REG - Caspian Sunrise plc - Annual Report and Financial Statements
RNS Number : 0508ACaspian Sunrise plc24 May 2019
Caspian Sunrise PLC
("Caspian Sunrise" or the "Company")
Annual Report and Financial Statements for the Year Ended 31 December 2018
Caspian Sunrise, the Central Asian oil and gas company with a focus on Kazakhstan, is pleased to announce its audited final results for the year ended 31 December 2018.
Highlights for the year:
Financial
· Revenue increased by 41% to $10.7m (2017:$7.6m) with a greater quantity of oil sold;
· Administrative costs fell 11% to $2.6 m (2017: $3.4m), resulting in a reduced loss from continuing operations of $3.4m (2017: $4.7m);
· Loss for the year of $8.5m (2017:$4.7m) includes $5.1m (2017:$Nil) on discontinued operations at Munaily, mainly due to historic foreign exchange losses recycled from equity to income statement on disposal;
· The carrying value of the Company's oil and gas assets fell from $69.7m to $55.7m, this movement was related to the value of oil produced being deducted from the carrying value in accordance with prevailing accounting conventions and currency devaluations partly offset by costs capitalised.
Operational
· Operational wells drilled at end of year 2018 was 17 (2017: 16);
· Daily production (based on average in December 2018) 1,903 bopd (2017: 2,208 bopd based on average in December 2017), which reflects the Company's decision to use smaller choke settings to prolong the productive life of the wells and production from some of the producing wells being suspended to allow workovers and the testing of different intervals;
· Reserves at 31 December 2018: P1 17.8 mmbls and P2 28.8 mmbls (2017: P1 17.8 mmbls and P2 28.8 mmbls);
· On 29 May 2018, Caspian Sunrise announced the conditional acquisition of 3A Best Group JSC ("3A Best"), 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 3A Best Contract Area surrounds and runs under the successful Dunga Contract Area (not owned by Caspian Sunrise), which the Directors believe to be producing some 15,000 bopd;
· Caspian Sunrise's technical team believe some of the geological characteristics of the Dunga Contract Area are also present at 3A Best. Additionally they 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; and
· In December 2018 the Company 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.
Post year end highlights:
Financial
· In January 2019, the Group completed the 100 per cent. acquisition of 3A Best for an all share consideration of $13.5 million.
Operational
· The Company believes the horizon found at Deep Well A8 extends across the full 58km2 of the Airshagyl structure
· 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 to have shown the presence of oil; and
· The anticipated receipt the MJF export licence will have a material effect on income as the Company embarks on a 10 well infill MJF drilling programme.
Other
· Timothy Andrew Field was appointed as a non-executive director of the Company in January 2019; and
· The Directors ambition is to significantly grow the Company both by the development of BNG and 3A Best but also by targeted acquisitions. The Board's focus will remain in Kazakhstan where several opportunities have been identified and preliminary due diligence conducted.
Related Party Agreement
· The Company announces it has entered into an agreement ('the Framework Agreement') with its CEO, Kuat Orazimanin respect of the use contractors for drilling or other oil services.
· Under the Framework agreement, where the Company uses the services of a company owned or partially owned by a member or members of the Oraziman family:
o The terms of the contract or services shall first be approved by the Independent Directors [1]
o Pricing of such contracts or works shall be at a rate[2] of an arms-length transaction
o Where appropriate, competing tenders will be sought and the opinions of both external and internal experts may be consulted by the Independent Directors in their assessment of terms.
· As a result of the shareholdings of the Oraziman family and the position of Kuat Oraziman as a director of the Company, the Framework Agreement is considered a related party transaction under the AIM Rules.
· The independent directors of the Company in respect of AIM Rule 13, being Clive Carver, Edmund Limerick, and Tim Field consider, having consulted with WH Ireland, that the terms of the Framework Agreement are fair and reasonable insofar as Shareholders are concerned.
The results are included below and the Report and Accounts will be posted to the Company's website at: https://www.caspiansunrise.com/
The Report and Accounts and Notice of Annual General Meeting will shortly be posted to shareholders. The Company's AGM will be held at the offices of Fladgate LLP, 16 Great Queen Street, London WC2B 5DG, at 11am on Friday 21 June 2019.
Clive Carver, Executive Chairman commented on the results:
"While progress was steady rather than dramatic in the period under review we have recently reported real progress with our deep wells on the Airshagyl structure.
We continue to look forward to the early award of the licence upgrade at the MJF structure, which will allow oil to be sold by reference world rather than domestic prices and broadly double the receipts from oil produced."
