REG - Caspian Sunrise plc - Interim Results for the period ended 30 June 2018

Caspian SunriseAnnouncement

28/09/2018 07:05

RNS Number : 2322C
Caspian Sunrise plc
28 September 2018
 


 
 
Caspian Sunrise plc
 
("Caspian" or the "Company")
 
Interim Results for the period ended 30 June 2018
 
Caspian Sunrise, the Central Asian oil and gas company with a focus on Kazakhstan, announces its unaudited results for the six-month period ended 30 June 2018.
 
Highlights
 
In the period under review
 
Corporate / Financial
Oil sales of $5 million
Proposed acquisition of 3A Best
 
Operational - shallow wells
Total oil produced 320,000 barrels - 1,750 bopd
Current production capacity approximately 2,000 bopd
Successful side track at Deep Well 801
 
Enquiries:
 



Caspian Sunrise PLC
Clive Carver, Chairman 
 


+7 727 375 0202 




WH Ireland Limited
James Joyce / Jessica Cave / James Sinclair-Ford
 


+44 (0) 207 220 1666 




Yellow Jersey PR
Tim Thompson


+44 (0) 203 735 8825    
 



 
Qualified Person
 
Mr. Nurlybek Ospanov, Caspian Sunrise's senior geologist who is a member of the Society of Petroleum Engineers ("SPE"), has reviewed and approved the technical disclosures in this announcement. 
 
The information contained within this announcement is deemed by the Company to constitute inside information under Market Abuse Regulation (EU) No 596/2014
 
 
Introduction
 
I am pleased to present this interim statement covering the six-month period ended 30 June 2018.
 
The period under review and subsequently has been one of steady rather than dramatic progress, with work continuing to bring the deep wells drilled at BNG into production so that extended flow tests may be conducted to allow assessments of a reserve base to be made.
 
This report focuses on
 
·      Operational developments at BNG
·      BNG licence renewal
·      Proposed acquisition of 3A Best
·      Financial performance and funding
·      Outlook
 
Operational developments at BNG
 
At our principal asset BNG we are fortunate to have both excellent shallow and promising deep prospects, either of which would provide the foundation for a commercially successful oil production company. Together they represent a rare opportunity to develop a meaningful mid-cap oil company. 
 
Deep Wells
 
In recent  years we have drilled three deep wells, one on the Yelemes structure (Deep Well 801) and two on the Airshagyl structure (Deep Wells A5 & A6).
 
The wells range in depth from 4,432 to 5,050 targeting oil in the Cretaceous and all have been drilled through the salt layer.
 
A common feature of the wells is that they are drilled into conditions of extremely high pressures and temperatures, which have required the use of dense drilling fluids to control the wells as they were drilled. Bringing each of these deep wells into production has proved more difficult and has taken far longer than expected. 
 
With the exception of approximately 20 days in Q4 2017, (including 15 days before the commencement of the formal test) with Deep Well A5, we have not so far succeeded in getting these wells to flow on an extended basis to allow flow tests and reserve estimates to be made. Nevertheless, based on recent operational activity, we are hopeful at least one of these wells may soon start to flow.
 
Deep Well 801
 
Deep Well 801 was originally drilled to a depth of 5,050 meters.  As with the other deep wells drilled at BNG the well was blocked by a combination of the excess drilling fluids and rocks from the potential reservoir.
 
For an extended period we sought to remove the blockage with the use of chemicals and by periodically opening and closing the well as pressures grew. During that time oil flowed to the surface under its own pressure.
 
In May 2018 we announced we successfully completed a 350 meter side-track from a depth of 4,501 meters by-passing the blocked pipe. A 5-inch liner was run to the new bottom of the borehole at a Total Depth of 4,852 meters.
 
During the drilling of the side-track we encountered four potentially oil-bearing intervals. The first of 6 meters between 4,535 and 4,541 meters; the second is of 20 meters between 4,554 and 4,574 meters; the third is of 59 meters between 4,635 and 4,694 and the fourth is of 36 meters between 4,812 and 4,848 meters. Subsequently we perforated 75 meters of the intervals identified.
 
The drilling fluids used to contain the high pressure in the well have been progressively changed to lighter density fluids in preparation for acidizing the perforated reservoir intervals.
 
The depths involved make the use of acid by local contractors more familiar with shallow wells more complicated than expected. Accordingly, it has taken longer than planned to complete the clearing of the well and the commencement of the flow tests.
 
