Caspian Sunrise PLC
Annual Report 2018

Plain-text annual report

Company number: 5966431 Caspian Sunrise plc Annual report and financial statements for the year ended 31 December 2018 Contents Strategic Report Chairman’s Statement Directors’ report Report on Corporate Governance Remuneration Committee Report Report of the Audit Committee Independent auditors’ report to the members of Caspian Sunrise plc Consolidated Statement of Profit or Loss Consolidated Statement of Other Comprehensive Income Consolidated Statement of Changes in Equity Parent Company Statement of Changes in Equity Consolidated Statement of Financial Position Parent Company Statement of Financial Position Consolidated and Parent Company Statement of Cash Flows Notes to the Financial Statements 4 8 17 20 23 25 26 30 31 32 33 34 35 36 37 2 Directors Mr C Carver (Executive Chairman) Mr K Oraziman (Chief Executive Officer) Lord Limerick (Non-Executive Director) Mr T Field (Non-Executive Director) Company Secretary Mr C Carver FCA, FCT Registered Office and Business address 5 New Street Square, London EC4A 3TW Company Number 5966431 Nominated Adviser and Broker WH Ireland Limited, 24 Martin Lane, London EC4R 0DR Solicitors Fladgate LLP 16 Great Queen Street, London, WC2B 5DG Auditors BDO LLP, 55 Baker Street, London, W1U 7EU Share Register Link Asset Services, 6th Floor, 65 Gresham Street, London EC2V 7NQ Principal Banker Barclays Bank 1 Churchill Place, London, E14 5HP 3 Strategic Report The Directors present their strategic report on the Group for the year ended 31 December 2018. Introduction This strategic report comprises: the Group's objectives; the strategy; the business model; and a review of the Group's business using key performance indicators. The Chairman's statement, which also forms the main part of the strategic review, contains a review of the development and performance of the Group’s business during the financial year, and the position of the Group's business at the end of that year. Additionally, a summary of the principal risks and uncertainties facing the business is set out in this strategic report immediately before the Chairman's statement. Objectives The Group's objective is to create shareholder value from the development of oil and gas projects and associated activities. The Group has a number of secondary objectives, including promoting the highest level of health and safety standards, developing our staff to their highest potential and being a good corporate citizen in our chosen countries of operations. Strategy The Group's long-term strategy is to build an attractive portfolio of oil and gas exploration and production assets initially in Central Asia, and in particular Kazakhstan where the board has the greatest experience. Additionally, the Group will seek to exploit associated opportunities where the board believes it can add significant value and contribute towards the success of the Group as a whole. The Group’s principal asset is its interest in BNG, which the Group will continue to develop. Business model The business model is straightforward. To take assets at any stage of the development cycle and to improve them to the point they contribute to the Group’s profitability or that they may be sold on at a profit to provide funding for additional development. Our main asset BNG has been developed over the past 11 years to the point it now contributes to Group revenues and is set to be a very substantial asset for many years to come. In 2015, in poor market conditions with the oil price below $65 per barrel, we sold our second asset Galaz for a headline price of $100 million, which represented a profit of $15 million, and which provided $33 million to re-invest into BNG. 3A Best is our most recent acquisition and plans to develop this asset are close to finalisation. Further growth by acquisition The Group will consider acquiring additional assets or related businesses where the board believes they would increase shareholder value, including by providing funding or infrastructure to develop the Group’s other assets. In Kazakhstan the Directors believe the Group is exceptionally well placed through its local presence to identify and buy undervalued oil and gas assets on an opportunistic basis. Key performance indicators The Non-Financial Key Performance Indicators are: • Operational (wells drilled at end of year) 2018: 17 (2017: 16) • Daily production (based on average in December 2018) 1,903 bopd (2017: 2,208 bopd based on average in December 2017) • Reserves (at 31 December 2018 P1 17.8 mmbls & P2 28.8 mmbls (2017: P1 17.8mmbls & P2 28.8) mmbls The Financial Key Performance Indicators are: • Revenue: $10.7 million (2017: $7.6 million) • Cash at bank: $0.6 million (2017: $1.5 million) • Total assets: $72.5 million (2017: $81.7 million) • CAPEX expenditures: $7.5 million (2017: $9.2 million) The new well drilled in 2018 was Deep Well A8. The average daily production in December 2018 is 28% lower than in the corresponding period in 2017. This reflects our choice to use smaller choke settings to prolong the productive life of the wells and that during the period under review production from some of the producing wells was paused to allow workovers and the testing of different intervals. Reserves Details of the Group's assets and reserves are set out in the Chairman's statement. 4 Strategic Report (continued) Financial Cash flow from oil sales from our shallow wells, even at domestic prices, cover the Group’s General & Administrative costs and day to day operational costs at our shallow structures. It also makes a significant contribution to the costs of developing our deep wells. Under a full production license and with world prices of $70 per barrel we would expect the majority of our production to achieve a net price of approximately $38 per barrel before lifting, treatment, storage cost, broadly twice the current domestic price. Once any of our four deep wells start to produce oil, the associated revenues would transform the Group’s cash flows. Each shallow well typically costs between $1.0 million and $2.0 million to drill and test and each deep well typically costs approximately $10 - 12 million to drill, complete and test. These estimates do not include the costs of additional or remedial work, such as that taking place at the existing three deep wells A5, 801 & A6. Drilling wells at a rate faster than could be funded from oil sales, would require additional funding, as would any acquisitions to be funded by cash. As production increases and in particular as the deep wells come into production at BNG there will also be a requirement for investment in additional infrastructure to store, treat and transport the oil. Our current estimate of such costs is approximately $30 - 40 million, much of which may be debt financed. Other than periodic advances provided by local oil traders and $3.0 million to date provided by way of loan from Kuat Oraziman, our CEO, the Group is debt free. The principal and other risks and uncertainties facing the business Risk assessment and evaluation is an essential part of the Company’s planning and an important aspect of the Company’s internal control system. Oil & gas exploration and production is a dangerous activity and as such is necessarily subject to an extremely rigourous health and safety regime. Currently, the Board aims to identify and evaluate the risks the Company faces or is likely to face in future both from its immediate activities and from the wider environment. This helps to inform and shape the Company’s strategy and to quantify its tolerance to risk. As the Company develops, its approach to risk management and mitigation will be refined. We plan to include a formal risk register including all the principal operational and non-operational risks to the business. Such a risk register would be reviewed and assessed at least once a year by a new Governance and Risk Committee. The Company and the Group are subject to various risks relating to political, economic, legal, social, industry, business and financial conditions. The following risk factors, which are not exhaustive, are particularly relevant to the Company and the Group's business activities: Permitting risks We operate in a highly regulated industry. As such we are only able to fulfil our work programme obligations once agreed with the Kazakh regulatory authorities after we receive all the required permits, licences and other permissions. Delays in receiving these regulatory clearances usually result in additional costs. Regulatory delays are inevitable and common place. However, our large Kazakh workforce has both a thorough knowledge of the complex rules and a detailed practical understanding of the workings of each of the regulatory bodies with whom we need to deal. Accordingly, we believe we are well placed to minimize the financial impact of regulatory delays. Financing risks Despite the sustained low price of rigs and crew, exploring for oil is still an expensive business. However, the relatively low value of the Kazakh Tenge compared to the US$ reduces the costs of exploration and production as most staff costs and some equipment costs are denominated in Kazakh Tenge. Even with domestic pricing cash from the sale of oil from our shallow wells comfortably covers the day to day costs of operating the shallow wells and the Group’s General & Administrative expenditure. The Group enters into contracts with oil traders to forward sell its production and receives advances as part of its operating activities. The continued availability of such arrangements is important to working capital and, in the event the Group was unable to continue to access these arrangements, additional funding would be required. The risk is considered reduced given the expected growth in production revenues and is mitigated by maintaining strong relationships with the oil traders. In the absence of such additional funding the Group has a reasonable amount of control over the extent and timing of new drilling. Under world prices, which would apply to the majority of oil sold from the MJF structure once the BNG licence upgrade is approved, the Group forecasts indicate sufficient working capital is available to meet all shallow structure cost and the Group’s G&A expenditure. In the event that the award of a production license is further delayed the Group would require additional working capital during the period to meet certain payments under its licenses and drilling and well repair expenditures. Pending any contribution from oil sales from our deep wells new drilling will require additional funding. Such funding is in the opinion of the directors available from a number of sources including further advances from local traders, industry funding in the form of partnerships with larger industry players, if appropriate equity funding from financial institutions, or from further loans from Kuat Oraziman, our CEO. In this regard he has provided a written undertaking facility to provide financial support as is required, which the Board is satisfied will be available, given the history of financial support and having considered his ability to provide such funding. 5 Strategic Report (continued) Refer to note 1.1 for further details on funding and going concern. Exploration risk Despite our successes with our shallow wells there is no assurance that the Group's future exploration activities will continue to be successful. In particular, the high pressure and high temperature encountered when drilling below the salt layer has proved extremely difficult to control to allow prolonged flow tests to commence. The Group seeks to reduce this risk by acquiring and evaluating 3D seismic information before committing to drill exploration and appraisal wells. The Company also seeks to engage suitably skilled personnel either as employees or contractors to undertake detailed assessments of the areas under exploration. Environmental and other regulatory requirements Existing and possible future environmental legislation, regulations and actions could cause additional expense, capital expenditures, restrictions and delays in the activities of the Group, the extent of which cannot be predicted. Before exploration and production can commence the Group must obtain regulatory approval and there is no assurance that such approvals will be obtained. No assurance can be given that new rules and regulations will not be enacted or existing legislations will not be applied in a manner, which could limit or curtail the Group's activities. The Group employs staff experienced in the requirements of the Kazakh environmental authorities and seeks through their experience to mitigate the risk of non-compliance with accepted best practice. Operational risks It is the nature of oil and gas operations that each project is long term. It can be many years before the exploration and evaluation expenditures incurred are proven to be viable and can progress to reach commercial production. To control these risks the Board arranges for the provision of technical support, directly or through appointed agents and also as appropriate commissions technical research and feasibility studies both prior to entering into these commitments and subsequently in the life of these projects. In addition, operational risks include equipment failure, well blowouts, pollution, fire and the consequences of bad weather. Where the Group is project operator, it takes an increased responsibility for ensuring that the Group is compliant with all relevant legislation. The Group endeavours to use competent people with appropriate skills to manage such risks at the appropriate levels within the Group structure. Additionally, where appropriate the Group engages expert contractors. Political risk To date the Group operates primarily in Kazakhstan. The nature of the Group's investments requires the commitment of significant funding to facilitate exploration and evaluation expenditure in Kazakhstan. While the Group enjoys very good working relationships with the Kazakh regulatory authorities there can be no assurances that the laws and regulations and the reinterpretation will not change in future periods and that, as a result, the Group’s activities would be affected. However, the Directors believe with the exceptionally high proportion of Kazakh nationals in key positions and the Group’s prolonged experience of operating in Kazakhstan, it is as well placed as any internationally listed company operating in Kazakhstan to avoid inadvertently falling foul of local regulations or customs. The recent transition to a new President suggests the political situation is stable. Pricing risk The Group’s financial performance could be adversely affected by a fall in the price of oil. World prices have remained relatively stable in the period under review and subsequently. To date, the bulk of oil sold is from the BNG Contract Area under the terms of the current license and has been at domestic prices, which in recent months have typically been approaching US$18 -20 per barrel. Under a full production license oil sold will be based on world prices, currently in the region of $70 per barrel, and we estimate the net price received (after and applicable taxes but before costs of production, treatment, storage) would be approximately $38 per barrel. Exchange rate risk The Group's income is denominated in US$ and its expenditure is denominated in US$ and Kazakh Tenge. In the year under review the Tenge depreciated by some 16% against the US$. In earlier years, the Tenge has suffered more serious depreciation against the US$, which while damaging to the country has materially benefitted the Group. Since 2008 the US$ has appreciated against the Tenge by more than 200%. 6 Strategic Report (continued) In the event the Kazakh Tenge is devalued further against the US$, the Company benefits as income is unaffected but Tenge denominated costs fall when reported in US$. However, the Group's presentational currency is the US$ such that when the BNG assets recorded in Kazakh Tenge in its subsidiary’s accounts are retranslated in to US$ for presentational purposes. Between 1 January 2015, and 31 December 2018 the Kazakh Tenge devalued against the US$ from US$1:KZT182 to US$1:KZT384 resulting in an accounting reduction in the US$ carrying value of our unproven oil and gas assets. The US$55.7 million carrying value at 2018 would have been approximately US$130 million in the absence of such a devaluation. Given the relative strengths of the US$ and the Kazakh Tenge, the Group has decided not to seek to hedge this foreign currency exposure. Clive Carver Executive Chairman 23 May 2019 7 Chairman’s statement Introduction Progress in 2018 at our flagship asset BNG in the period under review was limited. We continued to move forward at a steady pace with our shallow structures, in particular the MJF, but have not yet had the breakthrough we expected at any of the deeper structures. Nevertheless, we are a Group with reliable production from our shallow wells, the income from which is sufficient to cover the day to day operating costs of the Group with additional funding identified for our planned drilling programme. We expect our income to grow materially following the anticipated receipt the MJF export licence and as we embark on a 10 well infill MJF drilling programme. A significant proportion of the costs of our deep drilling programme have also been met from the income from our shallow production boosted from time to time by funds supplied by our CEO Kuat Oraziman. As a low-cost producer with strong cash flows, low debt levels and a huge upside potential the board remains extremely confident in the Group’s successful future. Background The Company’s principal asset is its 99% interest in the BNG Contract Area. We first took a stake in the BNG Contract Area in 2008 as part of the acquisition of 58.41% of portfolio of assets owned by Eragon Petroleum. In 2017 we increased our stake to 99% upon the completion of the merger with Baverstock GmbH. Since 2008 more than $95 million has been spent at BNG. The Contract Area is located in the west of Kazakhstan 40 kilometers southeast of Tengiz on the edge of the Mangistau Oblast, covering an area of 1,561 square kilometers of which 1,376 square kilometers has 3D seismic coverage acquired in 2009 and 2010. We became operators at BNG in 2011, since when we have identified and developed both shallow and deep structures. At that time Gaffney Cline & Associates (“GCA”) undertook a technical audit of the BNG license area and subsequently Petroleum Geology Services (“PGS”) to undertake depth migration work, based on the 3D seismic work carried out in 2009 and 2010. The work of GCA resulted in confirming total unrisked resources of 900 million barrels from 37 prospects and leads mapped from the 3D seismic work undertaken in 2009 and 2010. The report of GCA also confirmed risked resources of 202 million barrels as well as Most-Likely Contingent Resources of 13 million barrels on South Yelemes. In September 2016 Gaffney Cline & Associates assessed the reserves attributable to the BNG shallow structures. Based on these assessments we set out the year end positions as follows: BNG Shallow P1 (mmbls) Shallow P2 (mmbls) Deep P1 (mmbls) Deep P2 (mmbs) As at 31 December 2018 As at 31 December 2017 17.8 28.8 Nil Nil 17.8 28.8 Nil Nil The above is based on 100% of each Contract Area. GCA are working with us on an update to the 2016 estimates and seeking to confirm the reserves from our shallow structure based on actual rather than theoretical data. They are also on standby to update their work when any of the deep wells flow sufficiently for a reliable flow test. Shallow structures There are two confirmed and producing shallow structures at BNG with the possibility of a third. MJF We announced the discovery of the MJF structure in 2013 and have subsequently drilled 6 wells of which 5 are currently producing. We believe the productive reservoir consists of stacked pay intervals with most ranging in thickness from two meters to 17 meters. The current mapped lateral extent of the MJF field is approximately 10km2. The producing wells range in depth from 2,192 meters to 2,448 meters. In December 2018 we formally applied to move the MJF structure, which is currently part of the overall BNG licence, from an appraisal licence to a full production licence, under which the majority of the oil produced from the MJF wells could be sold by reference to world rather than domestic Kazakh prices. This would, in the Board’s view, broadly double the income from the same production levels. The impact of a combination in a change to the licensing systems coupled by a long-expected reshuffle of those occupying ministerial positions has resulted in a much greater delay than we anticipated or is warranted. 