Caspian Sunrise PLC
Clive Carver
Executive Chairman
+7 727 375 0202
WH Ireland, Nominated Adviser & Broker
James Joyce
Jessica Cave
James Sinclair-Ford
+44 (0) 207 220 1666
Yellow Jersey PR
Tim Thompson
Henry Wilkinson
+44 (0) 203 735 8825
This announcement has been posted to: www.caspiansunrise.com/investors
The information contained within this announcement is deemed by the Company to constitute inside information under the Market Abuse Regulation (EU) No. 596/2014.
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:
As at 31 December 2018
As at 31 December 2017
BNG
Shallow P1 (mmbls)
17.8
17.8
Shallow P2 (mmbls)
28.8
28.8
Deep P1 (mmbls)
Nil
Nil
Deep P2 (mmbs)
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.
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.
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.
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.
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.
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.
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.
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
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.
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 e-mail 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)
Directors' interests
Number of shares
Number of shares
Director
As at 31 December 2018
As at December 2017
Clive Carver
nil
nil
Kuat Oraziman*
37,285,330
37,285,330
Edmund Limerick**
6,430,000
3,210,000
Kairat Satylganov***
n/a
175,682,697
Timothy Field
nil
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.
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 on-going integrity of the financial statements contained therein.
Clive Carver
Executive Chairman
23 May 2019
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.
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.
Our application of materiality
Group materiality as at 31 December 2018
Basis for materiality
US$1,000,000
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.
Matters on which we are required to report by exception
In the light of the knowledge and understanding of the Group and the Parent Company and its environment obtained in the course of the audit, we have not identified material misstatements in the strategic report or the Directors' report.
We have nothing to report in respect of the following matters in relation to which the Companies Act 2006 requires us to report to you if, in our opinion:
• adequate accounting records have not been kept by the Parent Company, or returns adequate for our audit have not been received from branches not visited by us; or
• the Parent Company financial statements are not in agreement with the accounting records and returns; or
• certain disclosures of Directors' remuneration specified by law are not made; or
• we have not received all the information and explanations we require for our audit.
Responsibilities of Directors
As explained more fully in the Directors' responsibilities statement, the Directors are responsible for the preparation of the financial statements and for being satisfied that they give a true and fair view, and for such internal control as the Directors determine is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the financial statements, the Directors are responsible for assessing the Group's and the Parent Company's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the Directors either intend to liquidate the Group or the Parent Company or to cease operations, or have no realistic alternative but to do so.
Auditor's responsibilities for the audit of the financial statements
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).
Consolidated Statement of Profit or Loss
Notes
Year to
31 December
2018
Year to
31 December
2017
US$'000
US$'000
Revenue
3
10,747
7,575
Cost of sales
(10,747)
(7,550)
Gross profit
-
25
Share-based payments
(13)
(476)
Other administrative costs
(2,611)
(2,925)
Total administrative expenses
(2,624)
(3,401)
Operating loss
4
(2,624)
(3,376)
Finance cost
7
(348)
(167)
Finance income
8
-
194
Loss before taxation
(2,972)
(3,349)
Tax charge
9
(414)
(1,345)
Loss after taxation from continuing operations
(3,386)
(4,694)
Loss for the year from discontinued operations
21
(5,147)
-
Loss for the year
(8,533)
(4,694)
Loss attributable to owners of the parent
(8,366)
(3,928)
Loss attributable to non-controlling interest
(167)
(766)
Loss for the year
(8,533)
(4,694)
Basic loss per ordinary share (US cents)
10
From continuing operations
(0.19)
(0.29)
From discontinued operations
(0.31)
-
Total loss per share
(0.5)
(0.29)
Diluted loss per ordinary share (US cents)
10
From continuing operations
(0.19)
(0.29)
From discontinued operations
(0.31)
-
Total loss per share
(0.5)
(0.29)
Consolidated Statement of Comprehensive Income
Year ended
31 December
2018
Year ended
31 December
2017
US$000
US$000
Loss after taxation
(8,533)
(4,694)
