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Tony Tony, marmaris is more likely to be quoted on wiki, than be reading it

Stas20 14:15

Your explanation is muddying up the picture here, surface casing and the conductor or cellar are different things

Listen to Jay in this video, the surface casing will finish around 3500 feet. IMO that is where the drill is presently, conducting BOP testing before drilling ahead to first target

https://youtu.be/6b7iwv_t0H8?t=245

PANR Gas is starting to present as the little engine that could.

Transitioning from a reinjection cost, to a salable commodity that generates cash flow and enables development finance at better terms

Oil is without doubt the star of the show, it does all of the heavy lifting in absorbing the costs of OPEX and CAPEX, as can be seen in an oil price of $70 to $80 per barrel, yielding NPV 10 of $5 to $10pb

What interests is gas gets a free ride, this previous cost of disposal born by the oil, is contracted for sale at $1/1000scf or mmbtu

Effectively there is minimal OPEX and CAPEX, water removal, chilling for NGL recovery, and gas compression for reinjection, are all part of the oil costs. These are almost the same requirements as gas conditioning to pipeline specs.

Should the $1/1000scf of gas hold in the final contract, and there is no reason to believe it wont as that is a very low price. IMO a substantive factor in making Phase 1 of the LNG project viable.

PANR have 6.6 trillion cubic feet of gas, already IER estimated contingent in Ahpun and Kodiak, with another 3.3tcf on the prospective radar at Megrez 1

The numbers calculate out to 1tscf of gas being worth $1 billion, with the only notable deductible being royalties, at the upper level 16.5% from memory

Even so the discovered 6.6 tscf minus 16.5% yields 5.5 tscf x $1b, $5.5 b in current value for what was a cost item, it is a substantial lift to the targeted $5 to $10 on the 1.6 b barrels of liquids,

Accepted that not all gas will be sold, some will still be used as pressure support, site energy supply, and reinjected when pipeline storage capacity constrains

I keep thinking I have the maths wrong as this looks too good, but I double checked, numbers are numbers

Markconnor01

There are a couple of methodologies to assess the value of success at Megrez 1, Zeus discuss them in their most recent analysis

Compare with the most closely aligned recent transaction on the slope, both comparable in size and reservoir type, where Oil search paid US $3.3/barrel for a 51% stake. In todays dollars that would be $4.27/bo

I note they consider Megrez to be better located, close to pipeline and highway, so more valuable than Pika, as production and capital costs will be lower, and PANR is closer to FID, making the Pika comparison a conservative measure

In this case $4.27 x 609m = $2.6 billion, divide by fully diluted shares of 1194 m

Per share value US $2.18, allow some discount to this for the NGL component, maybe 5% discount

Compare to costed modelling of decline curves and production , gives a range of $4.42b to $9.42b, with oil price ranging from $60 to $80, and tax included or excluded

Calculates out to US $3.70 to US $7.89/share, if PANR take it to production

All the above is also subject to the mood of the market in the short term, but fundamentals prevail in the longer term

Looking at the chart, the share price closed at 29.2p on 14/6/24 and continued down from there on funding uncertainty.

On 15/6/24 the gas sales agreement RNS came out, the market gave zero value, or credibility to it, just a steady decline on funding uncertainty

Now that the President of the US has committed to building the pipeline, it is also time to recall that beyond the immediate value add of gas sales, and the lower production costs from reducing reinjection costs, by gas sales instead.

PANR have already flagged the substantive financing a Gas sales agreement carries, $250m quoted as possible. Perhaps we should all have given more credence to PANR putting a few eggs in this basket.

So financing is a big tick on conclusion of the GSA, and PANR are at the front of this queue with a GSPA held, and the only large, low Co2 gas supply available on the North slope

Summarising

$29m Funds already raised, tick

Future finance, tick

Gas sales income, tick

Lower cost oil production, on 1.6 billion already proven barrels, tick

A beaten down share price, because none of the above was expected, tick

Additional wild card Megrez 1 in play, with a 69% Cos and 609 million barrels @~$10+++

Hi Brom

Please refer to the provision in the contract "TAKE OR PAY" this gives precedence, some could argue exclusivity for up to the first 500mmscf/d. As yet the ramp up rates to the upper rate have not been specified, but it is clear PANR is at the front of the queue

Key GSPA Contract Provisions

The GSPA contains the key commercial terms to be incorporated into the binding take-or-pay Gas Sales Agreement ("GSA") to take effect after FID, including:

· Pantheon agrees to supply up to 500 million cubic feet per day ("mmcfd") of natural gas at a maximum base price of $1 per million BTU ("mmBtu") in 2024 dollars.

· The minimum daily contract volumes that are used to calculate the level of the take or pay obligation.

· Plateau natural gas deliveries for 20 years, with the potential for extension beyond that initial term.

· The State of Alaska has several options to reduce the natural gas unit price significantly by working with Pantheon to reduce the cost of project financing and/or enable other commercial opportunities, as specified in the GSPA.

