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The best alternative reference point for information on, the likely plan/timeline on Megrez 1 TS1 flow test, can be found in the 2 RNS's for Alkaid 2, in the SMDB reservoir

https://polaris.brighterir.com/public/pantheon_resources/news/rns/story/rgzzl3w

https://polaris.brighterir.com/public/pantheon_resources/news/rns/story/xqlk1kr

It is reasonable (not 100%) to assume the TS1 frack and flow plan will be similar, as the objectives, and reservoir are similar.

So a few copied (I capitalised the key sections) relevant facts on Alkaid 2 SMDB flow test.

"The programme of operations to achieve the three primary objectives includes:

1.Make well safe in preparation for operations

2.Run a plug to isolate the Alkaid ZOI below the SMD horizon

3.Perforate a limited section to ensure injection pressures are high enough to propagate the frac lobes horizontally as desired

4.Pump 11,000 BBLS OF WATER AND 400,000 LBS OF 100 MESH SAND

5.Flow back slowly to prevent or limit gas flashing in the reservoir (i.e. exsolving from solution in an uncontrolled manner) in order to gather the most representative fluid samples possible

6.Monitor pressures throughout to assess frac efficiency and original reservoir pressure"

Post flow test outcome

"The Company's preliminary estimate of the efficiency of the frac was 50% of theoretical design performance and compares favourably with the calculated frac efficiency of c.20% experienced in the Alkaid-2 operations in the deeper ZOI accumulation last year."

"During the flow test, after recovery of approximately 60% of the frac fluids, the oil rate (separator liquids) ranged from more than 100 barrels of oil per day ("bopd") to 30 bopd (AVERAGING 45 BOPD OVER THE 5 DAYS DURING WHICH OIL WAS RECOVERED). Water cuts were 90% initially, but declined over time as a larger share of the frac fluids was recovered."

"Expectations for flow rates, water saturations and water cuts had led to plans for nitrogen lift (necessary to reduce bottom hole pressure and ensure that fluids were recovered to surface). Encouragingly, nitrogen injection was not required until the LAST SIX DAYS OF THE ELEVEN DAY TEST,"

Summarising the key items

11000bbls of water and 400,000lbs of proppant were injected

It was an 11 day test, inferring mostly frack fluids returned during the first 6 days of flowback

Oil flowed for the last 5 days

A similar time line can be reasonably used for the TS1 flow test, and assuming this feedback from Contrarian8888 on 28th March is correct

“They mentioned that the earliest we could expect to be flow testing is this weekend”

Assume flow testing began on 30th March, and is now 6 days in, which is around the time we can expect flaring to begin. No confirmation of heat via satellite image yet, but it does require the satellite to be in the correct orbit to capture the zone and be a clear sky.

In any case, if a similar plan has been followed, the flow results are probably in the next 5 d

Glenfarne and AGDC have concluded the deal on the Gas Pipeline, full speed ahead on updating the FEED, prior to FID and construction.

FID anticipated within 2025, that's lightning fast for a project of this scale

Link Courtesy of COOPER on Discord

https://www.businesswire.com/news/home/20250327649356/en/Glenfarne-Becomes-Lead-Developer-for-the-Alaska-LNG-Project

Contrarian8888, a significant holder, with a large following, posted the below on Discord today. It provides insight to the flow testing commencement.

"I called mgmt to ask why Share px is so weak today. They mentioned that the earliest we could expect to be flow testing is this weekend so there cannot be any news yet (nor could any directors be allowed to buy if they had news be it good or bad). So any rumors to the contrary (pending bad news for eg) is just garbage. Now of course drill results could be bad but no one including the company knows. Thanks"

With the first of the flow test results on TS1 due soon, it comes into focus. Bearing in mind PANR have done the data analysis and stated “This has allowed definition of completion and flow testing programmes over six horizons beginning with Topset 1”

Expanding the message a little, it means they have now designed their completion, which is the fracture, stimulation plan and its flow test, so will have run models and come up with the 200bpd prediction for TS1