Acid was introduced to the well earlier this week with a view to cleaning any borehole damage caused in the perforating process and enhancing the permeability of the reservoir. We expect to learn soon whether this acid treatment has sufficiently cleared the well to allow a flow test to commence.
 
Deep Well A5
 
Deep Well A5 was originally drilled to a depth of 4,432 meters.  A side-track at an angle of 15 degrees from a depth of 4,082 meters was successfully completed and a 5-inch liner run to the new bottom of the well.
 
The well flowed at a rate of some 3,800 bopd for a 15 day period leading up to a formal flow test in Q4 2017. Several days into the formal flow test an obstruction in the well reduced the flow rate to some 1,000 bopd.  As the principal purpose of the flow test was to establish a reserve estimate we decided to suspend the well test and clear out the obstruction.
 
Recently, a metal obstruction was detected in the well and partially pulled free.  The remaining metal obstruction is being drilled out, after which we hope the well will be ready for re-perform the flow test interrupted earlier in the year.
 
Pressure in the well remains stable at around 450 bar at the wellhead, which suggests there is still good communication throughout the length of the well.
 
Deep Well A6
 
Deep Well A6 was drilled to a depth of 4,516. The principal issue with this well has been that the extreme pressures in the well have resulted in a failure of conventional perforation techniques.
 
Our plan to overcome the high pressure is to use more powerful explosives. The drill pipes to be used in this operation remain in use at Deep Well 801 and will be moved to Deep Well A6 once the current operations at Deep Well 801 are concluded.
 
Shallow Wells
 
MJF
 
The MJF structure was discovered by the Company in 2013.  That year the first well, Well 143, was drilled to a depth of 2,750 meters in the presumed centre of the structure.  Subsequently five further wells were drilled to depths between 2,500 and 2,750 meters.
 
As previously reported wells 142 and 146 reported high water contents. Similarly, during the period under review the water content at the first well drilled 143, increased.
 
The well was taken off production and the bottom of the well re-cemented to isolate the water.  We also reduced the choke size from 9 mm to 7 mm to better manage the reservoir.  We are therefore pleased to report that production from Well 143 has returned to its original level despite the reduction in choke size.
 
The same technique was recently used at Well 142, which is expected to produce at the rate of between 80 and 140 bopd once fully operational.
 
A similar exercise is planned at Well 146 in the near future. We also intend to use this method at Well 808, which if successful could result in a new shallow structure at BNG becoming commercial.
 
BNG Licence renewal
 
As first announced in October 2017,the licence at the BNG Contract Area, which was due for renewal in June 2018, was renewed early for a further six years allowing individual structures to move to a full production basis while allowing continued exploration and appraisal elsewhere on the Contract Area.
 
Under Kazakh regulations once a structure has moved to full production status a portion of the oil produced may be sold by reference to world prices rather than at the domestic prices. All oil produced to date from BNG has been sold at domestic prices less the costs of production, storage and transportation. Our estimate is that all oil sold by reference to international prices would be approximately at least twice the net domestic price.
 
During the period under review and subsequently there have been announcements of changes elsewhere in the relevant Kazakh regulations in relation to the calculation of historic costs, which would benefit the Company but to date have not been enacted. Accordingly, at the Company's request, the date for commencing the upgrade of the licence for the MJF structure to a full producing licence was pushed back to January 2019.
 
Other assets
 
Munaily
 
The Munaily field is located in the Atyrau Oblast approximately 70 kilometres southeast of the town of Kulsary. The field was discovered in the 1940s and produced from 12 reservoirs in the Cretaceous through to the Triassic. Roxi acquired 58.41 per cent interest of the 0.67 square kilometers rehabilitation block in 2008 and funded two wells and one well re-entry. Following the Baverstock Merger our interest in the Munaily Contract Area grew to 99.0%
 
No oil has been produced from the Munaily Contract Area in the period under review or subsequently and we no longer expect Munaily to play any meaningful part in the development of the Group.
 
Non-binding contracts to sell our interest in the Munailly Contract Area have been signed for a nominal purchase consideration and are now subject to Regulatory approval. The accounting value of the Munailly Contract Area was fully impaired in previous periods.
 
Aggregate Production
 
Production in the period under review was 320,000 barrels, principally reflecting decrease in daily production while Well 143 was out of operation.  In addition, all our wells were closed for a period of three weeks for regulatory reasons, after the end of the period under review, as part of the licence upgrade process.
 
