Member Info for KeithOz

The Brent price you normally see is the contract price for one-month future delivery. Dated Brent is the price for physical delivery, so better represents the immediate situation. Dated Brent yesterday hit $141.36. Because of the Easter holidays, Brent futures contracts stopped trading on Thursday night in the US at $109.03, and will not re-open until Tuesday morning Australia. The same for WTI Cushing, which closed at $111.54.

https://x.com/KQuick20704342/status/2040184018583552193

"The futures price is almost giving a false sense of security that things are not that stressed,” said Amrita Sen, founder of Energy Aspects, in an interview with CNBC’s The Exchange. "You are seeing it, but the financial market is almost masking the true tightness that everywhere else is showing up,” Sen said. The price for a barrel of diesel in Europe is almost $200 per barrel right now, she said.

Chevron CEO Mike Wirth warned last week that the futures price is not reflecting the scale of the oil supply disruption to the closure of the Strait. Wirth said the market is trading on “scant information” and “perception.”'

https://www.cnbc.com/2026/04/02/dated-brent-oil-price-actual-cargo-highest-level-2008.html#:~:text=@LCO.1,barrel%20right%20now%2C%20she%20said.

While I'm waiting for the barbecue to heat up...here's some numbers for you to think about.

February:

Average price per Bbl $60.213 sold by PRD. Average daily closing price of WTI $64.51 (EIA data). Therefore, PRD sold at 6.7% discount to WTI. 12.5% tax payable. 28 days in February.

That 6.7% discount covers NABI transport & storage costs, and their profit. There are no additional fees charged by NABI, contrary to some assertions here.

March:

*Assume NO increase in volume from 9000 Bbl in February (28 days). Each $10 rise in WTI gives an extra $8.164 sales (after 12.5% tax and 6.7% discount). So: 9000 Bbl @ $100 WTI gives $734,760 sales. If all of that was at the lower margin of 15%, that gives $110,200 profit to PRD.

* In reality, there will be a volume increase due to BON 18, 19 & 20 coming online, plus at least one Goudron workover. Let's assume a miserable additional 50 bopd. Let's also recognise that around 80% of February's numbers were legacy sales at 30% margin. Let's also recognise that 1077 Bbl were produced in February, but not sold.

* So actual numbers could be (9008+1077=10,085) / (31/28) =11,165 base. 11,165+(50*31)= 12,715 Bbl produced.

* (10,085*80%)*(81.64*30%) = $197,600 profit from legacy sales.

* (10,085*20%)*(81.64*15%) = $24700 for Feb incremental profit.

* (1,550*81.64*15%) =$18,981 for March incremental profit.

* March total profit, assuming modest incremental growth = $241,281 if average daily WTI = $100.

If oil prices remain at that level (who knows? No one here) and Snowcap-3 produces a base case stabilised flow of 500 bopd, that gives a monthly profit of (500*30*81.64) = $1,224,600. I have previously demonstrated (22/3/2026) that using the decline rates in the Snowcap ITR, in order to reach a stabilised flow rate of 500 bopd, it would be necessary to start with 1000 bopd.

That's an annualised post-tax profit of $18 million at WTI $100, without any further Snowcap wells. Now you have the worked example, you can drop in whatever oil price and production numbers you like, calculate the result, and stop complaining that Trinidad is a waste of time & money.

Now, where's those juicy eye filets?

109.72 vs. 109.12. I don't think that's happened since briefly in 2016. Doubtless the trolls, none of whom have ever negotiated a royalty agreement in their life, will find a negative for PRD in there somewhere. Must be really maddening for them to realise how much profit will be coming out of Trinidad this year. Happier Easter.

Gudin writes "The current revenue increase received outstrips the capex to date Matt".

Yes, that's really good news, it means all our royalties will have moved up into the 30% band. Double the expected income from Trinidad in such a short timeframe.

It must be so depressing trying to write bad news about a company that is not only doing very well, but whose performance is likely to accelerate beyond all recognition over the next six months. They know that, hence the increasing desperation and frequency of the posts. Happy Easter.

It takes a rare kind of 'investor' to see downside to what looks like to be a step change in the oil price. If you were NABI management, involved in new drilling, well workovers, oil storage & transport, and oil sales for export, what would you be doing at this time?

