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FWIW...Not sure where your data comes from but WOGCC database shows:-
1. Shannon not perforated. (GR-Res log shows Shannon sand thin and poor hydrocarbon indication)
2. Lakota perforated and produced water.
3. Frontier-1 & 2 both perforated and produced water but COPL CEO clarified during Investor Meet that water was tested as water from ~1000bbl water-based-mud losses (not formation water)
4. Dakota was perforated, flowed 111bopd initially and continues to date.
If your source is definitive, please advise as SWP and WOGCC would need to correct....
FWIW...probabilistic and deterministic 'hocus-pocus' not my 'bailiwick' but the number(s) you seek are in the full report.
F1 probabilistic as no existing production; normally a starting OOIP (no risking) and the low-med-high cases after 'processing'. If high case ~700mmbbls then starting OOIP could be multiples of that. You could ask COPL CEO?
F2 and Dakota deterministic as produced and RS has already 'processed' these at Cole Creek.
RS used smaller acreages for prospect estimation. If RS is constrained by Handbook Rules then OOIP would be higher if COPL acreages were valid in practice. Another question perhaps ?
Not sure if you consider FTSE 100 'blue chip' housebuilder Barratt representative of general investing but...
1 Apr '21 794p remained above 700p until 8 Sep '21....COPL (suspended 38p)
1 Jul '22 454p....COPL 16p....respective drops 43% (or 35% @700p) v 58%
....so, not a short-run thing, BDEV profits rose (not fell), profit/unit rose and house price inflation still +10%...go figure !
Cost recovery usually applies to Capex and Opex but its application is jurisdiction specific.
Internet has useful 'expert' explanations and specific examples....first article I found had a case of "50% of total production" i.e. Operator takes 50% of revenue and pays royalties/tax on remaining 50%. Regulators adjust % during boom/bust cycles to either attract investment or maximise its 'take'...as I said, I don't know what Chesapeake/Atomic/COPL terms are....
In part, yes but only to ask if 'cost recovery' was in your calculation ? Yes, COPL must fund Capex but if Regulator approves, the Government royalty/tax is zero until Capex 'rebated'.
COPL may have deferred oil plant upgrade to meet your growth request ? Although expected to give a better return, it can't afford it presently....maybe the same with 9x BFU wells' delay from '21 ?...COPL CEO looking to get 'best bang for your buck'....or, however many everyone else kicks-in !
gold001 (per Coplholer earlier),
If Wyoming is like other places, are you factoring BFU related 'cost recovery' on approved Capex spend (development wells/gas plant etc) i.e. no tax/royalty payments until rebated ?...COPL still has to 'front-up' with all the funds...
I do not know what the case is for Wyoming but usually Operators can 'cost recover' approved capex 100% against production revenue and generally related Government tax is not paid until that sum has been fully cost recovered...a bit like amortizing upfront...does that impact your financials ?
wwal17 & Coplholer,
WOGCC, Sundries, SWP details all NOI's...scroll down to 21-35H Nov '21 and compare text with latest NOI's...
...it is the planned ('emergency') measure for this situation and only an issue here as Governments no longer allow Operators to flare without approval as (a) wastes valuable national gas resource (b) controls 'unexpected' green-house emissions. One might expect, after latest blowdowns, those wells' production to follow a similar pattern to 21-35H...
wwal17 "There lots of tosh written on here, to be fair, everything worthwhile now has been said"....I doff my hat to you sir !
...you could well be right about my comments as 40yrs O&G experience doubtless pales into insignificance to yours and that your investing experience and insight gives you an assurance level I can only dream of....
...note to self...."don't use/share your technical experience and simply rely on "other" folk who just know better".......
FWIW, this time, COPL tried the intermediate step of reducing injection compared to Nov '21 21-35H 'blowdown' for the same elevated pressure issue. The advantage would have been flaring less gas and no need to mobilise HP separator. Worth a try but did not work. So, back to 21-35H procedure.
Jackman well was the one referenced by Tiburn.
I think the point Tiburn is making is more to do with horizontal.v.vertical well potential performance as it is generally independent of reservoir formation/type and location but, for sure, all actual production rates need to be put in context.
One other thing being discussed is lateral length. It is not generally a linear outcome that longer laterals yield proportionately higher rates. Longer length does indeed open more potential reservoir to flow but flow generally comes from the better quality reservoir wherever that is.
FWIW, JACOB FEDERAL 1-42-73-9H may well have produced peak 1805boepd. However, it is worth noting:-
Jan 2021 first full month of production 33,738bo (1088bopd) and Jan 2022 4,956bo (160bopd). Average production for 2021 was 424bopd.
