Member Info for Olderwiser

No surprises here, posting opinions that do not suit the ramp it up at all costs brigade, will inevitably cause a huge amount of vitriol about the writer.
Previous little about what is written, I have seen how Scotts factual and accurate analyses are treated by the flash mob of traders

23:27
Drill and evaluate, proposed start date 1/3/23
https://dog.dnr.alaska.gov/Document/Download/6B9F5580F4734848B54218CB77B307B6/LONS%2022-009%20AEA%20Hickory%201%20Lease%20Plan%20of%20Operations%20-%20Approved.pdf
They need to be off site before the ice pad starts to melt

This is showing all the signs of a train wreck, it is a short drilling window and they are late to the pad.
Why are they late to get the ice pad built, they had all year to fund and plan it.

To already be preparing the way for not entering Kuparuk is a failure, (subject to time remaining)
Preparing for the drilling to the deep and high pressure target KUP, adds a great deal of cost, high pressure means heavier casing pipe the entire length of the well, it a long lead item, considerably higher cost.
For this target to be at risk because they may run out of time is unacceptable management

I can understand the funds had to be in place to push go, so why so late for the fund raise, that is a management issue.

What else is at risk in this short season, if it becomes wireline, resignations should follow

The way in which the well is restarted has to deal with some complexities, as is known the last 1000ft has been blocked with proppant sand.
In effect that means the last 1000ft is all but a virgin zone, while the first 4000 ft has been in production for an extended period.
The 4000 ft will have returned in excess of 40% of its frack water and the proppant will have proven its stability.
Compare this to the back 1000ft section, which to date will have returned almost none of the frack water and had no opportunity to prove the proppant sands are safely locked in place.
With the clearing of the blocked section the two different operating sections of reservoir have become one, with one being robust and one being still delicate.
In bringing the well back on it will have required treating the whole well to the requirements of its most delicate part
My expectation was for a slow measured increase in flow, induced by a period of gas lift, but held back on the choke, and there has been time for this.
With the camera now showing a sky refection for the first time, there is no doubt it is now the flare. Tonight's overnight flare growth suggests, the delicate treatment period has concluded
.More vigorous and representative flows are on their way but will still need more time for the overall targeted ~60% frack water return to be achieved. Bear in mind the back section is starting from zero.

I asked the short pack to run the numbers on the convertible loan a while back, none took up the challenge.
Lazy sods, any ways it turns out, PANR have paid back US $15.8 m by issuing shares to the CN provider at an average of US $1.01/share. Not the bad deal the shorts would have you believe, as the other option was to issue more shares in the capital raise (8/12/2021)at 65p US $0.858
It has been a clear gain to shareholders to date, with dilution reduced by the ratio of 858/1010

Of course it is the play for the shorts to convince the gullible that worst case is most likely. Worst case naturally needs the company to fail in its exploration efforts first, in which case all the previous success in the field, has to somehow unwind itself.

Not likely at this stage with oil and HC liquids having already flowed at modeled
commercial rates

Interesting to see most of the combined short team appear as a pack on the day of the odd share price behavior. Much like a military campaign, first some shelling of share price, then send in some disposable FUD troops to amplify the effect

Jim/Louis, this is one of the lines of the bear or short team have pushed. It is a nonsense, I take the point on dilution, 88e with it 20 billion shares is a great example, yet Jim thinks its worth a punt on the FOMO
PANR on the other hand with 778m shares, could go to market with a 60m share issue at todays price and repay the convertible debt. (Analysts already use this larger base in their work) But why would they do that now as the share price is at a relative low, PANR are astute and have made good choices in capital management. It is reasonable to expect the BOD will continue to make good choices, especially given the hand they now have, farm out, sell a minor project, cap raise, debt finance off reserves, etc
With 2300 million barrels in play and a flow test of Alkaid looking promising, in the companies words "it is all to play for"
In summary the debt is hardly a threat as worst case is not so scary

