
35 |
0.0182 |
28/09/2016 |
28/09/2016 |
|
Stephen Sanderson |
- |
25 |
- |
25 |
0.0115 |
25/05/2017 |
24/05/2022 |
|
|
110 |
55 |
(42) |
123 |
|
|
|
|
Consultants |
2.5 |
- |
(2.5) |
- |
0.0040 |
28/11/2013 |
28/11/2020 |
|
Consultants |
65 |
- |
(54) |
11 |
0.0040 |
21/01/2015 |
31/12/2017 |
|
Consultants |
10 |
- |
- |
10 |
0.0182 |
28/09/2016 |
28/09/2019 |
|
Consultants |
- |
65 |
- |
65 |
0.0115 |
25/05/2017 |
24/05/2022 |
|
|
187.5 |
120 |
(98.5) |
209.0 |
|
|
|
The share price range during the year was £0.0088 to £0.0898 (2016 - £0.0088 to £0.0298).
The disclosure of Weighted Average Exercise Prices, and Weighted Average Contractual Life analysis is not viewed as informative because of the minimal variation of options currently in issue, and therefore has accordingly not been disclosed.
For those options granted where IFRS 2 "Share-Based Payment" is applicable, the fair values were calculated using the Black-Scholes model. The inputs into the model were as follows:
|
|
Risk free rate |
Share price volatility |
Expected life |
Share price at date of grant |
|
28 September 2016 |
2.5% |
90.1% |
3 years |
£0.0180 |
|
25 May 2017 |
0.5% |
56.7% |
5 years |
£0.093 |
Expected volatility was determined by calculating the historical volatility of the Company's share price for 12 months prior to the date of grant. The expected life used in the model has been adjusted, based on management's best estimate, for the effects of non-transferability, exercise restrictions and behavioural considerations.
The Company recognised total expenses of £474,000 (2016: £682,000) relating to equity-settled share-based payment transactions during the year, and £526,000 (2016: £117,000) was transferred via equity to retained earnings on the exercising or lapse of options during the year.
19. Financial Instruments and Risk Analysis
Financial Assets by Category
The categories of financial asset included in the balance sheet and the headings in which they are included are as follows:
|
Current assets - Group |
|
2017 |
|
2016 |
|
|
|
£'000 |
|
£'000 |
|
Inventory |
|
4 |
|
3 |
|
Loans and receivables |
|
3,787 |
|
2,890 |
|
Cash and cash equivalents |
|
1,748 |
|
2,444 |
|
|
|
5,539 |
|
5,337 |
Financial Liabilities by Category
The categories of financial liability included in the balance sheet and the headings in which they are included are as follows:
|
Current liabilities - Group |
|
|
|
Financial liabilities measured at amortised cost |
3,725 |
591 |
The group is exposed to market risk through its use of financial instruments and specifically to credit risk, and liquidity risk which result from both its operating and investing activities. The group's risk management is coordinated at its head office, in close co-operation with the board of Directors, and focuses on actively securing the group's short to medium term cash flows by minimising the exposure to financial markets. Long term financial investments are managed to generate lasting returns. The group does not actively engage in the trading of financial assets for speculative purposes nor does it write options. The most significant financial risks to which the group is exposed to are described below.
Interest Rate Sensitivity
The group is not substantially exposed to interest rate sensitivity, other than in relation to interest bearing bank accounts.
Credit Risk Analysis
The group's exposure to credit risk is limited to the carrying amount of trade receivables. The group continuously monitors defaults of customers and other counterparties, identified either individually or by Company, and incorporates this information into its credit risk controls. Where available at reasonable cost, external credit ratings and/or reports on customers and other counterparties are obtained and used. Group's policy is to deal only with creditworthy counterparties. Group management considers that trade receivables that are not impaired for each of the reporting dates under review are of good credit quality, including those that are past due. None of the group's financial assets are secured by collateral or other credit enhancements. The credit risk for liquid funds and other short-term financial assets is considered negligible since the counterparties are reputable banks with high quality external credit ratings.
Liquidity risk analysis
The group's continued future operations depend on the ability to raise sufficient working capital through the issue of equity share capital. The Directors are confident that adequate funding will be forthcoming with which to finance operations. Controls over expenditure are carefully managed.
20. Financial Instruments and Risk Analysis (continued)
Capital Management Policies
The group's capital management objectives are to:
· Ensure the group's ability to continue as a going concern; and
· Provide a return to shareholders
The group monitors capital on the basis of the carrying amount of equity less cash and cash equivalents.
Commodity price risk
The Group is exposed to the risk of fluctuations in prevailing market commodity prices on the mix of oil and gas products it produces. The Group's policy is to manage these risks through the use of contract-based prices with customers.
Commodity price sensitivity
The table below summarises the impact on profit before tax for changes in commodity prices. The analysis is based on the assumption that the crude oil price moves 10% resulting in a change of US$5.43/bbl (2016: US$4.35/bbl), with all other variables held constant. Reasonably possible movements in commodity prices were determined based on a review of the last two years' historical prices and economic forecasters' expectations.
|
Increase/decrease in crude oil prices |
Effect on profit before tax for the year ended 30 September 2017 Increase/(Decrease)
|
Effect on profit before tax for the year ended 30 September 2016 Increase/(Decrease)
|
|
|
£'000 |
£'000 |
|
Increase US$5.43/bbl (2016: US$4.35/bbl) |
25 |
16 |
|
Decrease US$5.43/bbl (2016: US$4.35/bbl) |
(25) |
(16) |
21. Commitments & Contingent Liabilities
As at 30 September 2017, the Group had the following material commitments;
Ongoing exploration expenditure is required to maintain title to the Group's exploration permits. No provision has been made in the financial statements for these amounts as the expenditure is expected to be fulfilled in the normal course of the operations of the Group.
There were no contingent liabilities at 30 September 2017.
22. Events after the Reporting Date
On 9 November 2017, 8,000,000 options were exercised at 1.15p per share, for £92,000.
On 15 November 2017, the Company announced that it had entered into £10 million convertible loan agreement. As at the date of signing the annual report, £4.75 million of the loan has been converted into 211,943,189 shares at an average price of £0.022 per share.
23. Related Party Transactions
The company had the following amounts outstanding from its investee companies at 30 September:
|
|
2017 |
2016 |
|
|
£'000 |
£'000 |
|
|
|
|
|
Horse Hill Development Ltd ("Horse Hill") |
2,117 |
2117 |
|
|
|
|
|
|
2,117 |
2117 |
The above loans outstanding are included within trade and other receivables, Note 14. 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 cashflows.
MArch
|
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 |
||
|
|
2017 |
2016 |
|
|
£'000 |
£'000 |
|
|
|
|
|
Short-term employee benefits |
599 |
678 |
|
Share-based payments |
474 |
682 |
|
|
1,073 |
1,360 |
24. Ultimate Controlling Party
In the opinion of the directors there is no controlling party.
25. Profit and loss account of the parent company
As permitted by section 408 of the Companies Act 2006, the profit and loss account of the parent company has not been separately presented in these accounts. The parent company loss for the year was £2,070,000 (2016: loss £2,911,000).
This information is provided by RNS
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