Member Info for Penguins

Phil,
'Shares to be "dumped" at 130% of market price.'

I think there's a bit about 90% of the vwap - and it's the lowest of the 2 possible conversion prices

Total control - that went well at BB - maybe if another company was there to be convinced they would have been more sensible and risk averse. Also means UKOG paying for 85% - which is fine when the production is sufficient for a positive cash flow - but not when there isn't.

Ocelot

'is going to make UKOG a much more attractive takeover target.'

Why, and who? - isn't it obvious nobody with the funds to do so is interested in the Weald. They could have had 35% of the HH licences for £12mm - possibly less with an all cash deal.

I can understand Tellurian not being interested - I've been suggesting they might sell out for some time - but if they were in sales mode they would have been able to present all the data available on HH (they were carried, not sole risked), not just what is in RNS - ie what we know.

Here is part of one of my posts, just after the £3.5mm fundraise, 27 March 2019, 9:19:-

If I were to guess that guess would be that this fund raise is for some, maybe all plus shares or a complex part carry, of Tellurian's share of the HH licences - a decision on whether they join in or dispose of their interest needing to be made before money starts to be spent as these two upcoming HH wells are obligation work and Tellurian are obliged in the JOA to participate or could lose their equity completely. If they want to avoid this they need to sell up to someone who will participate, and the only buyers in the Weald are..........UKOG and Angus (who have their own troubles).

on twitter:-

'[icon of a penguin] posting lying drivel yet again. Was Xodus I think who said up to 45% of Portland contacted oil recoverable. SS later mooted I think 10-12m bbl (~30% OIP) from HH licenses. Bird-brain (8m bbl) knows better than SS. Not. Why would SS leave proven reserves in the ground?'

You then tweeted a screen capture of my 16:05 post – but you have several criticisms that are wrong.

There are no proven reserves yet. Whatever plan UKOG have (2 wells one injector) will be the determinant of the reserves.

The updated 11 to 14mmbbls in the latest RNS is presumably the contacted Portland oil per well (doesn’t actually say that). With 30mmbbls OIP the 2 wells planned will only be contacting 22 to 28mmbbls so when you quote 30% recovery that’s 6.6mmbbls to 8.4mmbbls. So maybe bird brain is right.

As I used the mid of these (25mmbbls) your complaint elsewhere that I always use the worst case is wrong (The fish eating thicko always uses the same dishonest tactics -take the most negative interpretation and present it as 'fact'), and I actually used the maximum NPV value (£18) quoted by SS.

The 45% recovery of connected Oil in Place is could be attained if a successful full voidage replacement pressure support scheme is incorporated into the field's development.

Could, if, up to and there is no indication that a single injection well will provide a full voidage replacement pressure support scheme.

Rodders

You are depending on documents from 2014 repeated in a 2018 document. I don’t have to show you a document less than 5 years old. But FYI Magellan's understanding of the Farm in agreement is outlined many times in their most recent SEC filings.

Magellan quarterly period ended September 30, 2016 SEC filing: ‘Pursuant to a farmout agreement with Horse Hill Development, Ltd ("HHDL") dated as of December 20, 2013, the Company holds a 35% interest in PEDLs 137 and 246, where the Horse Hill-1 well ("HH-1") was drilled. In accordance with the farmout agreement, the Company’s costs in relation to these licenses are 100% carried by HHDL until production, including costs related to conducting flow tests.’

Repeated December 31, 2016, dated Feb 28 2017.

Following this filing Tellurian has reversed into Magellan and unfortunately Tellurian’s interest in Horse Hill seems so below their radar that their involvement is not mentioned in their filings.

As previously posted if Tellurian were paying their way the cash statement would not have 100% of the oil revenue attributed to HHDL. Even Thorpedo mentions it's 100% in his post of 30 July at 11:35.

Last post, probably.

If the carry had ended and Tellurian were paying their share of ewt costs it would be reasonable for them to take their share (as specified in the JOA) of oil. As has been pointed out the cash flow shows a value of 100% of the oil sales were credited to HHDL, not 65%.

As for Alba it seems that they believe there will be a 'dilutive' effect of not paying the cash call - so that would indicate that it is expected that the provisions in the current HHDL investment agreement will be enacted. 'In accordance with those provisions, and subject to the HHDL Board determining to apply those provisions, any dilution of Alba's shareholding will be negligible (less than 0.1%)' - From Alba RNS 18 June 2019)

So maybe they will lose their interest - but they don't seem to think so.

