1. Is the acid that was eventually sourced from China the same quality as that which had previously been ordered and is there any left for further acid treatments?
The replacement acid sourced from China had the same characteristics to that originally sourced via Russia. It has been delivered and fully used at Deep Wells A6 and A8.
2. What is the current production (BOPD) from MJF?
Without a contribution from wells 141, 144 or 151 the typical daily production capacity from the MJF structure was 1,400 – 1,600 bopd.
3. What will the total production be when 141/144 and South Yelemes 300 bopd are added?
With contributions from wells 141,144 and 151 the capacity of the MJF structure should be 2,000 -2,300 bopd.
With South Yelemes operating it should increase to 2,300 – 2,600 bopd.
4. You’ve stated that domestic oil prices remain at a historic low @ $6.20 per barrel, is that still the case ? Is there any indication that prices are going up, if so to what and when?
For logistical reasons the oil we are required to sell on the domestic market is sent to the Atyrau refinery. It would seem there is little demand for the diesel that this refinery produces hence the low prices received. On this basis therefore until local demand for diesel picks up it is unlikely the domestic price we receive will increase.
5. From the recent AGM questions, you stated that your net back would be $21 from gross oil @ $40. Oil has been above $40 for many months now, what prices are you currently achieving?
For international sales at $40 per barrel our net after processing and transportation costs is approximately $31 per barrel and after all taxes $23.5 per barrel.
6. 151 didn’t sound that promising, possibly a gas cap. A top of the structure target, are you still confident of success?
Well 151 has not yet flowed at the levels expected. We are installing a pump to assist the flow following which we expect to increase production levels of approximately 300 bopd. To date there is no technical data to suggest the presence of a gas cap.
7. The Caspian Explorer is a great asset if utilised. Is there anymore that can be said re the likelihood of rental income in the near term?
We expect soon to complete on the acquisition of the Caspian Explorer on the terms approved by shareholders in February 2020. No contracts are in place for the future use of the drilling vessel. The Company is however aware of potential interest in developing fields in the northern Caspian Sea previously drilled using the Caspian Explorer.
8. The deeps have been an expensive and painful process for all shareholders. The tone of the commentary on the existing wells suggested that they were unlikely to flow commercially, am I correct in that assumption?
The deep wells at BNG structure have not to date flowed commercially. If they did flow commercially they would be extremely valuable. We continue to work on the four deep wells already drilled with a view to bringing them into commercial production. We are also looking at ways of funding a fifth well, 802, for which we have an existing 2020 work programme commitment to drill,
9. You communicated there was a dispute with the Kazakh regulatory authorities regarding the historic charges due from BNG production, I can see the $23m in non-current liabilities, can you advise the sum you believe Caspian owes? Are you confident that this will be resolved, if it isn’t, what are the options?
When the licence for a structure is upgraded to a full production licence the state is able to levy an assessed charge for the past contribution of the state in the development of that asset.
Following the award of the MJF structure’s export licence the BNG Contract Area as a whole was assessed a charge of approximately $32 million. Our issue is that 100% of that charge has been assessed against the MJF structure, which accounts for only approximately 1% of the BNG surface area.
We are advised that under the regulations the amount assessed against the MJF structure should be pro-rated on the basis of surface area, i.e.1%
However, Covid-19 has resulted in all court hearings to decide the matter being postponed. Until we prevail in the courts we are obliged to continue to pay the assessed amounts on a quarterly basis.
10. Advances from Oil Traders: Please provide a summary of the outstanding amounts owed to oil traders ($3.8m as at 30 June), the current monthly rate of repayments being made (or additional advances being drawn down) and the planned date of final repayment which will allow local sales to return to the minimum required?
At 30 September 2020, the amounts owed to oil traders was $3.6million, all of which was in respect of domestic sales. This is being repaid by monthly deliveries of oil.
Each month we negotiate with the Kazakh authorities on the proportion of the production from the MJF structure which we are allowed to sell by reference to international prices. This will continue to be the case regardless of any amounts owed to international / local oil traders.
11. Please confirm the split between local and export sales likely to be achieved from MJF production after oil trader advances have been cleared.
The maximum we can sell on international markets under our licence is 70%. Recently we have been allowed to sell between 50-55% of monthly production on the international markets. As set out in the response to Q10 this number is not determined by oil trader advances.
12. Oil sales prices: At the AGM you confirmed that the expected net with Brent @ $40 was $21 ($50/$25).Is this net of all costs to Caspian (excluding G&A) and are these numbers still accurate.
Please see the response to Q5 above
13. Directors deferred entitlements: At the AGM you confirmed that the board would not accrue any deferred amounts until September 2020 and then review the situation.
The board has agreed to extend the period for which they receive approximately only 25% of previously paid amounts with no deferment of the balance due until the end of the year, at which point it will be reviewed again.
14. How long do you think that this is sustainable and have you identified a milestone that will trigger the reinstatement to pre Covid19 levels or at least to a level above the current 25%?
Such an arrangement is clearly not sustainable over the longer term. The position will be reviewed at the end of the year.
15. Caspian Explorer: Can you confirm the date that Caspian Sunrise has or will become liable for the Caspian Explorer expenses?
Caspian Sunrise will become liable for the costs of the Caspian Explorer from completion of the acquisition.
16. Is it anticipated that the transaction will go ahead on the terms originally outlined ie for a consideration of 160,256,410 new shares as the completion has passed the long stop date of 30 June 2020 originally agreed?
The original terms have not changed. The longstop date has been extended to the end of the year although we expect completion this month.