Other comprehensive income:
Exchange differences on translating foreign operations
(10,136)
72
Recycling of exchange difference on disposal of subsidiary
8,305
-
Total comprehensive loss for the year
(10,364)
(4,622)
Total comprehensive loss attributable to:
Owners of parent
(9,277)
(3,922)
Non-controlling interest
(1,087)
(700)
Consolidated Statement of Changes in Equity
Share capital
US$'000
Share premium
US$'000
Deferred shares
US$'000
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$'000
Total
equity
US$'000
Total equity as at 1 January 2018
25,401
228,974
64,702
(55,000)
(2,362)
(210,877)
50,838
(4,654)
46,184
Loss after taxation
-
-
-
-
-
(8,366)
(8,366)
(167)
(8,533)
Exchange differences on translating foreign operations and recycling of exchange differences on disposal of subsidiaries
-
-
-
(911)
-
-
(911)
(920)
(1,831)
Total comprehensive income/(loss) for the year
-
-
-
(911)
-
(8,366)
(9,277)
(1,087)
(10,364)
Disposal of subsidiary
-
-
-
-
-
-
-
136
136
Share options exercised
15
46
-
-
-
-
61
-
61
Arising on employee share options
-
-
-
-
-
13
13
-
13
Total equity as at 31 December 2018
25,416
229,020
64,702
(55,911)
(2,362)
(219,230)
41,635
(5,605)
36,030
Share capital
US$'000
Share premium
US$'000
Deferred shares
US$'000
Cumulative translation reserve
US$'000
Other reserves
US$'000
Retained deficit
US$'000
Total attributable to the owner of the Parent
US$'000
Non-controlling interests
US$'000
Total
equity
US$'000
Total equity as at 1 January 2017
16,000
146,728
64,702
(55,006)
(583)
(127,343)
44,498
2,617
47,115
Loss after taxation
-
-
-
-
-
(3,928)
(3,928)
(766)
(4,694)
Exchange differences on translating foreign operations
-
-
-
6
-
-
6
66
72
Total comprehensive income/(loss) for the year
-
-
-
6
-
(3,928)
(3,922)
(700)
(4,622)
Purchase of non-controlling interest in subsidiary
8,364
73,183
-
-
-
(81,861)
(314)
(6,571)
(6,885)
Arising on employee share options
-
-
-
-
476
476
-
476
Lapsed warrants
-
-
-
-
(1,779)
1,779
-
-
-
Debts converted to equity
1,037
9,063
-
-
-
-
10,100
-
10,100
Total equity as at 31 December 2017
25,401
228,974
64,702
(55,000)
(2,362)
(210,877)
50,838
(4,654)
46,184
Equity Description and purpose
Share capital The nominal value of shares issued
Share premium Amount subscribed for share capital in excess of nominal value
Deferred shares The nominal value of deferred shares issued
Cumulative translation reserve Gains/losses arising on retranslating the net assets of overseas operations into US Dollars, less amounts recycled on disposal of subsidiaries and joint ventures
Other reserves Fair value of warrants issued and capital contribution arising on discounted loans
Retained deficit Cumulative losses recognised in the consolidated statement of profit or loss, adjustments on the acquisition of non controlling interests and transfers in respect of share based payments
Non-controlling interest The interest of non-controlling parties in the net assets of the subsidiaries
Parent Company Statement of Changes in Equity
Share
capital
US$'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$'000
Total equity as at 1 January 2018
25,401
228,974
64,702
14,936
(144,073)
189,940
Total comprehensive loss for the year
-
-
-
-
(851)
(851)
Stock options exercised
15
46
-
-
61
Arising on employee share options
-
-
-
-
13
13
Total equity as at 31 December 2018
25,416
229,020
64,702
14,936
(144,911)
189,163
Total equity as at 1 January 2017
16,000
146,728
64,702
16,715
(143,775)
100,370
Total comprehensive loss for the year
-
-
-
-
(2,553)
(2,553)
Purchase of non-controlling interest in subsidiary
8,364
73,183
-
-
-
81,547
Arising on employee share options
-
-
-
-
476
476
Forfeited warrants
-
-
-
(1,779)
1,779
-
Debts converted to equity
1,037
9,063
-
-
-
10,100
Total equity as at 31 December 2017
25,401
228,974
64,702
14,936
(144,073)
189,940
Equity Description and purpose
Share capital The nominal value of shares issued
Share premium Amount subscribed for share capital in excess of nominal value
Deferred shares The nominal value of deferred shares issued
Other reserves Fair value of warrants issued and capital contribution arising on discounted loans
Retained deficit Cumulative losses recognised in the profit or loss
Consolidated Statement of Financial Position
Company number 5966431
Notes
Group
2018
US$'000
Group
2017
US$'000
Assets
Non-current assets
Unproven oil and gas assets
11
55,685
69,701
Property, plant and equipment
12
87
165
Inventories
14
132
21
Other receivables
15
8,445
9,255
Restricted use cash
250
263
Total non-current assets
64,599
79,405
Current assets
Other receivables
15
364
832
Cash and cash equivalents
16
557
1,479
Total current assets
921
2,311
Total assets
65,520
81,716
Equity and liabilities
Capital and reserves attributable
to equity holders of the parent
Share capital
17
25,416
25,401
Share premium
229,020
228,974
Deferred shares
17
64,702
64,702
Other reserves
(2,362)
(2,362)
Retained deficit
(219,230)
