Member Info for ZYX098

On behalf of all LTH's;

A) We feel your pain.

B) Nothing personal, but please sell if you think it will cause the price to rise - because nothing else on the horizon will....

Mirasol - the major problem with operating onshore the UK isn't the cost.
It's the byzantine and time consuming regulatory pathway that has to be negotiated, along which some critical approvals have to be made by local politicians with zero knowledge of the industry.
This increases costs, project duration, schedule uncertainty and also reduces the NPV of any project.
In many other Onshore environments, the main decision making is taken by the central Government ('national significance') and the local authorities only get involved (if at all) on things like water supply, negotiating compensation for landowners for access routes and the location itself.
The supply chain for operating in the UK is short and well supported, with nearly all required equipment and all personnel coming from the UK and they don't have to be accommodated on location.
Elsewhere this isn't necessarily the case and in remote location operations, these sorts of issues often push the daily spread rate well over $100k pd and it can be up to $250k pd.

Ocelot - If you work in the industry, 'initial drilling' usually does mean the actual drilling of the well.
But I don't think that's what UKOG are saying in the context of their RNS.

To add to Stockraisers 09:34am post;
If a placing is made on the basis that "We will use the money for A, B & C", legally can they then use the money raised from that placing for another purpose?

Ocelot - apologies, I made the same assumption as Penguins about your use of capitals on the 'INITIAL DRILLING' part of your post yesterday.

Mirasol - correct.
If an AME owned Rig (through an AME subsidiary) is used, then the rig rate will be based on an agreed benchmark. AME will be thus able to minimise their costs but it won't make any difference to the total amount billed to UKOG.
As for Operating, the Operator will always try and load up the licence on which it has the least exposure (i.e. make the Partners pay as much of your Overheads as possible).
Frequently this means office (local and head office) personnel who time write to that particular project will be charged out at 2.5 - 3 x their nominal hourly rate to cover rents / insurances / local taxes / admin etc.

Ocelot,
"Initial drilling and seismic costs" could cover a multitude of things, but I doubt very much it actually included the actual cost to drill the well - more likely the purchase of long lead items (casing, wellhead etc), site preparation and possibly mobilisation costs for the rig itself.
Similarly for the seismic work - I doubt it includes the actual acquisition costs, never mind the processing & interpretation.

With no sign of a CPR on the horizon for HH, it's clear a placing is coming. It's just a matter of when and for how much.

My guess is UKOG needs at least $3 Million and possibly as much as $5 Million, just for Turkey.

My thought is that this would entail a placing at around 0.1p, which would probably drive the share price down to 0.12p once it's all been rinsed through the markets.

Of course, the problem with that is he doesn't have approval for that size of a placing, so he'll either try and hang on until the next AGM, or call an EGM at which no shareholders will be allowed to be physically present and - as at the last AGM - effectively aren't allowed to vote on any of the motions.

Penguins - thanks.

On the operating costs, one other thing to consider is that they are claiming a 66% reduction over the year, yet they are now producing water (c. 35 - 40 bbls/day) which has to be disposed of.

No real idea of water disposal costs here, but I wouldn't be surprised if it was in the region of £8 - £10/bbl.

Ocelot - thanks - should have worked that out for myself....

Ocelot / Penguins,

Probably a daft question, but if UKOG paid PW in shares, would they need to issue an RNS?

They've already covered in an RNS that they have that option, and got permission at the last AGM to issue the amount of shares to cover the PW payment.

Ozzy 52

Looking back through your recent posts, I can see you have contributed nothing to this board except gratuitous insults and mindless posts showing your ignorance of how things work in the oilfield.

It is clear that you are an Ogre like cave dwelling creature, so I'd like to congratulate you on being the first poster that I consign to the round file.

I wish you all the best and also sincerely wish that you do not pass your genes onto the next generation.

Mirasol, you are wasting your time.

The majority of people wish to share their ideas, learn and expand their knowledge.

Others... well, you can lead a horse to water.
You can even force it's head under the surface.
But if it still chooses to drown.....

Ozzy,

Even if your 13:50 post made sense, the current theory is that the water on Earth mostly came from comets...

Again, do some basic research...

Cont'd..

But the biggest effect is how much water has flowed through the sediment and where that water has come from.
The cases where oil has formed in a structure and never moved in from elsewhere are very rare - it nearly always flows from somewhere else and gets trapped, displacing most (but not all) of the water that had been there previously.
The same goes for formation water which is usually the driving force and indeed may continue to flow after the oil had stopped moving (i.e. the oil has reached the structures spill point, so the water carries on flowing underneath it).

So the chemical composition of the formation water within the oil leg may be very different from that of the water below the oil column.

In that case, the formation water composition depends on what type of rock it has flowed through, as it will dissolve minerals from the rock as it goes – especially Halite or Carbonate sequences.

