REG - Caspian Sunrise plc - Annual Report and Financial Statements
Caspian Sunrise PLC
("Caspian Sunrise" or the "Company")
Annual Report and Financial Statements for the Year Ended 31 December 2019
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 2019.
Highlights for the year:
Operational:
• Operational (wells drilled at end of year) 2019: 17 (2018: 17)
• Aggregate production for 2019 was 506,620 barrels (2018: 589,750) a decline of 14.1 per cent.
• Reserves at 31 December 2019 P1 17.8 mmbls & P2 28.8 mmbls (2018: P1 17.8mmbls & P2 28.8) mmbls
Financial:
• Revenue: $12.1 million (2018: $10.7 million)
• Loss for the year $1.4 million (2018: $8.5 million)
• Cash at bank: $4.1 million (2018: $0.6 million)
• Total assets: $127.5 million (2018: $65.5 million)
• CAPEX expenditures:
o Exploration assets $61.8 million (2018: $55.7 million)
o Plant, property & equipment $48.9 million (2018: $ nil)
As at 31 May 2020 production was at the rate of 1,700 bopd, with a production capacity of 2,000 bopd.
The Report and Accounts and Notice of Annual General Meeting will shortly be posted to shareholders and available from the Company's website at https://www.caspiansunrise.com/investors/reports.
Caspian Sunrise PLC
Clive Carver
Executive Chairman
+7 727 375 0202
WH Ireland, Nominated Adviser & Broker
James Joyce
James Sinclair-Ford
+44 (0) 207 220 1666
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
In the past twelve months we have taken several large steps forward towards our goal of becoming a leading, profitable oil and gas exploration and production group focused on Kazakhstan. Operationally we are now significantly better placed in our quest to deliver real value to our shareholders over the medium / longer term. However, in the short term we are focused on surviving the impact of the Covid-19 virus.
Our principal weapon in this fight will be the revenues from be our MJF production. Since the year end Wells 150 & 153 have entered production increasing the production capacity from the BNG Contract Area to approximately 2,000 bopd, the majority of which may be sold by reference to international rather than domestic prices.
Our focus until the full impact of Covid-19 virus becomes clearer will be to continue to conserve cash to better preserve the medium / longer term value for shareholders. Further details on the Group's funding position is set out later in this statement.
The contents of the remainder of the statement are presented as follows:
· Significant events in the period under review and subsequently
· Our assets
· Finance & administration
· The investment case
· Outlook
There are separate sections on Kazakhstan and Risk Factors elsewhere in this Annual Report.
Significant events in the period under review
3A Best
In January 2019, we announced the completion of the acquisition of 100% of the 3A Best Group JSC, a Kazakh corporation owning an existing Contract Area of some 1,347 sq. km located near the Caspian port city of Aktau, for a consideration of $24 million payable by the issue of 149,253,732 Caspian Sunrise shares issued at a price of 12p per share.
The Contract Area, which has been designated by the Kazakh authorities as a strategic national asset, surrounds and goes below the established shallow field at Dunga, currently owned by Total, which we believe to be producing at the rate of approximately 15,000 bopd.
In February 2020, we announced amendments to the work programme inherited with the acquisition, whereby we are obliged to drill only one well to a depth of 2,500 meters at an expected cost of $2 million. Our approach with 3A Best is to develop the field but also to recognise its potential M&A value given its proximity to the successful Dunga field.
Further details of the 3A Best Contract Area are set out later in this report.
Non-executive director
Also in January 2019, we announced the appointment of Tim Field as an independent non-executive director.
Tim is a highly experienced international corporate lawyer specialising in securities law and corporate governance and is the principal of the specialist corporate and securities law firm "Field". He is also the equity capital markets consultant to the law firm Mishcon de Reya, where until recently he led its public company practice. He has a long and significant track record of advising AIM companies and Nominated Advisers. His input into the oversight of the Company and its future direction is much valued.
Further details are set out in the Corporate Governance Report.
MJF licence upgrade
In July 2019, we announced the long awaited upgrade to the MJF licence.
Under Kazakh regulations oil produced during the appraisal phase of a licence may be sold but only at domestic prices. An upgrade to a full production licence is required to be able to sell the majority of the oil produced by reference to international prices.
Separate changes to the oil laws in Kazakhstan resulted in much longer delays than expected when we submitted our licence upgrade application to split the licence and move the MJF structure to a 25 year full production licence with the remainder of the BNG Contract Area remaining under the appraisal rules.
The principal benefit from the licence upgrade is that the net price at which production from the MJF structure may be sold, was broadly double the domestic price previously received.
Following receipt of the licence upgrade we embarked on an up to 18 well infill drilling programme, which after the first two New Wells 150 and 153, and the spudding of New Well 151, was temporarily suspended until the impact of the Covid-19 virus became clearer. Drilling at New Well 151 has now resumed.
Further details of our all our assets and licences are set out later in this report.
Purchase of equipment
In September 2019, we announced the purchase of drilling equipment for a consideration of $7 million, payable by the issue of 58,333,333 shares at an issue price of 10p per share.
With the contraction of medium and smaller scale drilling activities in Kazakhstan and the consequential retreat of the larger equipment and services providers, our operations have on many occasions suffered delays waiting for the required equipment to be delivered to site. The lack of activity also reduced the equipment's effective resale value, thereby reducing its acquisition cost to a point where we concluded it was better to own and control certain key operational equipment rather than to continue to rent. We therefore decided to acquire a portfolio of assets comprising, four drilling rigs, two cranes, pumps, generators, a blow-out preventor and 12 vehicles, including trucks, crew buses and pickup trucks.
The largest of the rigs acquired is a 350 tonne G50 rig, with the capacity to drill to a depth of up to 5,000, meters. Two further drilling rigs are 225 tonne G40 rigs, each being able to drill to depths of up to 4,000 meters. The fourth is a workover rig of 80 tonnes, with a capacity to drill up to 1,500 meters and perform general workover tasks to a depth of 2,500 meters. The cranes are used in the assembly and dis-assembly of the rigs with one able to lift up to 50 tonnes and the other up to 25 tonnes.
The effect of the acquisition has been to provide greater certainty in the timing of our drilling operations, particularly with the MJF infill programme, together with a reduction in our development costs.
Deep Well break through
In early January 2020, we announced that Deep Well A5 had flowed without interruption or artificial stimulation for four days. Our priority at that time was to maintain the flow rather than to maximise production volumes. Accordingly, we quickly switched to smaller choke sizes than the 12 mm used when the well started to flow, or the 19 mm we used when the well flowed at the rate of 3,800 bopd in 2017.
This allowed the well to continue to flow without interruption for 40 days in total, albeit at rates much lower than expected from a deep high pressure well. In February 2020, the well was closed to clear excess drilling fluid, which was restricting production levels and limiting reserves estimates.
Our G50 rig is now in position to replace a broken link in the tubing before we attempt to re-commence production at rates more expected of a deep well.
Further details of the performance of each of the deep wells drilled at our BNG Contract Area are set out later in this report.
Caspian Explorer
Also in January 2020, we announced the proposed acquisition of the Caspian Explorer for a consideration of $25 million to be satisfied by the issue of 160,256,410 shares at an issue price of 12p per share. On 13 February 2020, we announced the acquisition had been approved by shareholders at a General Meeting. Completion of the acquisition remains subject to a number of regulatory consents and filings in Kazakhstan and the UAE.
In parts of the northern Caspian Sea, where the Group's management believe there are attractive oil producing prospects, the water levels are extremely shallow and prospects cannot be explored with traditional deep water rigs.
The principal ways of exploring these properties are either from a land base or by the use of a specialist shallow drilling vessel. Land based options typically involve either the creation of man-made islands from which to drill as if onshore or less commonly drilling out from an onshore location. Both are expensive compared to the use of a specialist drilling platform.
The acquisition of the Caspian Explorer will mark the Group's first step into off-shore exploration, which is typically more expensive and complicated than on-shore exploration.
Further details of our plans for the Caspian Explorer are set out later in this report.
Response to the Covid-19 virus
In March 2020, we announced that in response to the impact of the Covid-19 virus, and in particular the sharp fall in world oil prices, we would suspend all new drilling activities following the completion of planned work at New Wells 150 & 153 and Deep Wells A6, 801 & A8.
The BNG oilfields are typically staffed with two sets of workers or "crews" each working on a two 12 hours shift basis two weeks on and two weeks off. In recognition of the risks of contamination at the time of a crew changeover the decision was taken that there would be no crew changeover and that the crew then operating would stay in place for a longer period. To maximise the benefit of their limited time in the field we decided to focus on projects capable of quick success being principally the planned acid treatments at Deep Wells A6, 801 & A8, which do not require rig movements.
However, border and road closures delayed the specialist acid reaching BNG. We therefore mobilised one of the G40 rigs acquired in 2019 to spud New Well 151, the third of infill wells on the MJF structure and mobilised our G50 rig, previously in use at New Well 153, to continue the work at Deep Well A5.
In a series of announcements from March 2020, we updated the market with news of action taken to conserve cash, including reducing staff numbers in the field and in our administrative offices in Almaty together with deferrals of salary for all but field workers. In early May 2020, we announced that following further deferrals the aggregate cash costs of the board had fallen to 25% of the aggregate entitlement and that we had secured additional financial support from local oil traders.
New Wells 150 & 153 and 151
At the end of March 2020, we announced the success of New Well 150, the first of the planned infill on the MJF structure. Towards the end of April we announced the success of New Well 153, the second planned infill well on the MJF structure.
In early May 2020, we announced that New Well 151 had been spudded and drilled to a depth of 12 meters but that further drilling would be dictated by the overall funding position. Since that announcement additional local funding has been sourced to continue frilling New Well 151 and following that New Well 152.
Our Assets
BNG Contract Area
The Group'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 Limited. In 2017, we increased our stake to 99% upon the completion of the merger with Baverstock GmbH.
Since 2008, approximately $100 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.
Shallow structures
There are two confirmed and producing shallow structures at BNG with the possibility of a third.
MJF structure
In 2013, we announced the discovery of the MJF structure and have subsequently drilled 8 wells of which 7 are currently producing with an aggregate capacity of approximately 1,700 bopd.
The productive Jurassic aged 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 now approximately 13km2. The producing wells range in depth from 2,192 meters to 2,450 meters.
In December 2018, we formally applied to move the MJF structure, which was 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 may be sold by reference to world rather than domestic Kazakh prices.
A condition of the licence upgrade is that an amount assessed by the regulatory authorities on award of the production licence becomes liable to be repaid quarterly over a 10 year period. We are challenging the amount assessed on the basis that first it has been incorrectly calculated and second that despite the MJF structure accounting for approximately only 1% of the BNG Contract Area it has been assessed to repay an amount equivalent to 100% what would be due for the BNG Contract Area as a whole if under a production licence. On the basis of advice received we believe the basis of the payments due will be reassessed in accordance with our own calculations.
The MJF structure licence was upgraded in July 2019, and the first oil sold by reference to international rather than domestic prices in August 2019. Following the licence upgrade we have embarked on an infill drilling programme with the intention of extending the number of wells to up to 24 wells.
A third infill well, New Well 151, has been spudded and is to be drilled to a planned Total Depth of 2,500 meters. Assuming no unforeseen issues we expect this well to start to produce in Q3 2020. Funding has also been sourced to drill a fourth infill well, New Well 152 following the completion of New Well 151. Drilling at New Well 151 has now resumed.
As noted elsewhere in these financial statements the pace at which we undertake this infill drilling programme is dependent on funding and the international oil price.
We are started to workover existing wells at the MJF structure, with a view to improving production.
South Yelemes
This structure is the subject of an ongoing licence upgrade application for a separate 25 year production licence. Until the application is approved we are unable produce from the four existing wells on the structure.
The first wells were drilled on the South Yelemes structure during the Soviet era.
Well 54 was 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). The production from South Yelemes was in aggregate approximately 300 bopd. These older wells are the only wells on the BNG Contract Area which use artificial lift to assist the oil to flow to the surface.
We believe the structure 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.
As with the MJF structure, once the South Yelemes structure is moved onto a full production licence we will be able to sell the majority of oil produced by reference to world rather than domestic prices.
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. Re-evaluation of the wireline and mudlog data suggests additional untested potential within two intervals shallower in the well.
While not a prime focus we did test further in the period under review without yet finding a commercial interval.
Deep structures
We have identified two deep structures at the BNG Contract Area. The first is the Airshagyl structure and the second is the Yelemes Deep structure.
Deep wells of the type drilled to date at BNG are typically drilled by much larger companies and at much greater cost.
A common feature of the two discovered deep structures at BNG are the extremely high temperature and pressure that exist below the salt layer. At the Airshagyl structure the salt layer is typically found at depths between 3,700 -4,000 meters where at the Yelemes Deep structure the salt layer is typically found at depths between 3,000 - 3,500 meters.
The extreme pressure below the salt layer requires the use of high density drilling fluid to maintain control of the well during drilling. The high density drilling fluid's principal role is to help prevent dangerous blow-outs.
The attributes of the high density drilling fluid, which allow the wells to be controlled during the drilling phase, act against us when we attempt to clear the well for production. To the extent that drilling fluids, which include solid particles added to increase density, are not fully recovered they can form a barrier in the well or in the reservoir preventing or restricting the oil flow.