(210,877)
Cumulative translation reserve
(55,911)
(55,000)
Equity attributable to the owners of the Parent
41,635
50,838
Non-controlling interests
28
(5,605)
(4,654)
Total equity
36,030
46,184
Current liabilities
Trade and other payables
18
6,259
9,538
Short - term borrowings
19
2,572
2,132
Current provisions
20
3,515
4,399
Total current liabilities
12,346
16,069
Non-current liabilities
Deferred tax liabilities
22
6,733
7,784
Non-current provisions
20
125
721
Other payables
18
10,286
10,958
Total non-current liabilities
17,144
19,463
Total liabilities
29,490
35,532
Total equity and liabilities
65,520
81,716
Approved by the Board and authorized for issue:
Clive Carver,
Chairman,
23 May 2019
Company number: 5966431
Parent Company Statement of Financial Position
Company number 5966431
Notes
Company
2018
US$'000
Company
2017
US$'000
Assets
Non-current assets
Investments in subsidiaries
13
211,986
211,658
Other receivables
15
3,066
2,944
Total non-current assets
215,052
214,602
Current assets
Other receivables
15
6
5
Cash and cash equivalents
16
292
17
Total current assets
298
22
Total assets
215,350
214,624
Equity and liabilities
Capital and reserves attributable
to equity holders of the parent
Share capital
17
25,416
25,401
Share premium
229,020
228,974
Deferred shares
17
64,702
64,702
Other reserves
14,936
14,936
Retained deficit
(144,911)
(144,073)
Equity attributable to the owners of the Parent
189,163
189,940
Total equity
189,163
189,940
Current liabilities
Short - term borrowings
19
400
-
Trade and other payables
18
9,052
8,626
Total current liabilities
9,452
8,626
Non-current liabilities
Other payables
18
16,735
16,058
Total non-current liabilities
16,735
16,058
Total liabilities
26,187
24,684
Total equity and liabilities
215,350
214,624
The Company incurred a loss for the year ended 31 December 2018 in the amount of US$ 851,000 (2017: US$ 2,553,000).
Approved by the Board and authorized for issue:
Clive Carver,
Chairman,
23 May 2019
Company number: 5966431
Consolidated and Parent Company Statements of Cash Flows
Notes
Group
2018
US$'000
Group
2017
US$'000
Company
2018
US$'000
Company
2017
US$'000
Cash flows from operating activities
Cash received from customers
9,025
10,928
-
-
Return of taxes previously paid
9
1,013
-
1,013
-
Payments made to suppliers for goods and services
(2,747)
(1,319)
(1,175)
(872)
Payments made to employees
(1,185)
(1,548)
(614)
(692)
Net cash flow from operating activities
6,106
8,061
(776)
(1,564)
Cash flows from investing activities
Purchase of property, plant and equipment
12
(3)
(5)
-
-
Additions to unproven oil and gas assets
11
(7,733)
(9,973)
-
-
Transfers from/(to) restricted use cash
-
(20)
-
-
Proceeds from disposal of joint venture (net of cash disposed and taxation) in prior periods
-
1,696
-
1,696
Proceeds from disposal of subsidiaries
21
134
-
-
-
Advances repaid by subsidiaries
-
-
180
410
Advances issued to subsidiaries
-
-
(100)
(535)
Net cash flow from investing activities
(7,602)
(8,302)
80
1,571
Cash flows from financing activities
Net proceeds from issue of ordinary share capital
61
-
61
-
Loans repaid
19,25
(534)
(7,000)
-
-
Loans provided by subsidiaries
-
-
600
-
Loans received
19,25
1,047
8,315
400
-
Repayment of loans provided by subsidiaries
-
-
(90)
-
Net cash flow from financing activities
574
1,315
971
-
Net increase/(decrease) in cash and cash equivalents
(922)
1,074
275
7
Cash and cash equivalents at the beginning of the year
1,479
405
17
10
Cash and cash equivalents at the end of the year
16
557
1,479
292
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).
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.
1.2 New and revised standards and interpretations applied (continued)
Standard
Description
Effective date
IFRS 9
Financial Instruments
1 Jan 2018
IFRS 15
Revenue from Contracts with Customers
1 Jan 2018
IFRS 2
Amendment - Classification and measurement of share based payment transactions
1 Jan 2018
IFRIC 22
Foreign currency transactions and advance considerations
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
Leases
1 Jan 2019
IFRS 17
IFRIC Interpretation 23
Amendments to IFRS 9
Amendments to IFRS 10 and IAS 28
Amendments to IAS 19
Amendments to IAS 28
Insurance contracts
Uncertainty over Income Tax Treatments
Prepayment Features with Negative Compensation
Sale or Contribution of Assets between an Investor and its Associate
Plan Amendment, Curtailment or Settlement
Long-term interests in associates and joint ventures
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.
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.
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.
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 4-5 years
- other 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.
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.
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.
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: $Nil).
