Nickel- investor wondered about the reserves figures too at the weekend. I'd been trawling the annual accounts on the RPT website and listed below what I found. I've since discovered ERCE did the reserves estimate for GKP in Kurdistan so, I guess, they are a reputable outfit although I hadn't heard of them before.
I contacted RPT to ask if they'd put the latest D&M reserves report on their website (as some Operators do), but their PR guy (Chris Phillips), advised it was confidential and they would not be doing so. I've no doubt the latest figures are 'kosher' and the 2013 figure was BS because in fact RPT produced well over 1,9mmboe between 2012-2017 which probably explains why the new ex-BP guy commissioned this latest report.
Hope it helps.
Nickel-Investor....good morning.
Latest reserve estimate change by itself is outstanding. Several estimates done since RPT started in 2002:-
2018 1P 28 mmboe - 2P 50 mmboe - 3P 59 mmboe (D&M)
2013 1P 2 mmboe - 2P 12 mmboe - 3P 17 mmboe (ERCE)
2012 1P 8 mmboe - 2P 32 mmboe - 3P 53 mmboe (ERCE)
20?? 1P 40 mmboe - 2P 151 mmboe (Ryder Scott)
2013 estimate looks anomalous...but still, 2018 estimate a significant improvement over 2012. 1P reserves are a key metric to oil company value and, I would think, the ability/speed to extract reserves also to determine earnings.
Just a Driller and not my skillset to value oil companies...wish I'd been in since pre-Xmas when 3p as this is a 'wild-ride' at present...one can only wonder where the top is until some analyst 'comes forth'....
Hope this helps....ATB
Joeman1,
Sounds like the response I got from this arm of Slovenian Government is quoting 'old news' and not involved with the current discussions....not entirely surprising....meeting today hopefully clarifies the specific ARSO issues...
FYI. Sheds some light and hopefully confirmed at today's meeting...
Gas produced in the Petišovci field does not meet purification requirements which would enable the same to be fed into Slovenian gas network. Permitting process for construction of new purification unit in the Petišovci field is currently still in the environment acceptance approval process ran by the Ministry of Environment and Spatial Planning. Until this process along with the completion of the investment in the new gas purification unit is successfully concluded, the gas produced in Petišovci field won’t meet the necessary technical specifications which would enable its infusion into Slovenian gas network.
Hopefully, the above information meets your expectations. Should you have further queries of technical and/or economic nature, we suggest you to contact the Petišovci field concessionary.
Kind Regards,
-----------------------------------------------------------------------------------
REPUBLIKA SLOVENIJA
URAD VLADE ZA KOMUNICIRANJE
GOVERNMENT COMMUNICATION OFFICE
Gregorčičeva 25, 1000 Ljubljana, SLOVENIA
T: +386 1 478 26 30, E: info.ukom@gov.si
www.vlada.si, www.ukom.gov.si
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Nickel-Investor....good morning.
Latest reserve estimate change by itself is outstanding. Several estimates done since RPT started in 2002:-
2018 1P 28 mmboe - 2P 50 mmboe - 3P 59 mmboe (D&M)
2013 1P 2 mmboe - 2P 12 mmboe - 3P 17 mmboe (ERCE)
2012 1P 8 mmboe - 2P 32 mmboe - 3P 53 mmboe (ERCE)
20?? 1P 40 mmboe - 2P 151 mmboe (Ryder Scott)
2013 estimate looks anomalous...but still, 2018 estimate a significant improvement over 2012. 1P reserves are a key metric to oil company value and, I would think, the ability/speed to extract reserves also to determine earnings.
Just a Driller and not my skillset to value oil companies...wish I'd been in since pre-Xmas when 3p as this is a 'wild-ride' at present...one can only wonder where the top is until some analyst 'comes forth'....
Hope this helps....ATB
Potted history...
RPT started in 2002 - licences in Ukraine's main O&G basin - central Ukraine ~200km east of Kiev
RPT website has all FY accounts since inception in 2002
Between '02-'11, in Greece, Romania and Egypt also before divested - so no meaningful account yoy comparison
However, all workover, new well, facilities, subsurface and well production data quite well documented.
FY accounts from '11 to '17 are solely Ukrainian production based and performance clear to follow....major events being '13 reserve downgrade, '14 sub-soil tax increases (to be reduced for all new wells from '18), and '15 currency depreciation...back in profit FY '17 and operational RNS's to date advise increased production.
Post '11, self-funded all work and no change in shares issued ~362mm
Latest reserve report conducted by D&M (industry leader), previous authors also lacked latest production/geo data.
RPT BoD changes last year - Chris Hopkinson (ex-BP senior manager with significant regional experience) replaced Keith Henry (experienced construction 'bod'), and Dr. Frank Phillip (ex-BP experienced geologist), technical CPR joined in 2015.
