Member Info for Exploration

Mike 007

It’s all very quiet

Andromeda; Block 42/12 - Ensco 120 rig has now moved to work over the Jasmine well-head tower in Block 30/6. I expect Andromeda results confidential because it’s important relative to 32nd Round where CNRL will try to get Block 43/11.

Darach; Block 42/4 - Ensco 121 rig has now moved to Netherlands location, so we can assume well is completed. Oranje Nassau/Spirit group both private and not obliged to release results.

Otherwise, Shell completed their farm in to Simwell’s 41/4 and 41/9, adjacent to CNRL’s P2252, 41/5 & 41/10 and extended their 3D over all four blocks.

Cransly

What’s 1500 MW worth?

Residential power costs $0.12/kWH in Morocco

That’s $120/MWH

Therefore 1500 MW is worth $4.32 million per day.

And;

A 300 mmscfd project would justify a bigger pipeline to connect with the Maghreb pipeline system. In ‘electricity terms’ that about 1500 MW - or about 6% of Morocco’s current generating capacity.

Gassy

Thinking it through using published facts and figures, it is plausible that the value is there although the technical team has failed to see it. Sound is doing itself no favours by neither publishing its own prospect inventory nor a CPR which would provide more credibility.

I posted the comments below yesterday, but the post was removed within an hour. Since it was based on open-source information, I can only assume it was removed because it may have been uncomfortably close to the truth for someone.

Recent posts seemed to agree we will never see Sound’s Prospect Inventory or a CPR for Tendrara. So how can investors understand Sound’s NAV for the property through the eyes of a prospective buyer?

Come to that, how will Rothschilds/Sound justify and recommend the ‘right price’ to shareholders without revealing the commercial metrics in terms of, for example, $/bcf? Will it be a fair value relative to the current market value? To put it another way, does Sound run the risk of selling Tendrara ‘on the cheap’ by failing to understand its own full value potential to potential buyers?

As ‘advertised’ Tendrara is a 10,000 boe/d development + some risky exploration over the long run. But it could just as easily be a 50,000 boe/d project or even more, as described below, with some modest ‘close in’, low risk exploration with a short cycle time. This will attract the attention of potential buyers.

Tendrara Value?

MPE and Fastnet identified the following targets, with ‘most likely’ prospective resources (gross) in 2013. Remember, these PRE-DATE the staged-frac tests of TE6 and TE7, so the risks are probably substantially lower NOW because Fastnet’s risks were influenced by perception of poor Tagi reservoir/production performance without stimulation. Furthermore, various studies of the 3D seismic around TE5 showed amplitude anomalies at Tagi level which might be associated with better reservoir properties. The high side unrisked prospective resources in just this relatively small area of Tendrara exceed 4 tcf.

Belgrinate 212bcf
Rass 353bcf
TE4 262bcf
TE1 312bcf
SBK 205bcf
TE5 310bcf
TOTAL 1655bcf

See pages 14 and 15 of Fastnet’s 2014 presentation for maps/locations of these prospects.

https://www.proactiveinvestors.co.uk/upload/MediaFile/File/2/fastnet_proactive_presentation_july_2014_53c8e2af4de98.pdf

Taken as group, TE5 and nearby prospects could form a commercially robust development hub instead of just TE5 on its own because reservoir effectiveness is more likely to be correlative with TE5, 6 and 7. Here is a link to Edison’s report showing original CPR resource numbers. This is all open source material.

https://docplayer.net/43278631-Fastnet-oil-gas-building-moroccan-momentum-once-again-tendrara-cpr-moves-drilling-closer-foum-assaka-farm-out-terms-eagerly-anticipated.html

Significance;

In a success case, drilling these prospects increases unrisked gross volumes (and value) by a factor of FIVE.

Mr B

Good programme - but did no mention the oil - all the way from Horndean to Storrington

https://sp.lyellcollection.org/content/specpubgsl/471/1/333/F4.large.jpg?download=true

Thanks Sounding Off

I’d missed that. Where was that information announced to shareholders?

Can you say what the average size of prospects are, how many exist and what are the typical CoS.