4 Operating loss
Group operating loss for the year has been arrived after charging:
Group
2018
US$'000
Group
2017
US$'000
Depreciation of property, plant and equipment (note 12)
(31)
(43)
Auditors' remuneration (note 5)
(220)
(319)
Staff costs (note 6)
(1,319)
(1,403)
Share based payment remuneration (note 6)
(13)
(476)
5 Group Auditor's remuneration
Fees payable by the Group to the Company's auditor BDO and its member firms in respect of the year:
Group
2018
US$'000
Group
2017
US$'000
Fees for the audit of the annual financial statements
95
99
Audit related services
11
11
Other services - tax related
88
180
194
290
Fees payable by the Group to Grant Thornton and its associates in respect of the year:
Group
2018
US$'000
Group
2017
US$'000
Auditing of accounts of subsidiaries of the Company
26
29
26
29
6 Employees and Directors
Staff costs during the year
Group
2018
US$'000
Company
2018
US$'000
Group
2017
US$'000
Company
2017
US$'000
Wages and salaries
1,319
782
1,403
794
Social security costs
108
32
135
32
Pension costs
73
-
90
-
Share-based payments
13
13
476
476
1,513
827
2,104
1,302
Payroll expenses were capitalized in the amount of US$ 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
10
1
13
2
Field operations
47
-
53
-
Finance
9
2
10
2
Administrative and support
14
2
19
2
80
5
95
6
Directors' remuneration
Group
2018
US$'000
Group
2017
US$'000
Director's emoluments
540
524
Share-based payments
-
333
540
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$240,000).
7 Finance cost
Group
2018
US$'000
Group
2017
US$'000
Loan interest payable
337
165
Unwinding of discount on provisions (note 20)
11
2
348
167
8 Finance income
Group
2018
US$'000
Group
2017
US$'000
Unwinding of discount of loan receivable from Baverstock
-
100
Finance income related to the late receipt of receivable under SPA
-
94
-
194
9 Taxation
Analysis of charge for the year
Group
2018
US$'000
Group
2017
US$'000
Current tax charge
414
1,345
Deferred tax charge
-
-
414
1,345
Group
2018
US$'000
Group
2017
US$'000
Loss before tax
(2,972)
(3,349)
Tax on the above at the standard rate of corporate income tax in the UK 19% (2017: 19.25%)
(565)
(645)
Effects of:
Non-deductible expenses
23
545
Return of prior year CIT payment*
(1,013)
-
Withholding tax on interest expense
1,375
1,345
Utilization of tax losses not previously recognized
(2,882)
-
Unrecognised tax losses carried forward
3,476
100
414
1,345
* During the years ended 31 December 2014 and 2015 the Company incurred taxation in respect of interest accrued on non-current advances provided to a subsidiary. Following subsequent analysis of the agreements it was identified that interest had been incorrectly accrued under the terms of the agreements. Accordingly, during 2016 the Parent company results were restated. As a result the Company resubmitted its CIT returns to HMRC. During H1 2018 the amended CIT returns have been approved by HMRC and related tax payment from HMRC has been received by the Company during August 2018.
10 Earnings/(loss) per share
Basic earnings/(loss) per share is calculated by dividing the income/(loss) attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year including shares to be issued.
There is no difference between the basic and diluted loss per share as the Group made a loss for the current and prior year. Dilutive potential ordinary shares include share options granted to employees and directors where the exercise price (adjusted according to IAS33) is less than the average market price of the Company's ordinary shares during the period.
The calculation of earnings/(loss) per share is based on:
2018
2017
The basic weighted average number of ordinary shares in
issue during the year
1,669,706,698
1,362,172,379
The loss for the year attributable to owners of the parent from continuing operations (US$'000)
(3,219)
(3,928)
The loss for the year attributable to owners of the parent from discontinued operations (US$'000)
(5,147)
-
There were 7,200,000 potentially dilutive instruments in the year (2017: 8,400,000).
11 Unproven oil and gas assets
COST
Group
US$'000
Cost at 1 January 2017
83,223
Additions
9,158
Sales from test production
(7,535)
Foreign exchange difference
(10)
Cost at 31 December 2017
84,836
Additions
7,479
Sales from test production
(10,747)
Foreign exchange difference
(13,082)
Cost at 31 December 2018
68,486
ACCUMULATED IMPAIRMENT
Group
US$'000
Accumulated impairment at 1 January 2017
15,137
Foreign exchange difference
(2)
Accumulated impairment at 31 December 2017
15,135
Foreign exchange difference
(2,334)
Accumulated impairment at 31 December 2018
12,801
Net book value at 1 January 2017
68,086
Net book value at 31 December 2017
69,701
Net book value at 31 December 2018
55,685
Unproven oil and gas assets represent license acquisition costs and subsequent exploration expenditure in respect of two licenses held by Kazakh group entities. The carrying values of those assets at 31 December 2018 were as follows: Beibars Munai LLP US$ nil (2017: US$ nil) and BNG Ltd LLP US$55,685,000 (2017: US$69,701,000).
