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Please remember I'm just a 30yr O&G Driller with distant MBA and 10yr petroleum eng before that so, no more commercial 'nouse' than most folk on here...questions...
1 MD&A FY '21 text below - Anyone know what "and any further resulting damages" means ?...could it include any related default penalties imposed on COPL ?
2 From below, COPL won lawsuit placing it ahead of any CUDA creditor. How off-putting might that be to potential bidders or lenders ?
3 Why did COPL announce 1-2 billion bbl OOIP discovery and particularly the timing as it is odd to alert potential bidders and Receiver to an enormous potential upside ?
4 How could COPL afford CUDA LOI deposit let alone full purchase ?
MAYBE...
- Aug '21 - COPL drills exploration well while CUDA sale on-going
- Nov '21 - no CUDA buyer, enters Receivership, defaults on COPL payments while 14-30V not an approved production well cost $3.5mm (100% COPL). Lender sees covenants breached
- Dec '21 - Lender obliges COPL to restore financial covenants by emergency placing and sp 'tanks'
- Jan/Feb '22 - COPL announces discovery size to inform Market and restore sp and then CEO buys 250k GBP shares to send another positive signal
- Feb '22 - Bidders now have no idea what to bid plus unknown CUDA default/damages claim
- Mar '22 - Existing or new lender already agreed to CUDA
"...In July 2021 SWP filed a claim (the "Claim") in the Eighth Judicial District Court, State of Wyoming as plaintiff against Cuda, Bridging Finance, Inc. ("Bridging", and Tallinn Capital Energy L.P. ("Tallinn") as defendants. SWP's Claim seeks the following heads of relief: a judicial foreclosure order against the defendants of the SWP liens on Cuda's interest in the BFU, which includes Cuda Oil and Gas Inc., Bridging and Tallinn; an award of damages for breach of contract by Cuda; a quantum meruit or unjust enrichment judgment against Cuda; damages for a breach of promissory estoppel against Cuda; and a declaratory judgment as to the lien priority against Bridging and Tallinn to affirm SWP's first lien priority on Cuda's security against the BFU. Cuda received a copy of the court stamped Claim by email on July 27, 2021 and subsequently accepted service of the Claim on August 12, 2021. Subsequent to filing that Claim, SWP received a payment of $1.9 million from a legal advisor's trust account on behalf of Cuda to settle certain outstanding amounts. As that payment did not meet the full amount due, further expenses have been incurred on Cuda's account such that as at December 31, 2021, Cuda's current operating arrears owed to SWP is $3.2 million as reflected on Cuda's joint interest billings from July 2021 to December 2021, net of its petroleum sales. It should be noted that unless payments are received on time, the Claim against Cuda will be subsequently amended to reflect Cuda's ongoing cumulative arrears, and any further resulting damages. The Company intends to take all action available to recover sums due to it
Tiburn,
All well data from WOGCC database.
All previous Operators are long gone...and, until Chesapeake saw and bought-up the entire BFU Shannon area there was no chance to develop the whole field with MF e.g. Valentine-1 produced by itself from Frontier-3 for 30yrs initially by Mobil and Fed 12-26 produced from Muddy for 22yrs by itself operated by Gulf Oil initially until both switched to Shannon production in 2017 by a new, single Operator i.e. no-one previously looked for the deep 'big picture' either. I suspect Chesapeake had the goal to re-look at the deep horizons once the Shannon project was underway (as did Atomic), as it arranged both BFU Shannon and BFU Deep unitisation agreements which is evidenced by Atomic's WBF 40-36V 2018 well plan and COPL's 14-30V well drilled in 2021. Obviously, areas outside BFU Deep would need 'unitising' if any field-wide secondary recovery was to be implemented but, as with nearby Sand Dunes field and its MF, if there is money to be made then deals get done.