Longwait

All I’m saying is that MPE identified a cluster of prospects on the 3D seismic which are in a core area near their original TE5 area (subsequently tested by TE6 and TE7) These prospects are all parts of the TE5 Horst which they called ‘Belgrinate’, ‘Rass’, ‘TE1’ and ‘TE4’. Together, these features could create a ~2 tcf development ‘hub’.

TE1 was a gas well drilled by AGIP in 1966 on surface geology. TE4 is a gas well drilled by MPE in 2006 based on 2D seismic. With SBK the prospective resources of these four features add up to 363 -1345 - 4283 bcf gross. Add to this the separate TE5 resources of 30 - 310 - 891 bcf (gross).

These are the numbers from Fastnet’s CPR in 2013. Sound’s contribution to the venture was to demonstrate that staged fracs in sub-horizontal wells enabled commercial flow rates. But now they’ve squandered the opportunity which comes from those results.

MPE commissioned several detailed studies using local specialists including one by Professor Hafid at Kenitra University near Rabat in 2010 This is an excellent review of the structural, sedimentological and diagenetic analysis of the Triassic Formations in the Tendrara 3D Seismic survey area.

Regarding the rest of Tendrara Fastnet’s CPR didn’t add much, save to mention the Russian study with Onhym which estimated 31 tcf gas in place based on primitive geochemistry and paying no attention to the regional diagenitic events which wrecked the Tagi reservoir even before the gas migrated from its source.

PS - Sounding Off - please provide the ‘field inventory’ mentioned in your recent post which you say I have disregarded. On second thoughts, don’t bother - Sound has never revealed it.

Woodrow, Gregory

I made one buy in June 2016 @16.85. The technical fundamentals suggest a price around 40p to 60p for the TE-5 ‘cluster’ alone and assuming zero for the rest.

Based on the figures I have, Sound is trading at a substantial discount vs the technical assessment of just the ‘core area’ described in Fastnet’s CPR.

So why is it discounted? Seems to me the discount is mostly due to lack of confidence in the current management and technical team. To be frank, a couple of ‘junior manager’ types with big company experience could run this project with their eyes shut. It’s not rocket science

Crude

Based on the information I have, I expect those shareholders who bought early will be pleasantly surprised. Fundamental value is there - and always has been, but not to the levels asserted by Sound by exploration. I’m confident I will get my money back with a small profit.

I bought a modest number of shares right at the start of the Morocco venture based on Fastnet’s CPR published in 2013 and my own experience of working and living in the country.

Fasnet’s CPR was conducted by a company called SLR and is a very thorough document. SLR attributed similar gross volumes to the TE5 Horst to those published in Onhym’s more recent CPR. SLR’s work was also used by Edison to provide indicative value - but Fastnet never completed the farm-in to OGIF because their Board pulled out of Morocco when their offshore Foum Assaka-1 well was dry.

SLR’s assessment of TE-5 was contingent resources of 30 - 310 - 891 bcf (gross)

SLR also identified a number of prospects (as defined by PRMS) clustered around the TE5 where previous wells had found gas. These were within or close to the 3D seismic area and could form satellites to a development of TE-5. Their prospective resource figures for this ‘core area’ were 363 -1345 - 4283 bcf (gross). Never mentioned by Sound and we’ve never seen a detailed map of this ‘core area’.

SLR reported other leads and prospects mapped by MPE requiring further de-risking including the ‘A-Structure’ (TE-9), each with with CoS of about 10 % to 16% - mainly due to risk of reservoir presence and effectiveness. MPE had mapped the TE-10 stratigraphic lead, but did not attribute any resources to it and neither did SLR.

SLR also evaluated an existing development plan for the TE5 Horst which was similar to that proposed by Sound and calculated the commercial outcome at $9/mcf gas price at $2.29/bcf (NPV).

Neither MPE nor Fastnet/SLR attributed any resources to the Palaeozoic.

So, with this information and the technical breakthrough of staged fracs in TE-6 and TE-7, Sound clearly had a valuable asset. What could go wrong?

Well, instead of appraising the prospective area in the immediate area of TE-5 Parsons blundered into an exploration campaign of TE-8, TE-9 and TE-10, doomed the venture and pretty much validated Fastnet’s CPR warnings about the poor quality of the Tagi reservoir. If only BM had stood up to Parsons and Sound had explored the lower risk prospects around TE-5 we could all be enjoying a very different outcome.

