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Hmmmm!
On balance probably.

We get to participate for 12.5% on a cost basis on any Indo deals, for I think another year. So any deals ADL does we can participate. The process is that ADL has to give us notice and then we decide whether to participate or not.

It looks to me that the workovers at Betun will give them an increment of maybe 200 bopd, so with the existing 70bopd that gives them 270bopd. It looks like it will cost them maybe $500k for maybe 30% (it is a complex formula and is in an earlier RNS). Plus there is a large undeveloped target called Selo. So 10.125bopd will cost $62.5k an 8 year license with undrilled targets at Betun and a undeveloped target at Selo. We would have to pick up our share of the costs going forward but from October we can probably cashflow this.

The gig here is that CAV a local Private Equity group wants to reverse multiple deals into ADL if this first gig works out as intended. I should think they are ecstatic about the results to date.

If AOGL doesn't want it, they can probably sell the rights on.

DYOR

https://www.lse.co.uk/rns/ADL/andalas-energy-and-pwr-operations-update--tg2xpxvtumo5xr9.html

Getting there. We have participation rights here.

Starting to get there.

This should mean that ADL has decent cashflow by the end of the month and will likely convert its position late September.

https://m.londonstockexchange.com/exchange/mobile/news/detail/14190227.html

I don't know but my view is that it is decent money but won't break the bank. It opens other doors. The operatorships are where the big bucks are: circa $1,300 pm per well plus the add ons.

No chance. I have done non-exec roles in the past and it is a thankless task. I do find it frustrating that I think things could be done a bit quicker here but I think both CW and PA are getting into the swing of it. The cashflow from the increased production will be starting to hit now and having cash in the bank always helps. In my view they have proved up two parts of the business model as it currently stands: workovers using TB's skill set and securing oilfield services contracts using their back office systems. There are a couple of other bits they need to prove up; picking up operatorships, farming into assets using TB's skill set and the back office skill sets, disposing of assets at a significant uplift in value, acquiring assets on commercially advantageous terms.

I note that TB mentioned other assets. I think that they will be more confident about looking at other assets now. TB also clearly wants the business to be bigger and that either means more assets or bigger assets or maybe both.

DYOR

I double checked with the audio presentation on the website. They are using a modelled decline curve for the four wells and production in excess of the curve is what counts for the 90% revenue share. Worth a listen. If they have done what they said in the presentation then we are already on decent number. Mawhinney was saying that they were expecting an improvement of 20/22.5 bopd on BTN 14 but that if the total volume of fluids increases as they think it will and the oil cut improves as they think it will then we could be talking about 30bopd increase on BTN14. Mawhinney clearly differentiates between what he calls a well service and a workover. This increase in production is the result of a well service in his language and the well workover is to come.

DYOR

1 pumper can handle 100 wells as long as they are nearby each other. A pumper is on about $40k pa

The netback varies on each field. Water disposal is a big issue, if we have our own water disposal the cost drops right down. The netback also depends on the split between gas and oil. Assuming a cost of about $15 per barrel will be about right. We get a premium on the oil at Austin and a premium on the gas at ZR . So it is not straight forward.

DYOR

I was tempted to correct people on this, including that Doubleup but decided I was wasting my time and put him on filter instead. People mis-read that last RNS.

" To address challenges such as leaks in the production strings, the tubing has been replaced in three wells (BTN01, 04 and 14). As a result, there has been an increase in the barrels of oil lifted and so under the operating services and option agreement ("Services Agreement") announced on 21 June 2019 , this small increment to production means the first income for the Company"

"At re-start the well is now producing 450 barrels of total fluids per day including 4.5 bopd, representing a slightly better figure than the Company would have expected at this stage. The well is performing in line with expectations and given the workover has increased the total bfpd, the Company is hopeful of oil production at the well increasing back up to its January production rate of approximately 20 bopd"

So BTN14 when brought back online it was doing 4.5bopd but it was previously doing 20bopd. At the same total production had increased so the company now receives income on the incremental production. Taken together what that means is that they increased the production from the other two wells by at least 15.5bopd: increasing the production by 15.5bopd merely puts them at break even. They expect BNT14 to return to at least 20bopd soon.

So lets assume that BTN14 returns to 20bopd and that the increment on the other is 16bopd: then 16 bopd * $45 net back * 90% * 30 days is $19,440 pm. The pump replacement on the second well should be done by now and next week they should be on with perforations on the third well. If you check out the presenation you will see that ADL produces several steps in maximising these wells. An extra 16bopd on two wells just by stopping leaks in the production string is pretty good. Fingers crossed we should get a decent update by the end of August. Remember this is just a taster, the upside is the long term deal with CAV and multiple Indo assets.

DYOR

Excellent! Where will you be swimming to Greenland from? Does it count if RRR does a JV and the JV partner becomes the operator on Migori and/or on the other assets?

Just in case anyone who thinks that Moyes & Co are a bunch of hick idiots....

https://www.moyesco.com/maps/expertise

Moyes & Co. is a professional team with worldwide practical operating and technical experience in the natural resources industry including the oil and gas industry, mining industry, power and petrochemical industry. The company’s in-depth knowledge and experience in international trade and regulations and its familiarity with the business climate in most countries is the basis of advice to clients.