So it is quite normal for formation water to have high salinity levels even when it's never been anywhere near the ocean.

It would be better if you did some basic research on a subject before insulting other posters..

Ozzy - Mirasol and IBug are both correct.
'Salt water' can cover a whole variety of chemical make ups - as can sea water for that matter.

For example, the sea water in St. Georges channel contains 1% Calcium Chloride, which isn't present in the North Sea, while the composition of sea water off Africa is different to that of Asia, which is different to that of Europe.

Sea water actually isn't that salty.

Indeed, much more often than not, the formation water produced by a well is up to 10x as salty as sea water.

Most people think that 'salt water' just mean it contains Sodium Chloride (table salt). It can also contain salts made from Potassium, Magnesium or Calcium in varying concentrations and the drilling fluid has to be chemically adjusted for each.
The other component doesn’t have to be Chlorine either, for that matter.

There are many things that drive the salt concentration of formation water - the environment the sediment was laid down in, whether or not the water remained in situ or came from somewhere else and what the sediment is are usually the main three.

Taking the last point first, if the sediment was, say, sandstone, then the chemical composition of the water (if it remains in place) won't change much, although initial evaporation may make it more concentrated than the environment it was laid down in.
If the sediment was limestone (and again, the water remains in place), then over time it will dissolve the minerals in the rock around it and the chemical composition becomes much more complicated (and usually more 'salty').

Limestones were nearly always laid down in a sea water environment - although the chemical composition of sea water has itself varied considerably over geological time.

The environment that the sediment was initially laid down in is important as it affects the composition of the sediment. So a shale (and therefore the entrained water) laid down in a freshwater environment will have a different composition to that laid down in a saline environment.

TBC

Ozzy,
Ibug's post stated 'salt water'.

It was you that made the leap to presuming that meant 'sea water'.

Fizzocks @ 10:46 - Nailed it!!!

Ibug,

We can read between the lines and surmise that during Q4 2020, the average production rate was c. 135 BOPD when the well was flowing and that it flowed for c. 15 days in December.

What we can't tell is what the flow rate and water cut were AFTER the W/O was performed, as UKOG have chosen not to share any data that can tell us this information.

Since this is UKOG's only real asset, waiting until the OGA figures come out in 3 months time really isn't acceptable.

GKB47 - The OGA data is three months in arrears, so we have no idea of what the effects of the W/O were on production.

Art,
To produce both through the same well bore at the same time would require a dual Completion (i.e. two strings of Tubing), which HH-1 does not have.
It is possible, with the right configuration (sliding sleeves and downhole packers), to produce selectively from one or the other through the same tubing string, but for reservoir management purposes, you would not produce both at the same time.
With this second configuration, if you wanted to produce from the Kimm at the same time as doing a PBU on the Portland, you'd need a downhole pressure gauge with real time surface monitoring through a data cable attached to the outside of the tubing to get the PBU information.
This technology is relatively expensive and UKOG obviously decided it wasn't cost-effective to run during the W/O in light of previous production experience on the Kimm.

Cynderlad,
Good question, why didn't they dual complete the Portland and the Kimm, as previously stated was the intention?
We don't know, because UKOG didn't say in the RNS.

What is the post W/O production rate of HH-1?
We don't know, because UKOG didn't say in the RNS.

What is the water cut of the production on HH-1?
We don't know. because UKOG didn't say in the RNS.

So we can speculate a lot about costs, but there are a lot of unknowns which UKOG didn't take the opportunity to clarify.

I suspect your estimate of 650 bbls oil may be on the high side, but lets roll with it.

I understand UKOG quoted operating costs, PRIOR to the water breakthrough, of $13/bbl. These operating costs should include all site costs. Any rental equipment not needed would (should!) have been offhired long ago.

So that's $27k/week income.

From the OGA data, we can infer a water cut of c. 25%, so let's presume that means they are producing c. 162 bbls water/week.

My guess is the water disposal cost would be in the region of $10/bbl (maybe someone can look that up from another field in the Weald or Wessex Basins), bringing the income down to c. $25k/week.

The big question is what is included in the quoted operating costs. If it includes UKOG's overheads (office, staff etc), then clearly HH is making a profit.

However, this would be unusual as normally Head Office Overheads would be carried separately, especially since HHDL is a subsidiary of UKOG and isn't 100% owned.

In that case, what UKOG would be doing, as the Operator, is time-writing as much to the HHDL licence as they think that Partners will let them get away with. Overheads are typically grossed up by a factor of 2.5 - 3 when charged out.

So my gut feeling is that HHDL might be making a small operating profit (bear in mind HHDL owes UKOG a bunch of cash that needs to be paid back), but UKOG are definitely loosing money.