The decline rates are significant and should be expected unless secondary recovery can be implemented from the 'get-go'
You seem to reference an historical sp and mcap 'pair' as the benchmark of value and use that to reason later sp-mcap pairs...
May I ask if you also calculated/estimated your own actual BFU-CC asset value and how that correlated to the sp-mcap 'pairs' you reference ?
- Do you run discounted cash flow (DCF) and then apply an additional Market discount or somesuch ?
- Do you use your own input criteria and/or accept Ryder-Scott's April 2021 input data ?...bit like someone helping with your homework and, even better as, they give you the answers too ! As a dumb Driller, I could only use RS's data....calculations may still be flawed but final answer within 1% of RS i.e. NPV10 $MM173 versus RS $MM174....'blind luck' ?
In Apr '21, COPL had ~148B shares £/$ 1.37. So, 2P reserve NPV10 $MM174 'fair' value criterion would imply sp 0.86p (86p post-consolidation).
If 'Mr. Market 'fair' value sp' was 38p, say, that would imply an additional 'Market discount factor' of ~56%....at that time....
So, what has happened to BFU-CC asset and COPL since ?...exclude discovery 100%...for now
- (Positive) Price of oil forecast revised upwards....how much NPV impact ?
- (Positive) COPL WI increased to 85%...how much impact ?
- (Negative) Extra $MM28 Capex for (unexpected) gas and oil plant upgrade during 2022/23 ?
- (Negative) Reduced '22 production from '21 forecast...how much impact ?
- (No impact) 19x BFU wells ($MM44), are already included in RS Apr '21 NPV, agreed ?
- anything else ?
Yes, DCF's are like opinions (and 'a'-holes ?), right ?...everybody has one !...but, hopefully, the 'rough' value and certainly whether positive or negative should be clear, right ?
FWIW, my RS '22 POO case, keeping all else the same, showed NPV10 $MM232. Although not the same as COPL-RS end of year '21 NPV10 $MM258 it seems encouraging as (a) ~$MM50 higher than original $MM174 (b) ~$MM30 lower than COPL-RS suggesting RS made additional changes upside changes ....
It seems more like 2x placings @20p have 'set the tone', to date, and influence Mr. Market more than asset value (as only short-long PI's given no 'real' institutional investors yet)....
Clearly, COPL must restore the planned inclining production trend to meet NPV assumptions regardless of sp-to-value 'conundrum'....
But, returning to your sp-valuation assessment....
- If you previously agreed with ~56% Market discount to RS 'Apr '21 valuation i.e. 38p 'fair' for 90p 'calculated' then applying the current RS Dec '21 value for projected share base with warrants++, say 250m shares, is ~36p i.e. £/$1.26 NPV10 $MM258 / 250MM shares less 56%)....yet you say 16-20p is 'fair'...are you saying the asset has actually diminished/lost value overall (despite POO and likely Cuda), and/or Mr. Market has rightly increased its discount factor to 76% ?...if you said 30p was 'fair' originally then today it should be 29p (all else being equal)....I might be the weakest link but what's the mis
You may be right...could be reference to other, more recent, wells responding to the MF in the same general area which have just started flowing also but not permitted for workover yet ?
All I can say, is that a sub-section title of the existing workover programs is "convert to flowing well procedure"...
I'm just a dumb Driller...but the little I know is rate depends on reservoir parameters...the installation/completion equipment sizes/ratings give a capacity to flow but not what the well itself will do....
I don't recall rates being mentioned but these 2 wells are adjacent to injector 13-21 so it makes sense that if reservoir properties are better then it's likely to be in the better porosity*thickness area...as these wells are.
COPL has been reducing 13-21 injection possibly to control surface pressures at 34-20 and 44-21 resulting in decreased production...also 21-35H has seen water cut rise and production fall which could be related ? If so, upgrading the top-sides pipework pressure rating should have a healthy impact on production....
Contains diagram-explanation of BFU 'nodding donkey' completions.
Used where reservoir pressure is low and fluid has to be 'pumped' to surface.
COPL MF aims to re-build and then support reservoir pressure to optimise production. But, as reservoir properties are better than expected in some areas of the field those wells now have sufficient pressure to flow naturally. As such, the rod/pump completion is unnecessary and, in fact, a potential safety hazard and bottleneck downhole.
This additional pressure is such now to exceed the surface wellhead and pipework design working pressure which is why COPL is planning to upgrade the top-side facilities....hope this helps ?