The current capacity from our shallow structures is running at the rate of approximately 2,000bopd, consisting of:
· the MJF structure with the capacity to produce at the rate of approximately 1,850bopd.
· the South Yelemes structure with the capacity to produce at the rate of 250bopd
 
We expect to begin to enjoy higher income per barrel from export based prices from January 2019.
 
Reserve update
 
On 2 September 2016, we published a reserves update from Gaffney Cline & Associates, derived solely from our shallow fields, which based on an 100% economic interest is:
 
  (P90)  Proved reserves of 18.1million barrels
  (P50)  Proved and Probable of 29.3 million barrels
  (P10)  Proved, Probable & Possible reserves 45.0 million barrels
 
These  shallow reserves were based on drilling to 31 December 2015. Since then, a further five wells were drilled and of which four are currently producing on the MJF structure.
 
Wells 145 and 146 are outside the already stated MJF structure surface area of 10 km2. Therefore, with Well 145 already a success, and remedial work soon to start at Well 146, we believe the surface area of the MJF structure will increase.
 
We have recently commissioned Gaffney Cline to produce a reserve estimate on our shallow structures and expect the results to be available before the end of the year.
 
Acquisition of 3A Best
 
In January 2018, we announced the intention to purchase a new Contract Area, 3A Best by the purchase of 100% of the shares of 3A Best Group JSC for a consideration of $24 million payable in new Caspian Sunrise shares to be issued at a price of 12p per share.
 
Background
 
3A Best owns a Contract Area of 1,347 sq km located close to the Caspian port city of Aktau in the Mangystau Province of Kazakhstan. The Contract Area is adjacent to and runs under the commercially successful Dunga field, which was discovered in 1966 and developed by Maersk Oil.
 
Based on an assessment of the geology Caspian Sunrise's technical team believe some of the geological characteristics of the Dunga Contract Area are also present at 3A Best. Additionally, they believe the area 2,500 meters and below the Dunga Contract area, which forms part of the 3A Best Contract Area, also indicates the likely presence of oil.
 
490 sq km of 3D seismic has been shot. 1,327 linear km of 2D has been digitised and reprocessed. C2 reserves, using the Soviet system of classification, of 3.67 million tonnes (approximately 26.8 mbbls) have been assigned to the 3A Best Contract Area.
 
Two wells have been drilled on the Contract Area in recent years, both encountering water and signs of oil & gas, although neither was commercially successful.
 
Caspian Sunrise will, by completing the acquisition of 3A Best, become responsible for the outstanding work programme commitment represented by the drilling of one well to a depth of 3,000 meters at an estimated cost of up to $2 million.
 
Related Party Transaction
 
As a result of the shareholdings in 3A Best of the family of Kuat Oraziman, the Chief Executive Officer of Caspian that holds one third of 3A Best and of Kairat Satylganov, its former Finance Director who holds one third of 3A Best, the Acquisition was considered a related party transaction under the AIM Rules. The independent directors of the Company in respect of AIM Rule 13, being Clive Carver and Edmund Limerick, considered, having consulted with WH Ireland, that the terms of the Merger were fair and reasonable insofar as Shareholders were concerned. 
As at 30 June 2018, completion of the acquisition was dependent upon the satisfaction of a number of post signing conditions, including the issuance of a new licence, which remains the case at the date of this report.
Upon satisfaction of the outstanding conditions Caspian Sunrise will issue and seek listing for the new Caspian Sunrise shares. Following the issue of these consideration shares the total number of shares then in issue would then be 1,818,927,552, of which the family of Kuat Oraziman, would hold 795,457,858 shares representing 43.73%
 
Financial performance and funding
 
Interim results
 
These results show that the significant increase of operational and corporate activity has been accomplished without any material corresponding increase in administrative expenses and that the reported loss before tax has fallen compared to the prior period.
 
Accounting policies
 
The accepted international accounting treatment for oil produced under an appraisal licence is to treat the proceeds as a by-product of the Group's main activity.  This means that any revenue in respect of the Group's exploration assets is recorded in the income statement but an adjustment is recorded to cost of sales to reduce the margin on such production to nil and reduce the carrying costs of the development of the Contract Area. Accordingly, until we have a full production licence the full economic impact of oil sales will not be shown in the income statement.
 
