Caspian Sunrise plc: 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.