17. Prepayments made for drilling services: The accounts show a total prepayment of $4.3m as at 30 June. How much of this prepayment relates to work already carried out in the period to date, and given the tight cash position do you expect to be able to utilize these (prepaid) third parties in the short term without requiring significant further investment, for instance, to continue the development at MJF?
The prepayments in the accounts relate to wells already drilled but not invoiced. Any further new drilling would require additional funding.
18. Clarification of BNG licence obligations: In the RNS dated 18 September 2020 under the impact of Covid-19 you state “Extension to work programs secured at BNG and 3A Best” and you later state in relation to 3A Best that you have “been notified informally that our submission to defer the work programme commitments under this new licence has been accepted”. Have you received any such indication with regard to Yelemes Deep 802?
Not yet for (1) the formal confirmation expected at 3A Best, (2) the upgrade of the South Yelemes shallow structure to export status, or (3) the application to defer the obligation to drill 802 at the BNG Contract Area.
19. MJF: Despite the clear impact of Covid-19 it is easy to see with hindsight that not completing the wells that were planned last year has cost the company dear. Can you provide details of your current plans for MJF.
Agreed. All delays to drilling programmes are expensive in terms of lost production and income. The operational constraints imposed by the actions to deal with the Covid-19 virus have amplified the financial impact of the delays at the MJF structure. For the time being we will look to maximise production from the wells already drilled. Additional funding is required to drill new wells at the MJF structure.
20. MJF 151 – Gas encountered: Was the gas concentration at 151 encountered in the initially tested 0.7m zone or the main target zone? Do you have an understanding of the extent of the gas in relation to other wells planned on MJF and how this may impact your plans going forward?
To date there has been no free gas encountered in any of the wells drilled on the MJF structure. All gas encountered to date is associated gas which comes from the oil as it flows to the surface. This gas is typically used to power onsite generators.
21. Acid treatments: You state “The speciality acid required for the planned treatments at deep wells A6, A8 & 801 was not allowed through the Russian border” and that you sourced acid from China. Was the acid from China the “specific formula” designed by Baker Hughes or something else as you state that A5 had a “conventional” acid treatment?
The acid sourced from China had the same characteristics as that stuck at the Russian border.
22. Are you expecting the “speciality acid” blocked at the Russian border to arrive eventually?
No. The acid sourced via China was a replacement. However, should further acid treatments be conducted we would consider sourcing it via Russia if that option was viable.
23. Am I correct in assuming that A5 as well as A6, A8 and 801 will be treated with the “speciality acid” when/if available and do you have a reasonable expectation that the Baker Hughes designed acid will be more successful?
No. A5 was treated with conventional acid.
Wells A6 & A8 have now been treated with the speciality acid and work is ongoing to clean up both wells to assess the success of the acid treatments.
24. Quarterly update dates. For the avoidance of doubt please can you indicate the likely date of the next quarterly update
No specific date has been set for the update, which would cover Q4 2020. My expectation is that it would be mid-January. In the meantime operational updates will be made as events dictate.
25. Kazakhstan have announced today that they are auctioning 10 sites for sub soil use rights. Can you confirm that these are not Caspian current licences.
26. Can you also confirm that you are confident that the Kazakh regulatory authorities will approve South Yelemes licence and agree to the deferral of Licence commitments as you’ve requested. In summary, is there a risk that you will lose current licences.
We believe our applications are entirely reasonable and justified. There are not the rigs available nor the tubing required to complete the Deep Well 802 even if the funding was available. The impact of the Kazakh domestic oil price being so low and the operational constraints imposed by the impact of the Covid-19 virus have also severely restricted our ability to independently fund such work.
The Kazakh authorities could seek financial penalties of up to 30% of the costs of the well not drilled should they decide against our application for a deferral in the work programme. However, we believe a failure to drill the well according to the existing 2020 work programme may lead to a penalty payment rather than the forfeiture of the BNG licence.
27. In the Interims you’ve stated the following on A5 -;Following a long delay during the period under review work has resumed to attempt to stimulate the well to flow at rates nearer the 3,800 barrel per day experienced for a brief period in November 2017. A conventional acid treatment has resulted in oil flowing to the surface but not yet at the rates previously encountered. This intimates that the well is flowing oil but not at previous rates encountered. Please could you advise what those rates are.
The well is not currently flowing. Following a conventional acid treatment work is underway to remove the tubing to allow the perforated interval to be further cleared by the drillbit. We do not believe any further acid treatments will be required at this well.
28. Could you please give detailed updates re deep wells. Especially prospects on A5
Please see the response to the above questions and the RNS announcement issued earlier today.
29. Are we at risk now or anytime in the short term future of losing our licences with the Kazakh authorities?
We do not believe so. If we do not receive approval for the application to defer the 2020 work programme commitment to drill Deep Well 802 we may incur a penalty charge. Please also see the response to Q26 above.
30. Given how vague answers have been to date, can we please have a definitive answer to what is actually flowing at A5 -ie is it oil? If so what is the API?
No oil is flowing at A5.
31. Is it commercial?
32. How much is flowing ie at what rate and for how long?
None to date.
33. What are the choke sizes?
To be decided.
34. Could you please inform shareholders of which wells you are concentrating on at present
On the MJF structure we are about to commence a workover at well 144. On the Airshagyl structure we are continuing work at A5, A6 & A8. No significant work is underway at 801 and we are not allowed to produce from the South Yelemes shallow wells until the licence upgrade is approved.
12 October 2020