8 Chairman’s statement (continued) The principal change to the licence systems has been to reduce the length of an appraisal licence from the previous six years to the current five years. In return a licence holder's obligations to make meaningful social payments during the appraisal period has been significantly reduced. In the light of these events we understand a backlog of licence applications has arisen. Nevertheless, we continue to expect an early award of a full production licence for the MJF structure. Recent daily production from those MJF wells operating has been approximately 1,500 bopd and we believe the maximum production capacity from the wells drilled to date when working to their optimum is some 2,000 bopd. On receipt of the upgraded MJF licence we intend to embark on an infill drilling programme of 10 new shallow wells over a 24 month period at an expected cost of between $1 and $2.0 million per well. Following completion of the infill drilling programme we expect the productive capacity of the wells then drilled at the MJF structure when working optimally should increase to some 4,000 bopd. South Yelemes The first wells were drilled on the South Yelemes structure during the Soviet era. Well 54 remains intermittently active between periods of being shut in to allow pressure to be restored. There are three other wells at South Yelemes (805, 806 & 807) producing in aggregate 140 bopd, which in itself is not particularly exciting. However, as previously reported we believe the structure, including Well 54, may have untapped quantities of oil at higher levels than previously explored making it potentially suitable for a horizontal drilling campaign. At an appropriate time we intend to test this theory. Potential New Structure In April 2017, we drilled Well 808 to a depth of 3,070 meters to assess whether a new structure similar to the MJF structure existed. The results of limited testing were inconclusive indicating oil bearing intervals with high water saturation. Recent re-evaluation of the wireline and mudlog data suggests additional untested potential within two intervals shallower in the well. We have now re-completed the bottom of the well to isolate the water and are set to reperforate the well at intervals between 2,033.5 meters to 2,035.5 meters and between 2,250 meters and 2,253 meters. Deep structures Airshagyl We believe the Airshagyl structure extends to 58 km2. Deep Well A5 Deep Well A5 was spudded in July 2013 and drilled to a total depth of 4,442 meters with casing set to a depth of 4,077 meters to allow open hole testing. Core sampling revealed the existence of a gross oil-bearing interval of at least 105 meters from 4,332 meters to at least 4,437 meters. The well was difficult to drill with a salt layer of approximately 130 meters and high temperatures and pressures at the lower depths. The extremely high-pressure in the well required the use of drilling fluids with a high density (2.16 g/cm3). Removing this high- density drilling fluid to allow testing was problematic but was eventually completed to allow an extended flow test. In December 2017, the well tested for 15 days at an average rate of 3,800 bopd before the flow reduced by debris in the well to 1,000 bopd leading to the well test being suspended. Since that date we have struggled to clear the well from initially excess drilling fluid and latterly metal objects. Despite on occasion being very close to removing the remaining metal obstruction from the well in May 2019, we decided to suspend further work on the current side-track and plan to drill a new side-track from a depth of 3,850 meters to a depth of 4,450 meters. Discussions with potential contractors have commenced and we expect to complete the new side-track approximately two months after work commences. Deep Well A6 The second well drilled in the Airshagyl structure was Deep Well A6, which was spudded in 2015 and drilled to a depth of 5,050 meters. Repeated problems in perforating the well at the interval of interest prevented the well being put on test and for the period under review work on A6 waited on the completion of work being undertaken at both Deep Wells A5 and 801. Advice has been received from an international consultancy with expertise in high pressure / high temperature wells and a new internal work programme agreed upon. 9 Chairman’s statement (continued) We intend first to re-cement the bottom of the well in order to isolate the lower portion of the well preventing water encroachment from below. After cementing, the deeper most prospective portion of the reservoir; 4479m- 4489m, will be reperforated. Depending upon results we may also reperforate the upper prospective reservoir interval. Recently, oil from behind the casing came to the surface under its own pressure. The well has now been closed in anticipation of the planned works. Deep Well A8 In November 2018 Deep Well A8 was spudded with a planned total depth of 5,300 meters. To date we have drilled and laid casing to a depth of 4,100 meters. The well is targeting the same pre-salt carbonates that were successfully identified in the Deep Well A5. We also plan to evaluate deeper carbonate targets of Devonian to Mississippian ages. Drilling has now reached a depth of 4,391 meters, which is beyond the salt and clay layers and well into the first of the expected oil- bearing zones. We are pleased to report that oil bearing rock has been recovered, indicating the presence of an oil-bearing interval. A third-party specialist company engaged to collect core samples covering the full extent of the interval has reported oil and gas in a 4 meter core. Drilling and core sampling is set to continue. This find together with the finds at Deep Wells A5 and A6 marks the third of the three deep wells drilled on the Airsghagyl structure and which has shown the presence of oil. The Company believes the structure may extend across the full 58 km2 of the Airshagyl structure The second reservoir target is of Devonian age anticipated at a depth of approximately 5,200 meters. Based on progress to date we continue to expect to reach total depth in Quarter 3 2019. Summary Based on results to date we believe the Airshagyl structure will provide the greatest quantities of oil at the BNG Contract Area, with wells potentially consistently flowing at the rate of in excess of 2,500 bopd. With oil confirmed from three separate wells on the Airshagyl structure we expect this structure to be the next we apply to have moved to a full production licence with the majority of oil produced sold by reference to world rather than domestic prices. Yelemes Deep We believe the Yelemes Deep structure extends over an area of 36 km2. Deep Well 801 To date Deep Well 801 is the only well drilled at the Yelemes structure. The well was spudded in December 2014 and was drilled to a Total Depth of 4,950 meters. The well is located approximately 8 kilometers from Deep Well A5 and was planned to target prospects in the Middle and Lower Carboniferous The blockages in the well preventing an extended flow test are the result of high temperatures/ pressures and excess drilling fluids. A combination of invasion by the extensive heavy drilling fluids along with the usual challenge associated with the completion of high temperature, high pressure wells are believed to be hampering successful production test. We have used a variety of techniques including the use of chemicals and the drilling of a side-track in Q1 2018 to establish good reservoir connectivity. For a period we allowed the natural pressure inside and outside the drill pipe to build in the expectation this would over time reduce the blockage. More recently we have been looking at using the pressure in the well to stimulate activity inside the well by a process of reinjection. Recently, for safety reasons, the well has been opened on an almost daily basis to relieve the excess pressure build up and on those occasions water and gas has come to the surface to the surface. A technical review by leading international consultants confirmed our plan to conduct a pressurised acid treatment of the well as the best way forward. The common problems with the deep wells We have struggled with our deep wells since the outset. We believe all the issues in getting our deep wells to test on an extended basis are from blockages in the well stemming from a combination of extreme pressure and extreme temperatures. At Deep Well A5 the pressure has reached 930 ATM and at deep well 801 the bottom hole pressure has reached 850 ATM. Bottomhole temperatures are about 128 degree centigrade. These are exceptional levels when compared to wells of similar depths in other territories and we have found there to be a lack of skilled operators capable of first, drilling the wells and second, bringing such wells into production. Our specialist blow-out preventers have a certified capacity of 500 ATM. The additional overlying 5,000 meters of hydrostatic pressure above the open reservoir section provides a total of approximately 1,000 ATM of pressure control. Issues with deep wells is not uncommon in the region. The nearby Tengiz field, which targets the same aged reservoirs at about the same depths drilled the first discovery well in 1979 but first production did not happen until 12 years later. The field is now producing at the rate of 540,000 bopd. 10 Chairman’s statement (continued) The operators there developed specialist skills and now enjoy the rewards from operating one of the world’s most successful fields. We are seeking to replicate these skills by using the knowledge of leading international consultancies. We have also learnt from the problems of the first wells drilled. We are now able to drill through the salt levels and below with far fewer issues than at the outset. More difficult has been getting the wells once drilled to flow sufficiently long enough to conduct extended flow tests. With a history of blow-outs from wells drilled on the Contract Area in Soviet times every action to allow the wells to flow to conduct the extended flow tests is taken only after very careful safety considerations and often after lengthy discussions with the regulatory authorities. Infrastructure requirements We are able to transport our current production using storage tanks with aggregate capacity of 7,000 bbls and using a fleet of heated tankers. As production levels from the MJF structure increase and when production commences from the deep wells drilled relying on our present arrangements would no longer make commercial sense. At this point a pipeline either to an adjoining Contract Area or to a treatment facility with access to the main pipeline network would be required. In addition, we would look to conduct additional water separation and other treatment activities before selling the oil produced, increasing the price at which our production could be sold. The timing of a decision on how to proceed with a build-out of the infrastructure for the BNG Contract Area is inevitably linked to actual production levels. In the event we decide to construct significant additional storage, treatment and distribution facilities at the BNG Contract Area we believe the majority of the costs involved would be capable of being debt funded. Services division We have also decided to establish our own services division. This reflects the expected increase in operational activities as the Group develops. We believe significant cost savings would be available if we owned more of the equipment we currently hire. We would also avoid often lengthy periods of inactivity when the required equipment is not available for hire. We also believe there are significant opportunities to participate in new projects in part by way of supplying equipment otherwise difficult to source from the hire sector. BNG Summary It is clear to the Board that there is very significant value in the BNG Contract Area even if we have yet to prove its full extent. The Board remains confident that it is a matter of time before we are able to get at least some of the deep wells drilled onto an extended test, following which we plan to ask Gaffney Cline to assess a reserve estimate. 3A Best In January 2019, the Group acquired 100 per cent of the shares of 3A Best Group JSC, a company that owns a 1,347 sq km Contract Area located close to the Caspian port city of Aktau in the Mangystau Province of Kazakhstan.The site is located adjacent to and runs under the commercially successful Dunga field, which was discovered in 1966 and developed by Maersk Oil. Whilst the Company has acquired the equity of 3ABest Group JSC, the acquisition will be recorded as an asset purchase as the company’s sole asset is the exploration stage Contract Area. The 149,253,732 consideration shares were calculated by reference to an agreed issued price of 12p per share, which resulted in a total purchase consideration of $23 million. Before the acquisition was finalised we agreed with the vendors to reduce the notional issue price of the shares to 7.0p per share, being the market price at 21 January 2019, but keeping the number of shares at 149,253,732 thereby reducing the headline price to $13.5 million. Based on an assessment of the geology we believe some of the geological characteristics of the Dunga Contract Area are also present at 3A Best. Additionally, we believe the area 2,500 meters and below the Dunga Contract area, which forms part of the 3A Best Contract Area, also indicates the likely presence of oil. 490 sq km of 3D seismic has been shot. 1,327 linear km of 2D has been digitised and reprocessed. Two wells have been drilled on the Contract Area in recent years, both encountering water and signs of oil and gas, although neither was commercially successful. Under the terms of the inherited work programme we have the obligation to drill one well to a depth of 3,000 meters by the end of 2019 at an anticipated cost of $1.2 million and a second in March 2020 at a cost of $1.4 million. Discontinued activities Munaily We had for some time been seeking a buyer for our interest in Munaily following a disappointing outcome of a joint venture with a Chinese partner. In December 2018 we sold our interest in Munaily to WIX Energy LLP for an aggregate consideration of $0.134 million, resulting in an accounting loss of $5.147 million (note 21) primary due to the recycling historic foreign exchange losses from equity on disposal. 11 Chairman’s statement (continued) Beibars The force majeure declared in November 2015 in respect of our 50% interest in the Beibars Contract Area prevented any development work at the large but early stage asset. Given our successes at BNG, another previously early stage Contract Area and other opportunities in Kazakhstan we chose in March 2017 to surrender our 50% interest in the Beibars Contract Area for no consideration. Dilution Our recent strategy has been to avoid unnecessary dilution both at the individual asset level and at the shareholder level. With the exception of shares issued in connection with (1) the cancelation of the BNG royalty payments (2015); (2) the Baverstock merger (2017); and (3) the acquisition of 3A Best; there have been no material issue of new shares in recent years. This is despite the Company’s operational activities being constrained by a lack of cash. We have therefore been selective in choosing which of our structures to develop. Where necessary we have used funding provided by local oil traders secured on pre sales of oil backed up by periodic advances under the general loan agreement (referred in note 1.1) with Kuat Oraziman, our CEO. Dividends It is the policy of the Board to work towards an early position where meaningful dividends can be paid. This requires not only consistently profitable trading but also in all likelihood a corporate reorganisation. New corporate subsidiaries have been incorporated in the UAE, with a view improving and simplifying the Group structure and easing the future payment of dividends. The Board believes that with a sustainable dividend policy, the Group will be valued more highly than at present and will also help facilitate institutional investment. Any dividend declared will be set at an affordable level that does not conflict with the need to fund value enhancing growth, whether by further investments in our existing fields or by acquisition. Further acquisitions Notwithstanding our approach to dilution and dividends, it is the Group’s intention to make further asset acquisitions where the board believes the assets in question will add to the Group’s long-term value. Our ambition is to significantly grow the business both by the development of BNG and 3A Best but also by targeted acquisitions. Our initial focus will remain in Kazakhstan where there are attractive opportunities, limited local competition and where we have a competitive advantage being on the ground. We also intend to bid for new blocks, including offshore blocks, both in our own right and as part of larger consortia. Where appropriate, we will also consider the acquisition of allied businesses, including service businesses and stand-alone equipment, provided the expected net return to the Company makes any dilution worthwhile. Several opportunities have been identified and preliminary due diligence conducted. Kazakhstan Since our IPO in 2007 we have focused entirely on Kazakhstan and in recent years entirely on the pre-Caspian basin located on the north eastern shore of the Caspian Sea. Introduction The Republic of Kazakhstan is the world's largest landlocked country and the ninth largest in the world, with an area of 2,724,900 square kilometres. Most of the country is in Asia with only the most western parts being in Europe. Kazakhstan is the dominant nation of Central Asia economically, generating approximately 60% of the region's GDP, primarily through its oil and gas industry. It also has vast mineral resources. The recent transition to a new President suggests the political situation is stable. Oil and gas in Kazakhstan Super giants Three of the world’s largest oil and gas projects are located in Kazakhstan, Tengiz, Kashagan and Karachaganak, with Tengiz and Kashagan being close to BNG. Tengiz, Tengiz, which is located just onshore along the northeast edge of the Caspian Sea is only 40 km from our flagship BNG asset in the Pre-Caspian basin. Oil in place for the field is estimated to be 25 billion barrels, of which 7 billion barrels are likely to be recoverable. The Tengiz field currently produces approximately 540,000 bopd. Chevron, the lead operator, is spending a reported $37 billion to increase production by 260,000 bopd by 2022. Our technical team believe BNG may share a number of important geological features with Tengiz. 12 Chairman’s statement (continued) Kashagan The Kashagan oilfield is located 80km south-east of Atyrau in the North Caspian Sea, Kazakhstan, and is the largest offshore field outside the Middle East. The field contains more than 35 billion barrels of oil in total and an estimated recoverable oil reserve of nine billion barrels. It was discovered in 2000 and commercial development was announced in 2002. The field is being developed in phases by the North Caspian Sea Production Sharing Agreement (NCSPSA) consortium comprised of KMG (KazMunayGas), Eni, ExxonMobil, Shell, Total, ConocoPhillips and INPEX. The total cost of the project is estimated to be more than $100bn. Initial oil production from Kashagan started in 2013 but had to be stopped due to faults in onshore section of pipeline. Production resumed in 2016 with commercial production announced in October following the first export delivery of 26,500 metric tons. By mid-2017 production being delivered was over 200,000 barrels a day. By year end 2017 production capacity was 270,000 barrels of oil per day with the goal of increasing production capacity to 370,000. Also, at the end of 2017 the Kazakh government approved early engineering and design work for a further expansion project which could raise Phase 1 production capacity to 450,000 bopd. Karachaganak The Karachaganak oilfield is located onshore, several hundred kilometres away from BNG, on the northern edge of the ancient Pre- Caspian basin. Production is from the same Permian and Carboniferous aged reservoirs that are productive at Tengiz and Kashagan. Discovered in 1979, production from Karachaganak began in 1984. One of the world’s largest gas condensate fields, original hydrocarbons in place are estimated at 9 billion barrels of condensate and 48 trillion cubic feet of gas; approximately 18 billion barrels of oil equivalent in total. Estimated recoverable reserves are 2.4 billion barrels of condensate and 16 tcf of gas. The field is currently producing about 200,000 barrels of condensate and 18 million cubic feet of gas per day. Since becoming operator of the field in 1997, Karachaganak Petroleum Operating (KPO); Royal Dutch Shell (29.25%), Eni (29.25%), Chevron (18%), Lukoil (13.5%), KazMunayGas (10%), has invested over $22 billion dollars in the development. The rest Most of the other fields active in Kazakhstan are operated either by local privately-owned enterprises or by the subsidiaries of larger, often state-owned enterprises. Few are self-standing public companies such as Caspian Sunrise. The gap between the super-giant part of the Kazakh oil scene and the rest provides us with opportunities for the acquisition of fields too small for the multinational operators but still potentially very valuable. The economy The steady fall in the value of the Kazakh Tenge against the US dollar, and the impact of Kazakhstan being in a customs union with sanctions hit Russia, have resulted in Tenge denominated operating costs falling for companies operating predominantly in US dollars. National infrastructure As a result of the super-giant projects the oil and gas infrastructure in Kazakhstan is strong with a network of pipelines connecting the oil producing regions with the west, Russia and China. There is a deep pool of experienced workers and the full array of international support services. Licences As with all oil and gas territories the permission of the state is required to operate. The first international developments in Kazakhstan were operated under profit sharing agreements but more recently licences have been awarded to operators based on an agreed work programme, with the risk that failure to complete the work programme could lead to the loss of the licence without compensation. Exploration licences The initial licence to develop a field is typically an exploration licence where the focus is on completing agreed work programme. The work programmes under an exploration licence are typically two years in duration and it is usual for there to be several consecutive two-year work programmes agreed during the exploration phase. Appraisal licences In the event the project appears commercial, the exploration licence is typically upgraded to an appraisal licence. Under an appraisal licence, oil produced incidentally while exploring and assessing may be sold but only by reference to domestic prices. Recently, oil sold from our MJF field has been at $19 per barrel compared to a world price in the $70’s. Taxation under an appraisal licence is limited with only modest deductions. Appraisal licences were generally for six years during which the holder has the ability to assess all the parts of the Contract Area it considers interesting. Recent changes to the legislation has reduced the length of appraisal generally licences to five years, with a concession of reduced social obligation payments. 