Member Info for KeithOz

We knew this was coming this week, and had already been given the top line results. Note that the January 2024 ITR was completed before PRD had 100% of Cory-Moruga, hence the minor upward revision of some numbers in this latest version.

Both ITRs give a combined unrisked total of 14.31 MMBbl recoverable. Some quite conservative assumptions, imho, as perhaps should be expected where historical data is incomplete. Some things to watch for once SC-3 is done, which could give worthwhile upside to the Snowcap structure, which of course is only part of the C-M block.:

* Although there is pretty good data on the uppermost reservoir, Herrera #8, from Snowcap-1, this horizon will not be penetrated in SC-3. Data from the target levels of Herrerra #s 1, 2, 3 & 7 is projected from the old RD drills, where logging was rudimentary and incomplete. For this reason, the base case assumes thicknesses of these reservoirs below what is likely. Similarly, quite harsh risking is applied to the other parameters for these potential reservoirs.

* Historical logging was far from current practice, in particular resistivity is missing, which could have resulted in missed pay from additional intervals

* If significant oil is found in Herrera #s 1,2,3,& 7 in SC-3, this will of course de-risk those same reservoirs across the whole Snowcap structure, potentially leading to a revision from the current P50 (2U + 2C) of 8.73MM Bbl to 14.3MM Bbl.

* The financials were completed before the start of the latest Gulf War. We have no idea where the oil price will end up, but using $75 per bbl, and keeping the other parameters used in the ITR the same, this should provide around $1M additional profit in Year 1 from just SC-3.

* The potential Cretaceous horizons identified on seismic are analogous to those in the Cipero field quite a long way to the northwest which showed presence of oil. It is hoped that the Cretaceous is more prospective within the Cory-Moruga block. These prospects are deep, and would most likely be explored in partnership with another company.

There's a lot of detail here, I will go through it properly when I have more time, and add further comment if necessary.

Current events must be pushing quite a number of gas E & P companies to look for potentially large gasfields well away from conflict zones, but near to customers. Added plus points would be a stable jurisdiction, low taxes, availability of good infrastructure, and low extraction costs - ideally onshore. If you had such an opportunity, I can't think of a better time to be concluding a farmout on the most favourable terms.

@5th Feb RNS told us that at $60/BBl, netback was $32.60. So for each $5 increment, you need to deduct 12.5% royalty, giving $4.37 extra profit.

Brent is currently $78.5, WTI $72. Platts (Dubai) has trading suspended, so we will just have to average Brent & WTI, giving $75.25 for Trinidad oil.

TRIN $60 = netback $32.60 (per RNS)

TRIN $65 = netback $36.97

TRIN $70 = netback $41.35

TRIN $75 = netback $45.72 (current)

TRIN $80 = netback $50.10.

I said:

"Once you exclude the recent flurry of US shale gas transactions, over 90% of all deals concluded in the last year concern resources that have not been flow tested, indeed not even drilled."

You then said:

"Why do you keep referencing deals done in the long established , 100% proven , massive mid and downstream infrastructure heavy Permian basin to Guercif Morocco, where it is the polar opposite."

1. Do you not understand what 'exclude' means? or,

2. Are you deliberately misrepresenting what I say because the facts are contrary to your agenda?

and

3. Do you have a social or psychological issue that compels you to start quarrels with everyone? or,

4. Are you paid for your 845 negative posts on this one company over the last six months?

Trinidad.

Some derisive comments that the increase in oil prices is irrelevant for PRD. As @Oldslow has kindly pointed out twice, the resultant profitability pays off the NABI costs faster. While the current price may not be sustained, at the moment it is paying down the NABI bill twice as fast as last week, meaning that it will only take half the time before PRD is back on a 30% of sales payment schedule.

A reminder that SC-3 is not being funded by NABI, so PRD will accrue all the benefit of increased prices.

Morocco

The comments continue that because PRD have not yet flowed gas to surface, a deal will not go ahead. I appreciate that few here will wish to pay out $1800 a year for the 6-monthly WoodMac O&G mergers & acquisitions reports. If they did, they would see that once you exclude the recent flurry of US shale gas transactions, over 90% of all deals concluded in the last year concern resources that have not been flow tested, indeed not even drilled. Compared to most project sales / farmins, PRD has a massive amount of data available for prospective purchasers to evaluate. This includes Contingent Resources - i.e. DISCOVERED gas.