Other problem areas encountered in bringing these deep wells into production have related to drilling through the salt layer, often in excess of 100 meters thick; cementing the casing below the salt layer; and with the perforation the wells, where the presence of extreme pressure requires a much greater explosive force.
Competent third party experience has been difficult to find, as the exceptional temperature and pressure are unusual for many international consultancies more used to conventional shallower exploration. We have however, developed our drilling techniques and now use drilling fluids with lower density, which we have found easier to remove once drilling has been completed. Deep Wells A6 & A8, the third and fourth deep wells drilled, encountered fewer problems during the drilling phase than the earlier wells.
Our focus remains bringing into production all the deep wells drilled to date.
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.
As noted above the well was difficult to drill with a salt layer of approximately 130 meters with high temperature and high pressure encountered 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 sufficiently to allow an extended flow test.
In December 2017, using a choke setting of 19 mm, the well tested for 15 days at an average rate of 3,800 bopd before the flow reduced by debris in the well fell to 1,000 bopd leading to the well test being suspended.
Following two ultimately unsuccessful side-tracks a third side-track from a depth of 3,976 meters was completed in November 2019. On 31 December 2019, the well started to flow initially at a rate of 1,500 bopd using a 12 mm choke,
Given our experiences in 2017, our priority was to keep the well flowing by maintaining a good level of pressure. This required the choke setting to be reduced to just a few mm, which in turn quickly reduced the flow of oil. The unrecovered drilling fluid used in the original well and each of the three side-tracks further restricted the flow of oil from the well.
Accordingly, in February 2019, after 40 days of unassisted oil flows, the well was closed to allow work to remove excess drilling fluid which was restricting the flow rates and therefore any calculation of reserves. To date some 30 tonnes of excess drilling fluid has been removed using coil tubing equipment.
Our G50 rig is now on site to replace a cracked link in the tubing, following which we will once again attempt to get the well to flow at rates expected of a deep, high pressure well.
Deep Well A6
The second well drilled on the Airshagyl structure was Deep Well A6, which was spudded in 2015 and drilled to a depth of 4,528 meters.
Repeated problems in perforating the well prevented it being put on test. Additionally, work at Deep Wells A5 and 801 took precedence while we were operating with only two rigs and crews.
Plans to undertake an acid treatment at Deep Well A6 have been delayed waiting for the required acid to be delivered to the BNG Contract Area.
Deep Well A8
In November 2018, Deep Well A8 was spudded with a planned Total Depth of 5,300 meters, initially targeting the same pre-salt carbonates that were successfully identified in the Deep Well A5 at depths of 4,342 meters but with a prime target being the deeper carbonate of the Devonian to Mississippian ages towards the planned Total Depth of 5,300 meters.
We identified intervals of interest at depths of 4,342 meters. We then had to decide whether to seek to produce from the intervals identified or whether to continue to the original Total Depth of 5,300 meters. The arguments in favour of seeking to produce from the higher interval were short term commercial considerations of expected significant immediate income. The arguments for continuing to the original Total Depth were based on the far greater potential from intervals in the Devonian.
While we favour pressing on to the original Total Depth of 5,300 meters a final decision is yet to be taken. As with Deep Well A6 above the planned acid treatment at Deep Well A8 has been delayed.
Deep Well A9
The next deep well on the Airshagyl structure will be Deep Well A9, which, if successful, would extend the perimeter of the Airshagyl structure. The well has a planned Total Depth of 5,300 meters and will target the same Jurassic prospects as A5 & A6.
Our intention was to spud Deep Well A9 in the first half of 2020. However, we have delayed drilling the well pending greater certainty on the lasting impact of the Covid-19 virus.
Summary
Based on results to date we continue to believe the Airshagyl structure will provide the greatest quantities of oil at the BNG Contract Area.
Each of the three Deep Wells drilled on the structure has the potential to flow commercially
Should two or more of the deep wells flow consistently we expect that the Airshagyl structure will be the first deep structure for which we apply to move to a full production licence.
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 deep 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
As with the deep wells drilled on the Airshagyl structure the blockages in the well preventing an extended flow test are the result of high temperatures/ pressures and excess drilling fluids. We have used a variety of techniques including the use of chemicals and the drilling of a side-track, to establish good reservoir connectivity.
As at Deep Wells A6 & A8 on the Airshagyl structure our plans to use an acid treatment on Deep Well 801 have been delayed.
BNG Infrastructure requirements
We have limited treatment facilities on site and storage of approximately only 7,000 bbls, which represents less than one weeks production. Our production is transported using a fleet of heated tankers, however as production levels from the MJF structure increase and when production commences from the deep wells already drilled it will not be practical to rely on these present arrangements.
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.
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. The 3A Best Contract Area has been designated a national strategic asset by the Kazakh regulatory authorities.
Whilst the Group has acquired the equity of 3ABest Group JSC, the acquisition has been 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 issue 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 $11.8 million.
Based on an assessment of the geology we believe some of the 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. Neither was commercially successful.
The current 3A Best licence runs until June 2020. We are in the final stages of discussions with the Kazakh authorities regarding an extension of the 3A Best licence, which we expect will entail a new set of work programme obligations.
Caspian Explorer
Introduction
To date we have focused on exclusively on onshore exploration and production. To continue with this approach would exclude us from the very significant potential we see in the Northern Caspian Sea.
We decided to acquire the Caspian Explorer for two reasons. The first as a means to become involved in offshore development, which for a Group of our size would otherwise be difficult. The second as a conventional source of income when rented to other explorers.
Offshore exploration is traditionally much more expensive than on shore exploration. Projects therefore tend to go to the larger operators or more commonly to specially formed consortia of such companies.
We believe the Caspian Explorer is the only drilling vessel of its type capable of drilling exploration wells to depths of 6,000 meters in water as shallow as 2.5 meters currently ready to operate in the Caspian Sea. Further, given the lead times and construction costs, we do not expect a new competing drilling vessel to enter the market in the next few years.
Once acquired we will seek to rent out the Caspian Explorer for both an immediate economic return, in the form of rental payments, but also where appropriate seek a position in the development consortia.
Completion of the acquisition of the Caspian Explorer remains subject to regulatory approvals in Kazakhstan and the UAE.
Background
The Caspian Explorer was conceived of by a consortium of leading Korean companies including KNOC, Samsung and Daewoo Shipbuilding. The vessel was assembled in the Ersay shipyard in Kazakhstan between 2010 and 2011 for a construction cost believed to be approximately $170 million. The total costs after fit-out are believed to have been approximately $200 million.
The Caspian Explorer became operational in 2012 at a time of relatively low oil prices and reduced exploration activity in the Northern Caspian Sea. In 2017, the Korean consortium decided to sell the Caspian Explorer by way of a competitive tender with the buyer being KC Caspian Explorer LLP.
The Caspian Explorer typically operates between May and November as the Northern Caspian Sea is subject to ice in the winter months, with a crew of 20 and room to accommodate up to 100.
Commercial potential
We believe there to be two principal drivers for the further exploration of the Northern Caspian Sea. The first is continued development of existing projects and the second is following any awards of new blocks.
Although a big ticket item by our standards spending $25 - $30 million a year hiring a drilling platform such as the Caspian Explorer is a modest sum for companies often measuring their annual investment in $ billions.
By way of example, in 2017, the Caspian Explorer was hired out to a KazMunaiGas / Indian state oil company joint venture for $28 million after costs and drilled one exploration well to a depth of 3.5 km and in 2018, the Caspian Explorer was hired out KazMunaiGas for up to $24 million drilling one exploration well to a depth of 1.8 km.
The impact on the Group of a contract at these levels even once every three years would be dramatic. In any year when the Caspian Explorer is contracted it could fund the majority of the rest of the Group's annual drilling programme.
The Caspian Explorer did not operate in 2019 and has no contracts in place for 2020. Following completion our financial exposure in the event of no external contracts are costs of approximately $100,000 per month while the Caspian Explorer is in port.
Licences & Work Programmes
BNG
BNG LLP Ltd holds two contracts for a subsoil use. The first is the exploration contract, covering the full extent of the BNG Contract Area (except the MJF structure), originally issued in 2007 and successively extended until 2024. The second is the export contract covering just the MJF structure which runs to 2043 and under which the majority of oil produced may be sold by reference to international rather than domestic prices.
Our 2020 MJF work programme obligation to drill seven obligations has been reduced to two wells, which are already completed and producing.
We have also submitted an application to move the South Yelemes shallow structure to an export licence and look forward to receiving the regulators consent in the due course.
There are no 2020 work programme obligations at the Airshagyl structure.
At the Yelemes Deep structure the existing work programme commitments require us to drill a further deep well, Deep Well 802, by the end of 2020 and to test it in 2021. In light of the impact of the Covid-19 virus we have applied to the Kazakh regulatory authorities to defer that commitment and await their response.
3A Best
The licence is due for renewal in June 2020 and an application has been made for the licence's renewal and an early response is expected. Under our current 2020 work programme commitments we are obliged to drill only one well to a depth of 2,500 meters at an expected cost of $2 million. However, given the Covid-19 virus and the measures taken by the Kazakh authorities to mitigates its impact, we do not expect to be held to this obligation.
Reserves
BNG
In 2011 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 GCA assessed the reserves attributable to the BNG shallow structures.
Between then and the end of 2019, approximately 2 mmbls of oil were produced, which under financial reporting rules are deducted from the assessment of reserves as at 31 December 2019.
As at 31 December 2019
As at 31 December 2018
mmbls
mmbls
BNG
Shallow P1
16.1
17.8
Shallow P2
27.8
28.8
Deep P1
Nil
Deep P2
Nil
The above is based on 100% of each Contract Area.
3A Best
There has been no assessment of the reserve base at the 3A Best Contract Area.
Financial review
Review of the results to 31 December 2019
Revenue
Revenue in 2019 increased by 13 per cent compared to 2018, despite production volumes declining by 9 per cent.
We benefited for the final four months of the year by selling the majority of the oil produced by reference to international rather than domestic prices.
Production volumes in 2019, were 506,620 barrels compared to 589,750 barrels in 2018. This was the result of choosing to run the first five producing wells at the MJF structure at or near maximum capacity to generate income to fund the business without the customary shut-in's for routine maintenance. Accordingly, we experienced a higher level of depletion during the period under review than would have been the case with periodic workovers.
Gross profit
For the first time we report a gross profit of $5.1 million (2018: nil) This follows different accounting rules for oil sold under production licences rather than under appraisal licences.
The method of accounting for production sold under an exploration phase of an appraisal licence differs from the sale of oil under a full production licence in which commercial production is considered to have been reached.
Under an appraisal licence revenues are treated as a contribution to the costs associated with the main objective, which is to ascertain the productive capabilities of the producing wells concerned. Therefore, whilst revenue is recorded as an amount equivalent to the margin amounts derived from the sale of oil are charged to cost of sale and recorded as a reduction in the appraisal assets resulting in a zero gross profit.
Under a production licence only the actual costs of production are recorded as costs of sales so that any excess of receipts over direct costs is shown as gross profit.
Selling expenses of $2.2 million (2018: nil) relate to export and customs duties.
A reversal of impairment of $2.4 million (2018: nil) has been recorded, representing the portion of the historic impairment provision of c$12 million that relates to the MJF structure that has now commenced commercial production which enables it to realise significant economic value.
Other administrative expenses
Other administrative costs at $3.9 million (2018: $2.6 million) were $1.3 million greater reflecting the increased operational and corporate activity. We believe we remain a low cost operator, in comparison to other listed companies and companies operating in Kazakhstan.
Tax charge
The tax charge for 2019 at approximately $2.3 million (2018: $0.6 million) includes a provision of $1.9 million for withholding tax on inter group interest.
Oil and gas assets
The carrying value of unproven oil and gas assets in these consolidated group accounts increased from $55.7 million to $60.0 million. The increase represented the combination of the acquisition of the 3A Best exploration assets for $12.6 million and drilling and other capitalised costs of $8.9 million; before deductions in respect of sales from test production $5.5 million and transfers of the MJF assets to proven oil and gas assets within property, plant and equipment of $12.0 million.
Plant, property and equipment increased during the period under review from $0.1 million to $51.3 million, comprising principally the transfer in respect of the MJF structure ($12 million) following the export licence contract being secured and associated commercial phase production commencing; an amount of derived from the current value of the licence payments assessed by the Kazakh regulatory authorities against the BNG Contract Area ($28.3 million); and the purchase of drilling and other equipment ($8.0 million).
Cash position
Unusually, at the year-end we had cash balances of approximately $4.1 million (2018: $0.6 million). This resulted principally from the timings of the cash advances from local oil traders and are broadly offset by the amounts due to the oil traders recorded in liabilities.
Liabilities
The move of the MJF structure to an export licence resulted in a one-off working capital squeeze, which lies behind much of the higher than usual liabilities at the year end.
For domestic sales we generally receive payment from local oil traders one month in advance of production. However, for international sales we typically receive payments two months often after production once the oil has been delivered to a distant port. This in effect resulted, for that part of our production sold on the international markets, in a three month period in Q4 2019, with much reduced receipts from production.
Rather than raise additional long term equity capital thereby diluting shareholders we have sought to manage our way through by conserving cash and managing payments to suppliers. The issue is working its way through the business and we expect to have returned to normal trading terms with our suppliers by the end of Q3 2020.
Trade and other payables increased from $6.3 million at 31 December 2018 to $14.8 million at 31 December 2019. This comprises principally advances from local oil traders ($7.0 million); other payables ($4.3 million); and tax and social security ($1.8 million).