Gentlemen,
While we await official news...oilfield formulae online include volumetric original-oil-in-place. Other OOIP calcs exist which yield different values so please DO NOT treat as 'gospel' but does serve as a 'sense-check for claims made to date:-
OOIP = N=7758*A*h*?* (1-Swi)/BoiN where; A = acres, h = reservoir (net) thickness, ? = porosity, swi - water saturation, BoiN = formation volume factor
Using BFU/CC values. If A = 50,000 acres, h = 80ft, ? = 15%, swi = 30% and FVF = 1.2 RB/STB gives....or, reduce key volumetric variables (acres x ft), to 12,500 and 20ft gives......y'all can use a calculator like me....do they merit 'falling off your chair' or maybe rock slightly ??
Of passing note:-
- Gulf Oil drilled Parkerton Ranch 13-23 in 1997 (~330m from BFU 14-23V) and 'missed' BFU Shannon and PA'd having tested Lakota only. Of course, there may be nothing deeper but missing the BFU Shannon is maybe not a great start ?
- Mobil (of Exxon-Mobil), drilled Valentine-1 in 1981 and 'missed' BFU Shannon but found/produced ~114,000bbl from Frontier 3. Chesapeake then ‘discovered’/produced BFU Shannon from 2012 by simply reviewing data, re-completing and perforating !
- Mobil (of Exxon-Mobil), drilled Cole Creek 12X-22P in 1968 and 'missed' the Frontier. Blue Tip Energy drilled a new well 5-22 (~150m away), and ‘discovered’/produced it from 2012
- General American Oil Co Of Texas drilled Cole Creek 12F-23P in 1952 and 'missed' the Frontier. Blue Tip Energy drilled a new well 12-23 (~350m away) and ‘discovered’/produced it from 2012
- In 1952, KD Owen drilled Radigan-1, principle offset ~800m west of BFU Fed 14-30V (NB: Atomic 2018 permitted WBF 41-36 to the same target formations. I think COPL switched it to Federal 14-30V location to meet the Federal (deep) exploration obligation, suggesting Atomic owner who bought BFU in Chesapeake's bankruptcy was fully aware of its exploration potential and keen to drill ?).
- Some may wonder how the reservoir intervals, identified by COPL in 2021, were 'missed' earlier, particularly by such companies as Mobil and Gulf Oil. In part, COPL noted the particularly bad drilling/loss problems at 14-30V which are prevalent and widely reported in many other BFU/CC wells on WOGCC website. However, an important economic factor not to overlook is the prevailing oil price. In 1952, oil price was $2.77 ($30/bbl adjusted for inflation to 2021), in 1968 oil $3.18 ($26/bbl today) and in 1997 oil $18.64/bbl (or $32/bbl today), all of which would be tough to make money today and possibly the lack of commerciality at the time explains why they went 'undiscovered' ?
- Reading the well confidentiality rules on WOGCC website....it states confidentiality is for 6 months initially and can be extended by WOGCC BUT NOT if the well is producing...whether being a Federal/BLM well makes any difference I do not know but, if not, BFU Fed 14-30V data may be available toward the end of March....
Gentlemen,
At the risk of being boring, anyone can contact the Receiver and ask for the status of the CUDA sale. It is not 'inside information' as some claimed when first posted last Saturday.
"FWIW and y'all can verify with Receiver so please don't shoot the messenger.
Receiver advised today "....USA asset sale is still under review. Additionally, it will need to go through the same process of the 6 weeks with court approval, once a LOI is signed"
It would appear, to me, that the information given by the Receiver was accurate insofar as we saw/have seen nothing on SEDAR, COPL or Receiver's CUDA webpage as of the 15th. The Receiver did add that the Canadian asset sale was proceeding on the original schedule but would not announce anything formally until the Court had finally approved it.
If the latter advice is correct too and given we have seen nothing on SEDAR or Receiver's webpage, it suggests the preferred bidder is not disclosed in case something goes wrong during the Court approval process. That would seem a quite reasonable thing to do. And, I suspect Mr. Market figured this out well before me.