What is interesting is how much higher the 200bpd is compared to results of the Alkaid 2 SMDB test. It had an average of 45bpd over the 5 days of oil production, and then went on to be the basis of a modelled horizontal multi stage production well, with an EUR of 3.48 million barrels per well, and a NPV 10 value of ~$6/barrel

Assuming the frack will be similar to the vertical frack/completion used in the Alkaid 2 SMDB, yielded an Avg of 45 barrels of oil per day, the TSI modelling that shows 200 bpd must have considerably better reservoir. Clues to this perhaps lie in the average permeability in other earlier wells (Alkaid 1, ZOI, Talitha, Theta West) at one tenth of a millidarcy v TS1 at 1 millidarcy or less.

To summarise, 200 bbls of oil per day from a single stage in tight reservoir, is a very good tight reservoir

https://polaris.brighterir.com/public/pantheon_resources/news/rns/story/xqlk1kr

During the flow test, after recovery of approximately 60% of the frac fluids, the oil rate (separator liquids) ranged from more than 100 barrels of oil per day ("bopd") to 30 bopd (averaging 45 bopd over the 5 days during which oil was recovered). Water cuts were 90% initially, but declined over time as a larger share of the frac fluids was recovered. As highlighted before the operation, the flow rates themselves were not expected to be material because the objective was to limit drawdown in the initial flow back. However, the actual flow rates were substantially better than prognosed, given the conservative approach to production in order to limit gas flashing in the reservoir and ensure the best quality PVT samples, which bodes well for future SMD development in the Ahpun Field.

https://polaris.brighterir.com/public/pantheon_resources/news/rns/story/r7lm97x

As was the case with Lee Keeling & Associates ("LKA") which recently updated its IER on the Alkaid horizon of the Ahpun field, CGA has evaluated the economics of the best estimate or 2C case. Based on an ANS Crude price of $80 per barrel delivered to the US West Coast, CGA estimates the net present value of the total contingent resources in the western topsets in the Ahpun field (using a real discount rate of 10%) at $1.74 billion.

Part 2

Note, We have been advised, the 200 to 2000bbl range is based on a potential, not the specifics of individual tests. IMO this is part of the framing, to set investor expectations to match the intent

“The Company has designed its flow test programme to prioritise data quality rather than seeking to maximise initial flow rates in order to accentuate the understanding of the reservoirs to optimise future appraisal and development.”

Beyond the 5 conventional reservoirs stacked above, the deeper Upper Schrader Bluff TS1 and TS3 are more aligned with Ahpun West, being in the tight conventional range, and requiring horizontals and multi stage fracking to be economic. Disappointing at first glance as conventional was the expectation.

But before discounting these to much, consider how successful the Ahpun West flow test was, a single stage fracture in the vertical, yielded an average of 45 bopd, which culminated in a valuation by IER CGA, of $1.74 billion for 282 million barrels of oil and NGLs.

Then consider in Megez 1 these tight conventionals are expected to be at the bottom of the range 200 to 2000bpd, considerably higher than the 45 bopd at the successful Alkaid 2 SMDB test

Also bear in mind PANR have stuck with “Previous guidance still stands for the Upper Schrader Bluff and Prince Creek potential” , Making these 4 reservoirs a hybrid of conventional and tight conventional, with current guidance of 700 to 900mbbls of recoverable liquids

References

https://polaris.brighterir.com/public/pantheon_resources/news/rns/story/xqlk1kr

"Post well analysis indicates that the frac treatment resulted in vertical propagation across the entirety of the the 200 ft gross (100 ft net) reservoir column and extended laterally some 300-400 ft."

