Member Info for GreyPanther

Hi dai2belts. The dashed lines on Figure 2-4 of the diagram on page 77 probably represent faults. The solid lines are where the fault positions are fairly certain, and the dashed lines are where they ae conjectural, or much less certain. This particular diagram isn't by TRACS (the authors of the CPR) but was taken from an academic paper and I know its author, who is extremely competent. What I take from the Fig.2-4 is that the Kopervik Sand (the Lower Cretaceous reservoir which contains the Serenity discovery) is probably much less than 200 ft thick at the present appraisal location, but it should be present. In my opinion the big uncertainty is how much of it will be full of oil. The lower part of the Kopervik Sand, as seen elsewhere in Quad 13, can be shale-prone, and some thinner sands can be water-bearing in places,. In all honesty the CPR has made me a bit more cautious. In places I got the impression that TRACS don't share all of i3E's technical views.

Thanks tonynorstrom1. Lots to read there

The red line that runs through several wells shows the position of a well correlation diagram which, for some strange reason, neither i3E nor EOG seem to have included in their presentations. This is a pity as it could have been quite revealing, as it looks as if Serenity is a narrow tilted fault block, rather than another horst block. But perhaps they don't want to confuse punters with too much information. All the best.

I didn't want to get too carried away wondering what the UJO divi might be - assuming there will to be one - so I was interested in the following info that I came across recently. Only about 195 of the 867 AIM listed companies currently pays a dividend, which is only about 22% to 23% of them. The average yield from these 195 companies is about 2.5%. So, if there is to be a dividend, UJO doesn't really need to pay much more than about 0.75p (2.5% of our current 29.5p SP) to be comparable to the rest of the sector. Of course, this wouldn’t apply if the share price were to move significantly before a decision is made. Thinking about what this would cost, there are now112.866 million UJO shares, so a 0.75p divi would only cost about £846k, which is definitely affordable. However, a divi also needs to be sustainable on an annual basis, so I reckon we may not see the 2p to even 3p that I've saw mentioned on the board earlier.

Hi dai2belts. Thanks for your latest comments, and the Repsol Sinopec link was much appreciated. It strikes me that the reservoir sealing capacity, and even the presence of a local seal could be one of the critical issues, - at least in some places - along the extended East -West trend that constitutes the greater Serenity prospect.

Hi kinfisher. My take on the recently lower SP is that the stock market gave quite a lot of extra value to Egdon when the shale gas moratorium was rumoured to be about to end and, again,when it was actually lifted. Some investors are now querying whether any significant fracking activity will take place in the near future. However, UJO has next to no shale gas exposure, and they I believe they form quite a small part of the IGas portolio. Both have fallen back in September too but I reckon they haven't re-traced quite as much as Egdon.

Hi dai2belts. Thanks for your extra info. A Tain side-track of 1,400m (about 4,600 ft) from a well at ca. 5,000ft is quite a large step out. Do you know if it was done for development purposes rather than as a straight forward appraisal well?
And thanks boom.boom too. That Magnolia well at 13/23A-7 must have been drilled very close to the Captain field. So, if it "intersected oil in 120 feet thick captain sand (water wet)" was it oil -bearing or water-wet? I'm interested because if there was even a little oil in it, then it supports my idea that the boundary fault doesn't act as a seal everywhere a nd,IMO, this isn't so good for our finding an extensive Serenity oil accumulation. Still, time will tell.