Additionally, a consequence of the working capital squeeze has been an increase at 31 December 2019, in the loans provided by the Oraziman family under the existing framework agreement to $4 million.
As at 31 December 2019, the provision for payments to be made over the next 10 years as part of the award of the production licence, termed BNG Licence Payments, has been estimated at $27.4 million. Other current provisions increased primarily due to amount payable in respect of the 3A Best licence which are matched by a corresponding receivable as they are indemnified by the vendors.
Funding
Policy
Our approach to funding the business has not changed in the period under review or subsequently, despite the recent Covid-19 created fall in world oil prices. It remains to seek to minimise the issuance of equity and therefore to use other forms of funding to develop our assets. In this way we seek to preserve the upside for existing shareholders, even if this is at the expense of higher costs in the short term.
From time to time we are prepared to issue equity, in particular in situations where we expect the return to be a multiple of the price paid, for example with both 3A Best and the Caspian Explorer, or to fund the purchase of equipment that puts us in control of the pace at which we develop our shallow structures.
Where we have issued shares we have done so at prices which we believe more reflects the underlying value in the business rather than at the conventional 10 per cent discount to the prevailing share price. The premia achieved for share issues in the period under review and subsequently have ranged from 3.2 to 27.7 percent.
Going concern
The Board have assessed cash flow forecasts prepared for a period of at least 12 months from the of approval of the financial statements and assessed the risks and uncertainties associated with the operations and funding position, including the potential further effects of the COVID-19 pandemic.
The pandemic has had a significant impact on the business and its cash generation through the collapse of international and domestic oil prices and operational issues at local refineries and loading stations, whilst operations have also been disrupted through restrictions which continue to affect the ability of workers, contractors, supplies and equipment to reach the site.
This was exacerbated in May 2020 when, as a one-off event, with uncertainty in international demand and prices we had to decide where to sell our oil. 100% of oil produced was allocated to the domestic market which coincided with a fall in domestic prices below $10/bbl due to operational issues at the local refinery. As a result the income for production delivered in May 2020, was greatly reduced. However, from June 2020 onwards, we have reverted to our practice of seeking to sell approximately 60% of production on the export markets with headline Brent prices currently approximately $40 per barrel. Additionally, domestic prices are expected to return to previous levels.
Under the base case forecasts, production is estimated at 1,700bopd with approximately 60% of oil production sold on the export market at an anticipated $40/bbl and 40% sold on the domestic market at an anticipated $15/bbl. The forecasts indicate that the Group will be able to meet its operating expenditures, taxes, social payment obligations under the licences and certain licence obligations whilst enabling the Group to gradually pay down accumulated creditor balances.
However, the Group's liquidity is dependent on a number of key factors:
· The Group continues to forward sell its domestic production and receive advances from oil traders with $4.5m currently advanced and the continued availability of such arrangements is important to working capital. Whilst the Board anticipate such facilities remaining available given its trader relationships and recent increases, should they be withdrawn or reduced more quickly than forecast cash flows allow then additional funding would be required.
· The forecasts assume that certain material licence commitments and obligations respect of 3A Best and BNG will be deferred by the authorities based on applications submitted in May 2020. Additionally, the forecasts assume that quarterly BNG Licence Payments (refer to note19) will be revised to levels below the current assessments received from the authorities, based on legal proceedings initiated. In the event that the authorities refuse one or more of such applications or the BNG licence payment is not reduced additional funding will be required.
· The Group has approximately $0.5m of aged creditors which are being settled over the coming months from operating cash flows. Whilst relations are positive with the suppliers, if their support is withdrawn additional funding may be required.
· The Group has $4m of loans due on demand or within the forecast period to its largest shareholder and his connected companies. Whilst the Board has received assurances that the facilities will not be called for payment unless sufficient liquidity exists, there are no binding agreements currently in place to this effect and if repayment was required additional funding would be needed.
· The forecasts remain sensitive to oil prices, which have shown significant volatility. Independent of the factors above, if international oil prices fell below c$30/bbl additional actions would be required including further cost reductions, additional payment deferrals and raising funds.
The Directors remain confident that additional funding, if required, could be obtained through a number of sources including: further 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, there can be no guarantee that such funding would be available and the terms of any new funding, if required, may be onerous.
These circumstances indicate the existence of a material uncertainty which may cast significant doubt about the Group's ability to continue as a going concern and therefore it may be unable to realise its assets and discharge its liabilities in the normal course of business. The financial statements do not include the adjustments that would result if the Group was unable to continue as a going concern.
Notwithstanding the material uncertainty described above, after making enquiries and assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group will continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors continue to adopt the going concern basis in preparing the financial statements.
Low cost operator
We continue to pride ourselves on being a low-cost operator, both as operators in the field and in controlling our General & Administrative ("G&A") costs.
We believe our drilling costs, which following the acquisition of our own rigs are now broadly $1.2 million for shallow wells and $10 - $12 million (including completion and testing) for deep wells are among the lowest in the industry. The presence of high pressure at BNG reduces our lifting, treatment, storage and transport costs for domestic sales are estimated at approximately $3 per barrel. For export sales our lifting, treatment storage and transport costs are estimated to be $7 per barrel.
Employees
Following the suspension of operational drilling the Group now has 71 employees, including Directors, of whom 68 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.
For those working in the field oil exploration is potentially very dangerous with the risk of serious injury ever present. The work continues on a 24 hour basis with 12 hour shifts and fortnightly rotations. The work is undertaken often in terrible weather with temperatures peaking at more than 40 degrees in the summer and falling to as low as minus 35 degrees in the winter. In addition the geography the Steppe region results in very strong and dangerous winds for those working often many meters above the ground.
During the period under review I had the opportunity for an extended stay in the field at both assets we own and those we may have an interest in owning in the future and witnessed first-hand the difficulties faced by those working at each well location. The success of the Group is built on the efforts of these key workers.
Move to the UAE
During the period under review and subsequently we moved the location of the Group's intermediate holding companies to the UAE. The UAE is closer to our oilfields and to the corporate offices in Almaty. The move has allowed the Group to significantly reduce general & administrative expenditure in the UK and the Netherlands.
Over time we intend to make the UAE the centre of Group treasury operations.
Market reporting
Earlier this year we ended the monthly disclosure of prices achieved in the domestic and export markets for fear of impacting our commercial position in subsequent months.
However, announcing solely production volumes on a monthly basis is out of line with market practice and also seems to provoke suspicion in some of what is not included in such announcements. Accordingly, we will seek to provide much fuller operational updates on a quarterly basis but cease the practice of announcing monthly production numbers. Significant events, operational or otherwise, will continue to be announced at the appropriate time as required under the AIM Rules.
The investment case
Even before the recent international oil price fall the statistics for the smaller AIM Exploration and Production companies made for depressing reading. The sector was out of favour with few companies providing positive returns for their investors.
Early stage exploration has always been difficult to fund through the public markets. With exploration cycles of 7-10 years and the interest span of investors typically measured in months, even before the dramatic price decline, the days when interesting early stage exploration can be funded entirely via the public markets may be long gone.
The current position
Our immediate objective is to come through the present situation in good shape to benefit from the medium and longer term opportunities we believe still exist. In this we have the following advantages:
We have production.
The base production capacity from our existing shallow wells is already some 2,000 bopd. To that we hope to be able to add production from New Wells 151 and 152 and more impactfully from our already drilled deep wells.
We are a low cost operator
· we have low lifting costs and transportation costs
· a large proportion of our costs re in Kazakh Tenge, which has devalued significantly in recent years
· we now own four rigs thereby reducing the cash costs of future exploration
We do not have any long term debt
Other than the Oraziman family loan and short term finance provided by local oil traders, we have no external debt.
Medium / longer term
We continue to be believe that for much of the last decade there has been a very significant lack of exploration activities leading to the discovery of meaningful new reserves. Every year a significant portion of the world's proven reserves are consumed by production. As demand for oil recovers and with the lack of recent exploration activity those with proven assets should expect to attract interest over the medium and longer terms.
The current Covid-19 related problems in the market may well create new acquisition opportunities for those with access to funding.
Operating with a low oil price
Operating with a low oil price is nothing new as until August 2019, all our oil sales were at domestic prices, which continue to be much lower than international prices.
We have reliable production, which we expect will continue to increase at relatively low risk. In particular, the MJF structure infill programme already underway should be a succession of easy wins.
· The wells are typically only 2,500 meters deep and do not need to penetrate the salt layer, thereby avoiding any high temperature / high pressure issues
· The infill wells are located inside the perimeter of a structure we already know to contain oil.
· The oil flows naturally to the surface removing the need for expensive artificial stimulation
· With our own rigs we can drill when it suits us and at relatively low cost.
The bulk of the drilling costs of our four existing deep wells have already been incurred and already paid. In the event these wells come into meaningful production it will dramatically improve our cashflows
Once acquired the Caspian Explorer is capable earning up to $25 million per annum in the event it is commissioned for northern Caspian Sea exploration work.
Outlook
We have confidence in our assets and their value over the medium / longer term. To realise this value however, we first need to deal with the current situation.
Despite market conditions we have sourced additional funding to continue to develop both our shallow and deep prospects. We further believe the Group's advantages noted above and the steps already taken provide the basis to overcome the short term issues and then when the time is right move forward when we expect there to be plenty of new opportunities.
While the present situation is undoubtedly difficult, we believe we are well placed to come through and subsequently prosper.
Clive Carver
Executive Chairman
24 June 2020
Qualified Person & Glossary
Qualified Person
Mr. Assylbek Umbetov, who works in the Group's geological department, 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
Proven 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 2019. 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.
Results and dividends
The consolidated statement of profit or loss is set out on page 46 and shows US$1.4 million loss for the year (2018: US$8.5 million). The Directors do not recommend the payment of a dividend for the year ended 31 December 2019 (2018: US$ 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:
· The proposed acquisition of the Caspian Explorer
· The actions taken in response of the Covid-19 virus
· Operational and financial developments
all as disclosed in this annual report, including notes to the financial statements, there have been no material events between 31 December 2019, and the date of this report, which are required to be brought to the attention of shareholders. Please refer to note 27 of these financial statements for further details.
Board changes
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 is much valued.
Employees
Staff employed by the Group are based primarily in Kazakhstan. The recruitment and retention of staff, especially at management level, is increasingly important as the Group continues to build its portfolio of oil and gas assets.
As well as providing employees with appropriate remuneration and other benefits together with a safe and enjoyable working environment, the Board recognises the importance of communicating with employees to motivate them and involve them fully in the business. For the most part, this communication takes place at a local level and staff are kept informed of major developments through email updates. They also have access to the Group's website.
The Group 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
Timothy Field (appointed 25 January 2019)
Directors' interests
Number of shares
Number of shares
Director
As at 31 December 2019
As at December 2018
Clive Carver
nil
nil
Kuat Oraziman*
41,485,330
37,285,330
Edmund Limerick**
6,430,000
6,430,00
Timothy Field
nil
nil
* Taken together Mr Oraziman and his adult children held 807,275,739 shares on 31 December 2019
** includes 1,135,000 shares held by his wife
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 24 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 Group'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 Group's website is the responsibility of the Directors. The Directors' responsibility also extends to the ongoing integrity of the financial statements contained therein.
Clive Carver
Executive Chairman
24 June 2020
INDEPENDENT AUDITOR'S REPORT TO THE MEMBERS OF
CASPIAN SUNRISE PLCOpinion
We have audited the financial statements of Caspian Sunrise Plc (the 'Parent Company') and its subsidiaries (the 'Group') for the year ended 31 December 2019 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 2019 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.
Material uncertainty in relation to going concern
We draw attention to note 1.1 in the financial statements concerning the Group and the Parent Company's ability to continue as a going concern. Note 1.1 highlights that Group and Parent Company's ability to meet its liabilities and commitments as they fall due without additional funding is sensitive to the oil prices realised across the forecast period and, separately, it is dependent upon the deferral of financial obligations and drilling commitments associated with its licences, continued availability of oil trader advances and the continued support of certain creditors together with other matters set out therein. These factors are outside the control of the Group and the Parent Company and there is no certainty that any funding that may therefore be required can be secured within the necessary timescales. These events or conditions indicate that a material uncertainty exists that may cast significant doubt on the Group and the Parent Company's ability to continue as a going concern. Our opinion is not modified in respect of this matter.
We consider going concern to be a Key Audit Matter based on our assessment of the risk and the effect on our audit. Our response to this key audit matter is shown below:
• We discussed the potential impact of Covid-19 with management and the Audit Committee including their assessment of risks and uncertainties associated with areas such as production disruption, commodity price volatility and the impact on the availability of funding. We formed our own assessment of risks and uncertainties based on our understanding of the business and oil sector.
• We obtained management's cash flow forecasts and critically assessed the key inputs. In doing so we compared oil prices to market data, production levels to recent performance trends and operating costs to historical data.
• We evaluated the completeness of forecast license related expenditure against the license work programs and payments due under the 3A Best license. We inspected submissions made to the relevant authorities for deferral of work program commitments and payments due and held discussions with management and the Audit Committee regarding the status of such applications.
• We compared the forecast cash payments in respect of the BNG production license award against the $32m assessment received from the Government payable in instalments over 10 years. We discussed the status of the court process with management and the Audit Committee which seeks to reduce the payments to the level included in the forecast and considered the impact of the court process being unsuccessful.