If you recall, there was an early plan to produce CPR’s on a rolling basis as the new seismic arrived. But that fell by the wayside leading up to the ‘Deep Dive’ where the poor regional characteristics of the Tagi reservoir were ‘revealed’ - despite the fact this was well known from two decades of previous drilling. I remember a question was asked at that event about CPRs and the answer was ‘they cost a lot and tell us what we already know’. Well, they only had to read Fastnet’s CP

Soundingoff

Yes - you are absolutely correct.

Publishing a prospect inventory would be very unwise - it would probably reveal the truth about Tendrara’s value.

N4A

Good point. We’ve never seen a detailed risked, prospect inventory - either generated internally or by a third party which can be used to estimate a Risked Exploration Net Asset Value - or RENAV. This is so fundamental to strategy that it must exist - any chance we’ll see it?

Much has been said about ‘ramping’, ‘exaggeration’, ‘hype’ and so on. But even basic salesmanship Grade 1 requires an understanding of the consequences of claiming something is a lot better than it really is.

Exaggeration is one way to characterize description of oil & gas prospects, but the description of possible business outcomes or encouragement to invest in shares without basis in fact could be described as misrepresentation - ignorant or otherwise.

Hence, ‘Do Your Own Research’

See for yourselves;

https://en.m.wikipedia.org/wiki/Misrepresentation

PNE

If Sound signs the GSA the Exploitation Agreement - according to Moroccan law - requires the development programme to start ‘without delay’.

Clearly Sound cannot meet this requirement, so they’ve settled for a non-binding letter from ONEE indicating a price. But there is no mention of start date, delivery point, penalties etc which a full blown GSA would include. The new owner has to complete that work.

So you are right - there is still a lot of work for the Contractor Party (i.e. new owner) to complete.

The defining moment will be an announcement by Sound of ‘Exclusive rights to negotiate’ to be agreed between the Sound group and a the buyer. There is no requirement for Sound to identify the name of a potential buyer.

It’s same as selling a house - once you agree to a buyer, the house goes off the market to enable solicitors to do their work before the contract is signed.

CEO message to shareholders;

https://en.m.wikiquote.org/wiki/Richard_Mottram

It’s a common problem!

Oiler - I’m not trying to ‘ramp’ anything. I only deal in facts and professional judgement when investing.

Q.If you take another read of my last post you can see I'm saying it require BP as the only production platform available for tying into is the Etap, correct? And it is not a large enough play to justify a production platform, correct?

A. Correct - but CNRL’s strategy is to explore near existing infrastructure where marginal discoveries are commercial.

Q. Since we are on the subject can you inform posters of the Commercial cos for Dewar? Would rather not say? I am aware of the Geological cos.

A. The main determinant for commercial success is scale of reserves. The fact is that both Skua (between 2 and 5 mmbbl) and Seagull (14 mmbbl) are being developed via ETAP means they are commercial. The risked prospective resources for Dewar are 16 mmbbl - which, by comparison with Skua and Seagull, suggests a discovery could be commercial.

Q. Do you want to put a figure on the Pensacola commercial cos?

A. That’s premature. It’s a new play test of a Zechstein target. Could be huge, or nothing at all. But your 20% COS doesn’t take the new 3D seismic into account.

Q. since you disagree with centrica's commercial cos on Selena what's your expert view? Didn't think so.

A. This is my point about your use of old relinquishment reports. Centrica didn’t consider either horizontal drilling or fracking in their analysis. They put a minimum commercial threshold in their report based on a stand alone project + pipeline. Today, it’s a simple tie-back to Shell’s Barque platform and pipeline to Bacton. That’s why a) CNRL took the block and b) why Shell farmed in.

Q, Would you like to point out what in my last post was "irrelevant"

A. The original post by BadA mentioned Dewar. It was you who introduced a whole lot of other questions not relevant to the original discussion.

You are clearly not interested in a unbiased discussion and just want to try and ramp CLNR and disregard the facts.