There is no agenda here, except in good faith, informing the BB.
FWIW and y'all can verify with Receiver so please don't shoot the messenger.
Receiver advised today "....USA asset sale is still under review. Additionally, it will need to go through the same process of the 6 weeks with court approval, once a LOI is signed"
Sir,
Not a Yorkshireman but 3yrs at Leeds Uni too many decades ago and too many pints of Theakston's along Otley Road !
'Grand' idea and if ONS estimated 100,000 millionaires in Yorkshire could be 'tapped' then only need £6k/head....'small beer' to those folk and benefits Yorkshire and its folk and not some multi-national 'predator'.
Maybe also start Parliamentary petition, get 100,000 'hits' and earn right for questions in HoC to get national coverage ?
Completed survey more and happy to invest in SXX...was actually considering it when things went pear-shaped.
Good Luck
Good Luck
Gentlemen,
FWIW.. logical the answer lies somewhere between Alan2017 and xxxyyyzzz...Alan2017 can judge ramp/de-ramp ?
Agree, hard to imagine EA issue given all the SCC 'hoopla' and an RNS starting test and then EA shutdown.
Agree w/ Alan, oilfield is 24/7. What makes (some?) sense is an operational issue requiring kit/personnel not available this side of Xmas and Angus doing some additional analytical work (per RNS).
If so, disappointing but in reality simply a delay...Brockham oilfeild still there, right ?
Check HH-1 start-up and CEO interview, well did not flow straightaway and took some time. Maybe similar here or host of mechanical perforating/completion issues ?..."s_it happens" in the oilfield and you just have to work through and there's never a good time !
Before someone mentions Balcombe flow 'immediately' may be due to being in 'sweet spot'...
Have a great Xmas and New Years !
Gentlemen,
Like many others the Twitter news earlier was disappointing but things like this are not uncommon especially in the first well in a new location and new rig crews. However, I contacted James Berwick to check, received a similar response to others and confirmed subsequently the shutdown was for 2 days. (NB: he uses the term 'tight hole' below which is 'oily' speak for 'keeping things secret'...we will see how successful that turns out to be...)
"so far our geological model is spot on. We cleaned the mud tanks because we were seeing blockages in our pressure readings. We really like to deal with issues where possible before they arise. Wrt tight hole we are planning to release as much info as possible."
James.
Gentlemen,
FWIW...as drilling engineer, offer some 'oily' background:-
1. If R1/R2 last Fri-Sat and if 4 days to Mango then log (1-2 days), plus Govt RNS approval time (wouldn't expect much/any as more a courtesy given the data is the data).
2. Drilling HC indicators; background/connection gas, oil shows/staining on cuttings are not credible report to external sources...BUT if there were no sands/no indicators that might have 'leaked' by now...
3. Wireline log data is standard...if more logs run the more likely something of interest....the longer it takes...
4. So, barring any other delay, should be at section TD and preparing/conducting logs now
Nothing suspicious time-wise so far...but as data is acquired those with 'inner access' can move before PIs...but those Sp movements generally very quick up or down...unfair, yes, but AIM little different to main Markets....
Hope it helps steady any 'frayed' nerves but do please remember exploration (even early appraisal) is a risky business hence much higher potential reward....seen prognosed targets fail and then secondary or even unprognosed targets come in but also seen many 'dusters'.l...
".faites vos jours" and GLA
Gentlemen,
No doubt AST has 'chequered' past (and present TBA).
But to answer query re- 2012 production (from Phase I - 2 well production) and 2014 IPPC application (for Phase II contingent on Phase I results), seems a reasonable explanation for time difference per 2013 Final Report below.
Unless someone is aware of something else going on ?