I would be urgently reviewing my projects and workstreams, evaluating which had the highest returns in the new price environment. The venture with PRD must be high on that list, given that it involves royalties for new production, plus possible storage and transport fees, and any margin achieved on sales to local refineries and for export.

Not surprising that in the March 23rd RNS it stated

“Aggressive back-to-back drilling programme being evaluated to increase production coinciding with oil price spike.” And

“A schedule for increasing the frequency of swabbing cycles and the number of wells being swabbed has been put in place”. And

“New development well locations for the Bonasse field are being evaluated to support a back-to-back drilling programme to maximise rig use whilst mobilised on site”.

Add to this what was already under way – the February 25th RNS told us:

Goudron:

“The geological and reservoir engineering teams are conducting detailed evaluations to identify the most suitable heavy workover candidates. The team has opted to correlate these heavy workover results with a planned development well program, prior to final regulatory drilling approvals. Additional drilling candidates are also being reviewed within the Goudron field.

Inniss-Trinity

“A full field review is underway to identify potential wells present in the field that are not yet formally included under the Company's well listing, which may introduce opportunities to expand the active well inventory and production capability. The Company's management is contributing to this process based on its detailed knowledge of the field gained from its previous CO2 EOR pilot project in 2021”.

If PRD are contracting the Star Valley rig for SC-3, that leaves T-Rex's own T38 rig available for new work – I'm sure that NABI can find an additional drilling crew. Presumably NABI will be also able to redirect any other rigs they may have into what is likely to be a very profitable medium term business arrangement. NABI is a large well-managed business. This should not only be good for them, but obviously for PRD also.

https://nabienergyholdings.com/about-us/

This is partly true - I can confirm that the real deal is that Saudi Aramco are saving several hundred million Pounds which would have been spent on their London listing by agreeing to a reverse takeover of PRD, with 1 Aramco share exchanged for each PRD share, The cheque is in the post.

Paul said in the interview that 95 days was sufficient lead time to obtain the materials required for MOU-6, and that spud would be before the last week in July. You would not commit to spending maybe over half a million dollars that you don't have spare, until an agreement was finalised. We are about 120 days away from the last week in July, so you can draw your own conclusions about the latest contract signature date.

There are three different scenarios.

1. Change of Operatorship. If PRD are selling all or a major part of the licences to a new entity that becomes Operator, then approval is needed from ONHYM, the Ministry of Energy & the Ministry of Finance. ONHYM has the contractual right to make a pre-emptive offer, which of course must equal or exceed the offer made by the third party.

2. Farm out. If PRD are selling a minority part of the licences to a new entity, but retaining Operatorship, then this does not need governmental approval, but ONHYM has the contractual right to make a pre-emptive offer for the stake up for transfer, again at an equal or greater price.

3. Exploitation Concession. If PRD want to submit an EC, which would be required in advance of a gas sales agreement of any kind from any part of the licence, they are required to submit an Appraisal Report to ONHYM. This is in effect the ITR which they received a month ago. It must contain the data from which it is concluded that a commercial discovery has been made, and a preliminary plan for commercialisation. ONHYM, PRD, and any relevant third party (Afriquia Gaz? Vivo?) must then collaborate to produce a definitive Development & Exploitation Plan. An EC is awarded on the basis of this plan. ONHYM has no contractual pre-emptive rights, since a share of the licence is not changing hands. However, as a newly commercial organisation, there is nothing to stop them from making PRD an offer for an increase in their share from their current 25%.

I suspect that it is Scenario #3 which is currently under negotiation. From Paul's comments in last week's interview, it is probable that the main points of a DEP have been agreed, perhaps there is still some discussion as to whether ONHYM wish to increase their current 25% holding, and if so, at what price.

Hi MEM. I know that ADNOC were interested mid-2023, with current events I would expect that interest to be renewed. ONHYM are obviously in the frame, they have pre-emption rights if PRD are divesting all or part of the licence. However, we are potentially looking at a series of events:

* LNG and/or CNG gas sales agreement based on the limited area around MOU-1 & MOU-3, Shallow biogenic A-Sands & Ma-Sands only. No transfer of licence.

