Member Info for B2HS2L

I think the partners have more info about what went wrong at Brockham in Dec / Jan than we PI's.
Particularly the bit about
"During operations several key completion components failed for a variety of reasons beyond the Company's control".
A successful attempt to gloss over some practices / process issues we will never get to hear of.

From the above, I think the partners will want to have their say on the way forward, and we know Lucan thinks this is the most critical part of getting the well to perform as efficiently as possible.

'April 2017' = April 2019

The 'April 2017' presentation mentions the possibility of Brockham sidetracks (page 8),
but nothing about how they might be funded.
Our situation is that all funds raised are assigned to working capital, or to fund four primary objectives:

Brockham, Balcombe, Saltfleetby (assuming a deal is signed) and Lidsey.

I was thinking how the Brockham sidetracks might be funded.
I recalled Alan mentioning a way that, should Brockham prove commercial as expected, sidetracks could be funded.
Hope he does not mind me reproducing his 02.01.2019 post reproduced below.
+++++++
Alan2017 post 02.01.2019

Tax savings pay for entire Brockham

What folk may not appreciate about the incurred indefinitely available tax losses of circa £11 million to carry forward against future taxable income of the subsidiaries is that this additional pot of cash through tax savings will pay for all the wells / sidetracks to be drilled at Brockham, the entire development.

1 year of production of BRX4Z will pay for the entire Brockham development. The money leaves one pocket and goes back into the other pocket. Thats another big plus factor for choosing Angus when comparing Angus and UKOG for investor money.

Angus have 3 wells to surface out of a possible 6.
Yes you can use the existing well subsurface infrastructure to drill sidetracks and turn them in to Kimmeridge producers.

The best well to sidetrack would be the BRX3 well, which BP originally drilled and has now become a water injector. Whether they drill out of 9 5/8" casing, drill 8 1/2" hole, run 7" liner before drilling the Kimmeridge with a 6" hole before running liner and complete.

BRX3Z and BRX2X would take approximately 14-21 days each to drill and complete.
Angus only pay 65% of the well costs. So it wont be a costly outlay.

Angus will perform the BRX4Z EWT and from those results plan the best location for the sidetrack wells.

So to reiterate the tax savings on every barrel of oil produced during the commercial production test from the historical tax incurred looses of £11 million in effect pays for the entire Angus field development costs.

+++++++++++

So depending on a reasonably high sustainable flowrate, there is a possibility that after 1 year of production, a large chunk of the 65% of the well costs could be available for the next Brockham sidetrack.

This is not in the April 2019 presentation, but I hope it is something the BoD plan, since Brockham, Slatfleetby and Lidsey are apparently funded..

Go Brockham!

E_AL, Thanks for isolating the parts of GL and JTP's recent interviews concerning Brockham,
it was necessary for clarity.

I recall that when the YA deal was announced, with 2* £1.5M tranches on 09.01.2019, the first tranche had already been drawn down.

This does not make Lucan wrong about ANGS being fully funded, but rather shows how quickly financial matters can move rapidly to create such a financial requirement.

If the OO is not fully subscribed, he will have insufficient funds to do what is set out as costed in the April 2019 presentation is my only point.

Page 25 of this presentation shows that the board are trying to raise £3.5M to fund four projects and £1.2M working capital.

At the end of last month they raised £3M from II's.

This week they hope to raise £0.5M in an open offer from PI's.

If the Open Offer does not raise £0.5M, there will not be enough cash to provide
a) the full amount of working capital required,
or
b) the cash available for projects will be insufficient.

According to Page 8, there are 4 primary objectives.

Brockham and Balcombe are 1 & 2, Saltfleetby 3, & Lidsey 4. Order of priorities is not stated.

If they are in priority order, any cash shortfall might impact plans to survey Lidsey.

If Brockham is commercial, no mention is made of establishing the funding requirement to plan and drill sidetracks from present wells (*2).

Mirasol, - I feel this is the present owners - Gazprom and Wintershall - making as sure as they can be that they are not found liable at a later date for any abandonment costs. Is this your interpretation of the situation?

I feel that posters (myself included) on the subject of the gas field have not given full weight to the information on page 15 of the April 2019 presentation.
Please read the quote carefully, particularly the RISK WARNING:

"*Figures quoted in this presentation with regards to the Gas Field represent gross capital
requirements and total production. Angus will be liable for 51%.

RISK WARNING:

The heads of terms (including exclusivity provisions) agreed note that completion of the
acquisition of 51% of the licence is conditional on the prior acquisition of the field and licence by
a third party abandonment operator.
Therefore, over and above operational risks, there exists the risk that the transaction will not
proceed to completion.
In addition, considerable due diligence is required prior to completion which is expected to
occur within 45 days."

++++++++++
In order for ANGS to acquire a 51% working interest in Saltfleetby:

1 The gas field and license must first be acquired by a third party abandonment operator from Gazprom and Wintershall.
ANGS must be working on this with such an operator, or a deal would not be as near as Lucan implies.
So Angus's partner on this project is the abandonment operator.

2 51% of the license is to be acquired from the partner.

3 51% of the following known costs to be the responsibility of Angus, the rest is the responsibility of the partner:

a £1M workover of existing wells
b £500-700K for new 10 inch flowline (1200m)
c £1M compression and dewpoint control installation.