Funding
 
The Company's management have produced cash flow forecasts, which show that impact of the higher international prices expected from January 2019 covers the day to day costs of the Company, excluding further deep wells. Achieving increased prices from January 2019 is dependent on the processing of the formal application to move the MJF structure to a full production status allowed for in the renewed BNG licence described above. The Company's management expect the time required to process this application to be a few weeks.
 
Income from production from any of the three deep wells drilled to date would very materially improve the Company's cash flow generation.
 
To the extent that further deep wells cannot be funded from cash flows from our current wells (producing and yet to produce) or from advances from local oil traders against future production from these wells, alternative funding arrangements would need to be put in place.
 
The approach of using local oil trader funding, whilst relatively expensive in the short term, allows the Company to avoid undue dilution at the current share price, which does not yet reflect any deep well successes.
 
Additionally, an undertaking from our CEO Kuat Oraziman, remains in place to provide additional funding if so required.  If ever requested by the board such funding is expected by the board to be of a short term nature dovetailing the funding provided by local oil traders. Accordingly, rather than enter a commercial agreement at the time any such funding is provided, the board and Mr Oraziman have entered in to a framework agreement setting out the basis of any funds advanced by Mr Oraziman to the Company.
 
The benefit of this arrangement, other than providing for commercial clarity, is to allow the Framework Agreement to be approved by the Independent Directors and the Company's nominated adviser WH Ireland as a single related party agreement, rather than each time funds might be advanced.
 
Further details of the Framework Agreement are set out below.
 
Impact of the recent devaluation in the value of the Kazakh Tenge
 
Since 31 December 2017 the Tenge has been devalued by approximately 8 per cent against the Company's reporting currency the US$. As with previous Tenge devaluations this will result in a reduction in the Company's reported operating costs as most staff and many local costs are paid in or by reference to the value of the Tenge, while our income remains denominated in and payable in US$.
 
Despite this commercial benefit the prevailing international accounting standards will require a further reduction in the carrying value of the Company's assets as at the full year to reflect the impact of the exchange rate devaluation, should the current US$:Tenge exchange rates continue through to 31 December 2018.
 
Inclusion of the Company's shares in the AIM 50 index
 
We were pleased to accept a recent invitation for the Company's shares to be included in the AIM 50 index.
 
Related Party Framework Agreement
 
The Company and its CEO Kuat Oraziman have agreed the basis on which Mr Oraziman provides funds to the Company at the request of its Independent Directors as being as follows:
 
The funding would be characterised as an unsecured loan with a repayment period of up to 12 months, and carry an annual rate of interest of 7%.
 
As a result of the shareholdings of the Oraziman family and the position of Kuat Oraziman as a director of the Company the Framework Agreement is considered a related party transaction under the AIM Rules.
 
The independent directors of the Company in respect of AIM Rule 13, being Clive Carver and Edmund Limerick, consider, having consulted with WH Ireland, that the terms of the Framework Agreement are fair and reasonable insofar as Shareholders are concerned.
 
Corporate Governance
 
As required under the changes to the AIM Rules, Caspian Sunrise has adopted a new Corporate Governance Code, the QCA Code.  Full details of how the Company complies with the Code and where it is not in compliance is set out on the Company's website www.caspiansunrise.com.
 
Outlook
 
Getting our deep wells to flow is at the heart of the Group's operational strategy.  It should also have a huge bearing on the underlying value of the Group.
 
We cannot specify a date by which the first of the deep wells already drilled will start to flow, however we still believe we are close at both Deep Well 801 and Deep Well A5.
 
In the meantime, we will continue to develop the MJF and other shallow structures at BNG and move forward with the development of 3A Best.
 
Looking further ahead, it is clear to the board that, once we have the deep wells flowing at BNG, the prevailing reasonably attractive world oil price and limited domestic competition makes further corporate acquisitions of producing fields in Kazakhstan an attractive prospect.
 