* Scale up of above agreement, or else a farmout out of biogenic TGB-6 in the above area.

* Divestment of majority of interest in unconventional (shale) gas around MOU-1 to a company specialised in fracking.

* Either divestment of majority interest in thermogenic gas & Helium, or whole licence farmout, to enable an outfit with substantial funds, personnel & expertise to appraise & develop the deep MOU-Fan + Jurassic carbonates + Triassic + multiple other prospects.

I have no idea if these will be done sequentially or concurrently, or at all!

btw, I think your valuation is 'a little' on the optimistic side.

WTI $103

Brent $116

Murban $117

Following the concerted troll attack on Thursday after Paul's interview, I was delighted to see a total absence of green boxes on this board yesterday. Until late evening. Out of curiosity, I opened them up to reveal misinformation that I will address.

1. How does Europa get their license extended within weeks while we are waiting years?

* Ireland offers a staged system: Licensing Options (LO) are preliminary/non-exclusive authorisations (typically up to 2 years) that give the holder the first right to apply for a full exploration licence. Frontier Exploration Licences (FEL) are a category of exploration licence for frontier/deepwater areas. FELs have a standard 15-year term, divided into phases, with work commitments.

* Europa: Holds a full Frontier Exploration Licence FEL 4/19. This is an active 15-year exploration licence. Their approval yesterday was just for the next phase, and is essentially automatic.

* Predator: Holds Licensing Option LO 16/26, awaiting conversion to a FEL. Ministerial agreement is needed for such conversion, based on stringent financial, operational and environmental criteria. This is discretionary, not automatic.

Then accusations that PG isn't telling the truth about reasons for the delays.

* Do you really think that attorneys specialising in Energy Charter Treaty cases would take on PRD's case on a no win / no fee basis without doing due diligence?

2. Our failed financial journalist friend, who has to use emojis to express what he is unable to put into words, is accusing others of fanciful valuations per TCF of natural gas. I think those valuations are too low. My assumptions:

* A conservative $8 per MCF / $8M per BCF operating profit for PRD selling for CNG/LNG

- SDX are selling their gas at $11-12 per MCF to industry.

- The SLR study used a range of undiscounted net-back values from $7.37 for industry, up to $12.19 per MCF post-tax for CNG.

- SOU price to Afriquia Gaz is lower at $8.35, since AG need to truck it an extra 120km.

* Standard Net Present Value calculation with 10% compound discount (NPV10) based on $8 per MCF post-tax net-back; gives $2M per BCF for gas to industry.

* Gas for CNG/LNG could be worth almost twice that amount, but for now I will use the conservative number.

* Once outstanding warrants & options are exercised, there will be 980.6M shares in issue.

* GBP:USD is 1.34

That gives a value of £1.49p per share per TCF once Reserves status is achieved – once the gas is proven recoverable, and that a fully-financed route to commerciality is in place. We await the agreement that PG has referred to, and the successful drilling and testing of MOU-6. If all in the bag, this valuation should be achieved by August 2026.

If you think this valuation is fanciful, CHAR were claiming $4M per BCF ($4 Billion per TCF) NPV10 on Loukos, and TheBold was putting $10M per BCF for Anchois

Concerns are being expressed about the non-publication of the ITR. There are very good reasons for the delay. The following are relevant paragraphs from the published model agreement between ONHYM and an exploration company (PETCO), required before an application for an Exploitation Concession. ONHYM will have to pay 25% of development costs, so will be actively involved in the planning process:

5.1.3. Expenses for Development and Exploitation Works in respect of a Hydrocarbon deposit, incurred after the granting of the Exploitation Concession related to the said deposit shall be financed by the Parties in proportion to their respective Percentage Interest.

This is what is required to happen before agreement on any deal:

5.2.4. Following the completion of the appraisal work program, PETCO shall submit a detailed report (the “Appraisal Report”) [this is the ITR] on technical and economic information related to the discovery and which shall confirm, according to PETCO’s opinion, if the discovery is a Commercial Hydrocarbon Discovery.