I have been monitoring the camera and have a theory around what has been visible.
When the rig was over hole in the weekend there was light, which may have been interpreted as flare, I think this was rig lighting not flare. This light then disappeared for 12 hours or so as the rig moved off hole and preparations for flow began.
With the current return of illumination to site, it is likely to now be flare as the well recommences clean up.
All of the above with the caveat that it is all based on poor picture definition

About 5 hours ago an image from the weather camera looks very much like a flare surge
https://weathercams.faa.gov/map/-149.37961,69.91364,-145.67447,70.47202/airport/SCC/details/camera/11668/loop-full

Yes that is correct, the payment will be at a minimum of full ANS price for the light oil sold.
The 85 - 90% is a future prediction of what the blend of all 3 liquids would receive, when they have the additional processing plant to harvest the condensate and NGLs

It may not be viable to install the chilling plant in the test period remaining, as there are some uncertainties on the payback period. eg can it be assumed the 9 month test period will endure, as it is subject to 3 monthly reviews

Peakybrum,
My understanding is the 550 barrels is a combination of light oil (~200b) that is collected at the separator , and 350 barrels of condensate NGLs mix that go to flare as a vapor/gas, as they do not separate out in the separator, due to the temperature being currently higher than condensing temperature for this stream.
Measurement of this flare gas volume and composition, enables an accurate assessment of the recoverable condensate and NGLs entrained.
On this basis PANR are able to give a total liquids production from Alkaid 2

Correct it is PANRs choice,
https://polaris.brighterir.com/public/pantheon_resources/news/rns/story/r751p1w

Amortisation:

5.00% of the Initial Amount each quarter (US$2.5 million to US$2.75 million) payable quarterly, in cash or new Ordinary Shares at the option of the Company(1)

I have read the complete tomb previously, although it does focus on the exploitation so common to AIM companies, it does recognize it does not apply to all.
Surely finding the 1 in 100 is worth while, in fact the aim of this end of market investment

Great Bear bypass many of the early stage red flags as initially it was a private company, its work has been picked up at a heavy discount by PANR, with the bonus of bringing some of the GB team along to finish the project.

Louis10
Since we have the benefit of your attention, and you are so well abreast of oilman Jims thoughts.
Could you kindly comment on the obvious gap between his distain for PANR and his unwaning support for 88E

In summary PANR are unworthy because they are dodgy, this despite the support of multiple trustworthy parties, notably SLB the premier oil services company, State of Alaska in granting Unit status to projects Alkaid and Talitha (neeTheta West), eSeis who opted for royalty payments rather than full cash, Baker Hughes with VAS analysis, to mention just top of list

88e have an avid fan base worth exploiting on the pump and dump cycle, and some downdip lease on the south fringe of PANR, that also suffers about an additional 1000 ft of Dmax degradation.

It is curious that the inferior prospect, whose main promotional claim is how close it is to PANR proven oil resources in the up dip location, has his backing as an investment.

On a barrel for barrel basis, 88e is currently valued by the market at a higher price for prospective oil, than PANR is for the higher graded contingent oil.

After a few hours well spent watching the webinar, for me it comes to one central point.

PANR now understand where the unexpected gas flow is coming from, although it affects Alkaid 2 it will not translate to further problems at new wells in Alkaid or any other reservoirs.

Analysis of data from the horizontal drill section, showed only oil and water as expected, with no free gas as modelled, the modelling still stands. Flow data has shown higher gas rates than this would produce, the source is a minor gas cap in this updip location, at a high point in a structural trap, that has been both discovered and taped by the fracture stimulation.
Further wells can easily avoid this contact, and will also be better tuned for performance with the data gained. The rich gas volume is producing an unusually high proportion of NGLs and condensate, that are not being captured, as the plant design did not anticipate it. Whether it is worth spending the capital to capture and sell the condensate and NGLs that are being produced, in this 9 month test, is down to pure economics, is the additional cash flow going to justify the costs. Bear in mind Alkaid 2 is about proving the deliverability of the reservoir, not cash flow
What can be safely concluded is the current compromised (by high gas rates, frack fluid blocked and choked back) 4000ft of well is producing 137b of hydrocarbon liquids/1000ft, all of which is accepted by TAPS as an outlet at values of 80 to 90+% of ANS crude “Supports commerciality at current rates and product value stream”
Says it all, when flow is expected to increase to a new higher current flow and that higher flow will also increase the value per barrel as the well settles into a steady state.