Polite request. If folks are going to take my comments from other places and post them here, could they please post them as I wrote them. I answered a specific question on another bulletin board relating to what cost refund PG was hoping to receive for one of the options currently under discussion. I said "Total Guercif capitalised costs of £28.3M according to October presentation slides. Not sure if PG is after all this for a CNG and/or LNG operation, or only the bit that relates to MOU-1 & MOU-3."

Official WTI price stabilised at $72, 7% up.

Official trading in Australia doesn't open for another 35 minutes, but grey market price for WTI just opened 15% up at $78. No reliable price for Brent yet, but assume around $83.

Actually, it's a positive that AV has commented today - in so doing he has underlined his total ignorance and flagged up to all that he has a negative agenda. All war produces loss of life and suffering, so I am firmly in the resolve matters by negotiation camp. There are, though, positives for PRD.

* At a netback of $32 for Trinidad oil, a 10$ oil price increase will increase PRD profitability by 30%.

* PRD are in the process of concluding one or more agreements for gas sales in Morocco. The ITR demonstrating the substantial scale of those assets is currently being reviewed by ONHYM and should be available to us shortly. Those assets are in a politically stable country close to potential markets, well removed from any current or future disruptions, therefore should be priced at a premium. Should negotiations be proceeding with a larger scale farmout, this will serve as a timely reminder to our potential partners, especially if in Asia, that supply agreements have a 'force majeure' clause for good reasons.

Just spoken with an 'oily' friend in Dubai, who has been working all night (it's 4.00am there). Most insurance companies have withdrawn cover from vessels transiting the Strait of Hormuz. Although the Strait is physically open, authorities such as MARAD and companies including Hapag - Lloyd have declared it closed. No tankers are transiting; there is a large build-up of incoming (empty) ships at and around the port of Fujairah (UAE east coast), and outgoing vessels are remaining in Gulf ports. It appears that multiple facilities have been hit by Iran, including in Basrah (Iraq). He believes just the current disruption to tanker positioning will take weeks to resolve even if hostilities cease this weekend, and everyone expects a major spike in oil prices when trading reopens this evening (UAE time). Every day of closure removes 20 million Bbl form the world market - one fifth of the total.

Https://1a-1791.com/video/fwe2/39/s8/2/E/A/M/3/EAM3z.caa.mp4?b=1&u=ummtf

Not just a 10:1 consolidation, but also reorganisation of share capital into ordinary and deferred shares. Nothing to do with operations. Very confusing, especially the way the share price is incorrectly reported on lse. See https://www.lse.co.uk/rns/SOU/notice-of-gm-n0m0zymw5g5rvkz.html

Trinidad.

* Of note is that the updated ITR & associated financials are using $60 WTI. Trinidad oil is priced on an equally weighted index of WTI, Brent & Platts (Dubai). Platts is published weekly, I expect the next price to be a good bit higher considering the Shenanigans in the Gulf, but the current numbers give a T&T price of $68 per Bbl.

* We were previously told that we were using our own rig, acquired as part of the CEG operation. It now seems that Star Valley, who PRD have used in Morocco, are trying to pitch in with a better bid - presumably wanting to remain PG's favourite drilling co. in the future.

* Those of you who can use a calculator may wish to evaluate the NABI drilling costs per metre - we have been given the hole depth, flow rate, netback per Bbl, and payback time. With these variables applied to the other NABI holes, you can determine that NABI costs are remarkably low, and will be repaid a lot sooner than I expected. This means that PRD will benefit from moving from 15% to 30% of revenue a lot faster, and knocks on the head the complaints from the usual suspects that Trinidad only generates pennies.

* The workovers, currently underway on Goudron (which is an extension of the Guyana-Trinidad offshore field) will be even cheaper, with consequent faster payback.

* Wax treatment generates not only heat to melt the wax, but large volumes of nitrogen which helps lift the oil to surface. My guess is that this could cause problems with a borehole that is old and not very well drilled. Seems sensible to try it on a competent Bonasse new-drill.