#UKOG I bet pingu decides against posting about this on LSE. We know he reads my Tweets. Go on pingu, tell me I'm wrong.

'P.S. farm out agreements are often time limited. I suggest that the free carry has ceased and that Tellurian have to pay their costs as per the July 2018 docs'

You're wrong.

Firstly the JOA in the 2018 docs dates from 2014:- 'On an unspecified date in 2014 HHDL and Magellan entered into a joint operating agreement in relation to PEDL137 (the “PEDL137 JOA”)'

and all the other agreements mentioning 65% participation also date from that time.

So to claim the document reflects the position in 2018 is misleading, just because it doesn't detail the contents of the Farm In agreement, which it acknowledges exists, it certainly doesn't indicate the agreement has lapsed.

There was indeed a time limit - from UKOG RNS 20/12/2013 :- Magellan Petroleum (UK) Limited, a subsidiary of NASDAQ-listed 'Magellan Petroleum Corporation ("Magellan"), currently owns 100% of the 99.29 km2 (24,525 acre) PEDL 137 ("Horse Hill") and has agreements with HHDL to earn a direct 65% participating interest and operatorship in the licence, under certain contractual conditions, by the drilling of the proposed 2,646 m (8,680 ft) Horse Hill-1 well by the end of August 2014.'

As HHDL has 65% interest in the licences Magellan must have allowed this deadline to slip as the well was started September 2014.

But why would Magellan allow a time limit to the period that they wouldn't have to pay for drilling and testing as if there was a time limit it would be in HHDL's interest to delay testing as long as possible.

The limit that Magellan has published in official documents is after drilling and testing from the Magellan Company Report, For the fiscal year ended June 30, 2016.

'the Company holds a 35% interest in HH-1 and these licenses following a farmout agreement with Horse Hill Development, Ltd ("HHDL") dated as of December 20, 2013, pursuant to which agreement the Company’s costs in relation to these licenses are 100% carried by HHDL until production and including costs related to conducting certain flow tests.'

They have been more specific (2015):- 'Pursuant to a farmout agreement executed in December 2013, Magellan owns a 35% working interest in the HH-1 well and is being carried for its share of well costs through testing and completion.'

Why anybody thinks this agreement has lapsed or Tellurian are paying costs related to the ewt I can't imagine.

Thorpedo,

you advised me to read the JOA - I did:-

'Each party to the PEDL137 JOA is entitled to take in kind and separately dispose of, and will also be required to lift, its substance entitlement in the total quantities of petroleum available under the PEDL137.

As for who pays - well currently HHDL, 100% as per farm out agreement with Magellan.

When (if?) Tellurian takes it's share HHDL as operator will have (as Mirasol said earlier) agreed a budget with Tellurian and then issue an AFE (Authorisation For Expenditure) for specific work that has to also be agreed with Tellurian, HHDL then can then issue cash calls for the work as necessary.

As for I value the Portland at £69mm - that was solely to illustrate how, using UKOG and SS figures, wizard was giving a misleading valuation - not necessarily my valuation.

I'm not sure that wizard realises that contacted oil is the OIP that the well 'sees'. Not the recoverable oil. UKOG has never officially stated how much Portland oil will be recovered.

Wizard,

I know Crocqman thinks I only nit pick and much of what I write is petty and unimportant in the grand scheme of things. - but connected oil per well will not 'become reserves'. Maybe some part of it (30% recovery of connected oil based on 3 wells, 2 injectors according to SS) but not all of it. You are calculating a value of £200mm for the Portland based on a misconception.

2 wells 30% (maybe) of 25mmbbls connected oil (mid way between 22 and 28) @ £18 per barrel = £135mm but that is 100% - as UKOG is just over 50% of the licence say £69mm.

Croqman as long as another poster continues to discuss, so will I - this is a discussion board. If another poster disputed what you say I suspect you would respond, and you also seem to pull up other posters on specific points.

Thorpedo's assertion (Once HHDL starts producing later this year the profits will go to repay the loans (to UKOG) before splitting any profits with Tellurian) probably means the difference of many millions of pounds to UKOG/HHDL when he has no basis to state it as HHDL's loans are a matter between HHDL and it's shareholders.

To get back to the discussion...…..

Thorpedo,

I have read the re-admission document and as you point out ' Its about sharing costs not a free carry'.....precisely.

This is what Magellan think, from the Magellan Company Report, For the fiscal year ended June 30, 2016.

