Member Info for Penguins

Is Dragon's Den a good analogue.

Examining the story the contestants put across about their business and asking about what they don't present, often about their previous progress, past and future cashflow, is how the Dragons make their decision.

Would UKOGs story of value in hundreds of millions in Turkey hold up if you could ask questions about the analogue geological lookalike field adjacent to Resan/Basur - flow rates, decline rates, success rates and the cashflow resulting from the need to constantly drill to hold up production levels. Maybe even ask about theBasur-1 flow test and more details on why it was stopped after 6 hours.

Of course if you're happy to wait for results (very soon?, 2 - 3 months?) fine that's your prerogative, but plenty here speculate on the outcome - and the information is there to understand the likely outcome - which is what UKOG will have done, but seem unable to pass this sort of assessment to their owners.

UKOG haven't presented anything to show what Resan / Basur will deliver.

It's almost as if they don't want to give any information about the specific potential in production of the Mardin play despite the operator AME, having a field in production nearby producing from the Mardin reservoir.

So how can the market can be convinced of anything about UKOGs prospects in Turkey, more likely there's hope of making money on P&D around events on the way rather than the destination.

So far expectations from UKOG were that the first well would start drilling at the end of 2020, and that the licence application would be known about in 60 days. I did comment that the Turkish system had periods of 90 days followed by 60 days assessing applications, but already it has been more than 150 days from the application made in November.

It is apparent UKOG don't do negative news, look at their unwillingness to mention flow rates, water cut and even the information they are presenting in planning applications and EA applications for HH.

The positive news about Turkey is almost exclusively about large reserves in fields in different reservoirs, some in different countries, whilst information about the next door field is limited to reserves and initial flow rates that are unrepresentative of the production from that field, E Sadak.

What's left may not be part of the calculation as to whether there's a conversion before 12 May.

It not be a popular opinion but I would expect UKOG to use whatever authority remains from the last AGM before the next AGM, my best estimate, which was difficult to arrive at because of the different authorities shares might have been issued under, was between 1 and 1.3 billion shares.

What that might net depends on the SP and discount but maybe a minimum of £2mm - but if I was in charge, however unpopular it might be, I would do it as a guarantee of being able to fund Turkey beyond Basur-3 without raising more.

If there's any problems with Turkey (or other projects) the risk of an even lower SP and difficulty raising funds with next year's authority would be mitigated by converting before the drilling. If Basur-3 goes well no one will care what happened earlier.

Zoom,

unbelievable, not amazing.

are you expecting smaller tankers and a consolidation?

There's nothing to suggest that they can increase production much above a 100bopd average - if they let rip with oil production because they can cover water disposal costs the gas would cripple oil production - it would be an example of diminishing returns.

as for 3 to 4p - I'm sure everybody would like to see that - but surely it needs something fundamental to support a valuation of £400mm to £500mm - like decent steady production in Turkey for starters.

The rise in mcap during testing of BB was based on a false assumption that 1) SCDM were in for the long haul and 2) that BB was on the verge of testing like HH-1 did in 2016. Neither came true.

It would be verging on being over polite to suggest your posting over the years has been a bit optimistic, often exceeding even UKOG's over optimistic expectations.

Mirasol,

I'm embarrassed - blatently ramping a figure of 450bopd - who says I'm not positive.

But strangely it was based on the figures in the original version of the planning application that is being referred to now where the revised application is now 2 tankers a day. The figure of 450bopd was for production from Kimmeridge and Portland in HH-1 and the Portland in HH-2z.

This was my 'non' submission to the sweepstake (23/05/2020):-

Mirasol,

Production from HH.

Based only on UKOGs planning permission application ( 'The storage of crude oil in association with planning permission for retention of the wellsite and production of hydrocarbons.') which requested permission for 3 tankers a day leaving the site until the full site is built. Assuming that's a maximum over 6 days I'll go for average production of 450bopd from dual completion of HH and HH-2z ewt.

Skwizz,

depends if you believed the 880bopd that was quoted during the June 2020 P&D (based on 4 tankers seen in one day - of which at least one was produced water) which Ohmetoe got nearest to.