Latest RNS states reserve estimate based on 24 additional wells
RPT can continue self-funding development from cash generation although slower would retain all rewards internally.
Also, with latest, material reserve increase, can consider external funding to accelerate/optimise project NPV....
Will be interesting to see Mr. Market's analysis ahead of FY '18 accounts as they will be a 'jolly good read' for sure
ATB
Some light relief...
http://www.lettersofnote.com/2009/10/we-all-feel-like-that-now-and-then.html
Unless gas/condensate reserves are no longer there, surely there's value ?
2011 NPV was $MM200. Colin advises current 2018 version also ~$MM200 NPV...if so...7p/share
Sp is 0.72p as AIM takes no prisoners...fail to deliver at your peril...
No-one likes delays when they go beyond reasonable without knowing why...
Seems political...who knows, court case loser with high placed friends or influential folk wanting 'cheap-ride'...why do it if it's worthless ?...unlikely someone in AST dropped a political 'clanger' and now 'black-balled'.
If you can afford to play the long-game (even longer!), and the 'prize' still has attractive NPV......or
If you lose your patience or reach sp 'cut-off' then they win...and you 'faites vos jeux' elsewhere...
ATB
ps...sent e-m to Slpvenian Government asking why they allow gas sales to Croatia and prefer to pay for imported gas themselves and wouldn't it help GDP if Petiskovci fully developed to import even less ?...will let you know if meaningful response received !
Whilst not large, I made 5 x GBP 10k buys this morning and none show on H&L or LSE board yet...wouldn't move sp but disappointing real-time buy/sell activity not reflected...c'est la vie...
To clarify yesterday's transactions....bought 20mill shares during morning ~1.7p (more as/when MM focus here.... as with ALBA ~2 weeks ago ?)
PRIM under-valued to ALBA let alone PRIM/ALB to UKOG crudely based on HH-1 asset value...is that ramping or misunderstanding PRIM's other assets' value ?
Most BB are unhappy with management performance from time to time and PRIM no different there so unless some underlying weakness with assets then, again, PRIM like the rest. But, the asset with no weakness that attracts me, as a Driller, is oil/gas..
Wont post again to hopefully avoid any 'ramp' tag but offer sp/mcap comparison and non-reservoir engineer 'technical' view...
if UKOG@2.13p base ALBA@1.2, PRIM@0.40<br />if ALBA@0.57p base, PRIM@0.19
Sanderson at UKOG stated Feb 2016 with POO @$28-30/bbl HH..."on the edge of being commercial'...at $74/bbl allows some latitude for error, right?...
It's not often you come across an HH-1 scenario from an investing perspective....i.e.re-entering a well that has been tested at rates an order of magnitude higher then traditional offset wells and 2 other zones never flowed before in the basin at comparable rates, admittedly over a short test interval in 2016.. It appears to be that HH-1 has been drilled in a part of the structure where associated gas is trapped with resultant natural flow (no artificial lift), from its natural fractures which is a good sign compared to offset wells.
My main concern with UKOG ahead of this testing, given its BB-1z debacle, was if they'd suspended HH-1 in such a way to cause reservoir damage during its 2yr suspension. Last weeks' news suggests not....
So, presuming Portland zone is indicative of lower Kimmeridge zones' condition, and no reason why not now, UKOG will conduct a series of drawdown flow/pressure build-up periods to on each zone to establish each zones' 'drainage radius' indicating (a) longer-term flow profile (b) extent of connectivity to the main reservoir (c) preferred depth for horizontal well(s) and hence the number of wells to develop/drain the field and what, if any, scenario(s) is/are economic.
Other Operators in the Weald note Kimmeridge acreage with fractured limestone in the oil 'window' but UKOG's BB-1z 'failure' (unless caused by its drilling/completion practices), means it's more complex to predict success. So, unless/until UKOG reveals BB-1z problem(s), the distinguishing features at HH-1 are its elevated gas presence and proven flow rates i.e. gas enhanced flow through (well) connected fractures...
Flow data will dictate if commercial or not but certainly de-risked somewhat by the 2016 tests in HH only.