13 Chairman’s statement (continued) Full production licences To sell oil by reference to world prices requires either the field as a whole or a particular structure to be upgraded to a full production licence. Once under a full production licence there is only limited scope to develop areas not already drilled. Additionally, a minority portion of production typically remains priced by reference to domestic prices although the majority is sold by reference to world prices. Under a full production licence the Company is subject to the full array of taxes and levies, such that oil sold when the world price is $70 per barrel might result in a net price in the range of $38 per barrel after a discount to reflect the difference to Brent, transportation costs and all applicable taxes, but before lifting, treatment, storage. Deductions from world selling prices Operational The lifting costs at BNG are estimated to be $1 per barrel. Transportation The combined costs of treatment, storage and transportation are estimated to be $4 per barrel and set to rise to $9 per barrel on moving to a full production licence. Taxes Based on a world price of $70 per barrel the aggregate tax liability is estimated to be $24 per barrel. Financial review Review of the results to 31 December 2018 Revenue increased by 41% to $10.7 million with a greater quantity of oil sold. Despite this and the increased operational activity administrative costs fell 11% to $2.6 million. The reduction in the operating loss from $3.4 million to $2.6 million reflects reductions in staff costs, audit and related fees and in particular a $0.5 million reduction in the accounting charge relating to share based payments. The collective impact of the above was to report a $1.3 million reduction in the loss before tax from continuing operations. There was also a $0.9 million reduction in the tax charge for 2018 compared to 2017 following the repayment of $1.0 million overpaid UK corporate tax. The $5.1 million accounting charge in respect of the sale of Munaily took the total loss before tax to $8.5 million compared to $4.7 million in 2017. The carrying value of our oil and gas assets fell from $69.7 million to $55.7 million, which is after the impact of cumulative currency related write downs of $74.3 million. The reduction during the year matches the price achieved from oil produced as required under the prevailing accounting conventions. The $0.9 million reduction in cash at the year end reflects our policy of raising cash for operations from oil traders or our CEO, Kuat Oraziman, as it needed. Funding review As stated elsewhere in these financial statements the Group’s approach to funding has been to wherever possible avoid unnecessary dilution, either at the individual asset level or in the equity of the country. The majority of the funding comes from the sale of oil produced from our shallow structures, often in the form of advance sales to local oil traders. These receipts have funded our operations in the shallow structures and made significant contributions to the development costs of our deep wells. This funding has been supplemented by funds lent to the Group under a master loan agreement by Kuat Oraziman, the CEO. Currently the total advanced is approximately $3.0 million. In recent years the Company’s activities have been constrained by a lack of cash. With increased cash expected from the MJF structure we will be better placed in future periods to seek to develop more of our potential structures. Low cost operator We pride ourselves on being a low-cost operator, both as operators in the field and in controlling our General & Administrative (“G&A”) costs. 14 Chairman’s statement (continued) We have been aided in this by the steady fall of the value of the Kazakh Tenge compared to the US $ as approximately half of our G&A costs are denominated in Tenge. However, for both drilling campaigns and in our day to day activities our approach is to minimise the amount spent. We believe our drilling costs, which are broadly $1-2 million for shallow wells and $10-12 million (including competition and testing) for deep wells are among the lowest in the industry. The presence of high pressure at BNG reduces our lifting costs to $1 per barrel. For the past 4 years our G&A costs have been below $3 million despite the mounting levels of operational activity and the increasing regulatory burden of being a public company. Inevitably, as the scale of the business increase there will be some additions to the G&A costs but we plan to keep these to a level below most of the rest of the sector. Employees The Group has 80 employees of whom 79 are based in Kazakhstan and split principally between the corporate offices in Almaty and in the field. As ever the board is grateful for their continued contributions. Communications with shareholders Under the rules we are limited to what can be said and when it can be said in response to individual shareholder enquiries. Often therefore we have been unable to make any meaningful response to perfectly reasonable enquiries. The delays in getting our deep wells to flow long enough to conduct flow tests there has from time to time created a news vacuum as we have sought to avoid using the RNS announcements system for anything but real changes in the Company’s status. In the absence of hard news it is probably inevitable that rumours start and spread and in that climate individuals with their own agendas seek to exploit the situation at the expense of the Company and individual shareholders. In particular we are aware of a number of reports circulating which are either entirely false or based on partial information presented in a way to serve the individuals with their own agendas. Despite unfounded rumours to the contrary we have no intention in taking the Company private. The London listing for our shares is a valuable asset and one we intend to make more of as we grow. Our policy remains to only announce news as it happens rather than to rush announcements out whenever there is an adverse move in the share price. We consider ourselves to be a Group here for the long run and in attempting to build lasting shareholder value have no interest in pandering to those possibly looking to exploit shareholders for their own short-term benefit. Our intention is to start paying meaningful dividends at the first opportunity. This together with the fact we are predominantly self- funding without the need to access the equity markets for development capital should deter those tempted to artificially manipulate the market in the Group’s shares for the own rewards. Recently we have announced monthly production numbers and achieved average sale prices and intend to continue to do so. We will also look to make greater use of the Group’s website and possibly the RNS Reach platform. We shall also seek to hold further shareholder events and encourage interested shareholders to attend the Company’s Annual General Meeting on 21 June 2019. Outlook The Group is underpinned by steady and growing income from its MJF production, which on its own justifies a meaningful valuation. The Directors continue to regard additional potential arising on getting any of the four deep wells already drilled or in the course of completion as being huge. That coupled with new opportunities under review leads the board to look to the future with confidence. Clive Carver Executive Chairman 15 Qualified Person & Glossary Qualified person Mr. Nurlybek Ospanov, the Company's Chief Geologist & Technical Director, who is a member of the Society of Petroleum Engineers (“SPE”), has reviewed and approved the technical disclosures in this announcement. Glossary SPE – The Society of Petroleum Engineers Bopd - barrels of oil per day. Mmbs – million barrels. Proven reserves Proved reserves (P1) are those quantities of petroleum which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. Probable reserves Probable reserves are those additional Reserves which analysis of geosciences and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Possible reserves Possible reserves are those additional reserves which analysis of geosciences and engineering data indicate are less likely to be recovered than probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible (3P), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Contingent resources Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. Prospective resources Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. 16 Directors' report The Directors present their annual report on the operations of the Company and the Group, together with the audited financial statements for the year ended 31 December 2018. The Strategic report forms part of the business review for this year. Principal activity The principal activity of the Group is oil and gas exploration and production in Kazakhstan. Results and dividends The consolidated statement of profit or loss is set out on page 30 and shows US$8.5 million loss for the year (2017: US$4.7 million). The Directors do not recommend the payment of a dividend for the year ended 31 December 2018 (2017: US$ nil). The position and performance of the Group is discussed below and further details are given in the business review. Review of the year The review of the year and the Directors’ strategy are set out in the Chairman’s Statement and the Strategic Report. Events after the reporting period Other than as disclosed in this annual report, including notes to the financial statements, there have been no material events between 31 December 2018 and the date of this report, which are required to be brought to the attention of shareholders. Please refer to note 29 of these financial statements for further details Board changes Kairat Satylganov stepped down from the Board as Chief Financial Officer on 28 February 2018. Following Mr Satylganov’s departure from the Company, Clive Carver assumed the role of Chief Financial Officer in addition to being Executive Chairman. In January 2019, Tim Field joined the Board as a non-executive director. Tim is a highly experienced international corporate lawyer working in London. His input into the oversight of the Company and its future direction will be much valued. Employees Staff employed by the Group are based primarily in Kazakhstan. The recruitment and retention of staff, especially at management level, is increasingly important as the Group continues to build its portfolio of oil and gas assets. As well as providing employees with appropriate remuneration and other benefits together with a safe and enjoyable working environment, the Board recognises the importance of communicating with employees to motivate them and involve them fully in the business. For the most part, this communication takes place at a local level and staff are kept informed of major developments through email updates. They also have access to the Company's website. The Company has taken out full indemnity insurance on behalf of the Directors and officers. Health, safety and environment It is the Group's policy and practice to comply with health, safety and environmental regulations and the requirements of the countries in which it operates, to protect its employees, assets and environment. Charitable and Political donations During the year the Group made no charitable or political donations. Directors and Directors' interests The Directors of the Group and the Company who held office during the period under review and up to the date of the Annual Report are as follows: Clive Carver Kuat Oraziman Edmund Limerick Kairat Satylganov (resigned 28 February 2018) Timothy Field (appointed 25 January 2019) 17 Directors' report (continued) Directors’ interests Director Clive Carver Kuat Oraziman* Edmund Limerick** Kairat Satylganov*** Timothy Field Number of shares Number of shares As at 31 December 2018 As at December 2017 nil 37,285,330 6,430,000 n/a nil nil 37,285,330 3,210,000 175,682,697 nil * Taken together Mr Oraziman and his adult children hold 745,706,614 shares ** includes 1,135,000 shares held by his wife *** Mr Satylganov resigned from the Board on 28 February 2018. Biographical details of the current Directors are set out on the Company's website www.caspiansunrise.com. Details of the Directors' individual remuneration, service contracts and interests in share options are shown in the Remuneration Committee Report. Financial instruments Details of the use of financial instruments by the Group and its subsidiary undertakings are contained in note 25 of the financial statements. Statement of disclosure of information to auditors All of the current Directors have taken all the steps that they ought to have taken to make themselves aware of any information needed by the Group's auditors for the purposes of their audit and to establish that the auditors are aware of that information. The Directors are not aware of any relevant audit information of which the auditors are unaware. Auditors BDO LLP have indicated their willingness to continue in office and a resolution concerning their reappointment will be proposed at the next Annual General Meeting. Directors' responsibilities The Directors are responsible for preparing the annual report and the financial statements in accordance with applicable law and regulations. Company law requires the Directors to prepare financial statements for each financial year. Under that law the Directors have elected to prepare the Group and Company financial statements in accordance with International Financial Reporting Standards (IFRSs) as adopted by the European Union. Under Company law the Directors must not approve the financial statements unless they are satisfied that they give a true and fair view of the state of affairs of the Group and Company and of the profit or loss of the Group for that period. The Directors are also required to prepare financial statements in accordance with the rules of the London Stock Exchange for companies trading securities on the London Stock Exchange AIM Market. In preparing these financial statements, the Directors are required to: select suitable accounting policies and then apply them consistently; • • make judgements and accounting estimates that are reasonable and prudent; • state whether they have been prepared in accordance with IFRSs as adopted by the European Union, subject to any material departures disclosed and explained in the financial statements; prepare the financial statements on the going concern basis unless it is inappropriate to presume that the Company and the Group will continue in business. • The Directors are responsible for keeping adequate accounting records that are sufficient to show and explain the Group’s and the Company's transactions and disclose with reasonable accuracy at any time the financial position of the Group and the Company and enable them to ensure that the financial statements comply with the requirements of the Companies Act 2006. They are also responsible for safeguarding the assets of the Group and the Company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities. 18 Directors' report (continued) Website publication The Directors are responsible for ensuring the annual report and the financial statements are made available on a website. Financial statements are published on the Company's website in accordance with legislation in the United Kingdom governing the preparation and dissemination of financial statements, which may vary from legislation in other jurisdictions. The maintenance and integrity of the Company's website is the responsibility of the Directors. The Directors' responsibility also extends to the ongoing integrity of the financial statements contained therein. Clive Carver Executive Chairman 23 May 2019 19 Corporate Governance Report In September 2018, new regulations took force under which all companies with shares trading on AIM were required to comply with a recognised corporate governance code and to disclose how the implementation of the governance code has been applied or to explain any areas of departure from its requirements. Caspian Sunrise carefully reviewed and then in line with the majority of AIM companies elected to apply the rules of the Quoted Companies Alliance (QCA) Corporate Governance Code (“QCA Code”), which is based around 10 broad principles. The QCA Code requires significant additional disclosures which have been made to our corporate website www.caspiansunrise.com. It also requires explanations of departures from the guidelines of the QCA code. Under the QCA regulations we have the option to cross refer to disclosures made on the website rather than repeat them all in this annual report. The principal disclosures such as the Remuneration Committee and Directors’ report will continued to be included in this annual report. However, for a full assessment of the Company you are encouraged to review the website for both the regulatory disclosures, and as we progress, more information on the activities of the Company. Board composition, skills and capabilities Between 1 January and 28 February 2018, the Company had three executive directors and one Non-executive director. From 1 March to 31 December 2018 the Company had two executive directors and one Non-executive director, a situation which the Board recognized would not be a long-term state of affairs. Following the appointment of Tim Field in January 2019, the Company currently has two executive directors and two independent Non-Executive Directors as follows: Clive Carver, Executive Chairman Clive Carver takes the lead on all non-operational matters, financial matters and all aspects related to the listing of the Company’s shares on AIM, Corporate Governance compliance and Investor Relations. Clive is a fellow of the Institute of Chartered Accountants in England and Wales (FCA) and a fellow of the Association of Corporate Treasurers (FCT). While working in the UK broking industry Clive gained more than 15 years’ experience as a Qualified Executive under the AIM Rules having run the Corporate Finance departments of several of the larger and more active Nominated Adviser firms. He is also an experienced non-executive director having been chairman of a number of AIM companies in recent years. Kuat Oraziman, Chief Executive Officer Kuat Oraziman runs the Company’s operations in Kazakhstan. Kuat Oraziman is a trained geologist and member of the academy of sciences. He has more than 25 years oil and gas experience in Kazakhstan. The Oraziman family hold in aggregate 44% of the Company’s shares and Mr Oraziman has to date provided $3.0 million by way of cash advances against a master loan agreement. Edmund Limerick, Senior Non-Executive Director Edmund is a Russian speaking former lawyer and investment banker who ran an institutional investment fund focused on Central Asia. Edmund was called to the Bar in 1987 and served as an officer in the Foreign & Commonwealth Office until 1992 with postings in Paris, Dakar and Amman. He was an international corporate lawyer at Clifford Chance, Freshfields and Milbank Tweed (where he headed the Moscow Office) before joining Deutsche Bank as a director in Moscow, London and Dubai. In 2006 he joined Altima Partners where he managed the Altima Central Asia Fund, focusing on Kazakhstan. Edmund has served as a director of Roxi Petroleum plc and Caspian Sunrise plc since 2010 and chairs the Audit and Remuneration Committees. Timothy Field, Non-Executive Director (appointed 25 January 2019) Tim joined the Board in January 2019 and is an independent non-executive director. He is a highly experienced international corporate lawyer specialising in securities law and corporate governance and is the principal of the specialist corporate and securities law firm "Field". He is also the equity capital markets consultant to the law firm Mishcon de Reya where until recently he led its public company practice. He has a long and significant track record of advising AIM companies and Nominated Advisers. His input into the oversight of the Company and its future direction will be much valued. The Board believes it possesses the skills required to build a successful and durable oil and gas business focused on Kazakhstan. The executive directors are supported by an operational board comprising Kuat Oraziman and Clive Carver plus Nurlybek Ospanov (Geology and Operations), Yelena Teslenko (Finance) and Askar Sarbuffin (General Director - BNG). Operational skills are maintained through an active day to day interaction with leading international consultancies and contractors engaged to assist in the development of the Group’s assets. Non-operational skills are maintained principally via the Group’s interaction with its professional advisers plus the experience gained from sitting on the boards of other commercial enterprises. 