Looking at the limited information released by the OGA since reperforation it certainly looks like if they increase production volume to double the current level the water production could be well over one tanker a day. But at some point the pressure reduction as they produce - which is the reason for intermittent production - will also enter the equation and gas production will become an issue. They really need water injection, and they need it to work as pressure support as well as water disposal.

Wizard,

are you also zoom? My view is DoD are trying to sensationalise the tanker numbers. But there is definitely a pattern that UKOG tend to have an oil tanker morning and afternoon every few days rather than one more often (but still not every day). This could be because on days they are producing production is 200bopd, and they produce for a couple of days and then shut in for a couple of days to allow the pressure to recover (in December we know they produced for 50% of the time) - of course UKOG haven't and don't give specific details of what's happening since then.

I would imagine they currently only store up to 49tonnes (about 360bbls) anyway, which is why they know it would work, as they seem to want to get the oil sold asap.

Using cubic metres to barrels is converting a volumetric measurement to another volumetric measurement, for tonnes you need to input specific gravity as the weight of a barrel of oil varies depending on the API.
For January's figures using 6.29 oil barrels per cubic metre I get:-
504 * 6.29 = 3170.16bbls in January
3170.16 / 31 = 102.26bopd average during January
For the water 267 * 6.29 = 1679.43bbls in January
1679.43 / 31 = 54.17bwpd average in January
Gives a volumetric water cut at 34.6%.
As water has a higher sg than crude oil the water cut by weight is 38%.

In December the same calculation using cu m to barrels returned a water cut of 29.5% on an average of 85 bopd.

Looks like as they increase oil production water production increases significantly.

However in January UKOG claimed that water cut had been stabilised by the end of 2020:- 'Early results are encouraging, with stable water influx levels achieved by the end of 2020'.

I posted this on 21 April:-

.'....if they have 'turned the taps up' will there be an increase in water cut - maybe with the higher OP they can afford more water disposal?'

Zoom,

I do wish posters would understand that UKOG applying for a maximum amount allowed to be exported is not the same as UKOG expecting to export that amount every day.

You'll also notice that the water ingress has increased month by month - even more so as they increase oil production.

I wonder where they're installing the ramp?

apart from on twitter.

The question is why is the spread is being held at .215 to .23 when the actual sells/buys since 8:40 are between .216 to .219, so the published spread could be .215 to .22?

So why don't 'they' (or is it an algorithm) want to change the spread and show a small price rise instead of +3.49% - is it to encourage buys based on a (supposedly) rising SP?

Just look at the trade price not the colour - though the deception of whether a trade is a buy or sell can be masked by late listing, jumping the spread around and rollovers set at prices either end of the trading range - and the end of day UT to 'fix' the closing price - which is why the rise is 3.49% in the first place.

Despite comments here by the end of the day buys and sells will be more or less equal - and more or less throughout the day. If the price of trades is rising it will be buying pressure, and if falling selling pressure.

?..and then 46 small and tiny trades at exactly the same time.

Tony,

'this is because the EA can’t process the full application for higher storage quicker ( seams like the EA are massively under resourced)'

They haven't made any changes in the EA application being reviewed to the site storage of oil of a maximum of 500tonnes.

In fact they repeatedly state:-

'HHDL will continue to undertake the following activities at the site in accordance with the current permissions presented within the permit:
? Store and handle crude oil up to a capacity of 500 tonnes within the existing infrastructure and within the current permitted boundary. Permit EPR/SP3339YS will not be the subject of a permit variation.'

Ocelot,

Apologies, I over paraphrased your post, it was late.

The question is not have the so called derampers forced the price down, but have they just been calling it correctly.

Ocelot posted that nothing will stop the price rising, so obviously something has caused it to fall. Rises created by an orchestrated P&D also happen, but keeping it high requires substance.

This will be true for pictures of site preparation, rig arrival, oil shows (if), testing (if) in Turkey

But unless there's decent production the same will ultimately happen as happened at HH, false hopes meeting reality and a SP 97% off its high - but 100% more than its low because the story is no longer the transformational Weald.

What's sad is that being honest about the compamy and its projects has resulted in stupid accusations and such bile, often from posters that have so often been proved massively wrong in their expectations.