• We considered the appropriateness of the Board's judgment regarding the availability of sufficient 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 assessed the terms of the loans provided from the Group's largest shareholder and his connected companies, the dependence on continued support and the Board's conclusion that the loans will not be called for payment for at least the next 12 months unless the Group has sufficient liquidity. We obtained written representation from the Board regarding this assessment.
• We evaluated management's sensitivity analysis and performed our own sensitivity analysis in respect of the key assumptions underpinning the forecasts, including specific scenarios such as reduced revenue cash flows or the impact of one or more adverse events such as withdrawal of facilities, withdrawal of creditor support or license payments or commitments being enforced. We assessed the validity of any mitigating actions identified by Management.
• We reviewed the adequacy and completeness of the disclosure included within the financial statements in respect of going concern.
Key audit matters
In addition to the matter described in the material uncertainty related to going concern section, 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 the carrying value of the oil and gas assets require impairment or that previously recorded impairments should be reversed
As at 31 December 2019, the Group's oil and gas assets related to BNG and 3A Best were carried at US$103.2m as shown in notes 10 and 11. At each reporting period end, management are required to assess the oil and gas assets for indicators of impairment and, where such indicators exist, perform an impairment test. Additionally, management are required to assess whether circumstances that gave rise to historical impairment provisions no longer apply and the impairments should be reversed.
In performing the impairment indicator review for the unproven oil and gas assets in the exploration phase, management are required to make a number of judgements as detailed in notes 1.8 and 2.1. In respect of the 3A Best oil and gas assets, as detailed in note 2.5 management applied significant judgment in concluding that its application for deferral of the payments due in July 2020 under the licence will be successful following application to the Government and that the license will be extended. As a result, no impairment was considered to be appropriate by management.
In respect of the MJF production license, as detailed in note 2.3 management recorded a reversal of $2.4m of historical impairment provision based on the net present value forecasts for the field, which required estimation and judgment regarding the inputs to the forecasts and assessing whether the factors that gave rise to the original impairment no longer applied.
Given the judgment and estimation required by management, we considered this area to be a key focus for our audit.
How the matter was addressed in our audit
· We considered whether indicators of impairment existed in respect of the BNG and 3A Best unproven oil and gas assets. In doing so, we inspected the licenses to confirm valid title and assessed the compliance with the license conditions through review of correspondence with the authorities and inquiries of management. We inspected budgets and work programs submitted to the Kazakh authorities to confirm that further drilling and exploration is planned for the assets. We considered the results of exploration activity in the period for indications that the licenses would be abandoned or that the recoverable value would be below cost.
· In respect of the 3A Best license, we reviewed correspondence from the Government which included payment obligations which, if unfulfilled, would entitle the Government to withdraw the license. We discussed management's judgment that the obligations would be ultimately be deferred and the license be extended with the Audit Committee. In assessing the judgment, we inspected applications submitted to the Government, the history of investment in Kazakh oil fields by the Group and the previous extensions and revisions to work program commitments and obligations.
· In respect of the MJF producing assets we inspected the production license awarded in the period and obtained management's net present value forecasts and critically assessed the inputs. In doing so, we compared the oil price forecasts as at 31 December 2019 to market consensus forecasts and compared operational production and cost assumptions to the 2015 Competent Person's Report, historical data and other third party sources.
· We evaluated the independence and competence of the Competent Person as a management expert.
· We considered management's judgment that it was appropriate to record a reversal of previous impairment associated with the MJF producing assets. In doing so, we considered the impact of the production license award on the field economics and the recoverable value calculated by management. We evaluated the basis on which management determined the share of the historic impairment that related to the MJF structure for consistency with the ratio of the cost pool transferred into production upon the commencement of commercial production.
· We assessed the disclosures included in the financial statements at notes 2.1, 2.3, 2.5, 10 and 11.
Our observations
We found management's conclusion that no impairment exists on the BNG oil and gas assets and 3A Best oil and gas assets to be appropriate. We found the judgments made by management to be appropriately considered and the disclosures in the notes to be sufficient.
Key audit matter: Accounting for licence payment obligations triggered by the award of the BNG production contract
Under the terms of the BNG license, on award of the production contract the Group incurred an obligation for payments under the licence as detailed in note 2.6, 11 and 19. Whilst the quantum to be paid has been assessed by the Government authorities it remains subject to dispute with a legal process ongoing. Management recorded a provision and increase in the proven oil and gas asset cost of $28.3m on initial recognition. The determination of the appropriate accounting treatment and the estimate of the provision required management to exercise judgment.
Given the judgment required and the material impact of the transaction, this was considered to be a focus for our audit and a key audit matter.
How the matter was addressed in our audit
· We reviewed the terms of the license to confirm that a payment obligation was triggered upon award of the contract.
· We reviewed correspondence with the relevant authorities regarding the assessment of the quantum of the payment due and the terms of payment which formed the basis for the amounts recorded as a provision. We inspected court applications which were consistent with management's assertions that they were challenging the quantum of the assessment and discussed the basis for the legal proceedings with management and the Audit Committee.
· We recalculated the provision and compared the discount rate to market bond yield data for similar termed instruments.
· We evaluated that accounting policy established by management against relevant IFRS literature and the nature of the transaction. In particular, this involved assessing the extent to which capitalization of the cost was appropriate in conjunction with our technical specialists.
· We assessed the disclosures included in the financial statements at notes 2.6, 11 and 19.
Our observations
We found the accounting treatment of the transaction to be appropriate.
Key audit matter: Appropriateness of revenue recognition policies and the appropriateness of cut off for oil revenue
The Group generated revenues of $12.1m which arises both from the test production and, for the first time in 2019, export sales at BNG as shown in note 3. We considered there to be a risk that the accounting policy for export revenues did not meet the requirements of IFRS 15. In addition, we considered there to be a risk of revenue being recorded in the incorrect period for transactions around year end. Given these conditions we considered revenue recognition to be a focus for our audit and a key audit matter.
How the matter was addressed in our audit
· We evaluated the group's revenue recognition policies for each revenue stream (export and domestic) and assessed their compliance with IFRS 15 and its 5-step revenue recognition model based around control and consistency with the contractual arrangements with its customers.
· We examined the terms of all significant sales agreements and assessed the impact of such terms of revenue recognition.
· We performed cut off procedures on revenue around the year end for each revenue stream, to determine whether revenue had been recognised in the correct period. In doing so, we confirmed the appropriateness of the revenue recognition point against the terms of contract and delivery documents for items pre and post year end.
· We verified a sample of oil production revenues to supporting evidence.
Our observations
We found the revenue recognition policies to be compliant with accounting standards and found that revenue is recorded in the appropriate period.
Our application of materiality
Group materiality as at 31 December 2019
Basis for materiality
US$1,900,000
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 $1,900,000, being 1.5% of total assets (2018: $1,000,000). 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 $1,710,000, being 90% of Group materiality (2018: $800,000 capped at 80% of Group materiality).
In performing the audit we applied a lower level of performance materiality of $1,425,000, being 75% of Group materiality (2018: $750,000), in order to reduce to an appropriately low level the probability that the aggregate of uncorrected and undetected misstatements exceeds financial statement materiality. Each significant component of the Group including the parent company was audited using a lower level of performance materiality ranging from $300,000 to $900,000 (2018: $600,000 to $675,000).
We agreed with the Audit Committee that we would report to the committee all individual audit differences in excess of $70,000 (2018: $50,000). 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 oil and gas exploration and production in Kazakhstan. We assessed there to be 3 significant components comprising BNG, 3A Best and the parent company.
These locations, which were subject to full scope audit procedures represent the principal business units.
Non-BDO member firms performed a full scope audit of BNG and 3A Best in Kazakhstan, under our direction and supervision as Group auditors. 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 auditors, which included the significant areas to be covered by the audit.
• As a result of travel restrictions resulting from the COVID-19 pandemic, senior members of the group audit team were unable to visit Kazakhstan to meet with component management and the component auditors during the audit completion phase as we have done historically. Accordingly, we performed a remote review of the component audit files in Kazakhstan using online software platforms and held regular calls with the component audit teams during the planning and completion phases of their audit.
• We reviewed Group reporting submissions received and held calls and meetings with the component audit team during the completion phases of their audit to discuss significant findings from their audit.
• We held calls and meetings with members of Group and component management to discuss accounting and audit matters arising.
• 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.
Other information
The Directors are responsible for the other information. The other information comprises the information included in the Annual Report and Financial Statements, 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 set out on page 28, 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
24 June 2020
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
2019
Year to
31 December
2018
US$'000
US$'000
Revenue
3
12,108
10,747
Cost of sales
(6,971)
(10,747)
Gross profit
5,137
-
Selling expense
(2,220)
-
Impairment reversal of unproven and proved oil and gas assets
11
2,414
-
Share-based payments
(31)
(13)
Other administrative costs
(3,907)
(2,611)
Total administrative expenses
(3,938)
(2,624)
Operating income / (loss)
4
1,393
(2,624)
Finance cost
7
(452)
(348)
Finance income
-
-
Profit/(Loss) before taxation
941
(2,972)
Tax charge
8
(2,343)
(414)
Loss after taxation from continuing operations
(1,402)
(3,386)
Loss for the year from discontinued operations
20
-
(5,147)
Loss for the year
(1,402)
(8,533)
Loss attributable to owners of the parent
(1,278)
(8,366)
Loss attributable to non-controlling interest
(124)
(167)
Loss for the year
(1,402)
(8,533)
Basic loss per ordinary share (US cents)
9
From continuing operations
(0.07)
(0.19)
From discontinued operations
-
(0.31)
Total loss per share
(0.07)
(0.5)
Diluted loss per ordinary share (US cents)
9
From continuing operations
(0.07)
(0.19)
From discontinued operations
-
(0.31)
Total loss per share
(0.07)
(0.5)
Consolidated Statement of Comprehensive Income
Year ended
31 December
2019
Year ended
31 December
2018
US$000
US$000
Loss after taxation
(1,402)
(8,533)
Other comprehensive income:
Exchange differences on translating foreign operations
268
(10,136)
Recycling of exchange difference on disposal of subsidiary
-
8,305
Total comprehensive loss for the year
(1,134)
(10,364)
Total comprehensive loss attributable to:
Owners of parent
(1,010)
(9,277)
Non-controlling interest
(124)
(1,087)
Consolidated Statement of Changes in Equity
Share capital
US$'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 2019
25,416
229,020
64,702
(55,911)
(2,362)
(219,230)
41,635
(5,605)
36,030
Loss after taxation
-
-
-
-
-
(1,278)
(1,278)
(124)
(1,402)
Exchange differences on translating foreign operations and recycling of exchange differences on disposal of subsidiaries
-
-
-
268
-
-
268
-
268
Total comprehensive income/(loss) for the year
-
-
-
268
-
(1,278)
(1,010)
(124)
(1,134)
Shares issue
2,648
17,115
-
-
-
-
19,763
-
19,763
Share options exercised
56
164
-
-
-
-
220
-
220
Arising on employee share options
-
-
-
-
-
31
31
-
31
Total equity as at 31 December 2019
28,120
246,299
64,702
(55,643)
(2,362)
(220,477)
60,639
(5,729)
54,910
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$'000
Total equity as at 1 January 2018
25,401
228,974
64,702
(55,000)
(2,362)
(210,877)
50,838
(4,654)
46,184
Loss after taxation
-
-
-
-
-
(8,366)
(8,366)
(167)
(8,533)
Exchange differences on translating foreign operations and recycling of exchange differences on disposal of subsidiaries
-
-
-
(911)
-
-
(911)
(920)
(1,831)
Total comprehensive income/(loss) for the year
-
-
-
(911)
-
(8,366)
(9,277)
(1,087)
(10,364)
Disposal of subsidiary
-
-
-
-
-
-
-
136
136
Share options exercised
15
46
-
-
-
-
61
-
61
Arising on employee share options
-
-
-
-
-
13
13
-
13
Total equity as at 31 December 2018
25,416
229,020
64,702
(55,911)
(2,362)
(219,230)
41,635
(5,605)
36,030
Equity Description and purpose
Share capital The nominal value of shares issued
Share premium Amount subscribed for share capital in excess of nominal value
Deferred shares The nominal value of deferred shares issued
Cumulative translation reserve Gains/losses arising on retranslating the net assets of overseas operations into US Dollars, less amounts recycled on disposal of subsidiaries and joint ventures
Other reserves Fair value of warrants issued and capital contribution arising on discounted loans
Retained deficit Cumulative losses recognised in the consolidated statement of profit or loss, adjustments on the acquisition of non-controlling interests and transfers in respect of share based payments
Non-controlling interest The interest of non-controlling parties in the net assets of the subsidiaries
Parent Company Statement of Changes in Equity
Share
capital
US$'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$'000
Total equity as at 1 January 2019
25,416
229,020
64,702
14,936
(144,911)
189,163
Total comprehensive loss for the year
-
-
-
-
(8,223)
(8,223)
Restructuring of Intragroup Debt (see Note 17)
-
-
-
(14,936)
14,936
-
Shares issue
2,648
17,115
-
-
-
19,763
Stock options exercised
56
164
-
-
-
220
Arising on employee share options
-
-
-
-
31
31
Total equity as at 31 December 2019
28,120
246,299
64,702
-
(138,167)
200,954
Total equity as at 1 January 2018
25,401
228,974
64,702
14,936
(144,073)
189,940
Total comprehensive loss for the year
-
-
-
-
(851)
(851)
Stock options exercised
15
46
-
-
-
61
Arising on employee share options
-
-
-
-
13
13
Total equity as at 31 December 2018
25,416
229,020
64,702
14,936
(144,911)
189,163
Equity Description and purpose
Share capital The nominal value of shares issued
Share premium Amount subscribed for share capital in excess of nominal value
Deferred shares The nominal value of deferred shares issued
Other reserves Fair value of warrants issued and capital contribution arising on discounted loans
Retained deficit Cumulative losses recognised in the profit or loss
Consolidated Statement of Financial Position
Company number 5966431
Notes
Group
2019
US$'000
Group
2018
US$'000
Assets
Non-current assets
Unproven oil and gas assets
10
60,040
55,685
Property, plant and equipment
11
51,326
88
Inventories
13
384
132
Other receivables
14
5,745
8,445
Restricted use cash
241
249
Total non-current assets
117,736
64,599
Current assets
Other receivables
14
5,663
364
Cash and cash equivalents
15
4,060
557
Total current assets
9,723
921
Total assets
127,459
65,520
Equity and liabilities
Capital and reserves attributable
to equity holders of the parent
Share capital
16
28,120
25,416
Share premium
246,299
229,020
Deferred shares
16
64,702
64,702
Other reserves
(2,362)
(2,362)
Retained deficit
(220,477)
(219,230)
Cumulative translation reserve
(55,643)
(55,911)
Equity attributable to the owners of the Parent
60,639
41,635
Non-controlling interests
26
(5,729)
(5,605)
Total equity
54,910
36,030
Current liabilities
Trade and other payables
17
14,836
6,259
Short - term borrowings
18
4,050
2,572
Provision for BNG licence payment
19
3,178
-
Other current provisions
19
6,304
3,515
Total current liabilities
28,368
12,346
Non-current liabilities
Deferred tax liabilities
22
7,244
6,733
Provision for BNG licence payment
19
24,216
-
Other non-current provisions
19
428
125
Other payables
17
12,293
10,286
Total non-current liabilities
44,181
17,144
Total liabilities
72,549
29,490
Total equity and liabilities
127,459
65,520
Parent Company Statement of Financial Position
Company number 5966431
Notes
Company
2019
US$'000
Company
2018
US$'000
Assets
Non-current assets
Investments in subsidiaries
12
223,781
211,986
Other receivables
14
10,704
3,066
Total non-current assets
234,485
215,052
Current assets
Other receivables
14
7
6
Cash and cash equivalents
15
87
292
Total current assets
94
298
Total assets
234,579
215,350
Equity and liabilities
Capital and reserves attributable
to equity holders of the parent
Share capital
16
28,120
25,416
Share premium
246,299
229,020
Deferred shares
16
64,702
64,702
Other reserves
-
14,936
Retained deficit
(138,167)
(144,911)
Equity attributable to the owners of the Parent
200,954
189,163
Total equity
200,954
189,163
Current liabilities
Short - term borrowings
18
1,814
400
Trade and other payables
17
31,811
9,052
Total current liabilities
33,625
9,452
Non-current liabilities
Other payables
17
-
16,735
Total non-current liabilities
-
16,735
Total liabilities
33,625
26,187
Total equity and liabilities
234,579
215,350
The Company incurred a loss for the year ended 31 December 2019 in the amount of US$ 8,223,000 (2018: US$ 851,000).