* We already knew about potential for deeper hydrocarbons - particularly in the Cruse formation where TXP have had success nearby. This is a plus to be looked at later - let's pick the low-hanging fruit first.

Morocco.

* At least the ITR has been completed, and is now with ONHYM. I guess we may get it just a week or two later than promised, which is a major improvement over previous missed timelines. We now have confirmation that this ITR is focussed on the MOU-1 & MOU-3 structure, rather than a new look at the whole licence. The more focussed and detailed, the better for the initial planned commercialisation.

* It would seem that the CNG / LNG is the focus of discussions, rather than selling off a share of the whole lot. I am happy with that, since having a commercial, producing operation up and running will make the eventual farmout proposition more valuable to us.

"Keith Oz opinion is certainly not fact or correct , there is NO 100% GCOS for Guercif mentioned anywhere."

Clearly a statement made by someone who knows sfa about oil & gas exploration, and has never read or understood an ITR or CPR.

Contingent Resource = gas that has been discovered. If it is discovered, then of course geological success has already been proven.

What remains is the ccos, commercial chance of success, which, as I have stated numerous times, requires a number of factors to be in place in order that Contingent Resources may be upgraded to Reserves. Those factors are being prepared & finalised for Guercif.

@blissful. Just about every drill in Trinidad, oil or gas, starts with an impressive flow rate that then tails off. Snowcap-1 did this. You may have noticed that allowance for this phenomenon has been made in the flow forecasts in the October presentation. It would be deceptive to issue an RNS just giving Day 1 flow rate, I would expect that in a few more days we will get much more meaningful results - the stabilised flow. If I get the time this week, I will try to pull together some results from other Trinidad wells, so that we can compare our new wells with historic data.

@Croxie - that is correct, but these numbers are undiscounted - ie they assume that they have 100% cos - both gcos & ccos. Some of the Guercif assets are already Contingent Resources, thus by definition have 100% gcos. We just need to get to get the stuff flowing to surface and a gas sales agreement in place for the 100% ccos. No $53M+ required.

Hidden away in today's EOG Placing RNS are some details of their Barracuda prospect offshore Equatorial Guinea. This contains Pmean 893 BCF. They give it an NPV10 of $1823M. This is very close to the $2M per BCF NPV10 I have been using as a valuation of Guercif . However, it seems that our gas might be worth a lot more per BCF than theirs because of the negative effect of their much higher front-end loaded costs - a mere trifle of $53M for the well! Plus undersea connections to a nearby producing platform. Oh, but Predator doesn't have any gas. There, trolls, saved you the trouble of posting.

ONHYM do not award licences. ONHYM and the company agree the terms necessary to award a licence. This was completed last year. The licence is awarded by the Energy Ministry, after sign off by the Finance Ministry. This is a contractual obligation. I am not aware of a single situation where ONHYM, or their predecessor ONAREP, has agreed licence terms then a licence is not issued. If you know of such an instance, please reference it.

I have never said that a declaration of commerciality is up to Paul Griffiths “to make by himself “, so please do not distort my statements. I have made it crystal clear what specific events need to occur and be agreed before such declaration can be made – these constitute 3 of the 4 bullet points in my first post this morning, including commercial gas flow, a gas sales agreement and an FDP. So why suggest that I have not stated this when I have? I repeat, PG does have significant say on WHEN such declaration is made, and yes, the timing is driven by tax issues.

Dr Tim Wright, FGS, FSEG, MIMMM of Scorpion Geosciences is an accredited Competent Person, meaning that he is deemed fully qualified and has direct personal experience of the necessary geological, geophysical and geotechnical aspects of this project. He is well known within the industry. It is a requirement that he has full and free access to whatever data has been generated. There is a lot of data. This same data will have been supplied to all companies and organisations (including ONHYM) for review by their own technical experts. I cannot possibly imagine that any credible potential partner would sign an agreement without doing their own very detailed Due Diligence. If there were to be significant discrepancies in their interpretation of the data compared to Scorpion's, that would be resolved by further discussion. Please detail the qualifications and experience that you have that put you in a reasonable position to question the veracity of past and forthcoming ITRs.