"Phase 1: After the recompletion of Pg-10 and Pg-11A with custom designed production strings, it is planned that gas from these wells will be brought on-stream via dedicated well-site facilities, through the modified, existing, gas central processing plant (CPP) and, from there, to the national gas pipeline terminal. Previously, gas produced from the Petišovci wells was processed at a local methanol plant, but this is currently shut down. The modifications to the CPP are therefore required to upgrade the gas to the national pipeline specifications; these will reduce the CO2 content from approximately 3% to less than 1.5%, remove the condensate in the gas for sale separately and ensure dew point control by dehydration. The Phase 1 maximum production rate is set at 8,000 m3 per hour, approximately equal to 7 MMscfd. In May 2012 the Company announced it had secured a €15 million facility from BNP Paribas (BNPP) to enable Phase 1 to move ahead and for production to commence. Unfortunately this facility was subject to the obtaining of certain consents from its Joint Venture Partners and additional signatories to the Joint Venture Agreement. The consents from four additional signatories to the Joint Venture Agreement have yet to be secured. The Company continues to apply pressure at a number of levels in order to secure a resolution to the current impasse.
Phase 2:Â Once the medium term performance of the wells is established, and subject to obtaining the necessary consents, a new 'greenfield' processing facility will be designed. It will perform the same function as the modified existing CPP but will be of substantially higher capacity. This will necessitate enlarged gas export capacity and modifications to the national grid connection. It is estimated that 30 or more new wells are expected to be required to maintain these flow rates for a period of over 10 years and to be able to maximise the recovery from the reservoirs. The Phase 2 facility is expected to take at least 30 months to design, permit, construct and commission, and during this time the first of the new wells will be drilled.
Gentlemen,
Whilst fathoming NewCo, is it worth asking GR what Cadence's revised terms were which he rejected ?. RNS simply advised 'unable to reach final terms'. Is that option still open ?
Maybe GR right to reject but NewCo doesn't seem too well thought out based on its presentation and detail to date.
And, if NewCo is such a good idea why was it not presented (much) earlier ?
Bugsy-b
Saw headline too...24 October....one 'oil major' became BH 29 October...31 Oct RNS advises "second industry major"
Of little/no consequence.....que sera sera....ATB
Gentlemen,
Like many here, the 'industry major' turning out to be an industry major service provider was a little disappointing.
Has ZZ stated the second 'industry major' is an oil company ? Or, is ZZ using the term differently ?
If so, the other 'industry major' could be Schlumberger or Halliburton and not the Oil major (EoM, BP), hoped for ?
Not familiar with contracting rules in Georgia but elsewhere Operators must competitively tender to :-
(a) enable FRR to fully cost recover from the Government in the future
(b) avoid service provider (BH) simply charging Price Book rates which would be distinctly unfavourable.
However, if 2 industry major service companies are interested then some competition on rates exists.
Given the unknown/complex scope of work (i.e hard to define for contracting purposes), the Georgian Government may allow FRR's approach to expedite development and cost recovery purposes. And, if the second 'industry (service) major' withdraws FRR can say it had tried to obtain a second bid. Weaker negotiating position maybe with BH but until the second 'major' decides its approach then BH would need to be aware a 'sharp pencil' is required on any pricing proposal meantime.
If 'bona fide' Oil major then obviously good for FRR but it too would usually want competitive tendering to comply with its contracting standards. But, if only one (credible) service provider in-country then sole sourcing is permissible.
Thoughts ?
Gentlemen,
Invested here for just over 1yr so I don't know all the prior minutiae but have significant 'skin-in-the-game'
Someone claimed last night that a BoD member received a significant 'Production Commencement' Bonus. Do any LTH know if this is true ? I asked CH to clarify also today but no response thus far.
Personally, I agree with performance related payments (best administered with independent management oversight).
Now, it may not have surprised some (but it did me), to learn in Q1 2018 the reason for Pg-11a poor well performance was water production and a stuck toolstring which subsequently prevented remedial workover access. As such, the well had been produced at reduced and declining rate since production start-up compromising the revenue stream and AST's ability to sustain normal operations' self-funding as I (we all ?), had expected leading to the situation today. Management would have been aware of this though, right ?