Our client base ranges from start-ups through multi-national corporations, governments, and the financial and service sector. The company provides advice and services in the following:

Hopefully, these are the guys doing the work for us.

DYOR

It does appear that there are several intervals at ZR and Mathis that are capable of producing. Hopefully, the subsurface report will bottom out this issue and definitively confirm what we do have available to us in the various assets.

DYOR

https://markets.ft.com/data/announce/detail?dockey=1323-13273626-7VRBPKROKUAA1V5SBMMGSG3GOH

https://www.investegate.co.uk/northcote-energy-ltd--nct-/rns/operations-update-and-farm-out-of-zink-ranch/201403141400083617C/

https://www.proactiveinvestors.co.uk/companies/news/52035/update-northcote-energy-eyes-high-impact-from-first-horizontal-well-at-mathis-61827.html

“The Mathis Oil & Gas reserves, estimated by Moyes, represent on a gross basis a 24% increase in our P1 PV10 to US$76.7mln, further strengthening the asset backing behind our current market valuation of £12.2mln."

The NPV10 will be different now but the oil and gas is still there.

DYOR

Shaggy dog story time.

Northcote as it was then acquired the ZR, Horizon and Mattis assets in 2013/14. At the time the oil price was heading to $100 a barrel. In November 2014 the Saudis pulled the plug on the oil price and WTI went as low as $28 a barrel. At that price practically no one was making money on producing oil in Oklahoma or not very much. At that price no one was committing to new drills. ZR produces a fair amount of gas, which is plugged in for sales, and the gas price went as low as $1.40.

Separately, our OK assets are in Osage County, which is an Indian Nation. The Nation owns the mineral rights but the Bureau of Indian Affairs acts as the administrative agent. The BIA caused a dispute with the Nation and the oil & gas companies such that no work permits or drill permits where issued for three years.

The two things meant that the OK assets had to be pretty much parked and left alone.

A separate issue is that Northcote entered into an operating agreement with Glenn Supply. As the name suggests, GS is a supply company not an operator. The agreement was onerous and every time something needed doing GS would put the latest bright shiny piece of kit in place. So if you look at the pictures of ZR, it looks great. However, this meant that Northcote/Mayan/Attis was making no money out of our OK assets.

The agreement with GS has been dealt with and we are now generating income out of ZR. Separately the BIA has settled its dispute with the Nation and it is now possible to do stuff in OK but it is still slow to get permits. Apparently, beetle studies is a big thing.

So the stuff that was said about the assets in OK five years ago still holds and now we can exploit them.

https://www.rigzone.com/news/oil_gas/a/129431/northcote_plans_1st_mathis_lease_horizontal_well/

I think part of the hold up on the subsurface report and CPR is identifying just much potential there is at ZR and Mattis. In my view, I would get Fort Worth prettied up, get the production up a bit and sell it. FW is largely gas and generates poor cash returns in the current price environment. The gas price should start to rise from here on in as we go into the Winter. The best time to sell would be next March.
DYOR

Not at all. It is just waiting time. The pump on the second well should be replaced by now and they should start on the third well next week. Other than that we are waiting on Colter. No big deal.

More tweets, almost like someone is s bit excited.

https://twitter.com/RRR_RedRock/status/1161907129994948608?s=19

Yep I would agree with most of that however you need to factor in decline rates.

Normal production decline rates on stabilised production are about 9% pa. So whilst we are producing, if we do nothing then our production levels will gradually decline (the same for all oil & gas companies). So producing oil & gas and monetising the resource actually destroys your resource value.

When a well has been shut in for a while and then is brought back online, you normally get a higher level of production. This is partly because of pressure build up (the reservoir re-pressurises during the shut in) the reverse of the "coning effect". Any well only drains a small area around it. How effective that well is at draining the area depends on fracturing in the rocks and the permeability of the rocks. When shut in the drained area recharges.

Similarly, with a workover, we get an initial surge when we bring that well back online, which is really the point of doing the workover.

We may have brought several wells back online during July and experienced surge/flush production and then it has settled down to 110/120 boepd.

Bottom line is that we are much further on from where we were at the start of the year. What we need to see is what they are going to do next.

DYOR

It has already been cleaned and scraped. It should be pretty straightforward.

This is an example of the type of services Attis will be providing: obviously the details will be down to what has been agreed but this gives us an overview. Potentially big money in this for Attis.

https://www.webesa.com/oil-gas-compliance

Don't forget that they get an initial surge or flush production when they bring a shut in well back online and the same after a workover. So you have a mixed picture, a surge or flush short term combined with a steady state but declining production. It maybe that during July production was higher but that would have been from the surge or flush. I would trust the 110/120 boepd figure.

What we need to know next is how much higher can they take it, over what time and how much will it cost? Conventional fracks are expensive but there are cheaper alternatives. Refracks typically give you 60% of initial production from the well..

DYOR