 
Clive Carver
Chairman
28 September 2018
 
 
UNAUDITED CONDENSED CONSOLIDATED INCOME STATEMENT
 











Six months ended
30 June 2018
Unaudited






Six months ended
30 June 2017
Unaudited


 












US$000s






US$000s


 
























 




Revenue






5,036






2,761


 




Cost of sales






(5,036)






(2,760)


 




Gross Profit






-






1


 
























 




Share-based payments






(23)






(313)


 




Administrative expenses






(1,360)






(1,105)


 




Operating Loss






(1,383)






(1,417)


 
























 




Finance cost






(6)






(169)


 




Finance income






-






118


 
























 




Loss before taxation






(1,389)






(1,468)


 
























 




Taxation


8


1,013






(643)


 
























 
























 




Loss after taxation






(376)






(2,111)


 
























 




Loss attributable to owners of the parent






(276)






(439)


 




Loss attributable to non-controlling interest






(100)






(1,672)


 
























 




Loss for the year






(376)






(2,111)


 
























 
























 




Earnings per share


3














 
























 




Basic loss per ordinary share (US cents)


 
 


(0.02)






(0.04)


 




























 











































































UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
 











Six months ended
30 June 2018
Unaudited


Six months ended
30 June 2017
Unaudited












US$000s


US$000s






















Loss after taxation






(376)


(2,111)




Other comprehensive loss:
















Items to be reclassified to profit or loss in subsequent periods




















Exchange differences on translating foreign operations






(1,275)


1,743




Total comprehensive loss for the period






(1,651)


(368)






















Total comprehensive (loss)/income attributable to:
















Owners of the parent






(1,370)


831




Non-controlling interest






(281)


(1,199)










 
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
 
 
For the six months ended 30 June 2018







Share capital


Share premium


Deferred shares


Cumulative translation reserve


 Other reserve


Retained  deficit


Total


Non-controlling interests


Total equity




Unaudited


US$'000


US$'000


US$'000


US$'000


US$'000


US$'000


US$'000


US$'000


US$'000




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


-


-


-


-


-


(276)


(276)


(100)


(376)




Exchange differences on translating foreign operations


-


-


-


(1,094)


-


-


(1,094)


(181)


(1,275)




Total comprehensive income for the period


-


-


-


(1,094)


-


(276)


(1,370)


(281)


(1,651)




Arising on employee share options


-


-


-


-


-


23


23


-


23




At 30 June 2018


25,401


228,974


64,702


(56,094)


(2,362)


(211,130)


49,491


(4,935)


44,556



 
 
 
For the six months ended 30 June 2017
 
 







Share capital


Share premium


Deferred shares


Cumulative translation reserve


 Other reserve


Retained  deficit


Total


Non-controlling interests


Total equity




Unaudited


US$'000


US$'000


US$'000


US$'000


US$'000


US$'000


US$'000


US$'000


US$'000




At 1 January 2017


16,000


146,728


64,702


(55,006)


(583)


(127,343)


44,498


2,617


47,115




Loss after taxation


-


-


-


-


-


(439)


(439)


(1,672)


(2,111)




Exchange differences on translating foreign operations


-


-


-


1,270


-


-


1,270


473


1,743




Total comprehensive income for the period


-


-


-


1,270


-


(439)


831


(1,199)


(368)




Purchase of non-controlling interest in subsidiary


8,364


73,183


-


-


(81,861)


-


(314)


(6,571)


(6,885)




Arising on employee share options


-


-


-


-


-


313


313


-


313




Forfeited warrants


-


-


-


-


(1,779)


1,779


-


-


-




Debts converted to equity


1,037


9,063


-


-


-


-


10,100


-


10,100




At 30 June 2017


25,401


228,974


64,702


(53,736)


(84,223)


(125,690)


55,428


(5,153)


50,275



 
 



Reserve






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






Losses arising on retranslating the net assets of overseas operations into US Dollars




Other reserves






Fair value of warrants issued and gain/losses from the purchase of NCI




Retained deficit






Cumulative losses recognised in the profit or loss




Non-controlling interest






The interest of non-controlling parties in the net assets of the subsidiaries
 
 























 
 
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION











As at
30 June
2018


As at
31 December
2017








Note


US$000s


US$000s




Assets






Unaudited


Audited




Non-current assets
















Unproven oil and gas assets


4


64,788


69,701




Property, plant and equipment






112


165




Inventories






163


21




Other receivables


5


11,161


9,255




Restricted use cash






260


263




Total non-current assets






76,484


79,405






















Current assets
















Other receivables


8


1,710


832




Cash and cash equivalents






496


1,479




Total current assets






2,206


2,311






















Total assets






78,690


81,716




Equity and liabilities
















Equity
















Share capital


6


25,401


25,401




Share premium






228,974


228,974




Deferred shares


6


64,702


64,702




Other reserves






(2,362)


(2,362)




Retained earnings






(211,130)


(210,877)