Consolidated and Parent Company Statements of Cash Flows
Notes
Group
2019
US$'000
Group
2018
US$'000
Company
2019
US$'000
Company
2018
US$'000
Cash flows from operating activities
Cash received from customers
16,465
9,025
-
-
Return of taxes previously paid
8
-
1,013
-
1,013
Payments made to suppliers for goods and services
(6,767)
(2,747)
(1,128)
(1,175)
Payments made to employees
(1,226)
(1,185)
(597)
(614)
Net cash flow from operating activities
8,472
6,106
(1,725)
(776)
Cash flows from investing activities
Purchase of property, plant and equipment
(669)
(3)
-
-
Additions to unproven oil and gas assets
(5,830)
(7,733)
-
-
Transfers from/(to) restricted use cash
8
-
-
-
Proceeds from disposal of subsidiaries
20
-
134
-
-
Advances repaid by subsidiaries
-
-
108
180
Advances issued to subsidiaries
-
-
(100)
(100)
Net cash flow from investing activities
(6,491)
(7,602)
8
80
Cash flows from financing activities
Net proceeds from issue of ordinary share capital
220
61
220
61
Loans repaid
24
(28)
(534)
-
-
Loans provided by subsidiaries
-
-
-
600
Loans received
24
1,330
1,047
1,330
400
Repayment of loans provided by subsidiaries
-
-
(38)
(90)
Net cash flow from financing activities
1,522
574
1,512
971
Net increase/(decrease) in cash and cash equivalents
3,503
(922)
(205)
275
Cash and cash equivalents at the beginning of the year
557
1,479
292
17
Cash and cash equivalents at the end of the year
15
4,060
557
87
292
Significant non-cash transactions include the following and details can be found in notes 6, 7, 8, 10, 11, 16:
- Acquisition of 100% interest at 3A Best in exchange of issue of 149,253,732 new Caspian Sunrise shares with the consideration value of US$ 11,795,000 on the date (2018: US$ 0);
- Acquisition of PP&E in exchange of issue of 58,333,333 new Caspian Sunrise shares with the value of US$ 7,996,000 (2018: US$ 0);
- Share-based payments in the amount of US$ 31,000 (2018: US$ 13,000);
- Withholding tax in the amount of US$ 1,860,000 (2017: US$ 1,375,000);
- Exchange differences on translating foreign operations of US$ 49,000 (2018: US$ 3,154,000);
- Depreciation charge of US$ 148,000 (2018: US$ 31,000);
- Interest expense of US$ 452,000 (2018: US$ 348,000);
- Reversal of impairment on the BNG assets of US$2,414,000 (2018: US$Nil);
- Additions to the BNG proven oil and gas assets of US$28,335,000 (2018: US$Nil) associated with the provision for licence payments
* Additions to unproven oil and gas assets contain the amount of US$ 185,500 in relation to payroll expenses capitalized (2018: US$: 332,000).
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 24 June 2020.
The financial information set out herein does not constitute the Group's statutory financial statements for the year ended 31 December 2019, but is derived from the Group's audited financial statements. The auditors have reported on the 2019 financial statements and their report was unqualified and did not contain statements under s498(2) or (3) Companies Act 2006 but did contain a material uncertainty in relation to going concern.
The 2019 Annual Report was approved by the Board of Directors on 24 June 2020 The financial information in this statement is audited but does not have the status of statutory accounts within the meaning of Section 434 of the Companies Act 2006.
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 Board have assessed cash flow forecasts prepared for a period of at least 12 months from the of approval of the financial statements and assessed the risks and uncertainties associated with the operations and funding position, including the potential further effects of the COVID-19 pandemic.
However, the Group's liquidity is dependent on a number of key factors:
· The Group continues to forward sell its domestic production and receive advances from oil traders with $4.5m currently advanced and the continued availability of such arrangements is important to working capital. Whilst the Board anticipate such facilities remaining available given its trader relationships and recent increases, should they be withdrawn or reduced more quickly than forecast cash flows allow then additional funding would be required.
· The forecasts assume that certain material licence commitments and obligations respect of 3A Best and BNG will be deferred by the authorities based on applications submitted in May 2020. Additionally, the forecasts assume that quarterly payments in respect of the BNG production licence will be revised to levels below the current assessments received from the authorities, based on legal proceedings initiated. In the event that the authorities refuse one or more of such applications or the BNG licence payment is not reduced additional funding will be required.
· The Group has approximately $0.5m of aged creditors which are being settled over the coming months from operating cash flows. Whilst relations are positive with the suppliers, if their support is withdrawn additional funding may be required.
· The Group has $4m of loans due on demand or within the forecast period to its largest shareholder and his connected companies. Whilst the Board has received assurances that the facilities will not be called for payment unless sufficient liquidity exists, there are no binding agreements currently in place to this effect and if repayment was required additional funding would be needed.
· The forecasts remain sensitive to oil prices, which have shown significant volatility. Independent of the factors above, if international oil prices fell below c$30/bbl additional actions would be required including further cost reductions, additional payment deferrals and raising funds.
The Directors remain confident that additional funding, if required, could be obtained through a number of sources including: further 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, there can be no guarantee that such funding would be available and the terms of any new funding, if required, may be onerous.
These circumstances indicate the existence of a material uncertainty which may cast significant doubt about the Group's ability to continue as a going concern and therefore it may be unable to realise its assets and discharge its liabilities in the normal course of business. The financial statements do not include the adjustments that would result if the Group was unable to continue as a going concern.
Notwithstanding the material uncertainty described above, after making enquiries and assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group will continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors continue to adopt the going concern basis in preparing the financial statements.
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$8,223,000 (2018: US$ 851,000) 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 disclosed policies have been applied consistently by the Group for both the current and previous financial year with the exception of the new standards adopted.
The European Union ("EU") IFRS financial information has been drawn up on the basis of accounting policies consistent with those applied in the financial statements for the year to 31 December 2018, except for the following:
(a) IFRS 16 'Leases'
(b) IFRIC 23 'Uncertainty over Income Tax Positions'
(c) Prepayment Features with Negative Compensation - Amendments to IFRS 9
(d) Long-term Interests in Associates and Joint Ventures - Amendments to IAS 28
(e) Annual Improvements to IFRS Standards 2015 - 2017 Cycle
(f) Plan Amendment, Curtailment or Settlement - Amendments to IAS 19
In respect of IFRS 16 the Group amended accounting policies applied from 1 January 2019 are disclosed in Note 3 under 'Significant accounting policies'.
IFRS 16 specifies how to recognise, measure, present and disclose leases. The standard provides a single lessee accounting model, requiring lessees to recognise right-of-use assets and lease liabilities for all material leases. It results in almost all leases being recognised on the balance sheet by lessees, as the distinction between operating and finance leases was removed. Under the new standard, an asset (the right to use the leased item) and a financial liability to pay rentals are recognised. The only exceptions are short-term and low-value leases. The Group adopted IFRS 16 from 1 January 2019 using the modified retrospective approach and accordingly the information presented for 2018 is not restated. It remains as previously reported under IAS 17 and related interpretations. The Group undertook an assessment of contracts to identify potential lease arrangements and following such analysis determined that the impact was immaterial.
Effective as of 1 January 2019, IFRIC 23 explains how to recognise and measure deferred and current income tax assets and liabilities where there is uncertainty over a tax treatment. An uncertain tax treatment is any tax treatment applied by the Group where there is uncertainty over whether that treatment will be accepted by the tax authority. IFRIC 23 applies to all aspects of income tax accounting where there is an uncertainty regarding the treatment of an item, including taxable profit or loss, the tax bases of assets and liabilities, tax losses and credits and tax rates. refer to note 19 for details of uncertain tax positions.
Standards, amendments and interpretations, which are effective for reporting periods beginning after the date of this financial information which have not been adopted early:
Effective for annual periods beginning on or after
Amendments to IFRS 3, 'Business combinations'
01-Jan-20
Amendments to IAS 1 and IAS 8: Definition of Material
01-Jan-20
Amendments to References to the Conceptual Framework in IFRS Standards
01-Jan-20
IFRS 17, 'Insurance contracts'
01-Jan-21
Management are currently assessing the impact of the amendments to IFRS 3 vis a vis the proposed acquisition of Caspian Explorer as detailed in the subsequent events note.
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$"), which is the Group's presentational currency. Beibars Munai LLP, Munaily Kazakhstan LLP, BNG Ltd LLP and Roxi Petroleum Kazakhstan LLP, 3A_Best Group JSC, and Caspian Technical Services LLP subsidiary undertakings of the Group during the period, undertake their activities in Kazakhstan and the Kazakh Tenge is the functional currency of these entities. The functional currency for the Company, Beibars BV, Ravninnoe BV, Galaz Energy BV, BNG Energy BV and Eragon Petroleum FZE is USD as USD reflects the underlying transactions, conducts and events relevant to these companies.
1.5.2 Transactions and balances in foreign currencies
In preparing the financial statements of the individual entities, transactions in currencies other than the entity's functional currency ("foreign currencies") are recorded at the rates of exchange prevailing at the dates of the transactions. At each reporting date, monetary items denominated in foreign currencies are retranslated at the rates prevailing at the reporting date. Non-monetary items carried at fair value that are denominated in foreign currencies are retranslated at the rates prevailing at the date when the fair value was determined. Non-monetary items, including the parent's share capital, that are measured in terms of historical cost in a foreign currency are not retranslated. Exchange differences are recognised in profit or loss in the period in which they arise.
1.5.3 Consolidation
For the purpose of consolidation all assets and liabilities of Group entities with a functional currency that is not US$ 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 recognised 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.
In case of the uncertainty of the tax treatment, the Group assess, whether it is probable or not, that the tax treatment will be accepted, and to determine the value, the Group use the most likely amount or the expected value in determining taxable profit (tax loss), tax bases, unused tax losses, unused tax credits and tax rates.
