Member Info for KeithOz

Part 2.

In summary, the structure lets Predator (the majority controller) secure a substantial, low-risk, direct revenue stream (30% net) by outsourcing all operational risk and cost to a local contractor (NABI), while leveraging tax losses and operatorship/control via T-Rex/Steeldrum.

WIEGL participates only passively as equity minority in the owner entity, with no involvement in the NABI contract and no direct revenue carve-out. Predator’s RNSs therefore disclose only their own contractual receipts — there is no requirement or relevance to reference the minority partner’s indirect share. This arrangement remains unchanged in all disclosures throughout 2025 & 2026 (production updates, drilling reports, and financial statements). It is a classic “net revenue interest” or production-payment style services deal that heavily favours the controlling party (Predator) while fully de-risking the assets for the JV.

For the above reasons, I retract my profit forecasts for Trinidad operations I made on lse on 09 March 2026. Not only does profit accrue more rapidly to PRD, but NABI costs are paid twice as quickly, with faster reversion to the 30% level. In an environment of sustained high oil prices, this arrangement becomes hugely profitable. Using the same assumptions, but with corrected NABI %ages, the PRD profit for 2026 would be $9.7M, and $28.9M in 2027.

Part 1.

I have finally had time to review properly the NABI / PRD arrangements. This board appeared to have come to the consensus that West Indian Energy Group Ltd was entitled to 49% of the 30% royalty payments from oil sales from the former CEG fields. I now believe that is incorrect, and that PRD are entitled to the full amount. I have carefully re-read all the relevant RNSs, and discussed the issues with a former Finance Director of a US-based multinational.

Under the Production and Field Services Management Agreement (PAFSMA, also called the revenue-sharing or Master Services Agreement) executed directly between Predator Oil & Gas Holdings Plc (via its wholly owned subsidiary T-Rex Resources (Trinidad) Ltd) and NABI Construction (Trinidad and Tobago) Limited:

* NABI is contracted to operate and manage the former CEG fields -Bonasse, Goudron, Inniss-Trinity & Icacos, now held by Steeldrum Ventures Group St. Lucia Limited subsidiaries. NABI bears 100% of all field operating costs, employee costs, working capital, heavy workovers, drilling capex, and minimum work obligations.

* In return, Predator is contractually entitled to 30% of gross oil sales receipts (at the sales point) after deduction of the 12.5% government royalty. Predator utilises acquired legacy tax losses to reduce the effective Petroleum Profit Tax. For incremental production from workovers or new wells PRD receives 15% until NABI recovers its costs, then reverts to 30%.

This is not an ownership-based split or a distribution from Steeldrum (owned 51% by T-Rex, 49% by WIEGL). It is a direct contractual revenue entitlement to Predator (recognised as “crude oil sales” revenue in their financial statements, when control transfers at the sales point). Predator reports this in every RNS and financial update because it is their specific, de-risked income stream with zero cost exposure.

WIEGL has no direct entitlement or payment under the NABI PAFSMA — which is why it is never mentioned in Predator’s RNS or reports. WIEGL’s only economic interest is its 49% non-controlling interest in Steeldrum, the asset-holding company. It would however receive 49% of any asset sale.

Steeldrum (and its subsidiaries) is consolidated because Predator controls 51% via T-Rex. Any net profits at Steeldrum level are allocated 51% to Predator and 49% to WIEGL. The PAFSMA revenue itself flows directly to Predator, so it is only the residual economics at Steeldrum level (if any, after the 30% carve-out, NABI’s retained share for services/cost coverage, taxes, and liabilities) are what WIEGL participates in.

At acquisition completion (29 Aug 2025), WIEGL also assumed all legacy liabilities, provisions, and exposures of the CEG entities (valued at US$4.25 million for the transaction), giving Predator and the JV a clean balance sheet.

Not to be confused with Rosencrantz & Gildenstern, Goehring & Rozencwajg are commodity analysts I hold in high regard. You can access their latest report on the current oil crisis and its implications for investors here, free of charge:

https://www.gorozen.com/commentaries/2025-q4

Well, look at that. Trump has declared that the war has been won, it will all be over soon, and the oil price will return to the $60s. If that's the case:

* Why has there been an unprecedented release of 400M Bbl, one third of the entire global oil reserve? This leaves only 8 days usage, with US & Japan holding 62% of the remainder between them. Tough luck on everyone else.

* Why have three tankers been hit tonight by Iran that weren't even passing through Hormuz?

* Why has Iran stepped up its attacks on UAE, Qatar, Oman, Bahrain & Saudi oil & gas facilities overnight?

* Why have all flights to / from Australia & Europe via the Middle East been suspended again?

* Why did all the US banks close their UAE offices & evacuate their staff yesterday?

* Why has 'regime change' put in place an even more crazy leader who has promised every IRGC shuhada (martyr) 72 virgins each in paradise?