20 Corporate Governance Report (continued) As the Group develops and in particular moves from predominantly an oil exploration company to a balanced production and exploration company, the Board will periodically re-assess the adequacy of the skills on both the main Board and the operational board. Where gaps are identified as the Group evolves, new appointments will be made. The Board retains full and effective control over the Company. The Company holds at least four Board meetings each year, at which operational, financial and other reports are considered and, where appropriate, voted on. The Board also has a list of standing items, including compliance with the UK Bribery Act, litigation and existence of open and closed periods for director dealings, which are considered at each meeting. Apart from these formal board meetings, which have taken place in the year, additional meetings and calls are arranged when necessary to review strategy, planning, operational, financial performance, risk and capital expenditure and human resource and environmental management. Such additional informal discussions form an integral part of retaining full and effective control over the Company and continued through the year. The Board is also responsible for monitoring the activities of the Management. Board performance The Company currently does not evaluate board performance on a formal basis. However, it intends in the near term seek to formalise the assessment of both executive and non-executive board members. The Company is aware of its need to facilitate succession planning and the Board evaluation process will form part of this going forward. Following the expansion of the board such that all the board committee now contain only non-executive directors the board is working on the required processes and evaluation materials with a view to having them in place by the end of the year. Board and committee meetings Attendances of Directors at Board and committee meetings convened in the year, and which they were eligible to attend, are set out below: Director Number of meetings in year Clive Carver Kuat Oraziman Edmund Limerick Kairat Satylganov* Board Meetings attended Remuneration Committee attended Audit Committee Attended 4 4 4 4 1 1 1 1 1 N/A 2 2 0 2 N/A * Kairat Satylganov resigned from the Board on 28 February 2018. Committees of the Board From March to December 2018, the Board operated with only three directors, which inevitably meant that the Board committees comprised both executive and non-executive directors. In its QCA Corporate Governance statement published in September 2018, the Company acknowledged that this departure from the recommendations of the QCA was not a long-term solution and was actively seeking to appoint an additional non-executive director. The appointment of Tim Field in January 2019 to the Board and to the Committees of the Board has enabled the Company to have an appropriate balance of executive and non-executive directors. The committees of the Board are now comprised of independent non-executive directors. The Board has established the following committees: Audit Committee The Audit Committee which comprises Edmund Limerick and Tim Field, with Edmund Limerick acting as Chairman, determines and examines any matters relating to the financial affairs of the Group including the terms of engagement of the Group’s auditors and, in consultation with the auditors, the scope of the audit. The Audit Committee receives and reviews reports from the management and the external auditors of the Group relating to the annual and interim amounts and the accounting and internal control systems of the Group. In addition, it considers the financial performance, position and prospects of the Group and the Company and ensures they are properly monitored and reported on. Remuneration Committee The Remuneration Committee, which comprises Edmund Limerick and Tim Field, with Edmund Limerick acting as Chairman, reviews the performance of the senior management, sets and reviews their remuneration and the terms of their service contracts and considers the Group’s bonus and option schemes. The Report of the Remuneration Committee for 2018 is set out immediately after this Corporate Governance Report. 21 Corporate Governance Report (continued) Corporate Governance Committee Upon the appointment of Tim Field as a Non-Executive director, the Company decided to form a new Corporate Governance Committee comprising Tim Field and Edmund Limerick with Tim Field acting as chairman. Work continues on suitable terms of reference, which when finalised, will be uploaded to the Group’s website. The Board plans to include a formal risk register including all the principal operational and non-operational risks to the business to be considered by the Governance & Risk Committee. This will be in addition to the procedures already in place as set out elsewhere in this document. Rule 21 The Directors comply with Rule 21 of the AIM Rules relating to Directors’ dealing and take all reasonable steps to ensure compliance by the Group’s applicable employees. The Company has adopted and operates a share dealing code for Directors and employees in accordance with the AIM Rules. Internal controls The Board acknowledges responsibility for maintaining appropriate internal control systems and procedures to safeguard the shareholders’ investments and the assets, employees and the business of the Group. The Board has established and operates a policy of continuous review and development of appropriate financial controls together with operating procedures consistent with the accounting policies of the Group. Internal audit The Board does not consider it appropriate for the current size of the Group to establish an internal audit function. However, this will be kept under review. Bribery and corruption The Bribery Act 2010 came into force on 1 July 2011. The Company is committed to acting ethically, fairly and with integrity in all its endeavours and compliance with legislation is monitored. The principal terms of the Bribery Act have been translated into Russian and circulated to our Kazakh based staff. Consideration of the Bribery Act is a standing item at Company board meetings. The Company’s culture Our culture might best be described as one where we strive for commercial success while treating others fairly and with respect. The board firmly believes that sustained success will best be achieved by following this simple philosophy. Accordingly, in dealing with each of the Groups principal stakeholders, we encourage our staff to operate in an honest and respectful manner. Given the simplicity of the culture we do not believe lengthy illustrations of our culture in action add much. Operating with integrity is clearly good business and forms an important part of the annual assessment of staff and in setting their pay for future periods. We also believe in getting proper value for money spent. Given the high percentage of the Groups shares represented by senior management figures we seek to spend the Groups money very carefully. We believe this goes hand in hand with being a low-cost operator. Kazakhstan plays an important part in the Group’s culture. It is where we operate; where almost all staff are based; it is the nationality of most staff and of the majority of shareholders. The Group is committed to promoting a culture based on ethical values and behaviours across the business. Policies are in place covering key matters such as equality, protection of sensitive information, conflicts of interest, whistleblowing and health and safety as well as environmental concerns. 22 Remuneration Committee Report Remuneration Committee The Remuneration Committee comprises Edmund Limerick and Tim Field and is chaired by Edmund Limerick. Remuneration policy The Group’s and the Company’s policy is to provide remuneration packages that will attract, retain and motivate its executive Directors and senior management. This consists of a basic salary, ancillary benefits and other performance-related remuneration appropriate to their individual responsibilities and having regard to the remuneration levels of comparable posts. The Remuneration Committee determines the contract term, basic salary, and other remuneration for the members of the Board and the senior management team. Service contracts Details of the current Directors’ service contracts are as follows: Executive Clive Carver Kuat Oraziman Non-Executive Edmund Limerick Timothy Field Basic salary and benefits Date of service agreement/ appointment letter 20 March 2019 1 June 2012 Date of last renewal of appointment 24 July 2015 19 June 2018 1 March 2018 13 June 2017 25 January 2019 N/A The basic salaries of the Directors who served during the financial year are established by reference to their responsibilities and individual performance. The amounts received by the Directors are set out below in US$. Directors Clive Carver Executive Chairman Kuat Oraziman Kairat Satylganov* CEO CFO Edmund Limerick Non-Executive Total 2018 Salary/fees US$ 2018 Share options US$ 2018 Total US$ 2017 Total US$ 336,140 122,330 20,388 60,672 539,530 - - - - - 336,140 342,330 122,330 225,060 20,388 225,060 60,672 64,250 539,530 856,700 * Mr Satylganov resigned from the Board on 28 February 2018 Share option amounts refer to the IFRS 2 accounting charge. There were no company pension contributions in respect of any director Bonus schemes All Executive Directors are eligible for consideration of participation in the Company bonus scheme. However, as in previous years no bonuses are payable in respect of the year ended 31 December 2018 (2017: nil). 23 Remuneration Committee Report (continued) Share options The current interests as at approval of accounts of the current Directors in share options agreements are as follows: Directors Clive Carver Directors Clive Carver Kuat Oraziman Edmund Limerick Directors Clive Carver Kuat Oraziman Edmund Limerick Directors Clive Carver Kuat Oraziman Edmund Limerick Granted 2,400,000 Exercise Price 4p Expiry date 14 December 2021 Granted 538,264 269,132 200,000 Exercise Price 12p 12p 12p Expiry date 14 August 2019 14 August 2019 15 February 2020 Granted 750,000 3,090,000 750,000 Exercise Price 13p 13p 13p Expiry date 12 January 2021 12 January 2021 12 January 2021 Granted 3,000,000 3,000,000 750,000 Exercise Price 20p 20p 20p Expiry date 21 August 2024 21 August 2024 21 August 2024 The following options were exercised during 2018 Directors Edmund Limerick Granted 1,200,000 Exercise Price 4p Expiry date 12 December 2018 The following options were exercised after 2018 Directors Kuat Oraziman The following options expired during 2018 Directors Clive Carver Clive Carver Kuat Oraziman Kuat Oraziman On behalf of the Directors of Caspian Sunrise plc Edmund Limerick Chairman of Remuneration Committee 23 May 2019 Granted 4,200,000 Exercise Price 4p Expiry date 22 January 2019 Granted 1,215,385 387,692 607,692 193,846 Exercise Price 65p 65p 65p 65p Expiry date 29 February 2018 22 April 2018 29 February 2018 22 April 2018 24 Report of the Audit Committee Composition The Audit Committee, which comprises Edmund Limerick and Tim Field, with Edmund Limerick acting as Chairman, determines and examines any matters relating to the financial affairs of the Group including the terms of engagement of the Group’s auditors and, in consultation with the auditors, the scope of the audit. Role and responsibilities The Audit Committee is responsible for monitoring the integrity of the Company’s financial statements, reviewing significant financial reporting issues, reviewing the effectiveness of the Group’s internal control and risk management systems. In addition, it considers the financial performance, position and prospects of the Group and the Company and ensures they are properly monitored and reported on. It oversees the relationship with the Auditor (including advising on their appointment, agreeing the scope of the audit and reviewing the audit findings). The Board and the Audit Committee do not consider it appropriate for the current size of the Group to establish an internal audit function. However, this will be kept under review. Attendance at Audit Committee meetings Please see the table in the preceding Corporate Governance Report for attendance by the members of the Audit Committee. 25 INDEPENDENT AUDITOR’S REPORT TO THE MEMBERS OF CASPIAN SUNRISE PLC Opinion We have audited the financial statements of Caspian Sunrise Plc (the ‘Parent Company’) and its subsidiaries (the ‘Group’) for the year ended 31 December 2018 which comprise the consolidated statement of profit or loss, the consolidated statement of other comprehensive income, the consolidated statement of changes in equity, the parent company statement of changes in equity, the consolidated statement of financial position, the parent company statement of financial position, the consolidated and parent company 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 financial statements is applicable law and International Financial Reporting Standards (IFRSs) as adopted by the European Union and, as regards the Parent Company financial statements, as applied in accordance with the provisions of the Companies Act 2006. 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 31 December 2018 and of the Group’s loss for the year then ended; the Group 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 IFRSs 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. • • • 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 and the Parent Company 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 Group’s or the Parent 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 judgment, were of most significance in our audit of the financial statements of the current period and include the most significant assessed risks of material misstatement (whether or not due to fraud) we identified, including those which had the greatest effect on: the overall audit strategy, the allocation of resources in the audit; and directing the efforts of the engagement team. These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters. Key audit matter: The risk that a material uncertainty existed over going concern that required disclosure The Board is required to make an assessment of the Group’s and the Parent Company’s ability to continue as a going concern for at least 12 months from the date the financial statements are approved. Where a material uncertainty exists in respect of the going concern assessment, the Board is required to disclose those matters. The Board have reviewed cash flow forecasts prepared by management for the period to June 2020 which indicated that the Group would have sufficient funding to meet its liabilities as they fell due as detailed in note 1.1. This assessment included estimates and judgments regarding assumptions over future production, oil prices, costs, licence and drilling expenditure. The Board exercised judgment regarding the Group’s ability to obtain a full production licence during the period and commence sales at world oil prices and the timing of such a licence being awarded. Further, the Board exercised judgment regarding the continued availability of funding from oil traders in the form of advances on oil production and the extent to which additional funding requirements would be met by the Group’s largest shareholder to undertake the deep well drilling program commitments. This represented a significant risk for our audit due to the inherent judgements and estimates required. 26 INDEPENDENT AUDITOR’S REPORT (continued) How the matter was addressed in our audit • We obtained management’s cash flow forecasts and critically assessed the key inputs including oil prices, production levels, operating costs and planned drilling, licence and exploration expenditure. We assessed the inputs against recent empirical data, work programs, contracts, licence obligations and considered forecast oil market trends. • We considered the appropriateness of the Board’s judgment regarding the availability of oil trader funding through the forecast period. In doing so, we considered factors such as the production profile, oil price trends, the terms of the arrangements and the history of transactions with the oil traders. • We confirmed that the Group has applied for a production licence and assessed its impact on production cash flows. We discussed the status of the application with the Board and considered the potential for unforeseen delays. • We assessed the level of funding required from the Group’s largest shareholder under the forecasts and reasonable sensitivity scenarios, including a delay to the planned full production licence. We obtained management’s assessment of mitigating actions in the event of reasonable sensitivity scenarios and evaluated the ability of management to take such actions and the impact on the cash flows. • We obtained the undrawn loan facility agreement between the Company and its largest shareholder. We considered the appropriateness of the Board’s judgment that the funds would be available, as required. In doing so, we assessed the past history of funding provided by the shareholder and obtained evidence regarding the sources of funds available to the lender. • We assessed the disclosures included in the financial statements at note 1.1. Our observations Refer to ‘Our conclusions relating to going concern’ above. We found the disclosures in note 1 to be appropriate. Key audit matter: The risk that the carrying value of the unproven oil and gas assets require impairment As at 31 December 2018, the Group’s unproven oil and gas assets related to the BNG Contract area cost pool were carried at US$55.7m as shown in note 11. At each reporting period end, management are required to assess the unproven oil and gas assets for indicators of impairment and, where such indicators exist, perform an impairment test. In performing the impairment indicator review, management are required to make a number of estimates and judgements. In particular, the assessment involves consideration of the standing of the exploration licence and remaining term, the future planned exploration activity and results of activity to date. Following their assessment management concluded that no indicators of impairment existed in respect of the BNG cost pool. In forming their conclusion, management particularly considered the potential impact of the outstanding obligations under the licence detailed in note 20 and concluded that they remained satisfied that the outstanding obligations did not present a significant threat to their exploration rights or give rise to contingencies. Given the judgment and estimation required by management in assessing potential impairment indicators, we considered this area to be a key focus for our audit. How the matter was addressed in our audit • We reviewed the existing licence to confirm that the Group holds a valid right to explore the BNG Contract area and reviewed correspondence with the Ministry of Energy of Kazakhstan to confirm that the Group had been granted an extension to its exploration licence for a period of 6 years effective 1 July 2018. • We reviewed Board minutes, made specific inquiries of management and reviewed budgets and work programs submitted to the Kazakh authorities to confirm that further drilling and exploration is planned for the asset. • We reviewed the conditions of the licence and obtained reports submitted to the Kazakh authorities in respect of expenditure to assess the compliance with the licence terms. We specifically considered management’s judgment that the unfulfilled licence conditions set out in note 20 would not reasonably be expected to result in a loss of the licence. In doing so, we confirmed that necessary payments were included in the Group’s cash flow forecasts and considered factors including the history of expenditure and the recent extension to the licence which specifies financial penalties that apply to unfulfilled commitments. We recalculated the relevant accruals for outstanding obligations and commitments. • We reviewed the 2015 independent reserves statement prepared by Gaffney, Cline & Associates (“GCA”) for the shallow reservoir structures and the current financial model used by the Group in its impairment indicator review. We compared key inputs to the financial model to market oil price data and the GCA report. We considered the additional value associated with the deep reservoir structures and 3P reserves and prospective oil and gas resources not included in financial model. • We considered the Group’s market capitalisation which demonstrates a significant premium to its net asset value. • We assessed the independence and competence of GCA as a management expert. • We assessed the disclosures included in the financial statements at notes 1.8. Our observations We found management’s conclusion that no impairment exists on the BNG unproven oil and gas asset to be appropriate. We found the judgments made by management to be appropriately considered and the disclosures in the notes to be sufficient. 27 INDEPENDENT AUDITOR’S REPORT (continued) Our application of materiality Group materiality as at 31 December 2018 US$1,000,000 Basis for materiality 1.5% of total assets We apply the concept of materiality both in planning and performing our audit and in evaluating the effect of misstatements. We consider materiality to be the magnitude by which misstatements, including omissions, could influence the economic decisions of reasonable users that are taken on the basis of the financial statements. Importantly, misstatements below these levels will not necessarily be evaluated as immaterial as we also take account of the nature of identified misstatements, and the particular circumstances of their occurrence, when evaluating their effect on the financial statements as a whole. Materiality for the Group financial statements as a whole was set at $1,000,000, being 1.5% of total assets (2017: $1,230,000). We consider total assets to be the most relevant consideration of the Group’s financial performance as the Group continues to focus on oil and gas exploration. Materiality for the Parent Company financial statements was set at $800,000, being 1.5% of total assets, capped at 80% of Group materiality (2017: $1,088,000). In performing the audit we applied a lower level of performance materiality of $750,000, being 75% of Group materiality (2017: $923,000), in order to reduce to an appropriately low level the probability that the aggregate of uncorrected and undetected misstatements exceeds financial statement materiality. This was based on the low level of misstatements in the past and our overall assessment of the control environment. Each significant component of the Group including the parent company was audited using a lower level of performance materiality ranging from $600,000 to $675,000 (2017: $820,000 to $1,032,000). We agreed with the Audit Committee that we would report to the committee all individual audit differences in excess of $50,000 (2017: $65,000). We also agreed to report differences below this threshold that, in our view, warranted reporting on qualitative grounds. An overview of the scope of our audit Our Group audit was scoped by obtaining an understanding of the Group and its environment and assessing the risks of material misstatement in the financial statements at the Group level. The Group’s operations principally comprise exploration & development of oil and gas assets located in Kazakhstan. We assessed there to be 2 significant components comprising BNG and the parent company. These locations, which were subject to full scope audit procedures represent the principal business units. A non-BDO member firm performed a full scope audit of BNG in Kazakhstan, under our direction and supervision as Group auditors under ISA 600. The audit of the Parent Company and the Group consolidation were performed in the United Kingdom by BDO LLP. As part of our audit strategy, as Group auditors: • Detailed Group reporting instructions were sent to the component auditor, which included the significant areas to be covered by the audit. • We performed a review of the component audit files in Kazakhstan and held meetings with the component audit team • during the planning and completion phases of their audit. The Group audit team was actively involved in the direction of the audits performed by the component auditors, along with the consideration of findings and determination of conclusions drawn. We performed our own additional procedures in respect of the significant risk areas that represented Key Audit Matters in addition to the procedures performed by the component auditor. The remaining components of the Group were considered non-significant and these components were principally subject to analytical review procedures to confirm there are no significant risks of material misstatements within these components. 