MarkA8178
I take the point on the markets initial reaction, as can be seen by recent events, where a declared 125 barrels/1000ft got hammered. largely on confusion and bear thesis over the value and location of the condensate and NGLs.
Putting that aside, viability is the elephant in the room for any oil once discovered. PANR have given guidance on the number to achieve that in a number of referenced places (2 in my post and 1 in Sailplanes post)
With the flow test still in the early stages of testing, frack water still in the way and flow being held back on the choke.
500 to 550 barrels/day is already almost there with regard to the modelled numbers, but more importantly commerciality is below this number.
The market appears to have incorrectly latched onto the reservoir modelling number of 150 bpd/1000ft as the required number for commercial success. An oil company, whose focus will be on viability, will not make that mistake. They will run their own models, and negotiate accordingly, granted they will pay more for a higher lifetime flow rate per well.
As investors we do not have the information to make those determinations, so it comes down to whether the company s economic projections match up with the buyers.
The Webinar on the 24th should help with the current confusion, so I look forward to its effect on perception

Hi Sailplane
I will add this post of mine on discord, in support of your logic, re the bar is being set above the commercial requirement.
Commercial is at 600 bo/d for a development well (8000 to 1000ft)
https://discord.com/channels/827703739687239690/827703740143763466/1044073705099231272
With flow results from Alkaid 2 due in the near term, it is worth a reexamination of what it will mean.
First point, the 150BOPD/1000ft of horizontal is a modelled number, calculated by real data and comparative analysis, based on Alkaid 1 data. (Alkaid 2 data is better) I take particular note this is what the models predict, not what is required to be economic.
Second point, PANR have indicated in a generic form, applicable to Alkaid, Talitha and Theta West that 600 BOPD is the actual requirement for viability
https://www.pantheonresources.com/investors/presentations/666-investor-presentation-april-2022/file
Page 35
Illustrative Development Well 30-40 stages High IRR’s even as low as 600 BOPD
Further supported by Michael Duncan in the 26/04/22 webinar at 1hr 18 mins
https://www.pantheonresources.com/news-media/webinars
“We forecasted about 150BOPD/1000ft of completed horizontal, now I want to stress, that's not what we need, we can make it work with less than that, with significantly less than that”

There is reason to believe the 150BOPD/1000ft is very achievable, as the initial modeling has been conservative, and does not in corporate the improved data from Alkaid 2, nor the increased number of fracture stages per 1000ft implemented in the Alkaid 2 horizontal.
Also reason to believe as low as half of the 150BOPD/1000ft will be viable

RB 05:06
"Those holding after TD will either see their sp crash or soar depending on the outcome of the drill."

That is where the valuation is hard to follow, if Hickory hits a world record home run and finds all of the 647 million barrels of mobile oil, then advances some to contingent classification, and declares the rest discovered
PANR has already done this with 2300 million barrels and it is worth 19.5c/barrel
So why is 88e being valued at 23.4c/barrel, prior to proving the oil is there, on that unusual comparative logic the barrels of oil would drop from 23.4c to 19.5c if it was proven by the upcoming drill.