Cumulative translation reserve






(56,094)


(55,000)




Shareholders' equity






49,491


50,838






















Non-controlling interests






(4,935)


(4,654)




Total equity






44,556


46,184






















Current liabilities
















Trade and other payables






9,147


9,538




Short-term borrowings


7


1,743


2,132




Current provisions






4,354


4,399




Total current liabilities






15,244


16,069
























 




Non-current liabilities
















Deferred tax liabilities






7,444


7,784




Non-current provisions






688


721




Other payables






10,758


10,958




Total non-current liabilities






18,890


19,463




Total liabilities






34,134


35,532




Total equity and liabilities






78,690


81,716



 
 
This financial information was approved and authorised for issue by the Board of Directors on 28 September 2018 and was signed on its behalf by:



 
Clive Carver
Chairman
 


 
 
 
 



 

 
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS











Six months ended
30 June 2018






Six months ended
30 June 2017






 












Unaudited






Unaudited




















US$000s






US$000s






 




























 




Cash flow provided by operating activities






















 




Cash received from customers






4,282






6,276






 




Payments made to suppliers and employees






(995)






(1,327)






 




Net cash provided by operating activities






3,287






4,949






 




























 




Cash flow used in investing activities






















 




Additions to unproven oil and gas assets






(3,875)






(4,914)






 




Cash flow used in investing activities






(3,875)






(4,914)






 




























 




Cash flow used by financing activities






















 




Repayment of borrowings






(395)






(140)






 




Net cash used by financing activities






(395)






(140)






 




























 




Net decrease in cash and cash equivalents






(983)






(105)






 




Cash and cash equivalents at the start of the period






1,479






405






 




Cash and cash equivalents at the end of the period






496






300






 



 
 
 




NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL INFORMATION
 
1.      STATUTORY ACCOUNTS
 
The interim financial results for the period ended 30 June 2018 are unaudited. The financial information contained within this report does not constitute statutory accounts as defined by Section 434(3) of the Companies Act 2006.
 
2.      BASIS OF PREPARATION
 
Caspian Sunrise plc is registered and domiciled in England and Wales.
 
This interim financial information of the Company and its subsidiaries ("the Group") for the six months ended 30 June 2018 has been prepared on a basis consistent with the accounting policies set out in the Group's consolidated annual financial statements for the year ended 31 December 2017. It has not been audited or reviewed, does not include all of the information required for full annual financial statements, and should be read in conjunction with the Group's consolidated annual financial statements for the year ended 31 December 2017. The 2017 annual report and accounts, which received an unqualified opinion from the auditors, did not draw attention to any matters by way of emphasis, and did not contain a statement under section 498 (2) or 498 (3) of the Companies Act 2006, have been filed with the Registrar of Companies. As permitted, the Group has chosen not to adopt IAS 34 'Interim Financial Reporting'.
 
The financial information is presented in US Dollars and has been prepared under the historical cost convention.
 
The accounting policies adopted in the preparation of the interim condensed consolidated financial statements are consistent with those followed in the preparation of the Group's annual financial statements for the year ended 31 December 2017 except for the effect of new standards effective from 1 January 2018 as explained below. These are expected to be consistent with the financial statements of the Group as at 31 December 2018 that are/will be prepared in accordance with IFRS and their interpretations issued by the International Accounting Standards Board ("IASB") as adopted by the European Union ("EU"). 
 
The Group has not reclassified the potential Munaily disposal group as non-current assets and liabilities held for sale, as give the history of the licence and requirement for regulatory approvals in Kazakhstan, the criteria under IFRS 5 are not considered to be met at 30 June 2018. The Munaily asset was fully impaired historically.
 
During the period, several new and revised Standards and Interpretations issued by the IASB became effective. IFRS 2 - Classification and Measurement of Share-based Payment Transactions, IFRS 9 - Financial Instruments, IFRS 15 - Revenue Recognition as well as IFRIC 22 - Foreign Currency Transactions and Advance Consideration took effect on 1 January 2018.
 