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. 28 INDEPENDENT AUDITOR’S REPORT (continued) 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 [set out on page …], 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 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) 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. Use of our report This report is made solely to the Parent 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 Parent 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 Parent Company and the Parent Company’s members as a body, for our audit work, for this report, or for the opinions we have formed. Ryan Ferguson (Senior Statutory Auditor) For and on behalf of BDO LLP, Statutory Auditor London, United Kingdom 23 May 2019 BDO LLP is a limited liability partnership registered in England and Wales (with registered number OC305127). 29 Consolidated Statement of Profit or Loss Revenue Cost of sales Gross profit Share-based payments Other administrative costs Total administrative expenses Operating loss Finance cost Finance income Loss before taxation Tax charge Loss after taxation from continuing operations Loss for the year from discontinued operations Loss for the year Loss attributable to owners of the parent Loss attributable to non-controlling interest Loss for the year Basic loss per ordinary share (US cents) From continuing operations From discontinued operations Total loss per share Diluted loss per ordinary share (US cents) From continuing operations From discontinued operations Total loss per share Notes 3 4 7 8 9 21 10 10 Year to 31 December 2018 US$’000 10,747 (10,747) - (13) (2,611) (2,624) (2,624) (348) - (2,972) (414) (3,386) (5,147) (8,533) (8,366) (167) (8,533) (0.19) (0.31) (0.5) (0.19) (0.31) (0.5) Year to 31 December 2017 US$’000 7,575 (7,550) 25 (476) (2,925) (3,401) (3,376) (167) 194 (3,349) (1,345) (4,694) - (4,694) (3,928) (766) (4,694) (0.29) - (0.29) (0.29) - (0.29) The notes on pages 37 to 62 are essential part of these financial statements 30 Consolidated Statement of Comprehensive Income Loss after taxation Other comprehensive income: Exchange differences on translating foreign operations Recycling of exchange difference on disposal of subsidiary Total comprehensive loss for the year Total comprehensive loss attributable to: Owners of parent Non-controlling interest Year ended 31 December 2018 Year ended 31 December 2017 US$000 US$000 (8,533) (4,694) (10,136) 8,305 (10,364) (9,277) (1,087) 72 - (4,622) (3,922) (700) The notes on pages 37 to 62 are essential part of these financial statements 31 Consolidated Statement of Changes in Equity Total equity as at 1 January 2018 Loss after taxation Exchange differences on translating foreign operations and recycling of exchange differences on disposal of subsidiaries Total comprehensive income/(loss) for the year Disposal of subsidiary Share options exercised Arising on employee share options Total equity as at 31 December 2018 Total equity as at 1 January 2017 Loss after taxation Exchange differences on translating foreign operations Total comprehensive income/(loss) for the year Purchase of non-controlling interest in subsidiary Arising on employee share options Lapsed warrants Debts converted to equity Total equity as at 31 December 2017 Share capital US$’000 Share premium US$’000 25,401 228,974 - - - - - 15 - 25,416 - - - 46 - 229,020 Share capital US$’000 Share premium US$’000 16,000 - - - 8,364 - - 1,037 25,401 146,728 - - - 73,183 - - 9,063 228,974 Deferred shares US$’000 64,702 - - - - - - 64,702 Deferred shares US$’000 64,702 - - - - - - - 64,702 Cumulative translation reserve US$’000 (55,000) Other reserves US$’000 Retained deficit US$’000 (2,362) (210,877) Total attributable to the owner of the Parent US$’000 50,838 Non- controlling interests US$’000 (4,654) - - (8,366) (8,366) (167) (911) (911) - - - (55,911) - - - - - (2,362) - (8,366) - - 13 (219,230) (911) (9,277) - 61 13 41,635 (920) (1,087) 136 - - (5,605) Cumulative translation reserve US$’000 Other reserves US$’000 Retained deficit US$’000 Total attributable to the owner of the Parent US$’000 Non- controlling interests US$’000 (55,006) - 6 6 - - - - (55,000) (583) - - - - (1,779) - (2,362) (127,343) (3,928) - (3,928) (81,861) 476 1,779 - (210,877) 44,498 (3,928) 6 (3,922) (314) 476 - 10,100 50,838 2,617 (766) 66 (700) (6,571) - - - (4,654) Total equity US$’000 46,184 (8,533) (1,831) (10,364) 136 61 13 36,030 Total equity US$’000 47,115 (4,694) 72 (4,622) (6,885) 476 - 10,100 46,184 Equity Share capital Share premium Deferred shares Cumulative translation reserve Other reserves Retained deficit Non-controlling interest Description and purpose The nominal value of shares issued Amount subscribed for share capital in excess of nominal value The nominal value of deferred shares issued Gains/losses arising on retranslating the net assets of overseas operations into US Dollars, less amounts recycled on disposal of subsidiaries and joint ventures Fair value of warrants issued and capital contribution arising on discounted loans Cumulative losses recognised in the consolidated statement of profit or loss, adjustments on the acquisition of non-controlling interests and transfers in respect of share based payments The interest of non-controlling parties in the net assets of the subsidiaries The notes on pages 37 to 62 are essential part of these financial statements 32 Parent Company Statement of Changes in Equity Total equity as at 1 January 2018 Total comprehensive loss for the year Stock options exercised Arising on employee share options Total equity as at 31 December 2018 Total equity as at 1 January 2017 Total comprehensive loss for the year Purchase of non-controlling interest in subsidiary Arising on employee share options Forfeited warrants Debts converted to equity Total equity as at 31 December 2017 Share capital US$’000 Share premium US$’000 Deferred shares US$’000 Other reserves US$’000 Retained deficit US$’000 Total attributable to the owner of the Parent US$’000 25,401 - 15 - 25,416 228,974 - 46 - 229,020 16,000 - 146,728 - 8,364 - - 1,037 25,401 73,183 - - 9,063 228,974 64,702 - - - 64,702 64,702 - - - - - 64,702 14,936 - - - 14,936 16,715 - - - (1,779) - 14,936 (144,073) (851) 13 (144,911) (143,775) (2,553) - 476 1,779 - (144,073) 189,940 (851) 61 13 189,163 100,370 (2,553) 81,547 476 - 10,100 189,940 Equity Share capital Share premium Deferred shares Other reserves Retained deficit Description and purpose The nominal value of shares issued Amount subscribed for share capital in excess of nominal value The nominal value of deferred shares issued Fair value of warrants issued and capital contribution arising on discounted loans Cumulative losses recognised in the profit or loss The notes on pages 37 to 62 are essential part of these financial statements 33 Consolidated Statement of Financial Position Company number 5966431 Notes Group 2018 US$’000 Group 2017 US$’000 11 12 14 15 15 16 17 17 28 18 19 20 22 20 18 55,685 87 132 8,445 250 64,599 364 557 921 65,520 25,416 229,020 64,702 (2,362) (219,230) (55,911) 41,635 (5,605) 36,030 6,259 2,572 3,515 12,346 6,733 125 10,286 17,144 29,490 65,520 69,701 165 21 9,255 263 79,405 832 1,479 2,311 81,716 25,401 228,974 64,702 (2,362) (210,877) (55,000) 50,838 (4,654) 46,184 9,538 2,132 4,399 16,069 7,784 721 10,958 19,463 35,532 81,716 Assets Non-current assets Unproven oil and gas assets Property, plant and equipment Inventories Other receivables Restricted use cash Total non-current assets Current assets Other receivables Cash and cash equivalents Total current assets Total assets Equity and liabilities Capital and reserves attributable to equity holders of the parent Share capital Share premium Deferred shares Other reserves Retained deficit Cumulative translation reserve Equity attributable to the owners of the Parent Non-controlling interests Total equity Current liabilities Trade and other payables Short - term borrowings Current provisions Total current liabilities Non-current liabilities Deferred tax liabilities Non-current provisions Other payables Total non-current liabilities Total liabilities Total equity and liabilities Approved by the Board and authorized for issue: Clive Carver, Chairman, 23 May 2019 Company number: 5966431 The notes on pages 37 to 62 are essential part of these financial statements 34 Parent Company Statement of Financial Position Company number 5966431 Notes Company 2018 US$’000 Company 2017 US$’000 Assets Non-current assets Investments in subsidiaries Other receivables Total non-current assets Current assets Other receivables Cash and cash equivalents Total current assets Total assets Equity and liabilities Capital and reserves attributable to equity holders of the parent Share capital Share premium Deferred shares Other reserves Retained deficit Equity attributable to the owners of the Parent Total equity Current liabilities Short - term borrowings Trade and other payables Total current liabilities Non-current liabilities Other payables Total non-current liabilities Total liabilities Total equity and liabilities 13 15 15 16 17 17 19 18 18 211,986 3,066 215,052 6 292 298 215,350 25,416 229,020 64,702 14,936 (144,911) 189,163 189,163 400 9,052 9,452 16,735 16,735 26,187 215,350 211,658 2,944 214,602 5 17 22 214,624 25,401 228,974 64,702 14,936 (144,073) 189,940 189,940 - 8,626 8,626 16,058 16,058 24,684 214,624 The Company incurred a loss for the year ended 31 December 2018 in the amount of US$ 851,000 (2017: US$ 2,553,000). Approved by the Board and authorized for issue: Clive Carver, Chairman, 23 May 2019 Company number: 5966431 The notes on pages 37 to 62 are essential part of these financial statements 35 Consolidated and Parent Company Statements of Cash Flows Cash flows from operating activities Cash received from customers Return of taxes previously paid Payments made to suppliers for goods and services Payments made to employees Net cash flow from operating activities Cash flows from investing activities Purchase of property, plant and equipment Additions to unproven oil and gas assets Transfers from/(to) restricted use cash Proceeds from disposal of joint venture (net of cash disposed and taxation) in prior periods Proceeds from disposal of subsidiaries Advances repaid by subsidiaries Advances issued to subsidiaries Net cash flow from investing activities Cash flows from financing activities Net proceeds from issue of ordinary share capital Loans repaid Loans provided by subsidiaries Loans received Repayment of loans provided by subsidiaries Net cash flow from financing activities Net increase/(decrease) in cash and cash equivalents Cash and cash equivalents at the beginning of the year Notes 9 12 11 21 19,25 19,25 Cash and cash equivalents at the end of the year 16 Group 2018 US$’000 Group 2017 US$’000 Company 2018 US$’000 Company 2017 US$’000 9,025 1,013 (2,747) (1,185) 6,106 (3) (7,733) - - 134 - - 10,928 - (1,319) (1,548) 8,061 (5) (9,973) (20) 1,696 - - - (7,602) (8,302) 61 (534) - 1,047 - 574 (922) 1,479 557 - (7,000) - 8,315 - 1,315 1,074 405 1,479 - 1,013 (1,175) (614) (776) - - (872) (692) (1,564) - - - - - 180 (100) 80 61 - 600 400 (90) 971 275 17 292 - - - 1,696 - 410 (535) 1,571 - - - - - - 7 10 17 Significant non-cash transactions include the following and details can be found in notes 6, 7, 8, 9,12, 17, 27: - Share-based payments in the amount of US$ 13,000 (2017: US$ 476,000); - Withholding tax in the amount of US$ 1,375,000 (2017: US$ 1,345,000); - - - - - - - - Discounting of receivables in the amount of US$ 0 (2017: US$100,000); Exchange differences on translating foreign operations of US$ 3,154,000 (2017: US$ 72,000); Depreciation charge of US$ 31,000 (2017: US$ 43,000); Conversion of debt to equity of US$ 0 (2017: US$ 10,100,000); Interest expense of US$ 348,000 (2017: US$ 167,000); Conversion of Loan provided to Baverstock to investments in Eragon in the amount of US$ 0 (2017: US$ 3,254,000); Conversion of Receivable from Baverstock due to royalty to investments in Eragon in the amount of US$ 0 (2017: US$ 3,202,000); Non-cash effect from the acquisition of non-controlling interest in the amount of US $ 0 (2017: US$ 6,885,000) * Additions to unproven oil and gas assets contain the amount of US$ 332,000 in relation to payroll expenses capitalized (2017: US$: 330,000). The notes on pages 37 to 62 form part of these financial statements 36 Notes to the Financial Statements General information Caspian Sunrise plc (“the Company”) is a public limited company incorporated and domiciled in England and Wales. The address of its registered office is 5 New Street Square, London, EC4A 3TW. These consolidated financial statements were authorised for issue by the Board of Directors on 23 May 2019. The principal activities of the Group are exploration and production of crude oil. 1 Principal accounting policies The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. 1.1 Basis of preparation The Group’s and Parent’s financial statements have been prepared in accordance with International Financial Reporting Standards as adopted by the European Union (“IFRSs”), and with those parts of the Companies Act 2006 applicable to companies reporting under IFRSs. The Directors have prepared cash flow forecasts for the next 12 months which demonstrate that the Group will have sufficient funds to meet its day to day liabilities, including all expected G&A expenditure, as they fall due and operate as a going concern, including completion of its planned shallow structure drilling program. The forecasts include growth in revenue including both the impact of anticipated shallow structure well drilling and increased pricing associated with BNG production sold at world prices following the planned conversion of existing wells into a production licence. In addition, the Group continues to forward sell its production and receive advances from oil traders as part of its operations. The continued availability of such arrangements are important to working capital and, in the event the Group was unable to continue to access these arrangements additional funding would be required. The Directors are confident that the oil trader funding will continue, based on the production profile and relationships with the oil traders. Whether or not the award of a production licence is further delayed, the Group expects to require additional working capital during the period. The Board are confident such funding would be available from in the first instance additional advances from oil traders and should that be insufficient further support would be provided by our CEO, Kuat Oraziman. In this regard Mr Oraziman has provided a written undertaking to provide financial support as is required which the Board are satisfied will be available given the history of financial support and having considered the shareholder’s ability to provide such funding. Additional funding, for new deep wells, infrastructure and assets to accelerate development over and above the level included in the forecasts, is expected to be available from a number of sources, including debt funding for much of the infrastructure spending, advances from local oil traders from the sale of oil yet to be produced, industry funding in the form of partnerships with larger industry players, further support from existing shareholders and if appropriate, equity funding from financial institutions. However, such accelerated development is at the Group’s discretion. On this basis the Directors have therefore concluded that it is appropriate to prepare the financial statements on a going concern basis. The Company has taken advantage of section 408 of the Companies Act 2006 and has not included its own profit or loss in these financial statements. The Group loss for the year included a loss on ordinary activities after tax of US$851,000 (2017: US$ 2,553,000) in respect of the Company. The preparation of financial statements in conformity with IFRSs requires the Management to make judgements, estimates and assumptions that affect the application of policies and reported amounts in the financial statements. The areas involving a higher degree of judgement or complexity, or areas where assumptions or estimates are significant to the financial statements are disclosed in note 2. 1.2 New and revised standards and interpretations applied The following new standards and amendments to standards are mandatory for the first time for the Group for financial year beginning 1 January 2018. The implementation of these standards did not have a material effect on the Group results, although they resulted in certain amendments to disclosures. 37 Notes to the Financial Statements (continued) 1 Principal accounting policies (continued) 1.2 New and revised standards and interpretations applied (continued) Standard Description Effective date IFRS 9 IFRS 15 IFRS 2 IFRIC 22 Financial Instruments Revenue from Contracts with Customers Amendment – Classification and measurement of share based payment transactions Foreign currency transactions and advance considerations 1 Jan 2018 1 Jan 2018 1 Jan 2018 1 Jan 2018 IFRS 9 ‘Financial instruments’ addresses the classification and measurement of financial assets and financial liabilities and replaces the guidance in IAS 39 that relates to the classification and measurement of financial instruments. IFRS 9 retains but simplifies the mixed measurement model and establishes three primary measurement categories for financial assets: amortised cost, fair value through other comprehensive income (OCI) and fair value through profit or loss. The basis of classification depends on the entity’s business model and the contractual cash flow characteristics of the financial asset. There is now a new expected credit loss model that replaces the incurred loss impairment model used in IAS 39. It is noted that VAT receivables and prepayments are excluded from the scope of IFRS 9. The Group has applied the modified retrospective approach to transition. The adoption of IFRS 9 did not result in any material change to the consolidated results of the Group or Parent Company. Following assessment of the financial assets no changes to classification of those financial assets was required. The Group has applied the expected credit loss impairment model to its financial assets and has not recognised any expected credit loss impairment (note 15). The Company has recognised $286,000 expected credit loss impairment in relation to inter-company receivables from subsidiaries (note 15). IFRS 15 introduced a single framework for revenue recognition and clarify principles of revenue recognition. This standard modifies the determination of when to recognise revenue and how much revenue to recognise. The core principle is that an entity recognises revenue to depict the transfer of promised goods and services to the customer of an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The adoption of IFRS 15 did not result in any material change to the Group’s revenue recognition following analysis of its contracts. Revenue was previously recorded on oil sale at the fair value of consideration received or receivable, net of VAT and sales related taxes at the point title transferred when significant risks and rewards had passed to the customer. Using the 5-step method set out in IFRS 15 there was no change required to the revenue recognition reflecting the simple nature of the arrangements. Refer to note 1.19 for the Group’s revenue recognition policy and note 3 for details of revenue. Annual Improvements to IFRSs 2014–2016 Standards, amendments and interpretations, which are effective for reporting periods beginning after the date of this financial information which have not been adopted early: Standard Description Effective date IFRS 16 IFRS 17 Leases Insurance contracts IFRIC Interpretation 23 Uncertainty over Income Tax Treatments Amendments to IFRS 9 Prepayment Features with Negative Compensation Amendments to IFRS 10 and IAS 28 Sale or Contribution of Assets between an Investor and its Associate Amendments to IAS 19 Plan Amendment, Curtailment or Settlement Amendments to IAS 28 Long-term interests in associates and joint ventures 1 Jan 2019 1 Jan 2021 1 Jan 2019 1 Jan 2019 Unknown 1 Jan 2019 1 Jan 2019 The Management is currently assessing the impact of IFRS 16 as whilst there are no material operating leases in the Group it may be relevant to future operations including service agreements containing the use of assets. 