Let me make it clear for you
Selene prospect has a 15% Commercial cos. WRONG
Pensacola Prospect has a 20% Geological cos. WRONG
Dewar can only be produced from BP's Etap platform. CORRECT
CLNR produce no revenue. CORRECT

Oiler

So, with little knowledge about Dewar, you’ve deemed it non-commercial, too small + then rambled on about other irrelevant topics.

Fair enough, but why is Skua being redeveloped with ~ 2 to 5 mmbbl and seagull sanctioned for development with ‘only’ 14 mmbbl?

The Palaeocene play around Dewar is fairly well understood. In fact, BP drilled the 22/24-1 discovery well on a Palaeocene prospect in 1977 which found oil. Then they drilled deeper into underlying the Triassic structure and found the high pressure/high temperature Marnock field which eventually triggered the whole ETAP concept.

Maybe you can help us. What is the principal determinant between technical and commercial COS for Dewar in this part of the UKCS?

BadA

The link below is a recent example of how OGA encourages companies to co-operate by acting as an intermediary in dispute resolution.

https://www.ogauthority.co.uk/media/6024/summary-of-cygnus-pegasus-oga-recommendation-final.pdf

So if CNRL does drill a successful well on Dewar the government will support them in finding export options via ETAP. Of course, it should never reach a dispute and it’s likely BP will prefer to be involved in the whole value chain if it makes technical and commercial sense.

BadA

I wouldn’t worry about oiler87’s posts - they are mainly inaccurate using out of date figures from 20 year old relinquishment reports. The aim is to disrupt sensible discussion.

The Dewar prospect is right in the middle of the ETAP fields with prospective resources of 40 mmbbl with a technical COS of 40%. For OGA ETAP represents a great example of UK’s maximum economic recovery strategy where numerous interests work together constructively.

The nearby Seagull field (14 million bbl) is due for development and has been sanctioned by the Operator, Neptune and will become part of ETAP. The neat thing about ETAP is that it can handle oil/gas separation via separate oil and gas pipelines to shore terminals.

Regarding Dewar, it’s all in the timing of the need for more liquids at ETAP + a year or two lead to drill an exploration well.

This is a good read - see link below. Makes the case for energy abundance in terms of oil, prices and so on. Governments which rely on oil revenues are now scrambling to attract oil & gas companies attention which is opposite of how it’s been for last 40 years. BP is adapting to the transition.

https://www.bp.com/en/global/corporate/energy-economics/spencer-dale-group-chief-economist/peak-oil-demand-and-long-run-oil-prices.html

Treeman

I guess BP must be prime candidate for Dewar. They got 22/24 in the 5th Round 40 years ago, know the area and need to keep the ETAP fields working at full capacity into the Forties pipeline system. Shell did good work on restarting Skua, but gave up. The CATS pipeline system to Seal Sands has just be sold too.

Right now there are deals aplenty which will drive progress. Exxon is selling out of the Norwegian sector and rumored to be putting its share of UKCS up for sale. I imagine most of UKCS will go to their JV partner Shell.

So quite soon the late stage UKCS business will be dominated by BP and Shell + a few independents like CNRL picking off the remaining choice assets.

Block 22/24 activity - near Dewar prospect

BP is progressing towards a final investment decision (FID) for the redevelopment of a field in the central North Sea. Skua originally produced between 2001 and 2005 from a single subsea well tied back to the ETAP infrastructure. That well pumped put more than 10 million barrels of oil equivalent (boe) at rates of up to 15,000 boe per day. Operator BP and partner Zennor Petroleum (20%), intend to bring Skua back to life again as a subsea tieback to ETAP. An FID is expected in the first half of 2020, with first oil slated for the third quarter of 2022.

According to an update on the Oil and Gas Authority’s Pathfinder database, contracts have already been handed to Genesis for the concept development study and, more recently, to Wood for the topsides pre-FEED study.
The project will require the drilling and completion of two production wells.
Skua will also benefit from the development of the nearby Seagull project – operated by Neptune Energy through the sharing of chemical injection pumps.

https://www.zennorpetroleum.com/operation/skua/

http://www.devex-conference.org/pdf/Presentations_2009/1A0930%20Shell%20Further%20development%20of%20Skua,%20a%20mature%20Triassic%20HPHT%20Field%20in%20the%20Central%20North%20Sea.pdf