Hope PRIM management simply remains silent on all other fronts unless it has other good news elsewhere and simply wait for HH data to flow. PRIM management could consider engaging its broker/research analyst (or use ALBA's company, ALIGN) to rate/value ALBA sp...ATB
To clarify yesterday's transactions....bought 20mill shares during morning ~1.7p (more as/when MM focus here.... as with ALBA ~2 weeks ago ?)<br />PRIM under-valued to ALBA let alone PRIM/ALB to UKOG crudely based on HH-1 asset value...is that ramping or misunderstanding PRIM's other assets' value ?. <br />Most BB are unhappy with management performance from time to time and PRIM no different there so unless some underlying weakness with assets then, again, PRIM like the rest. But, the asset with no weakness that attracts me, as a Driller, is oil/gas..<br /><br />Wont post again to hopefully avoid any 'ramp' tag but offer sp/mcap comparison and non-reservoir engineer 'technical' view...<br />if UKOG@2.13p base ALBA@1.2, PRIM@0.40<br />if ALBA@0.57p base, PRIM@0.19<br />Sanderson at UKOG stated Feb 2016 with POO @$28-30/bbl HH..."on the edge of being commercial'...at $74/bbl allows some latitude for error, right?....<br />It's not often you come across an HH-1 scenario from an investing perspective....i.e.re-entering a well that has been tested at rates an order of magnitude higher then traditional offset wells and 2 other zones never flowed before in the basin at comparable rates, admittedly over a short test interval in 2016.. It appears to be that HH-1 has been drilled in a part of the structure where associated gas is trapped with resultant natural flow (no artificial lift), from its natural fractures which is a good sign compared to offset wells. <br />My main concern with UKOG ahead of this testing, given its BB-1z debacle, was if they'd suspended HH-1 in such a way to cause reservoir damage during its 2yr suspension. Last weeks' news suggests not....<br /><br />So, presuming Portland zone is indicative of lower Kimmeridge zones' condition, and no reason why not now, UKOG will conduct a series of drawdown flow/pressure build-up periods to on each zone to establish each zones' 'drainage radius' indicating (a) longer-term flow profile (b) extent of connectivity to the main reservoir (c) preferred depth for horizontal well(s) and hence the number of wells to develop/drain the field and what, if any, scenario(s) is/are economic.<br /><br />Other Operators in the Weald note Kimmeridge acreage with fractured limestone in the oil 'window' but UKOG's BB-1z 'failure' (unless caused by its drilling/completion practices), means it's more complex to predict success. So, unless/until UKOG reveals BB-1z problem(s), the distinguishing features at HH-1 are its elevated gas presence and proven flow rates i.e. gas enhanced flow through (well) connected fractures...<br /><br />Flow data will dictate if commercial or not but certainly de-risked somewhat by the 2016 tests in HH only.<br /><br />Hope PRIM management simply remains silent on all other fronts unless it has other good news elsewhere and simply wait for HH data to flow. PRIM management could consider engaging its broker/research analyst (or use ALBA's company, ALIGN) to rate/value its HH asset
Alan2017 and Ibug,
Thanks. I had seen the ANGS presentation. As Ibug said, Operators are often 'canny' with specific data release.
Key is the fractured limestone thickness and horizontal extent as total Kimmeridge can be misleading if UKOG's BB-1 well is analogous ?
As a Driller, and assuming Lidsey was not a drilling/completion problem, it shows how 'tricky' selecting the horizontal depth can be with limited data but less problematic, of course, if in the reservoir 'sweet spot'
Anyway, if that's all the data in the public domain then it's time to 'faites vos jours'....ATB
Alan2017,
Much appreciate all the Balcombe 'scoop'....have you seen any Balcombe-2/2z well log data ?
Looked at ANGS/DOR/CUA/UKOG sites and all I found so far is a regional GR/sonic plot from a UKOG document (page 11), showing Brockham-1 and Balcombe-1 either side of HH-1. Obviously, this data is specific to those wellbores and reveals nothing about hydrocarbons or fractures but does show relative depths, thicknesses and 'cleanness' of reservoir zones.
http://www.ukogplc.com/ul/UKOG%20Corporate%20Presentation%20Website%20March%202017.pdf
I'm late to this party but can see its potential...Brockham seems less risky as in ANGS control all along so just looking for Balcombe well data...if any....ATB
Final part...
"Unlike 88E, Sacgasco is actually producing and selling gas, has in place a program of workovers to produce more from its 27 wells, is leasing more acreage and has Dempsey deeps and Alvares as upside. Yet the company has less than 300 million shares on issue giving it a market cap of less than A$8 million compared to the $150 million or so of 88E. Go figure!
If in six months time we haven't seen a significant improvement in production, cash flow and the share price then we will have good reason to compalin".
Apologies but it will take 2 posts not 1....from Hot Copper SGC forum
"That's actually not true. The Dempsey well is ready to go on line all they are waiting for is approval from the pipeline operator to turn on the valve. With well shut in for so long initial flow rates should be above what was previously reported ie. more than 1.2 mmcf a day.
There is a lot of activity going on to increases production from the 27 wells the company owns across its various leases (see March quarterly for lease details). Sacgasco just doesn't believe it is necessary or desirable, given the competition in the basin for acreage, to report every actual field activity as it happens. We will learn in the next quarterly just what this workover and field improvement activity has meant for the bottom line.
The company considers that with just a bit more production it will have all up costs of US$2.00 an mcf so given the company is a low cost producer a significant increase in gas production from Dempsey and/or Alvares will be highly profitable.