On a quick look through stuff about the Southampton geothermal project.

The geothermal bit is a small percentage of the energy input.

Because it's a single well the water is disposed of into the sea, in 2010 the well produced 7.5 litres a second or about 4,000bwpd of salty water.

It won't be happening at HH, apart from lack of deep (to be hot enough), high permeability and porosity (to flow the water) rocks - the projects UKOG are looking at are 'standalone' according to the RNS.

Public funding seems to be a big (but not 100%) element of these projects in the UK, probably because of the uncertainty over the economic, rather than 'green' case, but how many projects are government going to support?

'The geothermal may open up new sources of funding to UKOG.'

You hit the nail on the head with that post Ocelot. Is that the driver for every project, not profit - just can UKOG spin a good story and get hold of more cash on the back of it.

Unbelievable,

This is a company supposedly searching for oil and gas. The expertise of the Chairman and CEO and Senior Management is in oil and gas.

They have failed at their expertise so they have partnered with AME to search for oil in Turkey who operate, and now they intend to 'research' geothermal, on top of their previous wheezes of solar and gas reforming. Forgive me for being ever so slightly underwhelmed by this distraction.

Tell your shareholders what's happening with the only production you operate, and indicate what you expect from Basur if it's successful, not BS RNS about an 'association'.

It's becoming a joke. Reforming natural gas they haven't found at Loxley, solar power at HH - probably because there's not enough gas for a generator so they have to flare it - now hot water for the showers heated by HH-1 hot water before they stick it back down HH-2z to be heated up on its way back to HH-1?

It looks like it will be next century before SS has run out of things to spend any Turkish profits on, if there are any. How much more BS can this company generate.

Still at least UKOG is familiar with the principle of 'not for profit'.

'GEAA is a not-for-profit stakeholder-driven association that advocates increased investment in and awareness of
this sustainable source for zero-carbon power, electricity, heat and hot water.'

Sting,

You concluded from that partial quote from a post a success rate of 66% in a development, which is dire. AME had already established commercial flow (though E Sadak - 1 started production at about 60bopd and dropped rapidly to 30bopd) not just a short, curtailed test, because of water production as in Basur-1.

But I did recently have a look at COS (post on 21 April, replying to gkb47) which concluded 43%:-

'It's back to E Sadak for a comparison where the success rate after being put into production seems to be about 63% (7 out of 11), but that's after establishing a commercial flow.

UKOG have said about the same as Loxley and Arreton at about 65% - but I'd like to see the risking they've applied to get to that figure for those two first. Whilst companies have tried over the years to take the subjective element out of risking because it is opinion the best they can do is police it with risking committees or peer review - I don't suppose there's much of that in UKOG.

It also depends on the number of factors. I'll have a subjective go at four factors.

source presence - 100%, it's there - some risking might include migration path
migration path maybe 90% as they are drilling away from Basur-3 (but it won't be migrating from Iraq - a note for Wizard)
structure maybe 60% - includes top seal - structurally very complex area - if E Sadak can miss the reservoir 37% of the time then that has to be a problem, seal, not sure how much of an issue top seal is - obviously Basur-3 tested oil
Reservoir presence - 80% - again as it's expected to be naturally fractured carbonate to deliver oil there may be less or zones without fractures..

On a four factor risk that's 43% COS. Then there's commercial success - but as they might have to put the well into production regardless if it tests I'll leave it at 43%.'

Here's the remainder of the post you quoted:-
'They may be a simple bumps on the surface but subsurface they can be extremely complex, and the seismic data is usually poor - which is why there's a tendency to drill first - if nothing else to be able to correlate the seismic events or horizons (if there are any) to actual strata.

So it's not shooting fish in a barrel - probably why the well which was originally hoped for in late 2020 has slipped to mid 2021 as not only are the targets not necessarily easy to locate - there seem to be issues with the actual drilling.'

Following yesterday's discussion of the EA permit application where I put this in a post:-

'though what planning permission the site layout conforms to I'm not sure.'

I had a look at the SSC planning site and on 6 April 2021 they submitted an amendment to the SCC Ref 2020/0018 planning application (originally submitted January 2020 but never went to consultatio) - titled:- 'The storage of crude oil in association with planning permission for retention of the wellsite and production of hydrocarbons'.