You might possibly be interested in a conversation I had recently with a geophysicist friend who worked in the Serenity / Halibut Horst area, albeit some time ago, but presumably using a similar geophysical data set to the one used by EOG and i3Energy to locate the current well. He said there are direct hydrocarbon indicators (DHIs) along the prospective trend but they are quite “patchy” in their distribution. There’s even a DHI where the current well is being drilled so, in his opinion, there’s a very good chance of our finding oil here. But "How much?" was his big question. He also thought there were several different sidetrack scenarios:
1. We find an oil column and the reservoir both of the expected thickness. In this case the partners might decide to step out to the east or west along the structural trend. This could provide useful information about any local reservoir variation but, as it’s likely to be a shallow well with a probable depth of only 4,000 to 5,000 feet, we may not be able to deviate more than a few hundred yards in either direction. In his opinion this isn’t likely to be enough of an off-set to improve the estimated amount of oil-in-place (OIP) by very much.
2. We find a fairly small oil column, or maybe even no oil at all - which now seems fairly unlikely – so we decide to drill up-dip (to the north). However, we’ve been told by i3E that the reservoir thins to the north against the Halibut Horst. This isn’t therefore likely to prove up much additional oil.
3. The best outcome - and this is only a personal view - would be a down-dip sidetrack (to the south). This could prove very useful if a) the reservoir is found to be entirely oil-filled and the oil water contact hasn’t been reached at this location, or b) there’s seismic or other evidence to suggests that the reservoir thickens to the south, in which case it would be very useful to know how much of the thicker reservoir is oil-filled, and where the oil / water contact sits, if it hasn’t been found at the current location. This should significantly increase the OIP.
4. On a more negative note my friend added that an apparently valid prospect was drilled some time ago to the west of Serenity - he couldn’t recall the actual well number - which found a very thick sand but the well was dry. The reason for this was thought to be that the boundary fault next to the Halibut Horst didn’t act as a sealing fault at that particular location. IMO this may explain the patchy distribution of the DHIs.
5. We’ll only learn about all this when we get to total depth and they’ve seen the logs. Good luck to all, I say.

Hi Exploration. Thanks for your helpful comments. I too can't understand why RPS have relied on Western Canadian reefs for their geological model when these are of Devonian age, and we are dealing with Zechstein (Permian) non-reef sediments in East Yorkshire. And can you suggest why the best case sales gas of the Ellerby, Spring Hill and Withernsea prospects add up to 323.5 Bcf when RPS show an aggregate 363.7 Bcf. I can't believe this is an arithmetical error, so maybe there's a "statistical" reason? I sometimes think that some CPRs should be called an "Incompetent Persons Report". Nevertheless, there's a lot of interesting and supportive technical info if one looks through the more detailed report that's been posted on the company website.

Can anyone explain why the geological chance of success is 85.5% for the Kirkham Abbey Fm? This sounds like a pretty decent number but, with gas and oil /condensate already found in three or four wells, the geological chance of success must actually be 100%. The 85.5% CoS suggests to me that RPS actually meant the chance of commercial sucess, presumably for the WN project as a whole, or perhaps for the horizontal well. Any thoughts?

Thanks JediMaster1. I assume that's RPS then. I'd expected Rathlin to commission the present CPR in Canada, as Connaught did for the previous CPR. In 2017 they used Deloitte's Canadian people, but maybe not this time.

Hi JediMaster1. Can you please advise who / what is "Bedford" in this context? Many thanks

From my look at the earlier BGS report, the Bowland Shales that occur on Egdon's East Midlands licences are exactly the same age as those in other areas of NW England where fracking has occurred, Our shales may even be slightly less faulted than those in NW England, so they might be a bit easier to develop. I don't therefore see much to worry about from a technical POV. I'm also wondering if some of this "News"may be sour grapes on Mr Cornelius part since he's been out of the Cuadrilla job for a long time now.

Thanks OliviaOil. Corallian's 2021 annual accounts indicated that there were 7.54 million x £1 Corallian shares in issue. So the additional 2.46 million shares must have been granted since the accounts were issued.

Can someone explain this please? We currently own slightly under 50% of Corallian, so I was thinking we might get about half (say £16 million) of the £32 million gross proceeds from the Victory sale. Yesterday's RNS shows that RBD expects to receive about £12.7 million, which is only 39.7% of £32 million. This implies that c. £6.6 million (£32 million less 2 x £12.7 million) of the gross proceeds have been used up. So does the £6.6 million represent Corallian's transaction costs?

This is a poor result for Reabold as their share of the proceeds will be about £12.7 million. This is only an approx.x1.7 uplift on Reabold's total investment of £7.5 million in Corallian since late 2017. And they'll not see it all at once either, so I'm hoping that the money they'll receive in the short term is enough for our immediate purposes at West Newton and elsewhere.

In my opinion this isn't an exactly wonderful result for RBeabold as their share of the proceeds will be about £12.7 million. This is only an approx.x1.7 uplift on Reabold's total investment of £7.5 million in Corallian since late 2017. They'll not see it all at once either, so I'm hoping that the money they will receive in the short term is enough for their immdiate purposes at West Newton and elsewhere.