Withholding tax payable at Kazakhstan
According to requirements of the Tax Code of Kazakhstan, withholding taxes payable for non-residents should be withheld from the total amount of interest income of non-residents and paid to the government when interest is paid (in cash) to non-residents. The companies should pay taxes from non-residents' interest income derived from sources in the Republic of Kazakhstan on behalf of these non-residents.
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. The costs transferred comprise direct costs associated with the relevant wells and infrastructure, together with an allocation of the wider unallocated exploration costs in the cost pool such as original acquisition costs for the field.
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.
As part of the Kazakh licencing regime, upon award of a production contract in respect of the BNG licence area, an obligation to make a payment to the licencing authority is triggered, settled over a 10 year period in equal quarterly instalments. Such payments are considered to form a cost of the licence and are capitalised to proven oil and gas assets and subsequently depreciated on a units of production basis in accordance with the Group's depreciation policy. In circumstances where the amount assessed by the authorities is contested, the Group records a provision discounted using a Kazakh government bond yield with a term approximating the payment profile and the discount is unwound over the payment term and charged to finance costs. Payments made are charged against the provision.
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.
Impairment of development and production assets and other property, plant and equipment
At each balance sheet date, the Group reviews the carrying amounts of its PP&E to determine whether there is any indication that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss (if any). Where the asset does not generate cash flows that are independent from other assets, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs. The recoverable amount is the higher of fair value less costs to sell and value in use. Fair value less costs to sell is determined by discounting the post-tax cash flows expected to be generated by the cash-generating unit, net of associated selling costs, and takes into account assumptions market participants would use in estimating fair value including future capital expenditure and development cost for extraction of the field reserves. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset for which the estimates of future cash flows have not been adjusted.
If the recoverable amount of an asset (or cash-generating unit) is estimated to be less than its carrying amount, the carrying amount of the asset (cash-generating unit) is reduced to its recoverable amount. An impairment loss is recognised as an expense immediately.
Where an impairment loss subsequently reverses, the carrying amount of the asset (cash-generating unit) is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset (cash-generating unit) in prior years. A reversal of an impairment loss is recognised as income immediately.
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. 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 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 recognised 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.
Under the terms of domestic oil sales arrangements, the performance obligation is satisfied when the local refinery provides the seller and the customer with the act of acceptance of crude oil of quantity and quality according to the agreement between the parties.
Under the terms of export sales arrangements, the performance obligation is satisfied when the Ocean Bill of Lading is issued by the transport company that reflects the fact of boarding the crude oil of specified quantity and quality on the tanker.
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
The Group started to calculate the cost of sales on crude oil sold during 2019 because its asset BNG has received the production license on part of its contract territory in July 2019. On the rest of its territory (%) BNG continues to work under Exploration license. During test production on Exploration 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 1.32 and the average rate during the year was 1.28. The year-end exchange rate from KZT to US$ was 382.6 and the average rate during the year was 382.8.
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 Carrying value of exploration and evaluation costs (note 10)
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 2019, the Group assessed the exploration and evaluation assets disclosed in note 10 and determined that no indicators of impairment existed at a cost pool level in respect of the BNG cost pool. The Group also considered whether the factors that gave rise to the original impairment loss no longer existed and reversal of the impairment is appropriate. In forming this assessment, the Board considered the oil reserves and resources associated with the licence area, 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 19 and the impact of outstanding obligations. Having undertaken this assessment the Group concluded that no indicators of impairment existed and that no reversal of previous impairment provisions attributable to the unproven oil and gas assets of US$9,654,000 was yet appropriate given the absence of a significant breakthrough on the deep structures at 31 December 2019.
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 Transfer of costs to proven oil and gas assets (note 10 & 11)
Judgment has been applied in assessing that the MJF area assets meets the criteria for reclassification to proven oil and gas assets under the Group's accounting policy in note 1.8. In concluding that it was appropriate to transfer the asset to proven oil and gas assets management took account of the award of a production licence enabling exports and sales at international prices together with the production volumes. In August 2019 BNG has received the required production license for its MJF structure and got the export permission starting September 2019. According to the approach above BNG moved the related O&G assets to the production stage in August 2019 and accordingly started charging DD&A expense. The Board considers the remaining 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 test oil in the domestic market which represents a substantial discount to the international market such that production is primarily a by-product of continued exploration and appraisal.
2.3 Recoverability of proven oil and gas assets (note 11)
The proven oil and gas assets, representing the MJF structure, have been assessed for indicators of impairment at 31 December 2019 including assessment of the discounted cash flows indicated by the Group's field plan. The Group also considered whether the factors that gave rise to the previously recorded impairment loss attributable to the MJF structure no longer existed and reversal of the impairment is appropriate and concluded that the factors no longer applied, noting the successful exploration activity and the transition to commercial production. Accordingly, the recoverable value of the MJF structure was assessed using the discounted cash flow analysis. This analysis required judgment and estimate in determining forecast prices as at 31 December 2019 based on conditions existing at that time, future production and reserves, operating costs and development costs for the field and the discount rate. The forecasts demonstrated significant headroom with prices based on forward prices of $60 adjusted for net back adjustments, reserves calculated using the most recent Competent Person's report and discount rates run at 10% and 15%. Having undertaken this assessment the Group concluded that the previous impairment attributable to the MJF structure of US$2,414,000 should be released. The allocation of the historic impairment provision between proven and unproven oil and gas assets required judgment and was based on relative costs incurred between the proven and unproven asset categories as the original impairment arose when the proven oil and gas assets formed part of the single BNG unproven oil and gas cost pool.
2.3 Recoverability of VAT (note 14)
The Group holds VAT receivables of $3.3 million (2018: $3million) as detailed in note 14 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 (2018: 3.5 years). This required estimates regarding future production, oil prices and expenditure.
2.4 Decommissioning (note 19)
Provision has been made in the accounts for future decommissioning costs to plug and abandon wells in note 19. 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 Acquisition of 3A Best and carrying value (note 21)
Judgment was required in assessing the accounting treatment for the purchase of 3A Best as an asset purchase rather than a business combination. In forming this assessment, management note that whilst the Group acquired legal entities to obtain control the legal entities held an exploration phase asset and associated obligations such that the criteria for a business combination were not met. As such, the fair value of the purchase consideration was allocated to the assets and liabilities acquired, costs associated with the transaction capitalised and no deferred tax arose on the transaction.
Judgment has been applied in assessing whether impairment of the asset is required at 31 December 2019 noting that the authorities have the right to withdraw the licence if payments due by July 2020 are not made in respect of obligations arising prior to the acquisition. The Board considers the risk of the licence being withdrawn to be remote given the history of investment by the Group in Kazakhstan, the impact of COVID-19 in 2020 on the Group's cash generation and ability to undertake work program commitments and past experience. An application to extend the licence has been submitted together with an application to defer the obligations and commitments. However, if the Group is unsuccessful the asset would be impaired.
2.6 Provision for BNG licence payments (note 11, 19)
As part of the Kazakh licencing regime, upon award of a production contract in respect of the BNG licence area, an obligation to make a payment to the licencing authority was triggered, settled over a 10 year period in equal quarterly instalments. Judgment was required in assessing the appropriate accounting policy for the transaction including assessment of the terms of the arrangement. Such payments are considered to form a cost of the licence and are capitalised to proven oil and gas assets. As at 31 December 2019, the Group is contesting the amount levied by the authorities with a legal process ongoing. As such, a provision for the amounts due has been made based on the most recent amount formally assessed although the final outcome may differ to the amount recorded and the Board is seeking a significant reduction to the amount. Estimation was also required in selecting an appropriate discount rate for the provision and a rate of 2.7% has been applied, based on US dollar Eurobonds yields in Kazakhstan with a comparable term.
2.7 Uncertain tax positions (note 19)
As detailed in note 19, judgment has been applied in assessing the extent to which tax treatments adopted by the Group historically will be accepted or rejected by the relevant tax authority and the resulting measurement of uncertain tax positions in circumstances were it is probable that the treatment will be challenged.
2.8 Indemnity receivables in relation to 3A Best acquisition (note 21)
Under the terms of the SPA for 3A Best, the vendors provided indemnities that obligations related to the period prior to acquisition would be reimbursed. Judgment has been applied in assessing the recoverability of the indemnity receivables detailed in note 21, which included assessment of the terms of the SPA, and assessments of the vendors' ability to meet such payments.
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 phase and commercial phase production are generated domestically in Kazakhstan. 100% of the Group's revenue was derived from two major customers (local market operator - 56% and the export trader - 44%). The revenue split in 2019 between the domestic trader (ANK-Energo LLP) and the export trader (Euro-Asian Oil SA) was US $6,818,000 and $ US $5,290,000 respectively.
Revenue
The Group's revenues are derived from the sale of oil in Kazakhstan. After moving part of O&G assets into Production phase The Group started to receive export revenues in September 2019. During the first quarter of sales the Group could receive cash one month after the delivery of oil. Later, in December 2019 The Group agreed to get a big advance from the export trader ($3.9m). Later, during 2020 The Group managed to repay this advance in full, mainly by way of delivering the crude oil to the export trader.
Under the terms of sales on the local market, 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.
Under the terms of export sales control over the oil delivered is with the Group until the customer confirms it has been shipped on the board of the tanker.
When advances are 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.
No trade receivables or accrued income was applicable at year end (2018: $Nil).
4 Operating income/(loss)
Group operating income/(loss) for the year has been arrived after charging:
Group
2019
US$'000
Group
2018
US$'000
Staff costs (note 6)
(1,420)
(1,319)
Depreciation of property, plant and equipment (note 11)
(148)
(31)
Auditors' remuneration (note 5)
(137)
(220)
Share based payment remuneration (note 6)
(31)
(13)
Reversal of impairment (note 11)
2,414
-
5 Group Auditor's remuneration
Fees payable by the Group to the Company's auditor BDO and its member firms in respect of the year:
Group
2019
US$'000
Group
2018
US$'000
Fees for the audit of the annual financial statements
94
95
Audit related services
9
11
Other services - tax related
8
88
111
194
Fees payable by the Group to Grant Thornton and its associates in respect of the year:
Group
2019
US$'000
Group
2018
US$'000
Auditing of accounts of subsidiaries of the Company
26
26
26
26
6 Employees and Directors
Staff costs during the year
Group
2019
US$'000
Company
2019
US$'000
Group
2018
US$'000
Company
2018
US$'000
Wages and salaries
1,420
590
1,319
782
Social security costs
76
12
108
32
Pension costs
90
-
73
-
Share-based payments
31
31
13
13
1,617
633
1,513
827
Payroll expenses were capitalized in the amount of US$185,500 (2018: US$332,000).
Average monthly number of people employed
(including executive Directors)
Group
2019
Company
2019
US$'000
Group
2018
Company
2018
US$'000
Technical
11
1
10
1
Field operations
47
-
47
-
Finance
9
2
9
2
Administrative and support
16
2
14
2
83
5
80
5
Directors' remuneration
Group
2019
US$'000
Group
2018
US$'000
Director's emoluments
729
540
Share-based payments
25
-
754
540
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$425,289 (2018: US$336,140).
7 Finance cost
Group
2019
US$'000
Group
2018
US$'000
Loan interest payable
82
337
Unwinding of discount on BNG licence payment provision (note 19)
368
-
Unwinding of discount on other provisions (note 19)
2
11
452
348
8 Taxation
Analysis of charge for the year
Group
2019
US$'000
Group
2018
US$'000
Current tax charge
1,860
414
Deferred tax charge (note 22)
483
-
2,343
414
Group
2019
US$'000
Group
2018
US$'000
Profit/(Loss) before tax
941
(2,972)
Tax on the above at the standard rate of corporate income tax in the UK 19% (2018: 19%)
179
(565)
Effects of:
Non-deductible expenses
1,183
23
Return of prior year CIT payment*
-
(1,013)
Withholding tax on interest expense
1,860
1,375
Utilisation of tax losses not previously recognized
(1,888)
(2,882)
Unrecognised tax losses carried forward
1,009
3,476
2,343
414
* During the years ended 31 December 2014 and 2015 the Company incurred taxation in respect of interest accrued on non-current advances provided to a subsidiary. Following subsequent analysis of the agreements it was identified that interest had been incorrectly accrued under the terms of the agreements. Accordingly, during 2016 the Parent company results were restated. As a result the Company resubmitted its CIT returns to HMRC. During H1 2018 the amended CIT returns were proved by HMRC and related tax payment from HMRC has been received by the Company during August 2018.
9 Earnings/(loss) per share
Basic earnings/(loss) per share is calculated by dividing the income/(loss) attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year including shares to be issued.
There is no difference between the basic and diluted loss per share as the Group made a loss for the current and prior year. Dilutive potential ordinary shares include share options granted to employees and directors where the exercise price (adjusted according to IAS33) is less than the average market price of the Company's ordinary shares during the period.
The calculation of earnings/(loss) per share is based on:
2019
2018
The basic weighted average number of ordinary shares in
issue during the year
1,824,955,952
1,669,706,698
The earnings / (loss) for the year attributable to owners of the parent from continuing operations (US$'000)
(1,278)
(3,219)
The loss for the year attributable to owners of the parent from discontinued operations (US$'000)
-
(5,147)
There were 3,000,000 potentially dilutive instruments in the year (2018: 7,200,000).