So, if any BoD member took a production start-up bonus then I would reason it's a little premature in the spirit of the award, at the least, and hope the BoD member(s) agreed given the circumstances.
And, if the sum is sufficient to avoid this proposed placing (a surprisingly large £MM 7.0 was mentioned), then would it not be reasonable for shareholders to request the bonus be returned at least until such time as the field is producing at commercially self-sustaining normal operations' revenue rate ?
The bonus would, of course, be due to the BoD member(s), at the appropriate time in the future ?
If the bonus(es) was/were paid and the BoD declined to return (temporarily), or not paid at all then there seems little choice but to approve the raising. But, is it worth clarifying first ?
I also suggested earlier that deferring the EGM might be worthwhile in order to allow sufficient time for CH to clarify the Environment Minister's position upon his return and advise shareholders prior to re-scheduling EGM if it is still required,...this presumes any (slight) delay with not compromise any other on-going activities. However, it may allow a decision to be taken whether to commence EU court proceedings earlier than maybe otherwise envisaged, not to be hostile to the Slovenian Government in any way but, simply because any lengthy delay would make AST's financial position much less secure.
Gentlemen,
Without real detail it doesn't seem possible to determine what sort of deal this is and even then maybe quite complex
So, before then, look for possibly simpler option(s) to avoid NewCo-type complexity ?
GR may well have considered the following and eliminated it and variants also but worth GR explaining to shareholders why it/they are not practical/preferable to a NewCo-type deal.
GR advised KME a drilling/mining contractor with lots of staff and kit but skillsets, equipment condition and suitability for RHA development (later Zulu) unknown, let alone KME fair market value compared to RHA/Zulu asset value. So, maybe there is an alternate approach to re-start production even faster ?
Rather than rush any deal on NewCo with all the unknowns/uncertainties (by all means continue in background if seen as best long-term option), consider a deal with KME where it provides services and capital equipment with payment in the form of RHA production revenue in return for drill/produce RHA and explore Zulu ?
Basic deal would be normal contract rates plus incentive to return RHA to production faster and production exceeding pre-set targets accrue additional payments.
Maybe offer KME (preferential) PREM share buy-in from its profits if it so chooses ?
This way, neither KME nor PREM need to go to the doubtless lengthy and complex route of "deal-makig" until (a) one is proven worthwhile from RHA profitability and Zulu DFS/development.
If KME is a drilling contractor like most worldwide, it generally would prefer the certainty of revenue from a term contract (with extensions), which PREM would offer..
Approach used in the oil industry where services companies (like Schlumberger), take payment from oil/gas production revenue without getting involved in the risk of asset sizing i.e. they get paid regardless for as long as the resource keeps producing economically.
Thoughts ?
Don't have GR's contact but someone who does could on-pass if deemed to have merit by others on BB ?
Good Morning Gentlemen,
Lots of interesting discussion about the way forward and some interesting history lessons.
Maybe slightly delay EGM to ensure full understanding of Environment Minister's position and possibly avoid unnecessary proposed dilution ?
Sent the following to CH this morning and will circulate any reply here immediately.
Colin,
Hi there !...I hope you are well in these 'dark days' ?
Cancer treatment complete and now on the long, 'wait-and-see' road. Interesting learning is not to 'kick the can down the road' which perhaps that has particular merit here ?
Regarding EGM. Four questions and 1 recommendation:-
Q1. What practical purpose does £MM1.5 serve for SR ?
(Surely, any interested party is aware of the commercial position and that the funds only offer temporary relief to cover day-to-day expenses ? Can AST continue with current income stream and, if so, for how long ?)
Q2. Seek recourse to EU courts without further ado, with all due respect to the Slovenian Government i.e. it is now simply a business imperative and absolutely no attempt to play 'hardball' ? (Obviously, only after confirming directly the media reports of the latest Slovenian Government review and re-stating ASTs Slovenian history and 'offering' per latest RNS).