"During the flow test, after recovery of approximately 60% of the frac fluids, the oil rate (separator liquids) ranged from more than 100 barrels of oil per day ("bopd") to 30 bopd (averaging 45 bopd over the 5 days during which oil was recovered). Water cuts were 90% initially,but declined over time as a larger share of the frac fluids was recovered. As highlighted before the operation, the flow rates themselves were not expected to be material because the objective was to limit drawdown in the initial flow back."

https://www.pantheonresources.com/index.php/investors/shareholder-documents/696-cg-a-certain-ahpun-west-field-properties-in-alaska-contingent-resources/file

Based on total oil and NGL of 282 mmbbl

"CGA has evaluated the economics of the best estimate or 2C case. Based on an ANS Crude price of $80 per barrel delivered to the US West Coast, CGA estimates the net present value of the total contingent resources in the western topsets in the Ahpun field (using a real discount rate of 10%) at $1.74 billion."

All in all a very positive update IMO

Part 1

There is quite a bit to consider in the Meg 1 flow test update, which I believe reflects a more conservative approach to communications, as expected of a company transitioning from explorer to producer

Trying to unpick and connect the reservoir information, I come up with

Lower Sagavanirktok (3) High permeability, in the range of 1 Darcy, so in the upper range of quoted 200- 2000 barrels flow

Lower Sagavanirktok (2) High permeability, in the range of 1 Darcy, so in the upper range of quoted 200- 2000 barrels flow

Lower Sagavanirktok (1) High permeability, but possibly lower than the range of 1 Darcy, so in the upper range of quoted 200- 2000 barrels flow

Upper Prince Creek In the conventional range with a lower Darcy, but still a high flow candidate

Lower Prince Creek In the conventional range with a lower Darcy, but still a high flow candidate

Although the combined net pay of the Sagavanirktoks at 670' supports decent volumetrics, the areal extent is not yet known. The areal extents and variations in depth/rock volume, will, as advised previously by PANR, require extensive reinterpretation of currently held seismic data, retuned/informed by the known properties encountered by the drill itself

Reasoning

PANR state “Lower Sagavanirktok formations, even exceeding a Darcy in the shallowest horizons.” I interpret the plural horizons to mean at least 2 of the Sagavanirktok formations exceed 1 Darcy

“while the permeabilities improve significantly in the shallower Prince Creek and Lower Sagavanirktok formations, even exceeding a Darcy in the shallowest horizons.” Logic dictates that significantly improved permeabilities in the 5 reservoirs within Prince Creek and Lower Sagavanirktok reservoirs, separate them out as true conventionals

Courtesy of Flight, from David Hobbs linked in

https://www.linkedin.com/posts/david-hobbs-4a4b338_london-based-operator-names-chief-executive-activity-7299105175305093120-ID8s/?utm_source=share&utm_medium=member_ios&rcm=ACoAABVFte4ByWKU_Kg5IsJvwTXJcdzpSYRTrG0

I could not be more delighted to welcome Max Easley to his new role as CEO of Pantheon Resources. He is already an exceptional leader, but the opportunity to drive Pantheon’s fast track development plans for its huge Alaska resource base is tailor made for him. We (colleagues, shareholders and stakeholders in Alaska) are lucky to have him on board for what we consider to be the most exciting development program in North America.

At the same time, let me express my deepest gratitude to Jay Cheatham for his immense contribution to Pantheon’s success to date. Over 17 years he has laid solid foundations for success and and hands over the reins of a company poised for further success. Jay was a key player in the search process and will remain as a non-exec director during the transition.

On a personal level, the progress that the team has made in executing the refreshed strategy during the past 20 months allows me to step back and, as non-executive Chairman, to work with Max in delivering what we hope will be exceptional returns for shareholders as we grow the next great Alaskan oil and gas production company.

DYOR, Balance the political white noise opinion, by an opposing party politician

Against the better researched opinions, like those of internationally recognised specialist analysts, such as Wood McKenzie. Who were specifically commissioned to provide an independent opinion for the State to consider

Pretty much covers all the FUD the trolls are spreading

https://agdc.us/wp-content/uploads/2024/11/2024.10-WM-AGDC-Alaska-LNG-Phase-1-Final-2.pdf

09:20

I hope not, 500 to 700bopd would be sub economic, in a production horizontal

Why would you convert, the claim was the ASX up 100%

Even if converted its only .00101

Justice2u

Where did you get a 100% rise on the ASX from, it started at .002 and finished at .002. With a VWAP of 0.00196, and volume of 58m