38 Notes to the Financial Statements (continued) 1 Principal accounting policies (continued) 1.3 Basis of consolidation Subsidiary undertakings are entities that are directly or indirectly controlled by the Group. Control is achieved when 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. Generally, there is a presumption that a majority of voting rights result in control. To support this presumption and when the Group has less than a majority of the voting or similar rights of an investee, the Group considers all relevant facts and circumstances in assessing whether it has power over an investee. The consolidated financial statements present the results of the Company and its subsidiaries (“the Group”) as if they formed a single entity. Intercompany transactions and balances between group companies are therefore eliminated in full. The purchase method of accounting is used to account for the acquisition of subsidiary undertakings by the Group. The cost of an acquisition is measured at the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date, irrespective of the extent of any non-controlling interest. The excess of the cost of acquisition over the fair value of the Group’s share of the identifiable net assets acquired is recorded as goodwill. 1.4 Operating Loss Operating loss is stated after crediting all operating income and charging all operating expenses, but before crediting or charging the financial income or expenses. 1.5 Foreign currency translation 1.5.1 Functional and presentational currencies Items included in the financial statements of each of the Group’s entities are measured using the currency of the primary economic environment in which the entity operates (“the functional currency”). The consolidated financial statements are presented in US Dollars (“US$”), which is the Group’s presentational currency. Beibars Munai LLP, Munaily Kazakhstan LLP, BNG Ltd LLP and Roxi Petroleum Kazakhstan LLP, subsidiary undertakings of the Group during the period, undertake their activities in Kazakhstan and the Kazakh Tenge is the functional currency of these entities. The functional currency for the Company, Beibars BV, Ravninnoe BV, Galaz Energy BV, BNG Energy BV and Eragon Petroleum FZE is USD as USD reflects the underlying transactions, conducts and events relevant to these companies. 1.5.2 Transactions and balances in foreign currencies In preparing the financial statements of the individual entities, transactions in currencies other than the entity’s functional currency (“foreign currencies”) are recorded at the rates of exchange prevailing at the dates of the transactions. At each reporting date, monetary items denominated in foreign currencies are retranslated at the rates prevailing at the reporting date. Non-monetary items carried at fair value that are denominated in foreign currencies are retranslated at the rates prevailing at the date when the fair value was determined. Non-monetary items, including the parent’s share capital, that are measured in terms of historical cost in a foreign currency are not retranslated. Exchange differences are recognised in profit or loss in the period in which they arise. 1.5.3 Consolidation For the purpose of consolidation all assets and liabilities of Group entities with a functional currency that is not US$ are translated at the rate prevailing at the reporting date. The profit or loss is translated at the exchange rate approximating to those ruling when the transaction took place. Exchange difference arising on retranslating the opening net assets from the opening rate and results of operations from the average rate are recognised directly in other comprehensive income (the “cumulative translation reserve”). On disposal of a foreign operator, related cumulative foreign exchange gains and losses are reclassified to profit and loss and are recognized as part of the gain or loss on disposal. 1.6 Current tax Current tax is based on taxable profit for the year. Taxable profit differs from profit as reported in the profit or loss because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. The Group’s liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the reporting date. 39 Notes to the Financial Statements (continued) 1 Principal accounting policies (continued) 1.7 Deferred tax Deferred tax is provided on temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. The following temporary differences are not provided for: the initial recognition of assets or liabilities that affect neither accounting nor taxable profit other than in a business combination, and differences relating to investments in subsidiaries to the extent that they will probably not reverse in the foreseeable future. The amount of deferred tax provided is based on the expected manner of realisation or settlement of the carrying amount of assets and liabilities, using tax rates enacted or substantively enacted at the reporting date. Deferred tax liabilities are generally recognised for all taxable temporary differences. A deferred tax asset is recorded only to the extent that it is probable that taxable profit will be available, against which the deductible temporary differences can be utilised. 1.8 Unproven oil and gas assets The Group applies the full cost method of accounting for exploration and unproven oil and gas asset costs, having regard to the requirements of IFRS 6 ‘Exploration for and Evaluation of Mineral Resources’. Under the full cost method of accounting, costs of exploring for and evaluating oil and gas properties are accumulated and capitalised by reference to appropriate cost pools. Such cost pools are based on license areas. The Group currently has two cost pools. Exploration and evaluation costs include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, but do not include costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to the profit or loss as they are incurred. Plant and equipment assets acquired for use in exploration and evaluation activities are classified as property, plant and equipment. However, to the extent that such asset is consumed in developing an unproven oil and gas asset, the amount reflecting that consumption is recorded as part of the cost of the unproven oil and gas asset. The amounts included within unproven oil and gas assets include the fair value that was paid for the acquisition of partnerships holding subsoil use in Kazakhstan. These licenses have been capitalised to the Group’s full cost pool in respect of each license area. Exploration and unproven oil and gas assets related to each exploration license/prospect are not amortised but are carried forward until the technical feasibility and commercial feasibility of extracting a mineral resource are demonstrated. Commercial reserves are defined as proved oil and gas reserves. Proven oil and gas properties Once a project reaches the stage of commercial production and production permits are received, the carrying values of the relevant exploration and evaluation asset are assessed for impairment and transferred to proven oil and gas properties and included within property plant and equipment. Proven oil and gas properties are accounted for in accordance with provisions of the cost model under IAS 16 “Property Plant and Equipment” and are depleted on unit of production basis based on commercial reserves of the pool to which they relate. Impairment Exploration and unproven intangible assets are reviewed for impairments if events or changes in circumstances indicate that the carrying amount may not be recoverable as at the reporting date. Intangible exploration and evaluation assets that relate to exploration and evaluation activities that are not yet determined to have resulted in the discovery of the commercial reserve remain capitalised as intangible exploration and evaluation assets subject to meeting a pool-wide impairment test as set out below. In accordance with IFRS 6 the Group firstly considers the following facts and circumstances in their assessment of whether the Group’s exploration and evaluation assets may be impaired, whether: § § § § the period for which the Group has the right to explore in a specific area has expired during the period or will expire in the near future, and is not expected to be renewed; substantive expenditure on further exploration for and evaluation of mineral resources in a specific area is neither budgeted nor planned; exploration for and evaluation of hydrocarbons in a specific area have not led to the discovery of commercially viable quantities of hydrocarbons and the Group has decided to discontinue such activities in the specific area; and sufficient data exists to indicate that although a development in a specific area is likely to proceed, the carrying amount of the exploration and evaluation assets is unlikely to be recovered in full from successful development or by sale. If any such facts or circumstances are noted, the Group perform an impairment test in accordance with the provisions of IAS 36. The aggregate carrying value is compared against the expected recoverable amount of the cash generating unit, being the relevant cost pool. The recoverable amount is the higher of value in use and the fair value less costs to sell. An impairment loss is reversed if the asset’s or cash-generating unit’s recoverable amount exceeds its carrying amount. 40 Notes to the Financial Statements (continued) 1 Principal accounting policies (continued) Workovers/Overhauls and maintenance From time to time a workover or overhaul or maintenance of existing proven oil and gas properties is required, which normally falls into one of two distinct categories. The type of workover dictates the accounting policy and recognition of the related costs: Capitalisable costs – cost will be capitalised where the performance of an asset is improved, where an asset being overhauled is being changed from its initial use, the assets’ useful life is being extended, or the asset is being modified to assist the production of new reserves. Non-capitalisable costs – expense type workover costs are costs incurred as maintenance type expenditure, which would be considered day-to-day servicing of the asset. These types of expenditures are recognised within cost of sales in the statement of comprehensive income as incurred. Expense workovers generally include work that is maintenance in nature and generally will not increase production capability through accessing new reserves, production from a new zone or significantly extend the life or change the nature of the well from its original production profile. 1.9 Abandonment Provision is made for the present value of the future cost of the decommissioning of oil wells and related facilities. This provision is recognised when the asset is installed. The estimated costs, based on engineering cost levels prevailing at the reporting date, are computed on the basis of the latest assumptions as to the scope and method of decommissioning. The corresponding amount is capitalised as a part of the oil and gas asset and, when in production is amortised on a unit-of-production basis as part of the depreciation, depletion and amortisation charge. Any adjustment arising from the reassessment of estimated cost of decommissioning is capitalised, while the charge arising from the unwinding of the discount applied to the decommissioning provision is treated as a component of the interest charge. 1.10 Restricted use cash Restricted use cash is the amount set aside by the Group for the purpose of creating an abandonment fund to cover the future cost of the decommissioning of oil and gas wells and related facilities and in accordance with local legal rulings. Under the Subsoil Use Contracts the Group must place 1% of the value of exploration costs in an escrow deposit account, unless agreed otherwise with the Ministry of Energy. At the end of the contract this cash will be used to return the field to the condition that it was in before exploration started. 1.11 Property, plant and equipment All property, plant and equipment assets are stated at cost or fair value on acquisition less accumulated depreciation. Depreciation is provided on a straight-line basis, at rates calculated to write off the cost less the estimated residual value of each asset over its expected useful economic life. The residual value is the estimated amount that would currently be obtained from disposal of the asset if the asset were already of the age and in the condition expected at the end of its useful life. Expected useful economic life and residual values are reviewed annually. The annual rates of depreciation for class of property, plant and equipment are as follows: - motor vehicles - other 4-5 years over 2-4 years The Group assesses at each reporting date whether there is any indication that any of its property, plant and equipment has been impaired. If such an indication exists, the asset’s recoverable amount is estimated and compared to its carrying value. 1.12 Investments (Company) Investments in subsidiary undertakings are shown at cost less allowance for impairment. Long-term advances to subsidiaries are discounted at estimated market rate of interest. Difference between a fair value and a face value of the advance is recorded within investments. Subsequently loan is accreted up using effective interest, unless loan is considered credit impaired, while interest is recorded on unimpaired amount. The loan at amortised cost is assessed for expected credit loss under IFSR 9. 41 Notes to the Financial Statements (continued) 1 Principal accounting policies (continued) 1.13 Financial instruments The Group classifies financial instruments, or their component parts on initial recognition, as a financial asset, a financial liability or an equity instrument in accordance with the substance of the contractual agreement. Financial assets and financial liabilities are recognised when the Group becomes a party to the contractual provisions of the financial instrument. Financial assets Financial assets are classified as either financial assets at amortised cost, at fair value through other comprehensive income (“FVTOCI”) or at fair value through profit or loss (“FVPL”) depending upon the business model for managing the financial assets and the nature of the contractual cash flow characteristics of the financial asset. A loss allowance for expected credit losses is determined for all financial assets, other than those at FVPL, at the end of each reporting period. The Group applies a simplified approach to measure the credit loss allowance for any trade receivables using the lifetime expected credit loss provision. The lifetime expected credit loss is evaluated for each trade receivable taking into account payment history, payments made subsequent to year end and prior to reporting, past default experience and the impact of any other relevant and current observable data. The Group applies a general approach on all other receivables classified as financial assets. The general approach recognises lifetime expected credit losses when there has been a significant increase in credit risk since initial recognition. The Group derecognises a financial asset when the contractual rights to the cash flows from the asset expire, or when it transfers the financial asset and substantially all the risks and rewards of ownership of the asset to another party. The Group derecognises financial liabilities when the Group’s obligations are discharged, cancelled or have expired. The Group’s financial assets consist of cash, amounts advances to subsidiaries and other receivables. Cash and cash equivalents are defined as short term cash deposits which comprise cash on deposit with an original maturity of less than 3 months. Other receivables are initially measured at fair value and subsequently at amortised cost. The Group’s financial liabilities are non-interest bearing trade and other payables, other interest bearing borrowings. Non-interest bearing trade and other payables and other interest bearing borrowings are stated initially at fair value and subsequently at amortised cost. Where a loan is renegotiated on substantially different terms, this is treated as an extinguishment of the original financial liability and the recognition of a new financial liability with a gain or loss recorded in the income statement. In accordance with IFRS 9, following a modification or renegotiation of a financial asset or financial liability that does not result in de-recognition, an entity is required to recognise any modification gain or loss immediately in profit or loss. Any gain or loss is determined by recalculating the gross carrying amount of the financial liability by discounting the new contractual cash flows using the original effective interest rate. The difference between the original contractual cash flows of the liability and the modified cash flows discounted at the original effective interest rate is recorded in the income statement. Share capital issued to extinguish financial liabilities is fair valued with any difference to the carrying value of the financial liability taken to the profit or loss. 1.14 Inventories Inventories are initially recognised at cost, and subsequently at the lower of cost and net realisable value. Cost comprises all costs of purchase and other costs incurred in bringing the inventories to their present location and condition. 1.15 Other provisions A provision is recognised when the Group has a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. 1.16 Share capital Ordinary and deferred shares are classified as equity. Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction from the proceeds. 42 Notes to the Financial Statements (continued) 1 Principal accounting policies (continued) 1.17 Share-based payments The Group has used shares and share options as consideration for services received from employees. Equity-settled share-based payments to employees and others providing similar services are measured at fair value at the date of grant. The fair value determined at the grant date of such an equity-settled share-based instrument is expensed on a straight-line basis over the vesting period, based on the Group’s estimate of the shares that will eventually vest. Equity-settled share-based payment transactions with other parties are measured at the fair value of the goods or services received, except where the fair value cannot be estimated reliably, in which case they are measured at the fair value of the equity instruments granted, measured at the date the entity obtains the goods or the counterparty renders the service. The fair value determined at the grant date of such an equity-settled share-based instrument is expensed since the shares vest immediately. Where the services are related to the issue of shares, the fair values of these services are offset against share premium where permitted. Fair value is measured using the Black-Scholes model. The expected life used in the model has been adjusted based on the Management’s best estimate, for the effects of non-transferability, exercise restrictions and behavioural considerations. 1.18 Warrants Warrants are separated from the host contract as their risks and characteristics are not closely related to those of the host contracts. Where the exercise price of the warrants is in a different currency to the functional currency of the Company, at each reporting date the warrants are valued at fair value with changes in fair values recognised through profit or loss as they arise. The fair values of the warrants are calculated using the Black-Scholes model. Where the warrant exercise price is in the same currency as the functional currency of the issuer and involve the issuance of a fixed number of shares the warrants are recorded in equity. 1.19 Revenue Revenue from contracts with customers is recognized when or as the Group satisfies a performance obligation by transferring a promised good or service to a customer. A good or service is transferred when the customer obtains control of that good or service. The transfer of control of oil sold by the Group usually coincides with title passing to the customer. The Group satisfies its performance obligations at a point in time. Revenue is measured at the fair value of the consideration received, excluding value added tax (“VAT”) and other sales taxes or duty. Royalties are not included in revenue, they are paid on production and recorded within cost of sales. Payments in advance by oil traders are recorded initially as deferred revenue, reflecting the nature of the transaction. Subsequently, the deferred revenue is reduced and revenue is recorded, as sales are made under the Group’s revenue recognition policy with the performance obligation satisfied. 1.20 Cost of sales During test production cost of sales cannot be reliably estimated and therefore a cost of sales equal to revenue is recognised and credited to the unproven oil and gas assets. 1.21 Segmental reporting Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker. The chief operating decision maker, who is responsible for allocating resources and assessing performance of the operating segments and making strategic decisions, has been identified as the Board of Directors. The Group has one operating segment being oil exploration and production in Kazakhstan and therefore one reporting segment. The Group has several cost pools divided based on the different contractual territory of its assets. As the activity of all cost pools is the same (oil exploration and production) and all of them operate geographically in Kazakhstan, the Group reports one segment in its financials. 1.22 Interest receivable and payable Interest income and expense are reported on an accrual basis using the effective interest rate method. 