COS by itself is not much help in assessing the real value of an explorer, what matters is commercial COS, geological COS is just one step towards cCOS
gCOS is a measure of how likely the target is to have mobile oil. In the case of the primary target, the SMD the 81% probability is derived by combining the 3 targets SMDs A,B and C, individually the gCOS is much lower.
What is already known, is all the targets, are down dip to the very PANR reservoirs 88e is promoting its chances off.
Also the hidden factor of DMAX, DMAX being how deep the reservoir has been before erosion took the top off the overburden.
Putting both factors together, 88e reservoirs south of the border are substantially deeper, which means the rocks will normally be tighter (lower porosity and permeability), and have been cooked at higher temperature, which shifts risks further into the gas zone, as heat cracks the more complex hydrocarbons into smaller molecules like methane.
Looking at risking 88e is at prospective resource stage, with all the risk to come. As the last 6 wells have shown, the risk is substantial, until a drill proves the resource even exists, there is nothing to count on.
PANR have already completed that stage of derisking, and now have a significant proportion of their 2300 mmbo, that they are calling discoveries, in the higher rated contingent resource classification. The prospective resource risk has already had the dice thrown and come up with a win, moving it to contingent.

Run the numbers and you will see the 88e share price, is valuing the higher risk 647million prospective barrels in Hickory, at more than the discovered updip barrels in PANR reservoirs.
Make it US$ to align with US $ oil quotes
Last EEENF sale at US $ 0.83c = Market cap $151.6m/647mbo = 23.4c/barrel
Last PTHRF sale at US $57.5c = market cap $447.6/2300mbo = 19.5c/barrel

It depends on how big a tad is, tads must be large

A few points to consider.

Is this shaping up to be the required flow rate to establish a commercial operation. 500Bpd from 4000ft (125bpd/1000ft) of horizontal, that is still in clean up phase suggests the 150bpd/1000ft is achievable. Particularly so, given the well is currently being held back on the choke to allow the proppant to settle in place.

Is the implied GOR shown in the flow test the same as the GOR in the reservoir pore spaces, if they are different, it is an operational production management issue eg reduce the drawdown rate and see if GOR comes back into the expected range. Operationally this would see a lower Initial production, but also a lower decline rate curve. The economics remain how much oil is produced over the life of the well, not how much is produced in the first year.

The 3 phases of liquid hydrocarbons, oil, condensate, NGLs, are all mixed together in the separator and would be sold as one product. It is only lab analysis that determines the composition ratio. There is no evidence of, nor mention of processing equipment on site to separate these 3 streams, so a fair assumption I believe.

Should the GOR prove to be higher in the reservoir, it does add reservoir drive, which feeds into a higher recovery percentage of the OIP, but offsetting that OIP may drop as some of that oil would prove to be gas. That is a calculation for the grown ups to make when the data is in.

It would have been tidy to have a clean 750 bpd announcement, but this is the oil business, problems are normal in bringing new fields into production.

Adding to previous thoughts on flare size and the potential oil flows implied.
28 days into December and balanced against M Duncan's expectation that it would take “2 to 3 weeks to get the majority of that done”. I interpret “that” to mean the 40% of frack water target.
There is photo confirmed proof of a substantial flare on the 5th December, so the 3 weeks has passed. Implying the 40% target is likely to have been achieved.
Here is the point that matters, thanks to others for highlighting it for me.
Flowback frack water has negligible methane in it, so would make very little difference to the flare, but now flowback will have a rising proportion of produced water v frack water return.
Produced water has been exposed to the reservoir for millennia, and will have a higher saturation of, methane and ethane that will separate at the 3 phase separator. We have no information on produced water volume, but logic says it is increasing v frack water.
If there is a significant produced water flow, the gas released from it must be deducted, from the flare flow when calculating the potential oil flow eg if half the flare flow is from produced water gas release, the implied oil flow will also halve.
Bear in mind 150bpd/1000ft of lateral is the modelled flow and would be an outstanding success, commercially viable is even lower @ 600bpd for a production well. At 8000ft that is only 75bpd/1000ft

Page 35
https://www.pantheonresources.com/investors/presentations/666-investor-presentation-april-2022/file