I repeat that I had absolutely nothing to do with any 'Research Report' posted on this bulletin board. Anything I post is my own opinion, under my own name, based on publicly available information, which I usually reference. Potential investors should always check the facts behind any statement here. Please note that the Company has made it very clear that information on social media can be inadvertently or even deliberately misleading, and urged investors to rely only on statements in an RNS and the Company's official X account.

I don't expect an apology - but if I said why I don't expect an apology, it would indeed be an insult, albeit a deserved one.

Get someone to read the big words for you. I have posted re. commerciality declaration and timing several times over the last month, but your playground friends respond with obscenities in order to get the whole thread removed. Thank you to @OlivettiChamp for re-posting this at 0751 6th February:

"1). It is correct that the standard ONHYM hydrocarbon contract states that the 10-year exemption from corporation tax begins upon commercialisation. However, the situation is more nuanced than this simple statement may seem to imply. I appreciate that nuance may be difficult for some to understand.

2). Upon the declaration of a commercial discovery, an Exploitation Concession must then be applied for within a defined period. This application must include timed and costed proposals to proceed to production.

3). Moroccan Hydrocarbon Code (Law No 21-90 and Decree No 2-93-786) then come into play. The concession can be revoked ("déchéance") for non-compliance, explicitly including "failure to timely complete development works and start operations."

4). It should be obvious that a company or its co-developers would not wish to prematurely announce a commercial discovery until it was in a position to be able to commence large scale production right from day 1, otherwise it would be losing serious amounts of tax benefits on the larger scale production likely in the later years of the exemption period.

5). PRD could have announced a commercial discovery a long time ago. They have not done so, and will not do so, until they have all the ducks in a row. These include * Completed quantification of available gas volumes. * Signed a definitive cooperation and gas sales agreement with an appropriate third party. * Ensured that a fully costed Field Development Plan is agreed. *The financial wherewithal and technical expertise are available to complete such an FDP.

6). The overarching reason for delaying announcement of a commercial discovery is for maximising tax benefits."

This is my opinion as to the timing of events that will lead to a closer accord between underlying value and market price. I will comment solely on the biogenic gas resource to the north and west of Guercif, extending down to about 1000m, which is the current focus of activity leading to commercialisation. The underlying value will only be acknowledged by the market once an Exploitation Concession is under way. What has to be done, and what is the time frame?

Four things need to be included in the application

* A definition of the resource under consideration – this will be in the ITR due for release by the end of the month.

* Proof that the resource is recoverable – MOU-6 results, I will deal with timing later.

* An agreed Field Development Plan – what work is necessary to get the gas out of the ground, process it and distribute it. This needs to be timed and costed. - currently under discussion with two parties for CNG and / or LNG. We believe the parties to be Afriquia Gaz and Vivo Energy respectively. Details of a finalised agreement may be released alongside the ITR, maybe later.

* How the FDP is to be executed and financed, and assurances on reliability of the sources of the necessary finance and expertise – the companies named, working most likely with Italfluid providing Flow Assurance and engineering, will not have any problems in meeting the necessary criteria.

Terms had been agreed with ONHYM for the exploration licence to be extended until 05/11/2026, the application has been submitted, and approval from the Ministries of Energy and Finance is awaited – RNS 17/12/25. PRD has a contractual, legal right, to this extension now that terms have been agreed. It may already have been granted – previously we have not been informed on similar approvals until well after the fact.

Timing of the Exploitation Concession. "Applications for concessions must be filed with the Ministry of Energy no later than three months prior to the expiry of the period of validity of the exploration permit pursuant to which the application is submitted." Source is the Hydrocarbon Code, S.22 of Decree 2-93-786, 03/11/93, amended by 2-99-210, 16/03/00, & Law 21-90 01/04/92, amended by 27-99, 15/02/00. This means all the above points must be included in a submission no later than 05 August 2026.

Therefore drilling + testing of MOU-6, which could take 10 days + 15 days, must start at the latest in early July. Agreement on the whole project, including financing the drilling and testing of MOU-6, must be earlier than that to ensure that all necessary materials are procured and on site. We know that some long lead time items are already on order.

The two key timing issues are the spud of MOU-6 in less than five months, and finalisation of a CNG and/or LNG agreement prior to that. Some of us have been more patient, and for a lot longer, than others, but I'm sure we all look forward to a return on our investment.