1.23 Exchange rates For reference the year end exchange rate from sterling to US$ was 1.27 and the average rate during the year was 1.33. The year- end exchange rate from KZT to US$ was 384.2 and the average rate during the year was 344.7. 43 Notes to the Financial Statements (continued) 2 Critical accounting estimates and judgements In the process of applying the Group’s accounting policies, which are described in note 1, the Management has made the following judgements and key assumptions that have the most significant effect on the amounts recognised in the financial statements. 2.1 Recoverability of exploration and evaluation costs Under the full cost method of accounting for exploration and evaluation costs, such costs are capitalised as intangible assets by reference to appropriate cost pools, and are assessed for impairment on a concession basis based on the IFRS 6 impairment indicators detailed in the accounting policy note 1.8. As at 31 December 2018, the Group assessed the exploration and evaluation assets disclosed in note 11 and determined that no indicators of impairment existed at a cost pool level in respect of the BNG cost pool. In forming this assessment, the Board considered the results of the Competent Person report, the economic models associated with the shallow wells, the results of exploration activity to date, the status of licences and future plans for the licence areas. In forming its assessment, the Board considered the Group’s commitments under the licence detailed in note 20. The Beibars cost pool remains impaired based on the continuance of the force majeure. The Group has decided to formally relinquish any interest in Beibars. Currently the Group is in the process of returning all available information and contract territory to the Ministry of Energy. 2.2 Classification of BNG as an unproven oil and gas asset The costs capitalised in respect of the BNG contract area are recorded within unproven oil and gas assets. Judgment has been applied in assessing whether the asset meets the criteria for reclassification to proven oil and gas assets under the Group’s accounting policy in note 1.8 given the increased production volumes and reserves. The Board considers the BNG contract area to remain in an exploration phase given the level of wells and production relative to plans for the field, the exploration status of the licence and the requirement to sell its oil in the domestic market which represents a substantial discount to the international market. 2.3 Recoverability of VAT The Group holds VAT receivables of $3 million (2017: $3.5million) as detailed in note 15 which are anticipated to be primarily recovered through offset of future VAT payable in accordance with Kazakh legislation. Management have assessed the recoverability of the asset based on forecast levels of VAT payables which demonstrate that the balance will be recovered within 3.5 years (2017: 3.5 years) . This required estimates regarding future production, oil prices and expenditure. 2.4 Decommissioning Provision has been made in the accounts for future decommissioning costs to plug and abandon wells in note 20. The costs of provisions have been added to the value of the unproven oil and gas asset and will be depreciated on a unit of production basis. The decommissioning liability is stated in the accounts at discounted present value and accreted up to the final expected liability by way of an annual finance charge. The Group has potential decommissioning obligations in respect of its interests in Kazakhstan. The extent to which a provision is required in respect of these potential obligations depends, inter alia, on the legal requirements at the time of decommissioning, the cost and timing of any necessary decommissioning works, and the discount rate to be applied to such costs. Actual costs incurred in future periods may substantially differ from the amounts of provisions. In addition, future changes in environmental laws and regulations, estimates of deposit useful lives and discount rates may affect the carrying value of this provision 2.5 Share-based compensation In order to calculate the charge for share-based compensation as required by IFRS 2, the Group makes estimates principally relating to the assumptions used in its option-pricing model. 3 Segment reporting & revenue Operating segments Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker. The chief operating decision maker, who is responsible for allocating resources and assessing the performance of the operating segments and making strategic decisions, has been identified as the Board of Directors. The Group operates in one operating segment (exploration for and production of oil in Kazakhstan). All revenues from test production are generated domestically in Kazakhstan. 86% of the Group’s revenue was derived from one major customer. Revenue The Group's revenues are derived from the sale of oil in Kazakhstan. The Group usually receives advances for future production. Under the terms of sale, the performance obligation is the supply of oil and the performance obligation is satisfied at a point in time, being the delivery of oil to the refinery. Control passes to the customer at this point with title and risk transferred. When advances received from oil traders for delivery of future production at specified prices, deferred revenue is recorded and the liability reduced as oil is delivered. Where advances are made for future production and the financing component of such transactions is material, a finance charge is recorded based on the market rate of interest. The level of forward production sales in the year ranged from 3 to 6 months (2017: 6 to 9 months. The performance obligations in respect of such sales remain outstanding at year end. No trade receivables or accrued income was applicable at year end (2017: $Nil). 44 Notes to the Financial Statements (continued) 4 Operating loss Group operating loss for the year has been arrived after charging: Depreciation of property, plant and equipment (note 12) Auditors’ remuneration (note 5) Staff costs (note 6) Share based payment remuneration (note 6) 5 Group Auditor’s remuneration Group 2018 US$’000 (31) (220) (1,319) (13) Group 2017 US$’000 (43) (319) (1,403) (476) Fees payable by the Group to the Company's auditor BDO and its member firms in respect of the year: Fees for the audit of the annual financial statements Audit related services Other services – tax related Fees payable by the Group to Grant Thornton and its associates in respect of the year: Auditing of accounts of subsidiaries of the Company 6 Employees and Directors Staff costs during the year Wages and salaries Social security costs Pension costs Share-based payments Group 2018 US$’000 Group 2017 US$’000 95 11 88 194 99 11 180 290 Group 2018 US$’000 Group 2017 US$’000 26 26 29 29 Group 2018 US$’000 Company 2018 US$’000 Group 2017 US$’000 Company 2017 US$’000 1,319 108 73 13 1,513 782 32 - 13 827 1,403 135 90 476 2,104 794 32 - 476 1,302 Payroll expenses were capitalized in the amount of US$ 332,000 (2017: US$ 330,000). Average monthly number of people employed (including executive Directors) Group 2018 Company 2018 US$’000 Group 2017 Company 2017 US$’000 Technical Field operations Finance Administrative and support Directors’ remuneration Director’s emoluments Share-based payments 10 47 9 14 80 1 - 2 2 5 13 53 10 19 95 2 - 2 2 6 Group 2018 US$’000 Group 2017 US$’000 540 - 540 524 333 857 The Directors are the key management personnel of the Company and the Group. Details of Directors' emoluments and interests in shares are shown in the Remuneration Committee Report. The highest paid director had emoluments totalling US$336,140 (2017: US$240,000). 45 Notes to the Financial Statements (continued) 7 Finance cost Loan interest payable Unwinding of discount on provisions (note 20) 8 Finance income Unwinding of discount of loan receivable from Baverstock Finance income related to the late receipt of receivable under SPA 9 Taxation Analysis of charge for the year Current tax charge Deferred tax charge Loss before tax Tax on the above at the standard rate of corporate income tax in the UK 19% (2017: 19.25%) Effects of: Non-deductible expenses Return of prior year CIT payment* Withholding tax on interest expense Utilization of tax losses not previously recognized Unrecognised tax losses carried forward Group 2018 US$’000 337 11 348 Group 2018 US$’000 - - - Group 2018 US$’000 414 - 414 Group 2018 US$’000 (2,972) (565) 23 (1,013) 1,375 (2,882) 3,476 414 Group 2017 US$’000 165 2 167 Group 2017 US$’000 100 94 194 Group 2017 US$’000 1,345 - 1,345 Group 2017 US$’000 (3,349) (645) 545 - 1,345 - 100 1,345 * During the years ended 31 December 2014 and 2015 the Company incurred taxation in respect of interest accrued on non- current advances provided to a subsidiary. Following subsequent analysis of the agreements it was identified that interest had been incorrectly accrued under the terms of the agreements. Accordingly, during 2016 the Parent company results were restated. As a result the Company resubmitted its CIT returns to HMRC. During H1 2018 the amended CIT returns have been approved by HMRC and related tax payment from HMRC has been received by the Company during August 2018. 10 Earnings/(loss) per share Basic earnings/(loss) per share is calculated by dividing the income/(loss) attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year including shares to be issued. There is no difference between the basic and diluted loss per share as the Group made a loss for the current and prior year. Dilutive potential ordinary shares include share options granted to employees and directors where the exercise price (adjusted according to IAS33) is less than the average market price of the Company’s ordinary shares during the period. The calculation of earnings/(loss) per share is based on: The basic weighted average number of ordinary shares in issue during the year The loss for the year attributable to owners of the parent from continuing operations (US$’000) The loss for the year attributable to owners of the parent from discontinued operations (US$’000) 2018 2017 1,669,706,698 1,362,172,379 (3,219) (5,147) (3,928) - There were 7,200,000 potentially dilutive instruments in the year (2017: 8,400,000). 46 Notes to the Financial Statements (continued) 11 Unproven oil and gas assets COST Cost at 1 January 2017 Additions Sales from test production Foreign exchange difference Cost at 31 December 2017 Additions Sales from test production Foreign exchange difference Cost at 31 December 2018 ACCUMULATED IMPAIRMENT Accumulated impairment at 1 January 2017 Foreign exchange difference Accumulated impairment at 31 December 2017 Foreign exchange difference Accumulated impairment at 31 December 2018 Net book value at 1 January 2017 Net book value at 31 December 2017 Net book value at 31 December 2018 Group US$’000 83,223 9,158 (7,535) (10) 84,836 7,479 (10,747) (13,082) 68,486 Group US$’000 15,137 (2) 15,135 (2,334) 12,801 68,086 69,701 55,685 Unproven oil and gas assets represent license acquisition costs and subsequent exploration expenditure in respect of two licenses held by Kazakh group entities. The carrying values of those assets at 31 December 2018 were as follows: Beibars Munai LLP US$ nil (2017: US$ nil) and BNG Ltd LLP US$55,685,000 (2017: US$69,701,000). The Directors have carried out an impairment review of these assets on a cost pool level as detailed in note 2.1. No impairment indicators were identified for BNG Ltd LLP. As a result of military training activities, the Group currently cannot access the Beibars license area which resulted in a force- majeure situation and the Group is in the process of relinquishing its interest in the asset and handing it back to the Kazakh authorities. Due to this ongoing position the carrying value remains fully impaired. 47 Notes to the Financial Statements (continued) 12 Property, plant and equipment Following the commencement of commercial production in December 2012 the Group reclassified its Munaily assets from unproven oil and gas assets to proven oil and gas assets. The assets were impaired in 2013. During 2018 the Group has disposed it Munaily assets (note 21). Group Cost at 1 January 2017 Additions Disposals Foreign exchange difference Cost at 31 December 2017 Additions Disposals Foreign exchange difference Cost at 31 December 2018 Depreciation at 1 January 2017 Charge for the year Foreign exchange difference Depreciation at 31 December 2017 Charge for the year Disposals Foreign exchange difference Depreciation at 31 December 2018 Net book value at: 01 January 2017 31 December 2017 31 December 2018 Proved oil and gas assets Motor Vehicles Other Total US$’000 US$’000 US$’000 US$’000 47 - - - 47 - (47) - - 47 - - 47 - (47) - - - - - 153 - - - 153 - (85) (12) 56 67 13 - 80 9 (51) (6) 32 86 73 24 328 5 (21) 1 313 3 (8) (42) 266 191 30 - 221 22 (8) (32) 203 137 92 63 528 5 (21) 1 513 3 (140) (54) 322 305 43 - 348 31 (106) (38) 235 223 165 87 48 Notes to the Financial Statements (continued) 13 Investments (Company) Investments Cost At 1 January 2017 Acquisition of Eragon non-controlling interest (note 27) Receipts Payments At 31 December 2017 Receipts Payments At 31 December 2018 Impairment At 1 January 2017 Impairment At 31 December 2017 Impairment At 31 December 2018 Net book value at: 31 December 2017 31 December 2018 Company US$’000 190,595 85,179 (398) 535 275,911 534 (206) 276,239 64,253 - 64,253 - 64,253 211,658 211,986 The carrying value of the investments has been assessed by the Directors including consideration of the underlying BNG contract area progress and the implied values of BNG based on the Baverstock merger occurred in 2017. Direct investments Name of undertaking Country of incorporation Effective holding and proportion of voting rights held at 31 December 2018 Effective holding and proportion of voting rights held at 31 December 2017 Eragon Petroleum Limited United Kingdom 100% 100% Eragon Petroleum FZE Dubai 100% 100% Beibars BV Netherlands 100% 100% Ravninnoe BV Netherlands 100% 100% Roxi Petroleum Kazakhstan LLP Kazakhstan 100% 100% Registered address Nature of business 5 New Street Square London EC4A 3TW Holding Company CN-135789, Jebel Ali, Dubai, UAE Management Company Utrechtseweg 79 1213 TM Hilversum The Netherlands Utrechtseweg 79 1213 TM Hilversum The Netherlands 152/140 Karasay Batyr Str., Almaty, Kazakhstan Holding Company Holding Company Management Company 49 Notes to the Financial Statements (continued) 13 Investments (continued) Indirect investments held by Eragon Petroleum Limited Name of undertaking Country of incorporation Effective holding and proportion of voting rights held at 31 December 2018 Effective holding and proportion of voting rights held at 31 December 2017 Registered address Nature of business Galaz Energy BV Netherlands 100% 100% BNG Energy BV Netherlands 100% 100% BNG Ltd LLP Kazakhstan 99% 99% Munaily Kazakhstan LLP Kazakhstan 0% 99% During 2018 the Group sold its share in Munaily Kazakhstan LLP for $134,000 (note 21). Utrechtseweg 79 1213 TM Hilversum The Netherlands Holding Company Utrechtseweg 79 1213 TM Hilversum The Netherlands Holding Company 152/140 Karasay Batyr Str., Almaty, Kazakhstan Exploration Company 152/140 Karasay Batyr Str., Almaty, Kazakhstan Oil Production Company Indirect investments held by Beibars BV Name of undertaking Country of incorporation Effective holding and proportion of voting rights held at 31 December 2018 Effective holding and proportion of voting rights held at 31 December 2017 Registered address Nature of business Beibars Munai LLP Kazakhstan 50% 50% 152/140 Karasay Batyr Str., Almaty, Kazakhstan Exploration Company Beibars Munai LLP is a subsidiary as the Group is considered to have control over the financial and operating policies of this entity. Its results have been consolidated within the Group. 50 Notes to the Financial Statements (continued) 14 Inventories Materials and supplies 15 Other receivables Amounts falling due after one year: Prepayments made VAT receivable Intercompany receivables Amounts falling due within one year: Prepayments made Other receivables Group 2018 US$’000 132 132 Group 2018 Group 2017 Company 2018 US$ ‘000 US$ ‘000 US$ ‘000 5,516 2,929 - 8,445 119 245 364 5,799 3,456 - 9,255 227 605 832 54 - 3,012 3,066 6 - 6 Group 2017 US$’000 21 21 Company 2017 US$’000 98 - 2,846 2,944 5 - 5 The VAT receivables relate to purchases made by operating companies in Kazakhstan and will be recovered through VAT payable resulting from sales to the local market and, after the commencement of oil production and its export from Kazakhstan, through cash refunds in accordance with Kazakh tax legislation. The current intercompany receivables bear interest rates between LIBOR + 2% and LIBOR + 7%. Inter-company receivables has been assessed for expected credit losses considering factors such as the status of underlying licenses, reserves, financial models and future risks and uncertainties. The provision substantially refers to balances considered credit impaired. Inter-company receivables from the subsidiaries in the table above are shown net of provisions of US$12.2 million (2017: US$34.2 million). The movement in the expected credit loss provision related to the inter-company receivables was as follows: Denomination As at 1 January Charge Write-off* As at 31 December Group 2018 US$’000 Group 2017 US$’000 - - - - - - - - Company 2018 US$’000 34,232 286 (22,306) 12,212 Company 2017 US$’000 33,310 922 - 34,232 *During 2018 the Company wrote off its fully impaired Munaily receivables following the sale of Munaily (note 21) and wroteoff of its fully impaired Roxi Petroleum Kazakhstan receivables. The Company recognised US$ 286 thousand of expected credit loss provisions in relation to it receivables from subsidiaries in 2018 (2017: US$ 922 thousand). 51 Notes to the Financial Statements (continued) 16 Cash and cash equivalents Cash at bank and in hand Group 2018 US$’000 557 Group 2017 US$’000 1,479 Company 2018 US$’000 292 Company 2017 US$’000 17 Funds are held in US Dollars, Sterling and Kazakh Tenge currency accounts to enable the Group to trade and settle its debts in the currency in which they occur and in order to mitigate the Group's exposure to short-term foreign exchange fluctuations. All cash is held in floating rate accounts. Denomination US Dollar Sterling Kazakh Tenge 17 Called up share capital Group and Company Group 2018 US$’000 448 60 49 557 Group 2017 US$’000 1,221 6 252 1,479 Company 2018 US$’000 Company 2017 US$’000 232 60 - 292 11 6 - 17 Balance at 1 January 2017 Acquisition of Eragon non-controlling (note 27) Debts converted to equity Balance at 31 December 2017 Share options exercised Balance at 31 December 2018 interest Number of ordinary shares 937,433,077 651,436,544 80,804,199 1,669,673,820 1,200,000 1,670,873,820 US$’000 16,000 8,364 1,037 25,401 15 25,416 Number of deferred shares 373,317,105 - - 373,317,105 - 373,317,105 US$’000 64,702 - - 64,702 - 64,702 Caspian Sunrise Plc has authorised share capital of £100,000,000 divided into 6,640,146,055 ordinary shares of 1p each and 373,317,105 deferred shares of 9p each. 18 Trade and other payables – current Trade payables Taxation and social security Accruals Other payables Intercompany payables Advances received (deferred revenue) Group 2018 US$’000 861 180 197 2,235 - 2,786 6,259 Group 2017 US$’000 1,220 175 225 2,120 - 5,798 9,538 Company 2018 US$’000 221 21 165 413 8,232 - 9,052 Company 2017 US$’000 380 38 195 318 7,695 - 8,626 As at 31 December 2018 and 31 December 2017, the Group has received a significant amount of prepayments from the oil traders in relation to increasing production on the BNG oil field. Amounts included in advances received that was recognised as revenue during the period: $10.7 (2017: $7.5m). Excess of revenue recognised over cash being recognised during the period is $3m (2017: excess of cash recognized over the revenue is $3.4m). Other payables relate to the original purchase of Munaily oil field. 52 Notes to the Financial Statements (continued) 18 Trade and other payables – non-current Intercompany payables Taxation and social security Group 2018 US$’000 - 10,286 10,286 Group 2017 US$’000 - 10,958 10,958 Company 2018 US$’000 16,735 - 16,735 Company 2017 US$’000 16,058 - 16,058 Taxation and social security payable relate to withholding tax accrued on the interest expense at the BNG subsidiary level. 19 Short-term borrowings Prosperity/Mr Oraziman (a) Fosco BV (b) Other borrowings (c) Group 2018 US$’000 913 650 1,009 2,572 Group 2017 US$’000 1,196 639 297 2,132 Company 2018 US$’000 - - 400 400 Company 2017 US$’000 - - - - a) During December 2017 Eragon Petroleum FZE (a subsidiary of the Company) received a US $1.2 million loan from KC Caspian Explorer (KCCE), a 100% subsidiary of Prosperity Petroleum Ltd (“PPL”) under a loan provided by PPL. PPL is a company controlled by Mr Kuat Oraziman and therefore a related party of the Group. The loan is interest free and matured in December 2018. During 2018 the Group has partially repaid the loan. On 21 December 2018 the loan was extended till 31 December 2019. On 23 December 2018 Eragon Petroleum FZE has assigned the loan to Mr Oraziman making it interest bearing with the rate of 7%. The loan extension represents a substantial modification of the terms of the existing financial liability and has been accounted for as an extinguishment of the original financial liability and recognition of a new financial liability. b) During July 2016 Fosco BV, a company controlled by Mr Oraziman, therefore a related party of the Group, provided an on demand loan to BNG LLP in the amount of US$ 0.63 million. The loan is interest bearing with the rate of Libor+ 1%. c) The total amount borrowed by the Group at 31 December 2018 US$1,009,000 (2017: US$297,000) was payable to Kuat Oraziman and a legal entity controlled by Mr Oraziman, KC Caspian Explorer. Loans are interest free and repayable on demand. 