* Why has WTI gone back up to the mid-$90s, Brent to $100 and Murban & Platts to $100+ this morning?

It seems more likely than not that this chaos will continue for longer than we are being told. Paul - With $60 profit per barrel, I suggest you get Snowcap-3 drilled & flowing asap. That's $30,000 to $120,000 profit per day, using the ITR range of initial flow rates.

Continued. (unfortunately).

Well production decline.

SC-1 production decline has not been used as a model for SC-3, since it was poorly drilled & completed, and had unaddressed waxing issue. The ITR states on p.21:

"Key aims of the initial development work programme being progressed by PRD are as follows:

SC-3 (Proposed)

• Target H#1 - H#3 and H#7 stacked sands in single well “Snowcap-3”

• Co-mingle Herrera H#1, H#2 and H#3 Sands for 1,000 bopd IP [initial production] declining by 35% over 12 months . [ie still at 650 bopd after 1 year]

• Once H#1, H#2 and H#3 Sands are at equal pressure add H#7 sands to production for an ADDITIONAL up to 400 bopd Initial Production (IP) declining by an estimated 35% over the first 12 months". [ie an ADDITIONAL 260 bopd]. My CAPS & [brackets].

and on p.22:

"SGL note that in common with other producing assets in the area, PRD have identified the opportunity to re-inject any solution gas at a later stage to sustain or boost flow rates. Oils tested in SC-1 were found to contain a component of wax which is common to oils in the area sourced from Cretaceous shales. PRD therefore have a plan in place to undertake chemical injection if waxy oil required intervention."

Mature oilfields (Bonasse etc) typically have decline rates of 8% per year without interventions such as NABI are planning to undertake - workovers, modern infill drilling, production from newly discovered reservoirs, modern completion and pumping technologies, gas injection, water injection, or CO2 EOR. Now what was the MONTHLY growth in December 2025, BEFORE the current ongoing campaign of new drills and heavy workovers began? Oh look, it was +19%.

Some here do not seem to understand the standard industry and business terminology I used in my projections. Perhaps this will be helpful.

"Best Case" in O&G means 'most likely', not highest possible. There is no such thing as 'very best case', and I have never used any such scenario. In my assumptions I was careful to use "Base Case' as defined by the ITR - for example, under Section 3, Snowcap Drilling Plans, it specifically states "Base Case 500 bopd (high end potential 1,000 – 2,000 bopd). (p.19). I have used conservative numbers throughout, which is why I ran with that figure of 500 bopd. 1000 - 2000 from just the one well would be transformational for PRD on its own.

"Netback" means the profit accrued after taking into account fixed costs and variable costs associated with production. The ITR states that at $60 per Bbl, netback is $32.60. The difference of $27.40 per barrel is accounted for by production costs, royalties, licence levies, taxes and abandonment levy. The numbers are all there. Increased production above the base case will result in fixed costs being reduced per barrel, giving an even better netback. The Net Present Value calculations in the ITR by definition account for all capital and ongoing expenditure, as well as taking into account the time value of money. That is why the ITR and I use NPV calculations, since this is standard practice across all industries.

Of course, under our agreement with NABI, PRD are not liable for any costs at all. Our profitability is therefore highly geared to the oil price, a brilliant arrangement put in place by the unfairly-maligned Mr. Griffiths, who clearly has a better understanding of business than some on here.

It's all there for anyone who can read. Very, very misleading to pretend otherwise, but you know that.

I asked for suggestions, some have been made, although most are more intended as insults rather than reasoned assumptions.

@Matt - the January RNS Trinidad update suggested an additional 300-400 bopd just from the Bonasse & Goudron current programmes. With an expanding work programme and additional availability of the T48 rig (PRD's own), I don't see a 500 bopd increase per six months from NABI as being unreasonable. The ITR consistently has given Snowcap-3 a base case of stabilised 500 bopd, with an upside of 1000 - 2000 bopd.

@ Trolls. I am not sure of your reasoning, if indeed you have stated any. Let's assume your criticism of NABI progress is reasonable (it's not). Let's remove ALL future NABI production from the calculation, and assume we just run with what they have produced to date.

Net profit to PRD is then $5.06M in 2026, and $19M in 2027. Since this runs contrary to your stated agenda of 2p share price, you will now have to come up with something a little more substantial than your childish attempts to mock.

@CReas - The dry season has now started in southern Trinidad, making engineering work a lot more practicable. However, the other limitation is likely to be availability of rig, crew and materials. I would imagine that if everything has a green light, PG would wish to move as soon as possible to capitalise on the current situation. We should get another Trinidad update by the end of this month.

The price of all oil and gas shot up again on open here in Australia, with all oil contracts now over $100 per barrel.

Qatar's energy minister Saad al-Kaabi said in an interview with the Financial Times that the current war will have a drastic effect on the economies of the world. “If this war continues for a few weeks, GDP growth around the world will be impacted. Everybody’s energy price is going to go higher." He said that even if the war ended immediately, it would take Qatar "weeks to months" to return to a normal cycle of deliveries.