The Directors have carried out an impairment review of these assets on a cost pool level as detailed in note 2.1. No impairment indicators were identified for BNG Ltd LLP.
As a result of military training activities, the Group currently cannot access the Beibars license area which resulted in a force-majeure situation and the Group is in the process of relinquishing its interest in the asset and handing it back to the Kazakh authorities. Due to this ongoing position the carrying value remains fully impaired.
12 Property, plant and equipment
Following the commencement of commercial production in December 2012 the Group reclassified its Munaily assets from unproven oil and gas assets to proven oil and gas assets. The assets were impaired in 2013. During 2018 the Group has disposed it Munaily assets (note 21).
Group
Proved
Motor
Other
Total
oil and gas assets
Vehicles
US$'000
US$'000
US$'000
US$'000
Cost at 1 January 2017
47
153
328
528
Additions
-
-
5
5
Disposals
-
-
(21)
(21)
Foreign exchange difference
-
-
1
1
Cost at 31 December 2017
47
153
313
513
Additions
-
-
3
3
Disposals
(47)
(85)
(8)
(140)
Foreign exchange difference
-
(12)
(42)
(54)
Cost at 31 December 2018
-
56
266
322
Depreciation at 1 January 2017
47
67
191
305
Charge for the year
-
13
30
43
Foreign exchange difference
-
-
-
-
Depreciation at 31 December 2017
47
80
221
348
Charge for the year
-
9
22
31
Disposals
(47)
(51)
(8)
(106)
Foreign exchange difference
-
(6)
(32)
(38)
Depreciation at 31 December 2018
-
32
203
235
Net book value at:
01 January 2017
-
86
137
223
31 December 2017
-
73
92
165
31 December 2018
-
24
63
87
13 Investments (Company)
Investments
Company
US$'000
Cost
At 1 January 2017
190,595
Acquisition of Eragon non-controlling interest (note 27)
85,179
Receipts
(398)
Payments
535
At 31 December 2017
275,911
Receipts
534
Payments
(206)
At 31 December 2018
276,239
Impairment
At 1 January 2017
64,253
Impairment
-
At 31 December 2017
64,253
Impairment
-
At 31 December 2018
64,253
Net book value at:
31 December 2017
211,658
31 December 2018
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
Registered address
Nature
of business
Eragon Petroleum Limited
United Kingdom
100%
100%
5 New Street Square
London
EC4A 3TWHolding Company
Eragon Petroleum FZE
Dubai
100%
100%
CN-135789, Jebel Ali, Dubai, UAE
Management Company
Beibars BV
Netherlands
100%
100%
Utrechtseweg 79
1213 TM Hilversum
The Netherlands
Holding Company
Ravninnoe BV
Netherlands
100%
100%
Utrechtseweg 79
1213 TM Hilversum
The NetherlandsHolding Company
Roxi Petroleum Kazakhstan LLP
Kazakhstan
100%
100%
152/140 Karasay Batyr Str., Almaty, Kazakhstan
Management Company
13 Investments
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%
Utrechtseweg 79
1213 TM Hilversum
The NetherlandsHolding Company
BNG Energy BV
Netherlands
100%
100%
Utrechtseweg 79
1213 TM Hilversum
The NetherlandsHolding Company
BNG Ltd LLP
Kazakhstan
99%
99%
152/140 Karasay Batyr Str., Almaty, Kazakhstan
Exploration Company
Munaily Kazakhstan LLP
Kazakhstan
0%
99%
152/140 Karasay Batyr Str., Almaty, Kazakhstan
Oil Production Company
During 2018 the Group sold its share in Munaily Kazakhstan LLP for $134,000 (note 21).
Indirect investments held by Beibars BV
Name of undertaking
Country of incorporation
Effective
holding and
proportion
of voting
rights held
at 31 December 2018
Effective holding and
proportion
of voting
rights held
at 31 December
2017
Registered address
Nature
of business
Beibars Munai LLP
Kazakhstan
50%
50%
152/140 Karasay Batyr Str., Almaty, Kazakhstan
Exploration Company
Beibars Munai LLP is a subsidiary as the Group is considered to have control over the financial and operating policies of this entity. Its results have been consolidated within the Group.
14 Inventories
Group
Group
2018
2017
US$'000
US$'000
Materials and supplies
132
21
132
21
15 Other receivables
Group
Group
Company
Company
2018
2017
2018
2017
US$ '000
US$ '000
US$ '000
US$'000
Amounts falling due after one year:
Prepayments made
5,516
5,799
54
98
VAT receivable
2,929
3,456
-
-
Intercompany receivables
-
-
3,012
2,846
8,445
9,255
3,066
2,944
Amounts falling due within one year:
Prepayments made
119
227
6
5
Other receivables
245
605
-
-
364
832
6
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$34.2 million). The movement in the expected credit loss provision related to the inter-company receivables was as follows:
Group
Group
Company
Company
2018
2017
2018
2017
Denomination
US$'000
US$'000
US$'000
US$'000
As at 1 January
-
-
34,232
33,310
Charge
-
-
286
922
Write-off*
-
-
(22,306)
-
As at 31 December
-
-
12,212
34,232
*During 2018 the Company wrote off its fully impaired Munaily receivables following the sale of Munaily (note 21) and wroteoff of its fully impaired Roxi Petroleum Kazakhstan receivables.