Under the GSPA, both parties agree to negotiate the GSA in good faith based on the agreed commercial terms. The GSA will be conditional on:

Courtesy of @Flight on discord

https://www.facebook.com/GovDunleavy/videos/873837411545792

3 minutes in ** Alaska will soon be a player in the gas world **

My comment

The message from Governor Dunleavy is quite clear, "a large "pipeline is getting Presidential support

Stas

You appear to be getting the distances mixed up in regards to Theta, perhaps confusing it with Talitha.

Theta west is approximately 16miles distant to Megrez, while Talitha is around 4 miles west distant to the Pipeline state well, which places it about 7 miles from Talitha

Theta west and Talitha both tested the giant basin floor fan, that is now called Kodiak.

It is worth correcting this error to prevent association of Theta west data with Megrez. note Talitha does have data on the upper zone SMD, in a poorer setting

The most relevant is Pipeline state, as it sampled the same reservoir as Megrez is targeting on its way to final depth. At Pipeline state it did not have a trap geometry, so held no notable oil, but was able to prove the sands porosity and permeability.

Megrez does have a trap geometry capable of trapping oil, which makes it such a high probability of success, further backed up by the AVO which shows a hydrocarbon accumulation signature. I asked a question in the webinar on the possibility of their being a gas cap, short answer no, the signature shows oil.

The unknown being the amount of gas dissolved in the oil

A point to also clarify is the flow rate from the conventional high porosity reservoir rock at Megrez. Although it will flow easily, the range of flow will be determined by the amount of stimulation that can be applied. I will not give a number for the norm for an unstimulated exploration well, but note a range of 2000 to 4000+ for lightly stimulated wells in the comparators Willow and Pika.

These flow rates are highly lucrative, for relatively cheap wells to drill and stimulate, on stimulation maybe 3 stages v 60 stages on tight conventional. This lower cost is then supported on the production side, by a gentle decline rate, maybe 6 to 10% per year v 50 to 60% on a tight conventional. It is the kind of maths that goes to model a production well at Megrez producing 10 million barrels from a single well in its economic life

Very pleasing to see the Wood Mackenzie draft on the viability of a gas pipeline construction released.

In its conclusion that a constructed $10.8 billon gas line, supplied by PANR Ahpun gas, will be in the range $8.97 to $12.80/mmbtu delivered to off takers. The price per mmbtu dropping as volume throughput increases.

Compared to the other option of importing LNG at a cost range of $10.21 to $13.72/mmbtu, it is a strong case for the cost competitive advantage of pipeline gas

IMO the prospect of the project going ahead moves from a possibility to a probability, it may explain PANR, with an inside view to the project, making it a priority financing option

Beyond the need for Alaska to provide an energy solution to replace the dwindling Cook Inlet gas supply, currently at $8.69/mmbtu, the full uptake option price with 20mtpa of LNG in play at $2.30/mmbtu, would be the dream scenario for all Alaskan residents and businesses.

Restating that for clarity, the imported LNG range of $10.21 to $13.72/mmbtu will drop to $2.3/mmbtu, when gas is supplied via the Pantheon pipeline, in the high flow case, ( best case with full capacity of 3100mmcfd flowing gas).

LNG imported suffers from a direct link to other liquid fuels as a price setting comparator, whilst local gas is less so. PANRs Gas Sales Precedent Agreement ("GSPA") with AGDC is for a set inflation adjusted $1/mmbtu for a 20 year initial term. Long term lower price and delivery security/stability will be a benefit over and above bettering the LNG import options higher pricing. Buying local gas puts control in local hands

Low energy cost will stimulate the Alaskan economy for decades, businesses will be drawn to it

The next step of the WM report, due on the 20th, will address the benefits to the state in, property, corporate, and production taxes, plus direct royalties on gas sold.

I note in this https://agdc.us/wp-content/uploads/2024/09/AGDC_Board-of-Directors-Meeting_Presidents-Report_September-12-2024.pdf

Page 12, the bar graph shows an average benefit to the State of a bit under $1 billion/pa over the life of the project

So in summary the pipeline will deliver cheaper gas than imported LNG, even in the base case, but massively discounts as demand increases

The pipeline owner will generate a 10% return on equity, as a stand alone project, not bad for a stable utility

But the largest benefit will come from lowering gas energy costs, which will stimulate industry, setting up a virtuous circle where lower costs stimulates demand/volume, which further lowers gas cost, the State then clips the ticket on the whole thing at every turn, securing a substantial and enduring income stream for its citizens, while also keeping them snug and warm with cheap energy

Looking backwards to the strategy reset on 21/11/2023, it is clear things have, on fundamentals developed positively since.

