Tim Watts, CFO at Shield Therapeutics #STX presenting at our Life Sciences Investor Briefing Watch Now
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
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?
The link below is a recent example of how OGA encourages companies to co-operate by acting as an intermediary in dispute resolution.
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.
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.
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.
Lone Star still in court. Lone Star became Maghreb and then morphed into OGIF.
Note, this involved SBK/Tendrara. The lawsuit, dating back 20 years, which was supported by the Moroccan royal family, alleged DeJoria mismanaged the company, inflated expectations and convinced Moroccan participants to invest in the venture.
Oiler/Edward/a1m1/etc doesn’t pay much attention to the wider picture. The posts are designed to provoke responses.
But here’s the situation;
Drilling on CNRL’s Zechstein play has seen two wells on trend in recent months. The first was Union Jack’s West Newton onshore appraisal well which found gas and condensate and is awaiting testing. The other is Oranje Nassau’s exploration well on huge the Ossian/Darach reef in Block 42/4, which is reported to have been sidetracked - probably for more coring. And Simwell farmed out their blocks 41/4 and 41/9 to Shell who extended their 3D survey by 200 sqkm.
The 32nd Round applications are due in November and CNRL has said it intends to re-apply for Block 43/11 which formed part of the P2248 licence. Hague and London are drilling the Andromeda prospect in 43/12 at the moment which might extend the Cygnus/Pegasus productive trend and turn 43/11 into ‘hot property’ - which means that drilling resultswill be highly confidential.
So there will be a lot of news flow in CNRL’s core area.
Thanks. Yes, it’s Onhym’s favourite video for which BM was awarded ‘arm waver of the decade’ award! Of course the big prize - ‘straw clutcher of the century’ goes to Parsnips for claiming the Tagi is nothing and the big gas is in the Palaeozoic.
Jobbinsci, fair enough
Cash was $14 million as on May 14. But at December 31 2018 cash was £20.5 million, call it $30 million so the cashburn was/is pretty steep. And trade payables from TE-10 would be outstanding.
Based on previous annual PLC overheads, the PLC spend rate for the remainder of 2019 will be, say another $6 million. Then there is the $2.7 raise.
So that means money left is $14 + $2.7 - $6 = $10 million. Not enough to pay for Sidi Moktar seismic.
But the $20 million loan is secured against Sidi Moktar, so they can’t lose that - unless the security is transferred to JP’s house etc.
All I’m trying to say is that Sound has to a) sell fast and b) juggle our money to stay in business without falling foul of Onhym and the Companies Act
No conspiracy involved. Just describing how companies run petroleum operations according to the law in Morocco.
See Clause 6 of the Association Agreement. Sure as night follows day, Management Committee meetings for Tendrara occur every six months. Accurate minutes are prepared and distributed for approval by all participants. Same for Sidi Moktar.
You can see the penalties for non-payment of contributions to budgeted operations. But I’m assuming there is little Sound can propose without plenty of cash in the bank or they wound fall foul of the Companies Act.
Just projecting estimates from JJ Traynor’s Malcy interview. There must be a point when liabilities and commitments imply more money is needed. It could be as soon as November - so Sound must sell before then or risk wrongful trading.
Follow the money.
Maybe the main reason for the ‘pause’ and start of marketing is that there is insufficient cash in the bank to pay all the TE-10 demobilisation bills, re-instate TE-8, 9 and 10 well sites, maintain the corporate fixed costs (acreage rentals, insurance, sevenoaks, etc) AND remain solvent until end-2019. My guess is that there isn’t enough cash to drill TE-11 and acquire the Sidi Moktar seismic according to the agreement with Onhym.
Sound is obliged to submit annual work programs and budgets for the coming year. If insolvency is a consequence, what will they do?
I agree - can’t beat drilling to see what’s there.
TE-1, TE-2 and TE-3 - all close to TE-5 - recorded gas shows in the same sequence as TE-5 and may be capable of producing gas. Same for SBK-1.
But wells drilled away from basement highs, including TE-8, 9 and 10 proved the reservoir is non-productive although there were gas shows. In TE-10 we didn’t get the whole story but it seems some gas reached the surface when the well was reverse circulated and a bubble of gas came up the Annulus. Not even enough for a BBQ.