53 Notes to the Financial Statements (continued) 20 Provisions Group only Balance at 1 January 2017 Increase in provision Paid in the year Unwinding of discount Foreign exchange difference Balance at 31 December 2017 Non-current provisions Current provisions Balance at 31 December 2017 Group only Balance at 1 January 2018 Increase in provision Sale of Munaily (note 21) Paid in the year Unwinding of discount Foreign exchange difference Balance at 31 December 2018 Non-current provisions Current provisions Balance at 31 December 2018 Employee holiday provision US$’000 Liabilities under Social Development Program and historical cost US$’000 Abandonment fund 2017 Total US$’000 US$’000 68 25 - - - 93 - 93 93 4,150 700 (19) - 2 4,833 527 4,306 4,833 Employee holiday provision US$’000 Liabilities under Social Development Program and historical cost US$’000 93 2 (8) - - (12) 75 - 75 75 4,833 - (795) (318) - (280) 3,440 - 3,440 3,440 153 39 (6) 2 6 194 194 - 194 Abandonment fund 4,371 764 (25) 2 8 5,120 721 4,399 5,120 2018 Total US$’000 US$’000 194 9 (49) (18) 11 (22) 125 125 - 125 5,120 11 (852) (336) 11 (314) 3,640 125 3,515 3,640 Liabilities and commitments in relation to Subsoil Use Contracts are disclosed below: a) Beibars Munai LLP During 2007 Beibars Munai LLP, a subsidiary undertaking, and the Ministry of Energy and Mineral Resources of the Republic of Kazakhstan signed a Contract for oil exploration within the block XXXVII-10 in Mangistauskaya oblast (Contract #2287). The contract term expired in January 2012 and the Group has applied to the Ministry of Oil and Gas for the extension of the Beibars exploration license, given the force majeure situation. However the Group was unsuccessful. In February 2017 the Group decided to formally relinquish any interest in Beibars. Currently the Group is in the process of returning all available information and contract territory to the Ministry of Energy. The Group has fully impaired its Beibars assets. 54 Notes to the Financial Statements (continued) 20 Provisions (continued) b) Munaily Kazakhstan LLP Munaily Kazakhstan LLP, a subsidiary, signed a contract # 1646 dated 31 January 2005 with the Ministry of Energy and Mineral Resources of RK (now the Ministry of Oil and Gas (MOG) for the exploration and extraction of hydrocarbons on Munaily deposit located in the Atyrau region. The contract is valid for 25 years. On 13 July 2011 Munaily Kazakhstan LLP and a competent authority signed Addendum No. 5 to the Subsoil Use Contract (SSUC), which stipulates the oil production period to be 15 years to 2025 and approves the minimum work program for the production period. During 2018 the Group decided to dispose its Munaily asset. The transaction was finalized on December 20, 2018 (note 21) c) BNG Ltd LLP BNG Ltd LLP a subsidiary, signed a contract #2392 dated 7 June 2007 with the Ministry of Energy and Mineral Resources of RK for exploration at Airshagyl deposit, located in Mangistau region. Under addendum No.1 dated 17 April 2008, the Contract Area was increased. The contract was valid for 4 years and expired on 7 June 2011. Addendum No. 6 to the Subsoil Use Contract for extension of exploration period up to June 2013 was obtained on 13 July 2011. On 16 July 2013 BNG Ltd LLP signed Addendum No. 7 extending the exploration period for two consecutive years until June 2015. On 22 June 2015 BNG Ltd LLP signed Addendum No. 9 extending the exploration period for three consecutive years until June 2018. On 24 December 2015 BNG Ltd LLP signed Addendum No.10 according to which the geological territory was extended by 140.6 sq kilometres. On 23 September 2016 addendum No.11 was signed that has reduced the penalties for non-fulfilment of the contractual obligations from 30% to 1%. On 20 December 2017 BNG Ltd LLP signed addendum No.12 where amended its contractual obligations increasing the minimal work program for 2016-2018 from US$16.5 million to US$27.5 million. All other obligations, including social obligations, remained the same. In June 2018 BNG Ltd LLP signed the Addendum No.13 with the Ministry of Energy for the 6 years appraisal period on the BNG oilfield until June 2024. In accordance with the terms of the addendum #13, BNG Ltd LLP remains committed to the following: • For the six-year appraisal period US$313,000 per annum should be invested in the social development of the region starting from January 2019; • To fund minimum cumulative work program during the appraisal period of US$ 28,103,000 • Investing not less than 1% of total investments in professional training of Kazakhstani personnel engaged in work under the contract; and • Transferring, on an annual basis, 1% of exploration expenditures to a liquidation fund through a special deposit account in a bank located within the Republic of Kazakhstan. The license commitments are established for the license term as a whole, with annual schedules contained therein under the license, should the company have unfulfilled commitments or outstanding payments under social programs, a 1% penalty is applied until the commitments are fulfilled. Refer to table above. 55 Notes to the Financial Statements (continued) 21 Munaily disposal During 2018 the Group entered into a sale and purchase agreement (“SPA”) with WIX Energy LLP to dispose of 99% of its interest in Munaily Kazakhstan LLP. Under the terms of the agreement, WIX Energy LLP agreed to purchase 99% of the equity for a total consideration of US$134 thousand from the Group. This transaction completed on 20 December 2018. The loss on disposal of Munaily Kazakhstan LLP was determined as follows: Total consideration Non-current assets Trade and other receivables Trade and other payables Non-current liabilities Net liabilities at date of disposal Less: minority share Gain on disposal before the effect of cumulative translation reserve Less: Release of cumulative translation reserve Loss on disposal The net cash inflow on disposal comprises: Cash received Cash disposed of Net cash inflow Munaily Kazakhstan LLP had the following results during 2018 and 2017: Revenue Expenses Loss before taxation Cash movements related to Munaily were negligible. 22 Deferred tax Deferred tax liabilities comprise: Deferred tax on exploration and evaluation assets acquired At date of disposal $’000 134 (58) (14) 350 2,882 3,160 136 3,158 8,305 5,147 134 - 134 2018 US$’000 - (334) (334) 2017 US$’000 16 (614) (598) Group 2018 US$’000 6,733 6,733 Group 2017 US$’000 7,784 7,784 The Group recognises deferred taxation on fair value uplifts to its oil and gas projects arising on acquisition. These liabilities reverse as the fair value uplifts are depleted or impaired. The movement on deferred tax liabilities was as follows: At beginning of the year Foreign exchange Group 2017 US$’000 7,784 (1,051) 6,733 Group 2017 US$’000 7,748 36 7,784 As at 31 December 2018 the Group has accumulated deductible tax expenditure related to BNG expenditure of approximately US$97 million available to carry forward and offset against future profits. This represents an unrecognised deferred tax asset of approximately US$19.4 million. Given the uncertainties regarding such deductions and the developing nature of the relevant tax system no deferred tax asset is recorded. Beibars have tax losses carried forward of US$5.1m. This asset is fully impaired and there is insufficient certainty of future profitability to utilise these deductions. 56 Notes to the Financial Statements (continued) 23 Share option scheme During the year the Group and the Company had in issue equity-settled share-based instruments to its Directors and certain employees. Equity-settled share-based instruments have been measured at fair value at the date of grant and are expensed on a straight-line basis over the vesting period, based on an estimate of the shares that will eventually vest. Options generally vest in three equal tranches over the three years following the grant. The options were issued to Directors and employees as follows: Number of options granted Number of options expired Options exercised Total options outstanding Weighted average exercise price in pence (p) per share 17 - - 13 32,992,011 (3,604,615) (6,840,000) 22,547,396 As at 31 December 2017 Directors Employees and others As at 31 December 2018 88,458,226 - - 88,458,226 (45,566,215) (2,404,615) (6,840,000) (54,810,830) (9,900,000) (1,200,000) - (11,100,000) 21,797,396 outstanding options as at 31 December 2018 are exercisable. The range of exercise prices of share options outstanding at the year end is 4p – 20p (2017: 4p – 65p). The weighted average remaining contractual life of share options outstanding at the end of the year is 3.8 years (2017: 4.4 years). 24 Warrants Equity - warrants The Company had 7.5 million warrants valid until 21 May 2017 that were recognised in equity (other reserves) in the amount of US$1,779 thousand. During 2017 the warrants expired therefore the Company reclassified the amount to Retained deficit. 25 Financial instrument risk exposure and management In common with all other businesses, the Group and Company are exposed to risks that arise from its use of financial instruments. This note describes the Group and Company’s objectives, policies and processes for managing those risks and the methods used to measure them. Further quantitative information in respect of these risks is presented throughout these financial statements. The significant accounting policies regarding financial instruments are disclosed in note 1. There have been no substantive changes in the Group or Company’s exposure to financial instrument risks, its objectives, policies and processes for managing those risks or the methods used to measure them from previous years unless otherwise stated in this note. Principal financial instruments The principle financial instruments used by the Group and Company, from which financial instrument risk arises, are as follows: Financial assets Intercompany receivables Other receivables Restricted use cash Cash and cash equivalents Financial liabilities Trade and other payables Other payables - current Other payables - non-current Borrowings – current Group 2018 US$’000 Group 2017 US$’000 Company 2018 US$’000 Company 2017 US$’000 - 245 250 557 1,052 - 605 263 1,479 2,347 3,012 - 292 3,304 2,846 - - 17 2,863 Group 2018 US$’000 Group 2017 US$’000 Company 2018 US$’000 Company 2017 US$’000 3,293 - - 2,572 5,865 3,565 - - 2,132 5,697 799 8,232 16,735 400 26,166 893 7,695 16,058 - 24,646 57 Notes to the Financial Statements (continued) 25 Financial instrument risk exposure and management (continued) Changes in liabilities arising from financial activities Below is the movement of financial liabilities of the Group for the years ended 31 December 2018 and 2017: 1 January 2018 Loans received Interest accrued Disposal of loans (note 21) Repayment Foreig exchange difference, net 31 December 2018 Financial liabilities Borrowings 2,132 1,047 337 (326) (534) (84) 2,572 1 January 2017 Loans received Interest accrued Conversion to equity Repayment Foreig exchange difference, net 31 December 2017 Financial liabilities Borrowings 10,744 8,315 165 (10,100) (7,000) 8 2,132 Below is the movement of financial liabilities of the Company for the years ended 31 December 2018 and 2017: 1 January 2018 Loans received Interest accrued Disposal of loans Repayment Foreig exchange difference, net 31 December 2018 Financial liabilities Borrowings Financial liabilities - 400 - - - - 400 1 January 2017 Loans received Interest accrued Conversion to equity Repayment Foreig exchange difference, net 31 December 2017 Borrowings 9,935 - 165 (10,100) - - - 58 Notes to the Financial Statements (continued) 25 Financial instrument risk exposure and management (continued) Principal financial instruments The principal financial instruments used by the Group and Company, from which financial instrument risk arises, are as follows: • • • • other receivables cash at bank trade and other payables borrowings General objectives, policies and processes The Board has overall responsibility for the determination of the Group and Company’s risk management objectives and policies and, whilst retaining ultimate responsibility for them, it has delegated the authority for designing and operating processes that ensure the effective implementation of the objectives and policies to the Group and Company’s finance function. The Board receives regular reports from the finance function through which it reviews the effectiveness of the processes put in place and the appropriateness of the objectives and policies it sets. The overall objective of the Board is to set policies that seek to reduce risk as far as possible without unduly affecting the Group and Company’s competitiveness and flexibility. Further details regarding these policies are set out below: Credit risk The maximum exposure to credit risk is represented by the carrying amount of each financial asset in the balance sheet which at the yearend amounted to US$ 1million (2017: US$ 2.3 million). Credit risk with respect to Group receivables and advances is mitigated by active and continuous monitoring the credit quality of its counterparties through internal reviews and assessment. The Company is exposed to credit risk on its receivables from its subsidiaries. The subsidiaries are exploration and development companies with no current commercial exploitation sales and therefore, whilst the receivables are due on demand, they are not expected to be paid until there is a successful outcome on a development project resulting in commercial exploitation sales being generated by a subsidiary. In application of IFRS 9 the Company has calculated the expected credit loss from these receivables (Note 15). The carrying amount of financial assets recorded in the Group and Company financial statements, which is net of any impairment losses, represents the Group’s and Company’s maximum exposure to credit risk. Credit risk with cash and cash equivalents is reduced by placing funds with banks with high credit ratings. 59 Notes to the Financial Statements (continued) 25 Financial instrument risk exposure and management (continued) Capital The Company and Group define capital as share capital, share premium, deferred shares, other reserves, retained deficit and borrowings. In managing its capital, the Group’s primary objective is to provide a return for its equity shareholders through capital growth. Going forward the Group will seek to maintain a gearing ratio that balances risks and returns at an acceptable level and also to maintain a sufficient funding base to enable the Group to meet its working capital and strategic investment needs. In making decisions to adjust its capital structure to achieve these aims, either through new share issues or the issue of debt, the Group considers not only its short-term position but also its long-term operational and strategic objectives. The Group’s gearing ratio as at 31 December 2018 was 6% (2017:5%). There has been no other significant changes to the Group’s Management objectives, policies and processes in the year. Liquidity risk Liquidity risk arises from the Group and Company’s Management of working capital and the amount of funding committed to its exploration programme. It is the risk that the Group or Company will encounter difficulty in meeting its financial obligations as they fall due. The Group and Company’s policy is to ensure that it will always have sufficient cash to allow it to meet its liabilities when they become due. To achieve this aim, it seeks to raise funding through equity finance, debt finance and farm-outs sufficient to meet the next phase of exploration and where relevant development expenditure. The Board receives cash flow projections on a periodic basis as well as information regarding cash balances. The Board will not commit to material expenditure in respect of its ongoing exploration programmes prior to being satisfied that sufficient funding is available to the Group to finance the planned programmes. For maturity dates of financial liabilities as at 31 December 2018 and 2017 see table below. The amounts are contractual payments and may not tie to the carrying value: Group 2018 US$’000 Group 2017 US$’000 Company 2018 US$’000 Company 2017 US$’000 Interest rate risk On Demand Less than 3 months 3-12 months 1- 5 years 2,572 936 8,632 7,695 710 911 210 359 2,583 3,850 589 534 - - - Over 5 years - - 23,617 23,617 Total 5,865 5,697 33,048 32,205 The majority of the Group’s borrowings are at fixed rate. As a result the Group is not exposed to the significant interest rate risk. Currency risk The Group and Company’s policy is, where possible, to allow group entities to settle liabilities denominated in their functional currency (primarily US$ and Kazakh Tenge) in that currency. Where the Group or Company entities have liabilities denominated in a currency other than their functional currency (and have insufficient reserves of that currency to settle them) cash already denominated in that currency will, where possible, be transferred from elsewhere within the Group. In order to monitor the continuing effectiveness of this policy, the Board receives a periodic forecast, analysed by the major currencies held by the Group and Company. The Group and Company are primarily exposed to currency risk on purchases made from suppliers in Kazakhstan, as it is not possible for the Group or Company to transact in Kazakh Tenge outside of Kazakhstan. The finance team carefully monitors movements in the US$/Kazakh Tenge rate and chooses the most beneficial times for transferring monies to its subsidiaries, whilst ensuring that they have sufficient funds to continue its operations. The currency risk relating to Tenge is significant. In the event that Kazakhstani Tenge devalues against the US$ by 30% the Group would incur foreign exchange losses in the amount of US$46 million (2017: US$51 million) that would be reflected in other comprehensive income. The impact of such a devaluation on the translation of monetary assets and liabilities (predominantly intercompany loans) held in Kazakhstan and denominated in non-Tenge currencies would be exchange losses recorded in the statement of changes in equity of US$46 million (2017: US$51 million). 60 Notes to the Financial Statements (continued) 26 Related party transactions The Company has no ultimate controlling party. 26.1 Loan agreements The Company has loans outstanding as at 31 December, 2018 and 2018 with Kuat Oraziman and legal entities controlled by him, details of which have been summarised in note 19. 26.2 Baverstock acquisition Before 1 June 2017 41% of Company's subsidiary Eragon Petroleum ltd was owned by Baverstock GmbH and 59% by Caspian Sunrise plc. On 1 June 2017 Caspian Sunrise plc acquired an additional 41% in its subsidiary Eragon Petroleum ltd. After that Company’s interest in BNG and Munaily increased from 58.41% to 99% and interest in Eragon increased from 59% to 100% (note 27). 26.3 Key management remuneration Key management comprises the Directors and details of their remuneration are set out in note 6. 26.4 Purchases As at year end the Group has prepayments made in the amount of US$2.3 million (2017: US$2.6 million) and trade receivables in the amount of US$80,000 (2017: US$92,000) in relation to STK Geo LLP, the company registered in Kazakhstan, which is owned by a member of Kuat Oraziman’s family. The Group previously purchased drilling services from STK GEO LLP. No purchases were made during 2018 and 2017. The Group expects that STK GEO LLP will provide drilling services during 2019 and utilise the major part of the advances. During 2017 the Group had purchased drilling and workover services from the related party KazSmartEnerKon LLP, a company registered in Kazakhstan, which is owned by Kuat Oraziman, in the amount of US$ 4.2 million (2017: US$4.6 million). These expenses were capitalized to unproven oil and gas assets. As at year end the Group has prepayments made in the amount of US$2.9 million (2017: US$2.8 million) in relation to these drilling service. 27 Acquisition of non-controlling interest On 1 June 2017 Caspian Sunrise plc acquired an additional 41% in its subsidiary Eragon Petroleum ltd in exchange of issuance of 651,436,544 Company's shares and forgiveness of the debt due from Baverstock fair valued at the level of US$6.5 million. As part of the transaction the Company incurred acquisition related costs in the amount of US$0.4 million. Following the transaction, the Company’s interest in BNG and Munaily increased from 58.41% to 99% and interest in Eragon increased from 59% to 100%. The related NCI share in net assets of Eragon at the date of acquisition was equal to US$6.6 million. The difference between the purchase consideration and net assets was charged directly to the consolidated statement of changes in equity as the transaction represented the acquisition of a non-controlling interest. Carrying amount of NCI acquired Consideration paid to NCI A decrease in equity attributable to owners of the Company 28 Non-controlling interest Balance at the beginning of the year Share of loss for the year Exchange differences on translating foreign operations and recycling on disposal Purchase of non-controlling interest in subsidiary (note 27) Disposal of Munaily (note 21) US$’000 6,571 88,432 (81,861) Group 2017 US$’000 2,617 (766) 66 (6,571) - (4,654) Group 2018 US$’000 (4,654) (167) (920) - 136 (5,605) As at 31 December 2018 non-controlling interest represents minority share in BNG Ltd LLP and Beibars Munail LLP (as at 31 December 2017- BNG Ltd LLP, Beibars Munai LLP and Munaily Kazakhstan LLP). 61 Notes to the Financial Statements (continued) 29 Events after the reporting period 3ABest Group In January 2018, the Company announced the intention to acquire 100% of the shares of 3ABest Group JSC, a company that owns a 1,347 sq km Contract Area located close to the Caspian port city of Aktau in the Mangystau Province of Kazakhstan. The purchase price of $13 million is satisfied by the issue of 149,253,732 new Companies shares at the afreed price of 7p per share. 62 

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