5.2.5. The Appraisal Report shall include the geological and petro-physical characteristics of the discovery, the estimated geographic extent of the discovery, the production test results, obtained from the formation, a preliminary economic study regarding the exploitation of the discovery, the provisional development and exploitation plan relating to the discovery, as well as any other information required by the Hydrocarbons Code.

5.2.6. ONHYM may request amendments and modifications of the provisional development and exploitation plan and of the designated area covering the discovered deposit. In any case, ONHYM and PETCO shall meet as soon as possible to examine the provisional development and exploitation plan, as well as the amendments and modifications proposed by ONHYM, if any. The Parties shall establish by mutual agreement the definitive development and exploitation plan (the “Development and Exploitation Plan”).

Addiitionally, if a third party such as Vivo or Afriquia Gaz are taking an ownership share in the Exploitation Concession, ONHYM may want to increase their share from 25%, which they are entitled to do under the Hydrocarbon Code, Article 71 of Law No. 21-90. It states: “ONHYM may exercise pre-emptive rights to increase its 25% licence holding only in the event of a total or partial transfer of interests in favour of a third party other than the parent company or an affiliate of the transferor”.

I now think it could be possible that the grant of an Exploitation Concession may occur before MOU-6 is drilled, since that could be part of the above 'Development and Exploitation Plan'. That ties in with Paul's statement about drilling materials, lead times and spud late July.

An agreement between all parties could be imminent.

@Sygmaa. I hope PG is not partnering with Manas. Their Albanian prospect was evaluated over the course of five years, through an extensive sequence of seismic surveys, independent resource studies, and ultimately five deep (5000+m) very awkward exploration wells drilled in partnership with Shell. The wells alone cost 500M Euros — but with no commercially viable discovery. Shell withdrew from the project and closed their Albanian operations in 2025, at a written down cost of 1.1 billion Euros. That's a little more than PRD is likely to have available for a new development.

No gas production is currently commercialised from Albanian fields. These are all discovered but undeveloped:

* Dumrea. This was licenced by ENI. Think they are still working on it.

* Delvina. Stopped production 2012, substantial resources remain. I think still owned by Albanian company Delvina, could be for sale / partnering.

* Molisht-Shpirag – Discovered by Occidental in early 00's, then followed up with drilling by Shell in 2019, but apparently not followed up further. Perhaps too small for Shell, so could be available?

* The following are all shown as 'discoveries' in my little black book, together with dates. I am unable to find any further info atm.

Kallm 1963, Frakull 1972, Finiq-Kranë 1974, Ballaj-Kryevidh 1983, Povelcë 1987 Panajë ?, Divjakë ?,

National organisation AlbPetrol estimates Albania's total natural gas reserves at 5.7 billion cubic metres, which is a long way short of 2-3 TCF. Maybe that is literally Reserves, not including Resources.

Another one for you. I see oil & gas prices have retraced half the loss from earlier in the week. Will be interesting to see what happens next week, when the USMC invade from the south, and the CIA/Kurds invade from the north.

Everyone is making wild guesses, so I'll join in. NB - only semi-serious!

!. Paul has been offered an Albanian gas project at a must-buy, bargain basement price.

2. He has bought in using Snowcap-3 cash.

3. Moroccan money, other than for drilling/completing/testing MOU-6, is conditional upon a success at MOU-6, so will not be available until Q3.

4. There will be a placing to re-finance SC-3, hence the month's delay in spud until June.

"Perhaps sooner than some people would like to expect" - like my today, your tomorrow?

* Happy with progress in Morocco - "it will deliver, perhaps sooner than some people would like to expect."

* MOU-6 will be drilled no later than the last week of July "will not currently be funded by the company, that's all I can say."

* SC-3 finished by end-June.

* Trinidad assets can be sold to local entities valued on $20,000 per Bbl per day.

* Looking at a non-EU European country project - Adriatic such as Albania? Turkey?

* Looking at West African project.

* Looking at additional Trinidad project.

Paul seemed very confident.

Sorry, map on Slide 33 is northWESTerly tip of the granite body.

Helium production is mostly from the radioactive decay of Uranium within granite bodies. When the Guercif Helium occurrence was first noted, it was not obvious where it had come from, since the nearest known granite was a small outcrop at Alouana, which although within PRD's licence area, is some 20km to the SE of Guercif city.