This amendment is to reduce the amount of storage on site:-

'In summary, a reduced requirement for crude oil storage at surface from a maximum of 285 tonnes to a maximum of 49 tonnes has been made possible through the adoption of more efficient site operations.'

49 tonnes is about 310bbls. This is whilst they are determining 'the character and nature of the crude oil and its flow. This will involve the production of a relatively small quantity of crude oil at surface.'

Though this is what they RNS'd about the flow levels (15/1/2021):- 'The intervention was immediately followed by an ongoing series of multi-week production optimisation trials to achieve an optimum balance between oil revenues and water handling and other operational costs. Trials include well-cycling (i.e., shutting in the well for a set period each day to reduce water inflow) and pump fill optimisation. The trials are expected to continue for several months. Early results are encouraging, with stable water influx levels achieved by the end of 2020.'

The reduction in storage of crude means that the classification under COMAH (The Control of Major Accident Hazards) of the site is reduced.

But it hardly indicates an expectation any time soon of turning up of the taps significantly.

Wizard,

Suggest you look at 13. Suface Water Management Plan - page 19 - Site Plan.

The same object on the other plan described as an interceptor is described as the bypass separator - and there's diagrams showing how it's set up.

But whatever you call it it sure isn't anything to do with the produced oil (unless it's spilt) - which is what I was responding to:- 'If that is a oil export pipeline on the environmental permit plans it could refer to that without increased transport requirements.'

I can assure you that they will never have oil exported by pipeline. As I replied to you on 11 April

' Wizard,

not the pipeline ramp again. A 6" pipeline would need about 110bbls to fill a km. That means a month's production at an average of about 80bopd would fill about 23kms of pipeline.

'If UKOG was spending money on a pipeline connection when they have no idea if any further wells at HH will be even as successful as HH-1 or HH-2z it would be disgraceful - they are not, it always has been the resort of desperate rampers even before the wells started producing water - it was complete BS then, and it still is - started by your ex-BFF FOTH.'

Wizard,

it's not. The pipework from the surface water separator goes to be discharged into the field by an outlet at the bottom right of the site - it's water. There is a pipe from the drainage ditch to the surface water separator.

Have a look at the Surface Water Management Plan.

As for HGVs - that's governed by the planning permission, not what the EA says, though what planning permission the site layout conforms to I'm not sure.

There's also underbalanced perforating, which can help with well cleanup. It also enables companies to issue misleading RNS:-

'Following each of four extensive perforation runs, a pressure increase was observed in the well annulus together with live, mobile oil shows at surface.'

Which would of course happen if you perforate underbalanced - and shouldn't happen if perforating is overbalanced - but it sounds good.

Wizard,

You need to read the RNS where it's quite clear there's little contribution to production from most of the Portland, not realised at the time of the CPR. The benefits of reperforation if it had somehow initiated production from the whole Portland interval should have been seen immediately. There was little (or no) improvement following the reperforation which suggests the bit of the reservoir (the sweet spot) that produces the 'lions share' of oil in HH-1 was pretty well 'plumbed into the well already. It's unlikely that water put into the higher porosity and permeability layer is going to permeate through the much poorer reservoir surrounding it and push out the oil and water. If anything it's going to head for HH-1, if it can.

22/10/2019:- 'The significant oil saturations and high permeabilities observed in HH-2 core and logs, indicate that the "sweet spot" has likely contributed the lion's share of the 29,568 barrels of Brent quality oil produced to date from Portland extended well testing ("EWT") operations at HH-1.'

and note the difference between the 'sweet spot' and the rest of the Portland in this RNS about the coring:-

'Live oil was observed "bleeding" profusely from core throughout the sweet-spot, the Upper Portland reservoir's most porous, permeable and oil productive interval. Lesser degrees of oil bleed, together with oil shows and oil staining were also observed from porous sandstone intervals lying above and below the sweet-spot.'

Ibug,

the 8-14% (of connected oil) was in the 2018 CPR - but in the EA Geological Report it's described as 'with full voidage replacemenr' and Xodus comment they don't know of a case where that's occurred in UK Onshore.