10 Unproven oil and gas assets
COST
Group
US$'000
Cost at 1 January 2018
84,838
Additions
7,479
Sales from test production
(10,747)
Foreign exchange difference
(13,082)
Cost at 31 December 2018
68,488
Additions
8,886
Sales from test production
(5,466)
Acquisitions (note 21)
11,293
Reclassification to PP&E
(12,000)
Foreign exchange difference
(1,507)
Cost at 31 December 2019
69,694
ACCUMULATED IMPAIRMENT
Group
US$'000
Accumulated impairment at 1 January 2018
15,135
Foreign exchange difference
(2,334)
Accumulated impairment at 31 December 2018
12,801
Reclassification to PP&E
(2,414)
Foreign exchange difference
(733)
Accumulated impairment at 31 December 2019
9,654
Net book value at 1 January 2017
69,701
Net book value at 31 December 2018
55,685
Net book value at 31 December 2019
60,040
Unproven oil and gas assets represent license acquisition costs and subsequent exploration expenditure in respect of three licenses held by Kazakh group entities. The carrying values of those assets at 31 December 2019 were as follows: Beibars Munai LLP US$ nil (2018: US$ nil), 3A Best-Group JSC US$12,666,000 (2018: US$ nil) and BNG Ltd LLP US$47,374,000 (2018: US$55,685,000).
The Directors have carried out an impairment review of these assets on a cost pool level as detailed in note 2.1. No impairment indicators were identified for the unproven oil and gas assets held by BNG Ltd LLP or 3A Best-Group JSC.
11 Property, plant and equipment
Following the commencement of commercial production in July 2019 the Group reclassified part of BNG assets from unproven oil and gas assets to proven oil and gas assets. During 2018 the Group disposed it Munaily assets.
Group
Proved
Motor
Other
Total
oil and gas assets
Vehicles
US$'000
US$'000
US$'000
US$'000
Cost at 1 January 2018
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
Additions
564
-
8,071*
8,635
Transferred from unproved oil and gas assets
12,000**
-
-
12,000
Additions to Proved O&G assets related to BNG licence payment provision
28,335***
-
-
28,335
Reversal of impairment (note 10)
2,414
-
-
2,414
Disposals
-
-
(3)
(3)
Foreign exchange difference
5
-
-
5
Cost at 31 December 2019
43,318
56
8,334
51,708
Depreciation at 1 January 2018
47
80
221
348
Charge for the year
-
9
22
31
Disposals
(47)
(51)
(8)
(106)
Foreign exchange difference
-
(7)
(32)
(39)
Depreciation at 31 December 2018
-
31
203
234
Charge for the year
130
8
10
148
Disposals
-
-
(3)
(3)
Foreign exchange difference
-
-
3
3
Depreciation at 31 December 2019
130
39
213
382
Net book value at:
01 January 2018
-
73
92
165
31 December 2018
-
24
64
88
31 December 2019
43,189
16
8,122
51,326
*$7,966,000 of $8,071,000 relate to the acquisition during 2019 of drilling rigs and other fixed assets. The Group acquired the drilling rigs in September 2019 with 58,333,333 shares issued as consideration with the assets recorded based on the market price of the shares issued.
**$12,000,000 - the amount of O&G assets transferred from Unproven O&G to Proved O&G assets at BNG asset for the MJF structure. Refer to note 2.
*** Refer to notes 19 and 2.
A previous impairment provision amount of US$2,414,000 (US$ 1,931,000 net of deferred tax) was reversed in the period (see note 2)
12 Investments (Company)
Investments
Company
US$'000
Cost
At 31 December 2018
275,911
Receipts
534
Payments
(206)
At 31 December 2018
276,239
Increase in investments
11,795
At 31 December 2019
288,034
Impairment
At 1 January 2018
64,253
Impairment
-
At 31 December 2018
64,253
Impairment
-
At 31 December 2019
64,253
Net book value at:
31 December 2018
211,986
31 December 2019
223,781
During 2019 the Company acquired 100% interest at 3A-Best group JSC for US$11,975,000 by means of issuing the Company's shares. The carrying value of the investments has been assessed by the Directors including consideration of the discounted cash flows associated with the proven oil and gas assets, underlying BNG and 3A-Best contract area progress and the continued exploration value of the assets.
Direct investments
Name of undertaking
Country of incorporation
Effective
holding and
proportion
of voting
rights held
at 31 December 2019
Effective holding and
proportion
of voting
rights held
at 31 December 2018
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
Indirect investments held by Eragon Petroleum Limited
Name of undertaking
Country of incorporation
Effective
holding and
proportion
of voting
rights held
at 31 December 2019
Effective holding and
proportion
of voting
rights held
at 31 December 2018
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
Oil Production Company
3A-Best Group JSC
Kazakhstan
100%
100%
152/140 Karasay Batyr Str., Almaty, Kazakhstan
Exploration
Company
CTS LLP
Kazakhstan
100%
100%
152/140 Karasay Batyr Str., Almaty, Kazakhstan
Drilling & Service Company
During 2019 Eragon Petroleum FZE has established the subsidiary with100% interest: Caspian Technical Services LLP (CTS LLP). The main activity of the new subsidiary is drilling services for the companies of the group. In December 2019 CTS LLP spuded the well #150 at BNG field and successfully completed it in March-April 2020. The company is using the rigs and other equipment acquired by the Group during 2019.
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.
13 Inventories
Group
Group
2019
2018
US$'000
US$'000
Materials and supplies
384
132
384
132
14 Other receivables
Group
Group
Company
Company
2019
2018
2019
2018
US$ '000
US$ '000
US$ '000
US$'000
Amounts falling due after one year:
Prepayments made
2,459
5,516
-
54
VAT receivable
3,286
2,929
69
-
Intercompany receivables
-
-
10,635
3,012
5,745
8,445
10,704
3,066
Amounts falling due within one year:
Prepayments made
1,159
119
7
6
Other receivables*
4,504
245
-
-
5,663
364
7
6
The VAT receivables relate to purchases made by operating companies in Kazakhstan and will be recovered through VAT payable resulting from sales to the local market.
*US$ 3,826,000 out of US$ $ 4,504,000 other receivables at the Group represent the amounts reimbursable by the vendors of 3A Best under the indemnities provided on acquisition of the exploration asset (note 21).
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$12.9 million (2018: US$12.2 million). The movement in the expected credit loss provision related to the inter-company receivables was as follows:
Group
Group
Company
Company
2019
2018
2019
2018
Denomination
US$'000
US$'000
US$'000
US$'000
As at 1 January
-
-
12,212
34,232
Charge
-
-
701
286
Write-off*
-
-
-
(22,306)
As at 31 December
-
-
12,913
12,212
*During 2018 the Company wrote off its fully impaired Munaily receivables following the sale of Munaily and wrote off of its fully impaired Roxi Petroleum Kazakhstan receivables.
The Company recognised US$ 701 thousand of expected credit loss provisions in relation to it receivables from subsidiaries in 2019 (2018: US$ 286 thousand).
15 Cash and cash equivalents
Group
Group
Company
Company
2019
2018
2019
2018
US$'000
US$'000
US$'000
US$'000
Cash at bank and in hand
4,060
557
87
292
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
2019
2018
2019
2018
Denomination
US$'000
US$'000
US$'000
US$'000
US Dollar
3,842
448
87
232
Sterling
-
60
-
60
Kazakh Tenge
218
49
-
-
4,060
557
87
292
16 Called up share capital
Group and Company
Number
of ordinary
shares
US$'000
Number
of deferred
shares
US$'000
Balance at 1 January 2018
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
Share options exercised
4,200,000
56
-
-
Acquisition of 100% interest at 3A Best-Group JSC (note 21)
149,253,732
1,919
-
-
Equipment bought during 2019 (note 11)
58,333,333
729
-
-
Balance at 31 December 2019
1,882,660,885
28,120
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.
17 Trade and other payables - current
Group
Group
Company
Company
2019
2018
2019
2018
US$'000
US$'000
US$'000
US$'000
Trade payables
1,384
861
575
221
Taxation and social security
1,813
180
22
21
Accruals
282
197
172
165
Other payables
4,368
2,235
364
413
Intercompany payables
-
-
30,678
8,232
Advances received (deferred revenue)
6,989
2,786
-
-
14,836
6,259
31,811
9,052
As at 31 December 2019 and 31 December 2018, 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: $6.6m (2018: $10.7m). Excess of revenue recognised over cash being recognised during the period is US$ 7m (2018: excess of cash recognised over the revenue is US$ 3m).
During 2019 the Company has started restructuring of the intercompany loans. The result of the transactions should be a simplified structure of mutual receivable/payable amounts within the group. As a result of the restructuring and associated loan assignments, the Company has a payable to Eragon Petroleum Limited, its 100% subsidiary, of US $30.7 million and other entities reduced their mutual indebtedness to a minimum. As part of the restructuring, previous interest free intercompany payables were extinguished. On initial recognition the liability was discounted using a market interest rate and US$14,936,000 recorded in other reserves, On extinguishment of the liability the reserves has been transferred to retained losses. The restructuring has not resulted in any cash outflows.
17 Trade and other payables - non-current
Group
Group
Company
Company
2019
2018
2019
2018
US$'000
US$'000
US$'000
US$'000
Intercompany payables
-
-
-
16,735
Taxation
12,293
10,286
-
-
12,293
10,286
-
16,735
Taxation payable relate to withholding tax accrued on the interest expense at the BNG subsidiary level.
18 Short-term borrowings
Group
Group
Company
Company
2019
2018
2019
2018
US$'000
US$'000
US$'000
US$'000
Mr. Oraziman (a)
2,288
913
727
-
Fosco BV (b)
661
650
-
-
Other borrowings (c)
1,101
1,009
1,087
400
4,050
2,572
1,814
400
a) At the start of the period under review Eragon Petroleum FZE, a wholly owned subsidiary, had an outstanding loan of US$ 913,000 from Kuat Oraziman. Caspian Sunrise had an outstanding loan of US$ 400,000 from Kuat Oraziman. During 2019 Mr. Oraziman provided an additional US$300,000 to Caspian Sunrise. The total balance of these loans as at 31 December 2019, including the accrued interest, was US$ 1,704,000. Additionally, during 2019 a loan due from Roxi Kazakhstan LLP to KC Caspian Explorer, an entity controlled by Aibek Oraziman, was assigned to Kuat Oraziman. The balance of the loan at 31 December 2019 was US$ 584,000.
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 2019 US$1,101,000 (2018: US$1,009,000) was payable to Kuat Oraziman and a legal entities controlled by Mr Oraziman. The loans are interest bearing with the rate of 7% and repayable during 2020 with the possibility of further extension.
19 Provisions and contingencies
Group only
Employee holiday provision
Liabilities under Social Development Program and historical cost
Abandonment fund
2018
Total
US$'000
US$'000
US$'000
US$'000
Balance at 1 January 2018
93
4,833
194
5,120
Increase in provision
2
-
9
11
Sale of Munaily (note 20
(8)
(795)
(49)
(852)
Paid in the year
-
(318)
(18)
(336)
Unwinding of discount
-
-
11
11
Foreign exchange difference
(12)
(280)
(22)
(314)
Balance at 31 December 2018
75
3,440
125
3,640
Non-current provisions
-
-
125
125
Current provisions
75
3,440
-
3,515
Balance at 31 December 2018
75
3,440
125
3,640
Group only
BNG licence payments*
Employee holiday provision
Liabilities under Social Development Program and historical cost
Abandonment fund
2019
Total
US$'000
US$'000
US$'000
US$'000
US$'000
Balance at 1 January 2019
-
75
3,440
125
3,640
Increase in provision
28,652
-
3,048
450
32,150
Paid in the year
(1,626)
(75)
(339)
-
(2.040)
Unwinding of discount
368
-
-
2
370
Foreign exchange difference
-
-
5
1
6
Balance at 31 December 2019
27,394
-
6,154
578
34,126
Non-current provisions
24,216
-
-
428
24,644
Current provisions
3,178
-
6,154
150
9,482
Balance at 31 December 2019
27,394
-
6,154
578
34,126
*The subsoil use contract held by BNG Ltd for the Yelemes field stipulates that it must make payments to the Kazakhstan Government upon award of a production contract after commercial feasibility. The Kazakhstan Government has assessed the amount payable as a total of US$32.5m. The sum is paid on a quarterly basis from 1 July 2019 in equal instalments and the final payment is due to be paid on 1 April 2029. The payments have been discounted to their net present value. This discounted value has been capitalised as Property, plant and equipment (note 11) and will be amortised over the productive period. Any changes in estimated payments and discount rate are dealt with prospectively and result in a corresponding adjustment to property plant and equipment. The Group is currently contesting the value of the amount assessed.
Amounts in relation to Subsoil Use Contracts are included in the table above and relate to the licence areas 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) 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 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$261,000 per annum should be invested in the social development of the region starting from January 2019;
· To fund minimum cumulative work program during the appraisal period of US$ 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.
On 11 July 2019, BNG Ltd LLP has signed the Production contract with the Ministry of Energy of Republic of Kazakhstan on the part of the territory. The Contract is valid during 25 years till 2043. To reach the expected production levels the Group will over the 25 year period need to drill approximately 15 wells.
c) 3A-Best Group JSC
As at 31.12.2019 3A-Best had the following debts related to its SSU contract: US$2,500,000 of social development payment and about $US 1,000,000 of the debts related to previous years' work program obligations. According to the Addendum #8 to the Contract signed by the company on January 20, 2020 3A-Best has agreed the following schedule of payments related to the social development and the work program related to previous SSUC extension(s):
· To make payment of US$580,000 quarterly during 6 quarters till June 2021;
· To drill 2 shallow wells with the total depth of 5,750 meters during the period January-June 2020;
· To make investments of approximately US$2,350,000 during the period January-June 2020.