'the Company holds a 35% interest in HH-1 and these licenses following a farmout agreement with Horse Hill Development, Ltd ("HHDL") dated as of December 20, 2013, pursuant to which agreement the Company’s costs in relation to these licenses are 100% carried by HHDL until production and including costs related to conducting certain flow tests.'

Thorpedo,

So you believe there is no agreement elsewhere covering the 'free carry' and Magellan gave away their 65% in the licence for nothing and will be cash called for the work they have said was 'carried'.

In the re-admission document there is mention of the 'Magellan Agreement' described as: 'the farmout agreement entered into between HHDL and Magellan on 20 December 2013' - but no details.

You are right in that we don't know the full details of the carry - but it is unlikely that Magellan would have committed to repay 35% of the costs of drilling and testing of HH-1 under any circumstances (in your original post - 'Once HHDL starts producing later this year the profits will go to repay the loans (to UKOG) before splitting any profits with Tellurian) - they passed the risk associated with drilling and testing to HHDL.

One small point is they will never 'split profits' with Tellurian. What they will do is cash call for expenditure and probably give Tellurian their share of cash from their share of oil sales - although Tellurian almost certainly have the right to sell 'their' share of oil.

Thorpedo,

If that's the case where is the payment for the 65% of the HH licences that HHDL got from Magellan. I'm not sure I would agree to a free carry if I had to pay for it afterwards, doesn't sound very free.

Loans are repayable out of HHDL's profits, not Tellurians. They are HHDL'S debts, not the licences.

Thorpedo,

Carried may not be a legal term but it is used to describe a situation where another company agrees to,pay the costs of another.

In this case HHDL agreed to pay 100% of the costs of drilling and testing HH-1 in return for 65% of the equity in the HH licences.

Why do you think that loans made to HHDL by its shareholders in a private arrangement give HHDL the right to retain all the oil of the development or from HH-1z and HH-2/2z if Tellurian have contributed their share of costs to those wells?

Assuming Tellurian remain in the licence as a full paying partner for the 2 appraisal wells and the development they will pay their share of costs and receive their share of the oil (35%). Loans enabled HHDL to perform the work that Tellurian were 'carried' through. Any loans to HHDL are between the shareholders and HHDL, nothing to do with Tellurian.

HHDL will repay loans to their shareholders out of the profit they make from their share of the oil, and the amounts will depend on what is owed not their shareholding (as UKOG may have paid to cover other companies shortfalls).

Once loans are repaid then HHDL profits will presumably be distributed as dividends to the shareholders.

Sting,

that picture shows the location of the HH-2 cellar - it's the circle nearer the tanks, it won't be moving. It has been covered over obviously. The concrete pad is the whitish area to the left of the crane

The production plan shows 5 more well locations. two beyond the hole the crane is working on (HH-1), the distance between each hole the same as the distance between HH-1 and HH-2. Two of the other three are to the right of HH-1 and 2 as you look at the picture (about the same distance from HH-1 and HH-2 as HH-1 and HH-2 are apart and parallel to them) just off the current pad. The third is the same distance further away (looking at the picture) in l

Imagine a rig placed over HH-2 with it's sound barrier and other equipment - the furthest well planned (the injector) would be far enough away but the two locations to the right would be under the rig unit and drill cabin and prevent any extension to the current pad in that direction.

Sting,

I won't repeat my previous post in response to your similar post about a we ago as there is a simple flaw in your argument about cellar placement.

The plan for the layout of the site during development shows the 7 wells in 2 rows, and those 2 rows include HH-1 and HH-2 surface location, designation of a well is tied to it's surface location. There is no new pad, they will have to extend the current pad, doing so with a rig in place will not be possible for most of the well cellar locations even if some of the ancillary equipment is moved around.

But there is no need to rush and prepare the extra cellars, trying to work around an operating rig.

Everything points to a pause after drilling HH-2 and HH-2z, the need to test to produce a CPR for Portland and the need for further data from Kimmeridge testing and the HH-2 deepening to decide the emplacement of the Kimmeridge horizontal.
There is also the small matter of paying for what will be 2 and a half wells back to back whist having little in the way of contingency even including the £3.5 miliion.

This becomes more of a problem now that Kimmeridge test rates have been confirmed. Rather than a build up of funds whilst the Kimmeridge testing continues (or at least a slower pace of outflow) which was anticipated with expectations of much higher flow rates than the prudent Portland testing, instead it is likely the net cash out will continue at previous rates so every month waiting for the rig to arrive will see a lot less cash in the kitty.

Assuming the Portland horizontal achieves at least the minimum rate anticipated and the Kimmeridge testing from HH-1 continues should provide positive cash flow at last.