Great work Scot126, it takes some effort to get that into such a coherent summary, on the X format

It deserves a lot more likes to make it more visible, investors can assist by doing so

Adding to the $30/bbl discussion, here is a transcript of Davids comments in Flight deck No 6. It is self obvious Megrez as a true conventional, with light oil and porosities above 20% in places, will be better

https://www.youtube.com/watch?v=bdy0hDGc_ig

1:09:20

David

Ahpun and Kodiak developments are already very low, arguably in the $30 per barrel

range, and a success at Megrez, with the higher Reservoir qualities that we've encountered would, undoubtedly help underpin the resilience of the projects, so that and being so close to infrastructure, the optionality provides even greater resilience, because you can ramp up and ramp down investment depending on on what the macro environment looks like.

We've got developments that require, much much less Capital At Risk than other developments in Alaska, and certainly than other developments in harsh environments, deep water offshore or wherever and so we're we're extremely well positioned

I missed this comment by Justin, on the first watch of Flight deck no 6 interview. Apart from clarifying that the flow testing of Megrez 1 is already funded, he also points to the intention to also pursue, pre US IPO funding options in the short term, utilising the newly appointed US investment banks, TO ADDRESS THE PRE IPO FUNDING ELEMENT, AND BY THAT I MEAN NON-EQUITY SOURCES, THINGS LIKE FARM OUTS, JOINT VENTURES,

https://www.youtube.com/watch?v=bdy0hDGc_ig

20/01/2025 ~5mins in

Flight

And to you Justin, what's the current liquid position of the company

Justin

So Flight we raised money in in the summer of 2024, we raised $29 million, and that was to be applied towards the drilling of Megrez, and the subsequent testing of Megrez, and as you're aware, we're waiting our core results for Megrez, and we'll therefore define the testing program. So that's all funded we're in good shape for that.

We also announced the appointment of two US investment banks to lead the charge, pursuing the ultimate US IPO for the company further down the track, BUT IN THE SHORT TERM, TO ADDRESS THE PRE IPO FUNDING ELEMENT, AND BY THAT I MEAN NON-EQUITY SOURCES, THINGS LIKE FARM OUTS, JOINT VENTURES, and we're in a very fortunate position, having 100% of each of our project areas, with such large resource bases, that we can make a deal that would work with whatever size counterparty we come across. We have a great amount of flexibility there, so Flight that gives us great optionality.

I am interested in what the perceived risks were

Resource ?

Financing ?

Pipeline ?

It is hard to overstate the change in circumstance post Megrez1 discovery and the recent gas pipeline support

I do see the risks pre flow test of Megrez1 confirming what the current data points to, but that currently released data showing a conventional reservoir, makes flow a low risk item

Megrez 1 has delivered beyond the initial estimates, I would call that a success, sure there is flow testing to come, but this is a conventional oil strike, where finding oil is the highest risk. Having found oil flow is unlikely to be a problem

Given that PANR have success, Zeus commentary is worth a revisit

Copied below from the Zeus analysis 11/11/24

“From that perspective, success at Ahpun East, would, at a stroke, provide a comprehensive funding solution. Why? The wells would generate colossal cash flow streams relative to the capex per well, to the extent that Ahpun East would simply alleviate, we believe, funding as the primary constraint on the company’s mid-term and long-term growth trajectory. Likewise, we would expect that success at Ahpun East would very significantly alleviate any challenges of attracting near-term capital for appraisal/development.”

Part 1

Investors now have, courtesy of Megrez 1, had a peek under the kilt of the Ahpun East reservoirs, and oh how magnificent it is. Pre drill modelling of 609m barrels, is now considered an underestimate, with an additional 15% to 50% bonus to be added, call it a range of 700m to 913m. Be clear this only the first 4 reservoirs of 7 they have drill data from.