The Gaffney Cline reserve report published yesterday by UJO was excellent news IMO but it seems to have been widely misunderstood, especially if you look at UJO’s bulletin board. It’s quite instructive to compare the new numbers with those in ERCE’s 2016 CPR. The combined reserves for the Ashover, Wingfield, Peni*stone and Santon reservoir are now thought to be 4.334 million barrels recoverable if GC’s speculative Ashover figure of 2.43 million barrels is accepted, This, along with the 0.203 million barrels produced up to the end of June ‘22, comes to 4.537 million barrels. This is an increase of 111% compared with ERCE’s 2.15 million barrels, although the latter figure was for just three reservoirs because ERCE ascribed no reserves to the Santon Sand.
The new numbers are expected by GC to sustain a conservative production rate of 800 bopd for about 5 years , or 1.46 million barrels for the plateau period only. This gives me a lot of confidence for the future. We can now probably expect to see a run of good financial results.
It looks at first sight as if GC’s 0.67 million barrels of 2P recoverable reserves (for just the Ashover and Wingfield reservoirs) have increased only slightly from ERCE’s 0.62 million barrels to That’s apparently only an 8% increase, but GC’s report is dated 30 June ’22 and so we must add to their figure the 0.203 million barrels produced before then, So the 0.87 million recoverable from the Ashover and Wingfield is actually an increase of 40%.
Even more interesting to me is that in order to account for Wressle’s impressive performance, GC have suggested that a much deeper Ashover oil - water contact may be present than previously thought. Their “speculative” figure is 2.43 million barrels recoverable for the Ashover alone, plus perhaps 0.05 million for the Wingfield reservoir, which gives us 2.48 million for both reservoirs. So, adding the extra ca. 0.2 million barrels already produced, we get 2.68 million recoverable.This is a massive increase of 330% compared with ERCE’s 0.62 million. I rckon that’s pretty good, so I hope I’ve understood these new numbers correctly!

The Gaffney Cline reserve report published today by UJO is excellent news, and it’s instructive to compare the new numbers with those in ERCE’s 2016 CPR. The combined reserves for the Ashover, Wingfield, Pen*stone and the Santon reservoir are now thought to be 4.334 million barrels recoverable if GC’s speculative Ashover figure of 2.43 million barrels is used. This, along with the 0.203 million barrels produced up to the end of June ‘22, comes to 4.537 million barrels. This is an increase of 111% compared with ERCE’s 2.15 million barrels, although the latter figure was for just three reservoirs because ERCE ascribed no reserves to the Santon Sand.
The new numbers are expected to sustain a production rate of 800 bopd for about 5 years , or 2.336 million barrels for just the plateau period. This gives me a lot of confidence for the future and we can perhaps now hope for a flow of dividends well into the future.
It looks at first sight as if GC’s 2P recoverable reserves (for just the Ashover and Wingfield reservoirs) have increased only slightly from ERCE’s 0.62 million barrels, to 0.67 million now. One might think that’s not very much, but GC’s report is dated 30 June ’22 and we must add to their figure the 0.203 million barrels produced before then, so at 0.87 million it’s actually an increase of 40%.
And, in order to account for Wressle’s impressive performance, GC are suggesting that a much deeper Ashover oil - water contact may be present than was assumed previously. Their possiblys speculative new figure is 2.43 million barrels recoverable for the Ashover alone, plus perhaps 0.05 million for the Wingfield, which gives 2.48 million for both reservoirs. So, adding the extra ca. 0.2 million barrels, we get 2.68 million recoverable, an increase of 330% compared with ERCE’s 0.62 million, This is pretty good IMO, so let’s hope I’ve understood all these numbers correctly!

Hi Yanis2005. In answer to your query about UJO, other than Wressle they have some limited additional revenue from the Keddington oil field and, from time to time, from the Fiskerton oil field but I think the latter is currently suspended. There's also potential income from a small Claymore/ Piper royalty from which I believe the cash is still awaited. IMO you could probably offset the fact that UJO has 40% of Wressle compared with EOG having only 30% by the fact that EOG has significant (but not nearly as profitable as Wressle) income from its Crosby Warren and other small UK onshore fields. My concern is therefore why EOG hasn't at least 75% of the cash that UJO now holds. We may very easily have this much, or more, for investment in the Serenity well but we haven't been told enough to form a judgement. Maybe our new FD Will Holland is financially conservative - not a bad thing in an FD - but I’m wondering if there could perhaps be something in the forthcoming annual accounts that concerns him slightly, and which some extra cash would resolve. But, quite frankly, I wonder why our directors seem bent on trashing the share price for the second time in about six months.