(If, as you say, even after the extraordinarily lengthy review processes to date, the Slovenian Government is still not prepared to issue the permits you understood to be verbally approved by ARSO last week and that other non-Slovenian entities are experiencing similar situations, AST's commercial viability and merger-T/O position will continue to worsen still with no guarantee of permitting),
Q3. Claims including multi-million pound remuneration/bonus payments to AST BoD member(s), could, if true, offer a way to avoid the proposed, further dilution ?
(If these 'eye watering' amounts, as Chancellor Hammond would describe, are true then given recent UK press with Persimmon perhaps it is timely for AST to review at EGM. If true, perhaps the individual(s), could see the merit in returning the funds temporarily at least until AST achieves a credible definition of sustained production, commerciality ?
In addition, BoD members may take this opportunity to purchase shares to demonstrate to Slovenian Government and potential partners that the BoD is strongly committed financially to the project ?)
Q4. SR status and any realistic JV-T/O prospects;
(a) how many companies interested without permit in place
(b) which companies were interested but withdrew and any offers made if no longer covered by NDA
(c) how many companies interested with permits in place
R1. Recommend delay EGM until items 2 and 3, at least, have been communicated to shareholders.
I look forward to your reply.
Kind Regards, Mike
Not sure what happened to formatting....try again...
Not sure if some direct experience is helpful here.
Been exploration drilling for most of my 35+yr career working for Client companies worldwide.
Have known first hand collapsed pad and near-collapsed - in Algeria amidst hundreds of no problem pads. Caused lots of management finger pointing but the reality was, as likely here too, "s_it happens" with mother nature.
Mechanical problems are a fact of life too. You simply expect less problems from premium contractors even with PMS ! A rig contractor on 'zero day-rate' will move quicker (very quickly!) to fix problems than if Client allows them to carry on which they will always try to get you to do ! Always disappointing when spares required are not in-country spares but, as we've seen, "s_it happens" and contractor/client get caught out but then source from either contractor central store/sister rig/OEM supplier. With the oil industry in a 'slump' this favours the client with respect to time.
Not sure if knowing the specific parts helps and, as with the pad collapse, maybe it takes a little more time to properly estimate the delay. If AAOG does as last time, once it knows, then shareholders will be advised.
Given pad delay, would expect nothing less from AAOG management to not risk compromising the well objectives...that would be truly unforgivable.
Finally, some of the worst wells have ended in success and vice-versa (!!)....the point being any problems in the overburden have no bearing on the potential 'prize' below....keep the faith !
Not sure if some direct experience is helpful here. <br />Been exploration drilling for most of my 35+yr career working for Client companies worldwide.<br /><br />Have known first hand collapsed pad and near-collapsed - in Algeria amidst hundreds of no problem pads. Caused lots of management finger pointing but the reality was, as likely here too, "s_it happens" with mother nature.<br /><br />Mechanical problems are a fact of life too. You simply expect less problems from premium contractors even with PMS ! A rig contractor on 'zero day-rate' will move quicker (very quickly!) to fix problems than if Client allows them to carry on which they will always try to get you to do ! Always disappointing when spares required are not in-country spares but, as we've seen, "s_it happens" and contractor/client get caught out but then source from either contractor central store/sister rig/OEM supplier. With the oil industry in a 'slump' this favours the client with respect to time.<br /><br />Not sure if knowing the specific parts helps and, as with the pad collapse, maybe it takes a little more time to properly estimate the delay. If AAOG does as last time, once it knows, then shareholders will be advised promptly.<br /><br />Given pad delay, would expect nothing less from AAOG management to not risk compromising the well objectives...that would be truly unforgivable.<br /><br />Finally, some of the worst wells have ended in success and vice-versa (!!)....the point being any problems in the overburden have no bearing on the potential 'prize' below....keep the faith !