Here's a left field idea. Maybe drill HH-1Z as a Portland well if HH-2Z is successful kicking the HH Kimmeridge development down the road or at least until after the Loxley well is drilled and tested.

Just spotted that 'only' crept in, and I could be more specific about where the idea for the hybrid play came from.

So second sentence should be :- I certainly referred to the fact that the BGS report was only about the shale, but actually the report suggested the micrites might form a target for an hybrid play(before HHDL came up with the idea) - seems the experts were right.

I can't imagine who you might be referring to because it certainly wasn't me. I certainly only referred to the fact that the BGS report was only about the shale, but actually suggested the micrites might form a target for an hybrid play(before HHDL came up with the idea) - seems the experts were right.

The BGS report did calculate a much lower figure for moveable oil within the shales than the total OIP that Nutech came up with, and they thought maturity would be an issue in certain parts of the Weald - certainly UKOG refer to maturity in their planning application for Loxley-1 (better placed than HH or BB) and it seems to be a problem at Brockham.

I also would not have said that because big oil missed it it couldn't be there - I'm well aware that they miss stuff, and sometimes don't bother because it's below their thresholds.

So who are you referring to?

JPtop,

I think you've been reading too many posts by Alan2017 where he was desperate to infer that because Brockham X4Z was a 'perfect' well it would produce loads more than the 'imperfectly' completed HH-1.

Let's think about that for a moment...…………………………………………...

There's no evidence they are not producing through production tubing, nor that any of the completion is sub-optimal.

It certainly has never been stated or implied by UKOG - the reason they didn't flow the Portland at the optimal 362 bopd was not said to be due to the completion - just prudence.

Oktane,

By way of context HHDL stated in the environmental method statement for HH-1 that the Kimmeridge might have to be swabbed to obtain even a sample of Kimmeridge oil before the 2016 test, so no, I wasn't certain it wouldn't flow - I just repeated the company's concerns - which turned out to be unfounded.

What has yet to be proved is the commerciality of the Kimmeridge - I haven't said it won't be commercial (it was UKOG that said HH was sub commercial - presumably worried about the previous 'unstable' testing) - just it might not be commercial Weald wide and the level of commerciality is unknown, in fact I have used the projected value of produced Kimmeridge oil in calculations of NPV for HH and used the projections of production indicated by tanker trips per day and the gas production forecast in other calculations.

Caution is certainly a good strategy with AIM oilers (or any AIM company) - extrapolating figures that require a lot more explanation than is provided in RNS is dangerous.

Firstly claims of 2 tankers most days since the start of the Kimmeridge test, with 3 some days, seems to have been a massive exaggeration. I make 5,524 bbls about 25 tankers in about 25 days, an average over 25 days since restart of the Kimmeridge ewt of about 221bopd – just about what Mirasol predicted yesterday morning.

So posters calculating revenue based on 440bopd based on the 2 tankers a day also wrong - with an initial half hour rate of 332bopd, and since then a ‘stable’ production rate between 200 and 266 bopd

How come a poster on this board can come up with a more accurate figure than the guys who boast how truthful they are and they should be believed above all others.

I would say part of the malaise with this share is their constant tweeting of expectations that keep turning out to be massively wrong – 2 maybe 3 tankers a day turns out to be an average of about one a day, 2 tankers just catching up on days with no tankers.

Theupgrade in Portland connected oil seems to have gone up by about 40% - but recovery of a decent amount of that (30%) depended on injecting water using 2 injectors for 3 horizontals, but the plan has one injector and 2 producers. But water has still has failed to appear from either formation for injection into the Portland so the CPR will make interesting reading.

The expectation of commerciality of the Kimmeridge seems to have improved – what’s worrying is that obviously the previous testing – which went on for a few months – had issues ‘The resumption of Kimmeridge oil flow at more stable rates than previously seen is welcome news for the Kimmeridge's commercial future’. Not exactly an A+ in the end of term report – and it certainly wasn’t previously mentioned the rates weren’t stable.

A steady as she goes RNS – nothing startlingly bad but the Kimmeridge not delivering anything like the volumes predicted by certain individuals. Unfortunately they will now be bleating about restricted rates etc when there’s no evidence they are doing so beyond careful reservoir management – which will be a requirement through production anyway.

Redheadedrager,

The income from oil sales over the 3 months April, May , June was less than £900,000 (read my post), not £900,000 per month.

That's messes your 50k a month prof it, So even your figure should be minus about £600,000 a month.