Another 3 shallower reservoirs (shallow predicts better porosity/permeability, in effect storage capacity and flow rate go up) have yet to be calculated for recoverable volume, which will then add to the 700 to 913 mmbo range. It is without doubt a huge discovery, deserving of a fundamental rerate

Copied below the 6/8/24 Canaccord valuation string for the Ahpun East, pick it apart as it does not copy well, nor highlight the keys effectively

Ahpun - Eastern Topset 609 100% 609 2.8 1,724 30% 517 411 37 1,724 1,369 123

Est. Net Rec. 609

Ownership 100%

Valuation per barrel $2.80

CoS 30%

Value add per share risked 37 p

Value add per share unrisked 123 p

Firstly I disagree with the $2.80 pb valuation, PANR have clearly stated their expectation, Ahpun East barrels as a true high porosity/permeability conventional resource, will have NPV10 of $10+ pb. Why the analyst was so conservative is beyond me

CoS in this case must be the full commercial chance of success, as PANR had already given a 69% CoS for the chance of a discovery. At this present point a discovery is 100% confirmed. IMO a discovery in a high porosity/ permeability set of stacked reservoirs, delivering high resource density, next to the export pipeline, also has an extremely high probability of full commercial success, I will speculate at 90%+

Part 2

To work an example using Canaccord's numbers

609mmb x $2.8 x 30% cos = $512m, which is then divided by the prevailing exchange rate to give £411m, then divide by the prevailing SOI (1111m) to give 37p as the risked valuation

How things change with a new interpretation (mine) post drilling data release, using a mid point of the new recoverable oil range, and my speculations above

807mmb x $10 x 90% cos = $7264m x Ex rate of .81 = £5883m /SOI of 1139m to give a risked valuation of £5.16/share

I freely admit this is speculation based on an educated number crunch, but I believe it is not unreasonable, and bear in mind this is just the value Ahpun East can add to the pre existing Kodiak and Ahpun West valuations, and again without factoring in any gas value gain.

PANR now has a substantial to truly bigly asset right on the pipeline, in an oil friendly state, with a Trumpian policy to advance USA energy dominance in play

To the main point now, Investors can reasonably predict Ahpun East will be the launch pad to cash flow self sufficiency. Its wells as true conventionals will be cheaper to develop and will flow at high rates, with low rates of decline, as such upfront capital requirements to self sufficiency will significantly drop. I expect a reset to Ahpun East first, the rest is going to be developed with cash flow surpluses to envy, the goal is minimum dilution, Megrez has delivered the goods to achieve it, on its own

Combine that lower capital requirement with the increasing certainty of the Gas pipeline(who would bet against it now), and its associated PANR gas sales precedent agreement leverage to finance of $250m, backed by a gas sale contract, for arguably the cheapest gas Alaska will ever be able to purchase.

PANR are now in the position of ever better options opening up to them, and with 100% ownership it is entirely their choice.

As an aside the strategy reset, was about convincing potential buyers or farmin partners, that PANR can go to market with production, IMO that is easily achieved on the low cost Megrez 1 results.

By all means bring your offers, but now PANR can safely demand top dollar

Looks interesting

All the right people for a gas pipeline update are in attendance

https://x.com/alaskalandmine/status/1876337587327037790

This is the result PANR has hoped for, simple as that.

Conventional oil is fairly black and white, if the oil is there in quantity, it is commercial

The greatest prior risks were, is the trapping mechanism effective, and does it have the required seal. The drill bit has proven light oil is there in substantial columns, although not all of it will be pay, as reservoir will also have tight sequences, the presence of an oil column demonstrates the seal and trap are effective.

Further supported by encountering porosity as expected of a conventional reservoir, it screams commercial

Also it can reasonably be assumed the prospective resource classification will upgrade to contingent.

Fair enough to be cautious, as it will be some time, before a flow rate is determined by an actual flow test, but at this point a generous flow can be assumed based on the now known data, porosity, permeability, oil presence and type.

Three legs of this trifecta have come in

The oil previously discovered 1.6 b barrels

Megrez 1 conventional oil discovery, has gone from 69% gCOS to 100%

The gas pipeline proposal has full momentum