4 Although not stated, once the field is supplying gas to the grid, the abandonment operator is a sleeping partner, responsible for 49% of running cost, and benefiting from 49% of profit.

So is the abandonment operator making abandonment funds available to ANGS, (£2M) in the form of a loan?
Nobody on the this BB can say how abandonment costs can be made available to an operator for uses other than abandonment.

*** For those not keen on this gas project, Angus highlights the risk that the transaction (gas field purchase by abandonment operator) might not proceed to completion. ***

From Page 21 of the April 2019 presentation:

The field presents an opportunity for field rehabilitation and further development. To get production going
we believe the following would be required:
• A short pipeline extension (1.2km) to bypass the old terminal
• New hydrocarbon and water dewpoint control. Compression to enable export into the national grid
• Agreement of the national transmission system to feed into the grid

From Page 19:

SMALL – SCALE PROCESSING
In-house processing including compression and dewpoint control are estimated to cost £1million to install

NEW PIPELINE
New 10 inch flowline (1200m) to divert around current
facilities and feed directly into National Grid (£500-700k)

From Page 20:

Workover of existing wells: £1 million

From 30.04.2019 RNS:

"Under the currently discussed terms, the Proposed Acquisition licence would also bring with it a cash contribution toward eventual abandonment costs. The Directors believe, taking into account site visits and discussions with abandonment operators and extrapolating from abandonment quotes on the Company's existing wells, this contribution will cover the Company's 51% share of abandonment costs on the Gas Field. Alternatively, but not additionally, the same cash contribution will, in the opinion of the Directors but without external verification, suffice to pay for the reconnection costs of the Gas Field to the National Gas Grid. This, plus anticipated additional work on the Gas Field, is currently anticipated to cost a total of £1.7million."

These costs (£2.7 Million as a minimum), will need to be incurred to make gas available to the grid.
A gas professional to oversee the project would be a wise move, with or without board appointment.

Knowing there is X amount of gas in place is one thing, but the infrastructure to access and export it is no longer in place.

Capital expenditure on re-connection to gas grid is stated as £1.7m + , so ROI might be a year, without spending on any well refurbishment required.

Doesn't this fact impact the Lucan 'doubling the market cap on clinching the deal' statement?

Alan:
These are my Candidate answers from Angus:

Q1 Surely you would analyse the data from the Weald and then perforate with this knowledge in hand leading on to flow test afterwards.

A1 As much Weald experience gathered as possible (amount of experience and number of sources unknown). Decisions made and well perforated accordingly. Well awaits flow test.

+++++++++

Q2 Why reperforate the shale section and then halt operations to analyse data both at Brockham and HH.

A2 Because the ANGS perforation and reperforation experience differs from that at HH.
(for instance well instrumentation reading differences, what happened [or didn't happen] and when).

Brocombe was designed for Kimmeridge production using one bore size, and HH for oil exploration at Kimmeridge 3/4 and other layers, using a different bore size.

These design differences may make perforation comparison difficult, - but if no comparison is attempted,
how do you know there are no lessons to learn.

Alan2017 score preassigned at 1/10 - 'see me', (unless you assign a lower value).

FWIW I think Lucan would not allow further expenditure on a well that was not likely to be profitable, - he has a financial reputation to uphold.

Good post Mirasol.
Knowing how difficult it might be to get things right, and avoid a second Broadford Bridge, the parties may be demanding to have their say on how things are to proceed?

Alan,
I assume we need to provide gas to wire facilities from day 1 of EWT.
Is this system in use on many other wells in UK, or are we pioneering please?

Purchased the same number of shares today at 3.725 as I was allotted in the Open Offer.
Will do same again each time sp falls 0.25p.
Little and often, - well hopefully not that often!

My guess would be Q4 next yr, but it is a guess.
There is the potential here for regulatory problems to adversely affect timescales.

Baits, - agreed.
Fleetby oil evaluated so far:
https://www.energy-pedia.com/news/general/roc-updates-saltfleetby-drilling-operations

IMO Lucan shouldn't be saying gas will be contributing to profits in Q1 next year, I don't think this is a realistic timeline.

Could be DL moaning about cost and work package content, or more likely the speed of progression.
You could imagine him throwing Teddy's out the pram about present sp, the fact he has 8M shares under water blah blah.

Alan has pointed out that the partners are contracted to supply necessary funds at various points in the program.

If there are significant differences between whats in the contract, and what ANGS want to do next in terms of bringing oil to surface, extra monitoring facilities, paying for specialist services, anything to do with extra cost, then the partners will be wanting the meeting as much as ANGS.

For example, it became obvious in Feb that the the next stage was to fix the water ingress problem in order to see the wood for the trees. The partners would have had to fund their part of the rework, presumably a meeting took place to discuss the cost of rework, and any risks involved. I don't think a fax would have sufficed for that.

Alan,

Lucan has talked about learning from UKOG producing from the Kimerage.

Is there a possibility that ANGS want to enhance the flow test equipment package, to perform further operational monitoring, and they need agreement with partners to spend the extra?

Real Analyst -

"Ergo - I don't think we will know how much Brockham is capable of providing for quite a while."

I was talking about after there is oil to surface.

Some companies want to turn the taps full on for a short period, and produce a headline maximum flowrate, for sp inflation purposes.

This could damage a naturally fracked well.

From Lucan's comments I think a slow but sure flowrate increase over a number of weeks after oil to surface is what I am expecting.