IFRS 9 'Financial instruments' addresses the classification and measurement of financial assets and financial liabilities and replaces the guidance in IAS 39 that relates to the classification and measurement of financial instruments.  IFRS 9 retains but simplifies the mixed measurement model and establishes three primary measurement categories for financial assets: amortised cost, fair value through other comprehensive income (OCI) and fair value through profit or loss.  The basis of classification depends on the entity's business model and the contractual cash flow characteristics of the financial asset. There is now a new expected credit loss model that replaces the incurred loss impairment model used in IAS 39. It is noted that VAT receivables and prepayments are excluded from the scope of IFRS 9. The Group has applied the modified retrospective approach to transition. The adoption of IFRS 9 did not result in any material change to the consolidated results of the Group. Following assessment of the consolidated financial assets no changes to classification of those financial assets was required.  The Group has applied the expected credit loss impairment model to its financial assets.
 




IFRS 15 introduced a single framework for revenue recognition and clarify principles of revenue recognition. This standard modifies the determination of when to recognise revenue and how much revenue to recognise.  The core principle is that an entity recognises revenue to depict the transfer of promised goods and services to the customer of an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The adoption of IFRS 15 did not result in any material change to the Group's revenue recognition following analysis of its contracts.
 
Another new Standard, IFRS 16 - Leases takes effect on 1 January 2019. The Management are currently assessing the impact of this standard as whilst there are no material operating leases in the Group it may be relevant to future operations including service agreements containing the use of assets.
 
Going Concern
 
The financial information has been prepared on a going concern basis based upon projected future cash flows and planned work programmes.
 
Additional funding would in the opinion of the Directors be available if required from the sale of oil produced during testing.
 
The Directors are confident, on the above basis, that the Group will have sufficient resources for its operational needs over the relevant period, being until September 2019. Accordingly, the Directors continue to adopt the going concern basis.
 
 
3.         LOSS PER SHARE
 
Basic loss per share is calculated by dividing the 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 loss per share is based on:
 







Six months
ended
30 June 2018 Unaudited


Six months
ended
30 June 2017 Unaudited


 




The basic weighted average number of ordinary shares in issue during the period


1,669,673,820


1,043,807,337








The loss for the year attributable to owners of the parent (US$'000)


(276)


(439)







 
There were 8,400,000 potentially dilutive instruments in the period (2017: 8,400,000).
 
4.         UNPROVEN  OIL AND GAS ASSETS
During six months period ended June 30 2018 the Company's oil and gas assets decreased by US$4.9 million mainly due to foreign exchange difference in the amount of US$ 6.7 million; also additions were made in the amount of US$ 1.8 million (2017: US$3.1 million increase due to additions).
 
5.         OTHER NON-CURRENT RECEIVABLES
During six months period ended June 30 2018 the Company has provided advances related to its drilling operations in the amount of US$2 million (2017: US$3.8 million).




 
 
 
6.         CALLED UP SHARE CAPITAL
 



 






Number
of ordinary
shares


 
 
$'000


Number
of deferred
shares


 
 
$'000
































Balance at  31 December 2017 and 30 June 2018






1,669,673,820


25,401


-


64,702



 
 
 
7.         BORROWINGS







Six months ended 30 June 2018


Year ended 31 December 2017




US$'000
Unaudited


US$'000
Audited




Amounts payable within one year












Prosperity(a)


1,003


1,196




Other payables(b)


740


936








1,743


2,132



 
(a)  During December 2017 Eragon Petroleum FZE (a subsidiary of the Company) received a US $1.2 million loan from KC Caspian Explorer (KCCE), a 100% subsidiary of Prosperity Petroleum Ltd ("PPL") under a loan provided by PPL. PPL is a company controlled by Mr Kuat Oraziman and therefore a related party of the Group. The loan is interest free and matures in December 2018. The loan has been repaid partially during the 6 month period ended 30 June 2018.
 
(b)  The total amount borrowed by the Group at 30 June 2018 US$740,000 (31 December 2017: US$936,000) was payable to Kuat Oraziman  and legal entity controlled by Mr Oraziman. The loans bear the rate of 1.7% and are repayable on demand.
 
 
8.         OTHER RECEIVABLES
 
During the years ended 31 December 2014 and 2015 the Company incurred taxation in respect of interest accrued on non-current advances provided to a subsidiary.  Following subsequent analysis of the agreements it was identified that interest had been incorrectly accrued under the terms of the agreements. Accordingly, during 2016 the Parent company results were restated.  As a result the Company resubmitted its CIT returns to HMRC. During H1 2018 the amended CIT returns have been approved by HMRC and related tax receivables in the amount of US$ 1,013,000 have been recognized in the accounts. The tax payment from HMRC has been received by the Company during August 2018.
 
 
 
 
 




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