About a year later, I posted here that I had located the brief abstract of a technical paper suggesting that the local granite intrusions were much larger in extent than previously realised. I have finally obtained the full text of the paper from the authors. They have used magnetic and gravitational survey methods to identify the large-scale structures beneath the region. This includes subsurface mapping around the Alouana granite outcrop.

Much of the paper is highly technical, detailing their methodology. The native language of the authors is Arabic; I have made some very minor changes to their English text to aid readability, but this in no way changes the meaning. Here are some extracts from their conclusions, specifically relevant to our Guercif area:

“The qualitative interpretation of the residual gravity anomalies demonstrates the close relationship between the positive anomalies and the local uprising of the basement; and between the negative anomalies and the presence of buried Hercynian granitic plutons.”

“The granite's outcrop does not describe the observed anomalies in terms of numbers and sizes. In this work, we propose a map of the granite's [subsurface] lateral extensions that is very large compared to the smaller intrusions outcropping at the surface.”

“The N2 [negative] anomaly is due to two granitic massifs investigated in this area, buried at depth as suggested by the outcrop of the Alouana granite apex. The orientation of the N2 anomaly is NW-SE”

“Anomaly N2, located to the North of the village of Mahirija, showing a very complex shape, with an intensity of -20 mGals, is associated with the Alouana granite outcrop. Considering the size of the anomaly and the position of the Alouana apex, the buried part of the granite should extend to the NW for a distance of about 30km”

NB – Guercif is 20km to the NW of Alouana.

El Azzab D., Ghfir Y., Miftah A. (2019) — "Geological interpretation of the Rifian foreland gravity anomalies and 3D modelling of their Hercynian granites (Northeastern Morocco)". Journal of African Earth Sciences, volume 150, pages 584–594.

Hidden away at the top right of slide 33 of the October 2025 presentation is a small map showing just the most northeasterly tip of this very large granite body, linked to PRD's MOU drilling area by a set of deep transfer faults. The Alouana granite has been producing Helium for 284 million years. Clearly, Paul has worked his way through the same paper.

When using AI to answer a question it is important to ask for references, and to check them. Sometimes the references are completely imaginary. I have also discovered a post I have made here used as a 'reference', and even a untrue post here by one of our resident trolls being presented as a fact that the AI uses to come up with an answer. I have found the same problems with CoPilot, Grok, ChatGPT-4 and Claude. For profession purposes I use Chat-GPT5-Scientific, which is a subscription-only service. It's slightly better, but far from perfect. With reference to today's post of AI conclusions:

* NABI & WIEGL are completely unrelated companies, the AI response has confused the two.

* WIEGL is not the operator of any PRD licence, it is the minority owner of a company (Steeldrum Ventures Group) that holds the licences, and was used as an acquisition vehicle for them.

* PRD is the sole operator, the work schedule is agreed by PRD & NABI, and carried out by NABI at their cost, in return for 70% of oil revenues net of 12.5% tax. WIEGL is not involved.

* WIEGL does not receive any income from either NABI or PRD.

Some are (quite reasonably) asking why WIEGL would agree to such an arrangement. At the time the agreement for Bonasse was made, the oilfield effectively had negative value - no oil was being produced, and there were substantial outstanding debts and licence fee obligations. In return for a payment of $170,000 PRD agreed to take on operatorship, return the field to a productive position, at PRD's cost, in return for oil revenues. WIEGL would retain their 49% share in an asset that would return to a positive valuation, thus benefitting from any future asset sale. SVG was used for acquisition purposes to consolidate tax losses. PRD structured the agreement so that they could not become liable for WIEGL's outstanding obligations should for any reason WIEGL pull out or be liquidated. PRD then subsequently agreed an arrangement with NABI to perform the restoration work. This agreement is solely between NABI & PRD, and has nothing to do with WIEGL's minority ownership.

A clever deal sequence by PRD, whereby for a small capital outlay they have not taken on debt or other financial obligations, gained operatorship, are able to make use of the Bonasse tax losses across other oilfields, not take on any additional capital cost, and receive what is in effect a decent royalty from oil sales.

This model was then copied for the CEG oilfields, obviously with a much greater initial capital outlay, since these were producing fields.