The Company recognised US$ 286 thousand of expected credit loss provisions in relation to it receivables from subsidiaries in 2018 (2017: US$ 922 thousand).
16 Cash and cash equivalents
Group
Group
Company
Company
2018
2017
2018
2017
US$'000
US$'000
US$'000
US$'000
Cash at bank and in hand
557
1,479
292
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.
Group
Group
Company
Company
2018
2017
2018
2017
Denomination
US$'000
US$'000
US$'000
US$'000
US Dollar
448
1,221
232
11
Sterling
60
6
60
6
Kazakh Tenge
49
252
-
-
557
1,479
292
17
17 Called up share capital
Group and Company
Number
of ordinary
shares
US$'000
Number
of deferred
shares
US$'000
Balance at 1 January 2017
937,433,077
16,000
373,317,105
64,702
Acquisition of Eragon non-controlling interest (note 27)
651,436,544
8,364
-
-
Debts converted to equity
80,804,199
1,037
-
-
Balance at 31 December 2017
1,669,673,820
25,401
373,317,105
64,702
Share options exercised
1,200,000
15
-
-
Balance at 31 December 2018
1,670,873,820
25,416
373,317,105
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
Group
Group
Company
Company
2018
2017
2018
2017
US$'000
US$'000
US$'000
US$'000
Trade payables
861
1,220
221
380
Taxation and social security
180
175
21
38
Accruals
197
225
165
195
Other payables
2,235
2,120
413
318
Intercompany payables
-
-
8,232
7,695
Advances received (deferred revenue)
2,786
5,798
-
-
6,259
9,538
9,052
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 $3.4m).
Other payables relate to the original purchase of Munaily oil field.
18 Trade and other payables - non-current
Group
Group
Company
Company
2018
2017
2018
2017
US$'000
US$'000
US$'000
US$'000
Intercompany payables
-
-
16,735
16,058
Taxation and social security
10,286
10,958
-
-
10,286
10,958
16,735
16,058
Taxation and social security payable relate to withholding tax accrued on the interest expense at the BNG subsidiary level.
19 Short-term borrowings
Group
Group
Company
Company
2018
2017
2018
2017
US$'000
US$'000
US$'000
US$'000
Prosperity/Mr Oraziman (a)
913
1,196
-
-
Fosco BV (b)
650
639
-
-
Other borrowings (c)
1,009
297
400
-
2,572
2,132
400
-
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$297,000) was payable to Kuat Oraziman and a legal entity controlled by Mr Oraziman, KC Caspian Explorer. Loans are interest free and repayable on demand.
20 Provisions
Group only
Employee holiday provision
Liabilities under Social Development Program and historical cost
Abandonment fund
2017
Total
US$'000
US$'000
US$'000
US$'000
Balance at 1 January 2017
68
4,150
153
4,371
Increase in provision
25
700
39
764
Paid in the year
-
(19)
(6)
(25)
Unwinding of discount
-
-
2
2
Foreign exchange difference
-
2
6
8
Balance at 31 December 2017
93
4,833
194
5,120
Non-current provisions
-
527
194
721
Current provisions
93
4,306
-
4,399
Balance at 31 December 2017
93
4,833
194
5,120
Group only
Employee holiday provision
Liabilities under Social Development Program and historical cost
Abandonment fund
2018
Total
US$'000
US$'000
US$'000
US$'000
Balance at 1 January 2018
93
4,833
194
5,120
Increase in provision
2
-
9
11
Sale of Munaily (note 21)
(8)
(795)
(49)
(852)
Paid in the year
-
(318)
(18)
(336)
Unwinding of discount
-
-
11
11
Foreign exchange difference
(12)
(280)
(22)
(314)
Balance at 31 December 2018
75
3,440
125
3,640
Non-current provisions
-
-
125
125
Current provisions
75
3,440
-
3,515
Balance at 31 December 2018
75
3,440
125
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.
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.