Key points being the independent expert opinions confirming the value of the current proven Ahpun SMD and ZOI reservoirs, Kodiak field resource upgraded 25% to 1.2 billion barrels of recoverable liquids by NSAI and the signing of a Gas Sales Precedent Agreement ("GSPA")with the AGDC

Each of these steps has reduced risk while advancing value

Bearing in mind the strategy reset plan, was in essence to bring Ahpun oil into production, in sufficient volume, to fully self fund the full field development of Ahpun and Kodiak, all at a minimum of shareholder dilution.

FID on this first step in Ahpun was planned for the end of 2025, and was progressing well

Two substantial positive events combined to clash with this timeline

Securing the Ahpun East leases, and the volume of estimated oil recovery from the entire Ahpun field combining to reach, the threshold at which an environmental impact statement (IES) is required

While it is great to have more oil to produce, the IES pushes production out by an estimated additional 2 years

The impact of the timeline change, is to push short and near term financing options, such as vendor and off take financing, to closer to 2028

It now requires a further tweak to the plan, financing uncertainty has now become a drag on the markets perception, and share price.

PANR have acted, bitten the bullet, raised capital at a low level.

So the question is will this ultimately be less dilutive than waiting out the delay, I would argue there is a 69% chance, the $29m raised, will be so. ~$16m is being spent drilling Megrez 1. To be clear PANR had to drill this well, as they have to know its potential now, before they commit to a field development plan, or further finance plan. It is too good an option to be left wondering, imagine the rancour if it was parked, then proven to be the lowest cost/dilution option to self sufficiency, after the SMDB was developed at greater dilution

Megrez in a modelled success case will recover 9.6 million barrels of hydrocarbon liquids per well, at twice the value per barrel of the SMDB discovery. Conventional oil reservoir is that much more lucrative than tight conventional, it will jump the queue to be first development reservoir, halving the number of wells required to reach fully self funding.

600 million barrels at even the ultra conservative $10 to $15 per barrel of Bob Rosenthal , for an initial proving cost of just $16m @ 69% COS is an extraordinary risk return. Note PANR have modelled Megrez NPV10 of $30.9 per barrel at $80 oil pricing

IMO PANR has been beaten down from above 30p by the weight of anxiety over funding and a delayed production schedule, not concern over the quality and quantity of its assets, I look forward to a fully funded Megrez bonus providing the lowest dilution path to self funded.

Typo 58b is 58m

This is deception on a Trump scale, and a whole tribe of pumpers pushing this error ridden line

Careful people the gang is at it again

The 17m is AU$

The 23m MCAP is GBP

Work it out in AU$ (29b x 0.002 = AU $58b)

Sharebel 09:53

Are you writing speeches for Trump here, none of that post rings true

Sharebel

You continue with the conspiracy theory nonsense, FYI the share price is not anyone but 88es fault

They have invested poorly, so here they are.

How an experience trader like your self could miss the 80% owing on the Hickory flow test at 31/3/24, is beyond belief

Newbie

Not rubbish, its a proven fact, go look for yourself

Sharebel

What's not to like ?

The $25m you quote is prior to deducting the outstanding 80% of the Hickory 1 flow test cost, that's one of the whys to the need for the last capital raise

Come the quarterly report due at the end of July, the real cash in bank, post this payment will be revealed

88es home base where the action springs from is in sell off mode, todays ASX results

Volume of 62m

VWAP of 0.00157, that's only an average of 0.83 GBX, and the ASX and AIM normally track

Bid is at 0.001

Offer is at 0.002

It is untradable the gaps up or down are to large, if you "need" to buy pay 100% more, or need to sell its a 50% drop

Even those with access to the mid point trade, it still 50% 0r 25% respectively

Still spinning the pumps eh Sharebel

Its gotten old

Sharebel

If you check the ASX, 408 m shares were sold down today, wiping out the support at 0.2c. Now the only bids on the book are at 0.1c

That does not look like short action of any kind

Chrisev1

The shorthand version is, the project has grown so substantially, it now requires an EIS that will delay cash flow to 2028.

Concurrent with this a probability has emerged that gas sales will eventuate, this would fund development beyond FID, via debt funding, backed by a gas sales take or pay contract.

Additionally the testing of an additional 600m barrels of high flow conventional in the new Ahpun East leases at Megrez 1 is planned

All of these probabilities can now be tested within the IES timeline of 2 to 3 years, without adding further delay

Funding required to FID is $60m, which includes the drilling and testing of Megrez 1, G&A, hot tap into TAPS, IES, US IPO costs. A further $25m is possible should an additional Ahpun test well be required

Presume around $25m of the $60m is for Megrez 1, with the balance for the other activities, and also note that the need for funds will be spread over the draw down timing

For perspective, consider the potential benefits investing $25m for an additional 600m barrels of true conventional, with a COS of 70%. That would be an easy sell as a stand alone project

14:26

Tr1 due from, on or around tomorrow Brom

"Application will be made to the London Stock Exchange for the New Ordinary Shares to be admitted to trading on AIM at 8.00 a.m. on or around 20 June 2024."