A larger player with fewer monetary constraints might come in and say lets frac Dempsey now and see what we have got in the deeper zones. But Sacgasco wants to keep the number of shares at a minimun and build up cash flow first so it can pay for the fracking of Demspey at a later date with its own money and not hit shareholders again or go into debt..
The Alvares operation is waiting on final approval from DOGA to commence and payment of cash calls from partners . Remember SGC is free carried thru the well bore integrity test. You have to give GJ a lot of credit for the farm in deals he has done.
There is a sheet load of gas in the Sacramento Basin and Sacgasco and its partners have a good shot at claiming some of it via the wells it bought in recent years and Dempsey and Alvares. GJ has also done well in acquiring leases in an environment where landowners are seldom willing to sell acreage particularly that held by production. Red Emperor found that out recently as I recall.
Yes, its frustrating to see the share price make new 12 monthly lows every day but at this time of the year there is nothing the company can or should do about it. Let those who want out get out for tax reasons do so. Good riddance!
Its curious to me how the market reacts to companies. 88 Energy has what 5.5 billion shares on issue no commercial anything just a lot of blue sky and a willingness to tout a multi billion barrel OIP which may or may not be true. More likely not true IMO.
Sacgasco and its parters are possibly sitting on multi Tcf of pipeline quality gas but you won't get GJ making the same sort of claims Dave Wall and his brokers are prepared to make about the HZR zone at Icewine. And the funny thing is the HRZ at Icewine won't free flow hydrocarbons it has had to be fracked."
Didso.
Just my 'take' on the last few years in oil business and how management has many things to decide but in no way a 'free pass' for ineptitude nor a prediction of next few years as slumps come and go...and current POO is a welcome sign. If sustained (a) onshore is (very) profitable (b) offshore recovers as EME needs for 'farm-inees'. Meantime, positive onshore cash flow helps EME but without knowing criteria it's not possible to assess if onshore California is the best 'bang for the buck' but it's what we have for now....
Your view of SGC's management may well turn out to be correct but, for me, it's too early to tell (unfortunately), and if one's investment time horizon expires then what happens after is moot...nothing new there.
A recent and interesting recap from an SGC investor is enclosed in next post. You may have seen it already ? I can't vouch for the 'sheet loads of gas' as I'm not intimate with California Gas (so-to-speak), but I met this chap 'moons' ago and 'bullspit' wasn't his style....see what you think...
35yrs O&G business as a contract drilling engineer and no wish to offend or re-state the obvious, but worth remembering offshore business is 'dead' presently and only onshore making real money...who knew that in 2014, '15, '16, or '17 ?...and companies need a strategy which fits the business/economic climate, right ?
Like shares, oil business is all about timing (and luck !), whether BP/Shell or UKOG/EME...plus, need good assets or potential assets only when economic time is right...else risk 'going bust'...
Sure, Sacramento is 'small beer' if you have BP/Shell overheads. But, for SGC (EME?), an onshore opportunity still with significant risk to show 'proof of concept' for deep gas (like, UKOG?). Also, to best manage funds, SGC may have compromised vertical well location to recover well costs from expected, commercial upper zones as mother nature rarely places the best deeper zone right above the best upper zone. And, like UKOG, 88E, you don't always get it right/quite right first time (or at all sometimes)....but, then what ?...shareholders expect instant success (so does company !), but now the reality is usually harder as serious analysis is required before deciding next course of action and if a second attempt is merited how then to convince potential investors....
Given 'strange goings-on' at BMR/ANGS lately, maybe SGC is managing shareholder funds as well as can be expected (better?...only time will tell)....at least senior management has significant industry specific experience.
EME will have reviewed and will review its portfolio regularly but imagine its current strategy took time to decide and expect any changes receive equal consideration...these are tough times in the oil business and hard be assured of success at any time let alone right now...
Hope this helps ?
Just with respect to the discussion on well flow rates it's worth remembering two useful web references:-
1. "maximum" flow rate on test does not equate to reservoir management set production flow rate (1st link below).
2. tight gas reservoir requires hydraulic stimulation ('fracking'), to achieve commercial production rates, maybe current approval delays are partly due to past, accepted practices being reviewed with a new environmental 'eye'...
3. INA contract flow rate range 2.1 - 2.9 MMSFCD (2nd link below).
Yes, Pg-10 could possibly compensate for Pg-11a to meet/maximise INA range (to maximise revenue), but usually the reservoir management team advise senior management technically in the first instance.
(www.ascentresources.co.uk/wp-content/uploads/2017/01/PDC_2011-09-06Petisovci-Commerciality-ReportWeb.pdf)
(www.energykeyfacts.com/latest-oil-and-gas-news/ascent-resources-provides-update-export-gas-production-peti%C5%A1ovci-field)
Hope this helps ?