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:
At date of disposal
$'000
Total consideration
134
Non-current assets
(58)
Trade and other receivables
(14)
Trade and other payables
350
Non-current liabilities
2,882
Net liabilities at date of disposal
3,160
Less: minority share
136
Gain on disposal before the effect of cumulative translation reserve
3,158
Less: Release of cumulative translation reserve
8,305
Loss on disposal
5,147
The net cash inflow on disposal comprises:
Cash received
134
Cash disposed of
-
Net cash inflow
134
Munaily Kazakhstan LLP had the following results during 2018 and 2017:
2018
2017
US$'000
US$'000
Revenue
-
16
Expenses
(334)
(614)
Loss before taxation
(334)
(598)
Cash movements related to Munaily were negligible.
22 Deferred tax
Deferred tax liabilities comprise:
Group
2018
Group
2017
US$'000
US$'000
Deferred tax on exploration and evaluation assets acquired
6,733
7,784
6,733
7,784
The Group recognises deferred taxation on fair value uplifts to its oil and gas projects arising on acquisition. These liabilities reverse as the fair value uplifts are depleted or impaired.
The movement on deferred tax liabilities was as follows:
Group
2017
Group
2017
US$'000
US$'000
At beginning of the year
7,784
7,748
Foreign exchange
(1,051)
36
6,733
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.
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.
Number of options granted
Number of options expired
Options exercised
Total options outstanding
Weighted average exercise price in pence (p) per share
As at 31 December 2017
88,458,226
(45,566,215)
(9,900,000)
32,992,011
17
Directors
-
(2,404,615)
(1,200,000)
(3,604,615)
-
Employees and others
-
(6,840,000)
-
(6,840,000)
-
As at 31 December 2018
88,458,226
(54,810,830)
(11,100,000)
22,547,396
13
The options were issued to Directors and employees as follows:
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$1,779 thousand. During 2017 the warrants expired therefore the Company reclassified the amount to Retained deficit.
25 Financial instrument risk exposure and management
In common with all other businesses, the Group and Company are exposed to risks that arise from its use of financial instruments. This note describes the Group and Company's objectives, policies and processes for managing those risks and the methods used to measure them. Further quantitative information in respect of these risks is presented throughout these financial statements.
The significant accounting policies regarding financial instruments are disclosed in note 1.
There have been no substantive changes in the Group or Company's exposure to financial instrument risks, its objectives, policies and processes for managing those risks or the methods used to measure them from previous years unless otherwise stated in this note.
Principal financial instruments
The principle financial instruments used by the Group and Company, from which financial instrument risk arises, are as follows:
Financial assets
Group
2018
US$'000
Group
2017
US$'000
Company
2018
US$'000
Company
2017
US$'000
Intercompany receivables
-
-
3,012
2,846
Other receivables
245
605
-
Restricted use cash
250
263
-
-
Cash and cash equivalents
557
1,479
292
17
1,052
2,347
3,304
2,863
Financial liabilities
Group
2018
US$'000
Group
2017
US$'000
Company
2018
US$'000
Company
2017
US$'000
Trade and other payables
3,293
3,565
799
893
Other payables - current
-
-
8,232
7,695
Other payables - non-current
-
-
16,735
16,058
Borrowings - current
2,572
2,132
400
-
5,865
5,697
26,166
24,646
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
2018Loans 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
2017Loans 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
2018Loans received
Interest accrued
Disposal of loans
Repayment
Foreig exchange difference, net
31 December 2018
Financial liabilities
Borrowings
-
400
-
-
-
-
400
1 January
2017Loans received
Interest accrued
Conversion to equity
Repayment
Foreig exchange difference, net
31 December 2017
Financial liabilities
Borrowings
9,935
-
165
(10,100)
-
-
-
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.
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:
On Demand
Less than 3 months
3-12 months
1- 5 years
Over 5 years
Total
Group 2018 US$'000
2,572
710
2,583
-
-
5,865
Group 2017 US$'000
936
911
3,850
-
-
5,697
Company 2018 US$'000
8,632
210
589
23,617
33,048
Company 2017 US$'000
7,695
359
534
-
23,617
32,205
Interest rate risk
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).
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$6.6 million. The difference between the purchase consideration and net assets was charged directly to the consolidated statement of changes in equity as the transaction represented the acquisition of a non-controlling interest.
US$'000
Carrying amount of NCI acquired
6,571
Consideration paid to NCI
88,432
A decrease in equity attributable to owners of the Company
(81,861)
28 Non-controlling interest
Group
2018
Group
2017
US$'000
US$'000
Balance at the beginning of the year
(4,654)
2,617
Share of loss for the year
(167)
(766)
Exchange differences on translating foreign operations and recycling on disposal
(920)
66
Purchase of non-controlling interest in subsidiary (note 27)
-
(6,571)
Disposal of Munaily (note 21)
136
-
(5,605)
(4,654)
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).
Notes to the Financial Statements
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.
[1] All Directors of Caspian Sunrise PLC not members of the Oraziman family or others deemed under the AIM Rules to be non-independent
[2] A commercial rate no better than a rate payable to an independent third-party contractor
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