According to the SPA related to the acquisition of 3A-Best the Company has been indemnified by the previous owners from any previous debts (quarterly payments of US$580,000 to discharge the historic obligations) and they guaranteed to make repayments on a timely basis. The Group is responsible for the work program obligations agreed with the Ministry of Energy of Kazakhstan for the period January-June 2020 (US$2,350,000). The Group has applied for a deferral of the amounts due and work program commitments. Management believes that the declaration by the Government of Kazakhstan of an emergency situation during March-April and partly in May 2020 as a result of COVID-19 are such that the Kazakhstan authorities will agree postpone the requirement for works until 2021 without negative consequences.
Contingent liabilities
A subsidiary of the Group is subject to an open tax assessment in respect of the 2012 tax year. The Group has taken professional advice and continues to dispute the assessment. If the Group is unsuccessful in defending its position, the amount payable based on the assessment would be US$2 million plus potential fines and penalties. The assessment involves interpretation of contractual arrangements between companies in the Group. The matter is considered to represent an uncertain tax position under IFRS and management have determined that the most likely outcome method of measurement is most appropriate. Based on professional advice, the development of the matter over several years and all relevant facts and circumstances no provision is considered to be applicable.
20 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$'000
Revenue
-
16
Expenses
(334)
(614)
Loss before taxation
(334)
(598)
Cash movements related to Munaily were negligible.
21 Purchase of 3A-Best Group JSC
On 21 January 2019, the Company acquired 100% of the shares of 3A-Best Group JSC, a company that owns a 1,347 sq km Contract Area located close to the Caspian port city of Aktau in the Mangystau Province of Kazakhstan.
The purchase price is satisfied by the issue of 149,253,732 new Companies shares at the price of 6.15 p per share, that represents closing price of Company's shares at the date the SPA was signed and the substantive conditions had been met such that control passed to the Company, notwithstanding delays in the shares of 3A-Best being legally transferred to the Company and associated issuance of the Company's shares in consideration owing to procedural delays. Management have analysed the structure of the transaction and the underlying activities and concluded that the transaction represents an asset purchase.
The fair value of the identifiable assets and liabilities of 3ABest as at the date of acquisition were:
US$'000
Exploration assets
6,404
Receivable from sellers recognized in other non-current receivables*
3,826
Other non-current receivables
502
Total assets
10,732
Current contractual provisions
2,906
Other payables related to contractual obligations
920
Total liabilities
3,826
Total identifiable net assets at fair value
6,906
Total value of shares issued as consideration
11,795
Additional fair value recorded to unproven oil and gas assets
4,889
* Based on the terms of SPA previous owners of 3A-Best must compensate the Group for all contractual obligations of 3ABest incurred in the period up to SPA sign off date under an indemnification in the SPA. Therefore, the Group has recognized the receivable equal to the contractual provisions and other payables related to the contractual obligations in the completion date balance sheet. The Group have assessed the receivable for expected credit losses, considering scenarios around the probability of default by one or more of the vendors and concluded no expected credit loss is applicable.
22 Deferred tax
Deferred tax liabilities comprise:
Group
2019
Group
2018
US$'000
US$'000
Deferred tax on exploration and evaluation assets acquired
7,244
6,733
7,244
6,733
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
2019
Group
2018
US$'000
US$'000
At beginning of the year
6,733
7,784
Deferred tax related to impairment reversal (note 8)
483
-
Foreign exchange
28
(1,051)
7,244
6,733
As at 31 December 2019 the Group has accumulated deductible tax expenditure related to BNG expenditure of approximately US$89 million (31 December 2018 US$97 million) available to carry forward and offset against future profits. This represents an unrecognised deferred tax asset of approximately US$17.8 million (31 December 2018: 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$5.1 million (31 December 2018: US$5.1 million). This asset is fully impaired and there is insufficient certainty of future profitability to utilise these deductions.
23 Share option scheme and LTIP scheme
During the year the Group and the Company had in issue equity-settled share-based instruments to its Directors and certain employees. Equity-settled share-based instruments have been measured at fair value at the date of grant and are expensed on a straight-line basis over the vesting period, based on an estimate of the shares that will eventually vest. Options generally vest in three equal tranches over the three years following the grant.
Number of options granted
Number of options expired
Options exercised
Total options outstanding
Weighted average exercise price in pence (p) per share
As at 31 December 2018
88,458,226
(54,810,830)
(11,100,000)
22,547,396
13
Directors
2,000,000
(807,396)
(4,200,000)
(3,007,396)
-
Employees and others
1,000,000
(200,000)
-
800,000
-
As at 31 December 2019
91,458,226
(55,818,226)
(15,300,000)
20,340,000
15
The options were issued to Directors and employees as follows:
20,340,000 outstanding options as at 31 December 2019 are exercisable.
The range of exercise prices of share options outstanding at the yearend is 4p - 20p (2018: 4p - 20p). The weighted average remaining contractual life of share options outstanding at the end of the year is 4.3 years (2018: 3.8 years).
The options granted in the year are exercisable at 20p with a life of 10 years with employment based vesting conditions. The fair value of the options was determined to be US$ 130,061 using a Black-Scholes valuation model. The key inputs were: Stock price - 0.12 GBP, Expected life in years - 3, Annualized Volatility - 80%, Discount Rate, Bond Equivalent Yield - 1.81%.
Long Term Incentive Plan (LTIP) scheme:
On 5 June 2019 the Company made awards under a long term incentive plan. Clive Carver, Executive Chairman, and Kuat Oraziman, Chief Executive Officer, are entitled to receive cash payments to be triggered by the Company's attainment of both pre-set market capitalisation and share price targets as follows:
Market cap threshold
Share price target
Pay-out rate (each)
Pay-out amount (each)
$ billion
Pence per share
%
$' million
0.8
17.23
0.6
3.0
1.3
20.67
0.6
3.0
1.8
24.81
0.6
3.0
2.3
29.77
0.6
3.0
2.8
35.72
0.6
3.0
The scheme continues beyond the numbers in the table such that with the threshold for market capitalisation increasing at the rate of $0.5 billion and the corresponding share price threshold increasing from the earlier threshold by a constant factor of 1.2. Each threshold must be sustained for at least 30 consecutive days for the awards to be triggered. Payments shall be made only when the Company has free cash either in the form of distributable reserves or as a result of a non interest bearing subordinated shareholder loan or an equity placing at a price not below the relevant share price threshold.
There may be only one pay-out for each market capitalisation threshold crossed no matter how many times it is crossed.
The Group has determined that at inception and 31 December 2019, the fair value of the cash settled share based payment award is immaterial based on analysis of the thresholds, historical volatility rates and the applicable share price and market capitalisation in the period.
24 Financial instrument risk exposure and management
In common with all other businesses, the Group and Company are exposed to risks that arise from its use of financial instruments. This note describes the Group and Company's objectives, policies and processes for managing those risks and the methods used to measure them. Further quantitative information in respect of these risks is presented throughout these financial statements.
The significant accounting policies regarding financial instruments are disclosed in note 1.
There have been no substantive changes in the Group or Company's exposure to financial instrument risks, its objectives, policies and processes for managing those risks or the methods used to measure them from previous years unless otherwise stated in this note.
Principal financial instruments
The principle financial instruments used by the Group and Company, from which financial instrument risk arises, are as follows:
Financial assets
Group
2019
US$'000
Group
2018
US$'000
Company
2019
US$'000
Company
2018
US$'000
Intercompany receivables
-
-
10,635
3,012
Other receivables
4,504
245
-
-
Restricted use cash
241
250
-
-
Cash and cash equivalents
4,060
557
87
292
8,805
1,052
10,722
3,304
Financial liabilities
Group
2019
US$'000
Group
2018
US$'000
Company
2019
US$'000
Company
2018
US$'000
Trade and other payables
6,606
3,293
1,111
799
Other payables - current
-
-
30,678
8,232
Other payables - non-current
-
-
-
16,735
Borrowings - current
4,050
2,572
1,814
400
10,656
5,865
33,603
26,166
Changes in liabilities arising from financial activities
Below is the movement of financial liabilities of the Group for the years ended 31 December 2019 and 2018:
1 January
2019Loans received
Interest accrued
Disposal of loans
Repayment
Foreign exchange difference, net
31 December 2019
Financial liabilities
Borrowings
2,572
1,330
160
-
(28)
3
4,050
1 January
2018Loans received
Interest accrued
Disposal of loans
Repayment
Foreign exchange difference, net
31 December 2018
Financial liabilities
Borrowings
2,132
1,047
337
(326)
(534)
(84)
2,572
Below is the movement of financial liabilities of the Company for the years ended 31 December 2019 and 2018:
1 January
2019Loans received
Interest accrued
Disposal of loans
Repayment
Foreign exchange difference, net
31 December 2019
Financial liabilities
Borrowings
400
1,330
84
-
-
-
1,814
1 January
2018Loans received
Interest accrued
Conversion to equity
Repayment
Foreign exchange difference, net
31 December 2018
Financial liabilities
Borrowings
-
400
-
-
-
-
400
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$ 8.8 million (2018: US$ 1 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. Refer to note 21 for details of the 3A Best credit risk 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 2019 was 9% (2018:6%).
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 2019 and 2018 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 2019 US$'000
4,050
1,384
5,222
-
-
10,656
Group 2018 US$'000
2,572
710
2,583
-
-
5,865
Company 2019 US$'000
1,814
575
536
-
30,678
33,603
Company 2018 US$'000
8,632
210
589
-
23,617
33,048
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$49 million (2018: US$46 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$49 million (2018: US$46 million).
25 Related party transactions (please see also note 26)
The Company has no ultimate controlling party.
25.1 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 18.
25.2 3A-Best acquisition
On 1 July 2019 Caspian Sunrise plc acquired 100% interest at 3A-Best Group JSC by the way of exchange of the shares (note 21). 33.33% of the interest at 3A-Best was owned by Mr. Rafik Oraziman, the member of Oraziman family. As a result of the deal the interest of Oraziman family at Caspian Sunrise plc at 31.12.2019 increased to 44%.
25.3 Key management remuneration
Key management comprises the Directors and details of their remuneration are set out in note 6.
25.4 Purchases
As at year end the Group has no prepayments made (2018: US$2.3 million) and no trade receivables (2018: US$80,000) in relation to STK Geo LLP, the company registered in Kazakhstan, which is owned by a member of Kuat Oraziman's family. Major part of the prepayments to STK Geo LLP has been settled through delivery of works. The remaining part of the receivable from the company of US $ 261,000 has been impaired during 2019.
During 2018-2019 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, amounted US$ 3 million (2018: US$4.2 million). These expenses were capitalized to unproven oil and gas assets. As at year end the Group has prepayments made in the amount of US$ 0.5 million (2018: US$2.9 million) in relation to these drilling services.
25.5 Caspian Explorer
In February 2020, shareholders approved the acquisition of Prosperity Petroleum FZE, the UAE registered entity that is the ultimate holding company for the Caspian Explorer, a shallow water drilling vessel operating in the norther Caspian Sea. The acquisition remains subject to regulatory approvals in the UAE. (see note 27)
26 Non-controlling interest
Group
2019
Group
2018
US$'000
US$'000
Balance at the beginning of the year
(5,605)
(4,654)
Share of loss for the year
(124)
(167)
Exchange differences on translating foreign operations and recycling on disposal
-
(920)
Disposal of Munaily
-
136
(5,729)
(5,605)
As at 31 December 2019 non-controlling interest represents minority share in BNG Ltd LLP and Beibars Munail LLP (as at 31 December 2018: BNG Ltd LLP, Beibars Munai LLP and Munaily Kazakhstan LLP).
27 Events after the reporting period
Acquisition of the Caspian Explorer
In February 2020, the Shareholders approved the proposed acquisition of 100% of the shares of Prosperity Petroleum FZE, the UAE registered holding company of the Caspian Explorer, a drilling vessel capable drilling exploration wells in the shallow waters of the northern Caspian Sea. A majority of the shares of Prosperity Petroleum are owned by members of the Oraziman family and therefore a related party transaction on completion.
The estimated consideration of $25 million to be satisfied by the issue of 160,256,410 new Ordinary shares at a price of 12p per share, a premium of 27.7 per cent to the closing mid-market price on 20 January 2020. Currently the Company is in a process of acquiring the related consent from the officials of Kazakhstan, the Company expects to get all the related permissions during the second part of 2020.
At the date of approval of these consolidated financial statements, Covid-19 continues to spread internationally, contributing to a sharp decline in global financial markets and a significant decrease in global economic activity. On 11 March 2020, the Covid-19 outbreak was declared a global pandemic by the World Health Organization and has since then resulted in numerous governments and companies, including Caspian Sunrise, introducing a variety of measures to contain the spread of the virus. The outbreak has also created significant volatility in financial markets and is considered to have negatively impacted commodity prices, including oil prices, which is relevant to financial performance since year end and may impact future asset values including the carrying value of proven and unproven oil and gas assets should they remain depressed for a prolonged period.
This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.ENDFR ZZGZVRDVGGZM
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