I have been researching world oil reserves – it seems that only China & Australia (phew!) have the actual reserves they are supposed to have. The US has never topped up the reserve that was run down under Biden, and the UK (and therefore Ireland) reserve is almost non-existent. The EU collectively is way under the required 90-days of reserves. All these reserves will not only be run down in the short term, but have to be topped up to the proper levels again in the medium term. World oil consumption continues to increase; new production is limited.

In this environment, even if the current situation does not spiral into another Vietnam / Afghanistan / Iraq, the prices of oil and gas are likely to remain higher and for longer than expected just a week ago.

I have therefore revisited forecasts for PRD Trinidad production. Here are my assumptions. Any sensible alternative suggestions are welcome; I will drop them into my spreadsheet and update if required.

* PRD has 300 Bbl/day base production at 30% of revenue after 12.5% royalty.

* After accounting for PRD having a 51/49 share of CEG licences, PRD gets half the above as profit, ie 15% net.

* NABI new production added at 500 Bbl/day every 6 months, gives 7.5% of revenue accounting for 51/49 as above.

* 2027, NABI new production costs for 500 Bbl/day per 6 months are written off, so that moves up to 15% of sales (51/49 of 30% as above). I think this is a reasonable projection of what NABI have achieved to date.

* PRD's own production starts H2 2026, based on $32.60 netback per Bbl at $60 per Bbl, as per the ITR.

* PRD own production increases at 500 Bbl/day every 6 months from new C-M production. Of course, this requires Base Case success at SC-3, SC-4 and SC-1 workover.

* This gives total gross production (NABI + PRD) of 1800 Bbl/day by end 2026, 3800 Bbl/day by end 2027.

* PRD get 87.5% of any price increase of own production after paying 12.5% royalty.

* Average oil price of $85 H1 2026, $80 H2 2026, $70 throughout 2027.

This gives net profit to PRD of $7.1M in 2026, $23.7M in 2027.

Continued high oil price and upside at any of the Snowcap wells blow this out of the water.

Thanks for posting that @Flombo, but it reads suspiciously like something supplied to the newspaper by EUR's PR agency. In fact, it reads very similarly to other articles published recently in the Irish press, so I suspect it is part of the EUR campaign. Why isn't Flagstaff following a similar strategy? Tim? Are you here?

Not only is the tit ignorant of business, investing, geology, oil & gas industry, basic arithmetic or good manners, but doesn't even know the meaning of 'trollop'.

40% of global helium is produced and used in the US. The remainder is produced by countries that export it for end use by other countries. 30% of global helium is produced by Qatar from the North Field, and processed at Ras Laffan, which has now suspended operations indefinitely. Thus, half of the available supply for non-US markets has shut down. This will clearly have major implications for helium pricing. Medical imaging use is inelastic, and usage for semiconductor fabrication (lithography & cooling) is accelerating in line with the demand for chips for AI.

The attached report from IMARC may be of interest. No, I am not forking out the required $8000 for monthly updates, but this free summary is sufficiently detailed for our purposes. In particular, it references prices paid to producers at the wellhead, which as I have pointed out on a number of occasions, are far below the (wholesaler) prices that many helium producers claim their output is worth. Asian markets (think TSMC) are the largest customers, and currently paying around $125 per mcf. This is likely to increase substantially.

No, PRD do not yet produce any helium, but its proven presence on our licences should add a little spice to any farmout negotiations. Please note that CNG and/or LNG discussions do not include helium, and are a small subset of any larger farmout process.

https://www.imarcgroup.com/helium-pricing-report

P.23 of the 5th March ITR states that at a base case of $60 / Bbl, netback is $32.60 / Bbl. For every $1 increase in selling price, profitability will increase by 87.5 cents, after 12.5% royalty. But... but... I hear some say, oil prices won't stay high for ever. Correct of course. Oil futures prices are not the opinion of random bulletin board trolls, they are the result of negotiations between buyers and sellers, arguably the most knowledgeable people in the world on likely oil supply and demand.

WTI futures quotes are indicating that oil will not get back down to our base case of $60 until December 2035. That is not a typo.

https://oilprice.com/commodity-price-charts?&page=quote&sym=CL*1&name=Crude%20Oil%20WTI

Since some here believe that I am always wrong, what follows is my own opinion, so is also likely to be wrong.

The ITR has not been delayed because it's Ramadan and ONHYM are working reduced hours. ONHYM do not reduce hours during Ramadan, and throughout the year they also work on Fridays, the Islamic equivalent of Western Sunday. You may have noticed that Amina Benkhadra never wears a headscarf, nor does her boss, Minister Leila Benali.

The data coalesced into this ITR is being used by all parties to establish the basis on which an Exploitation Concession will be approved for a CNG and/or LNG operation, and therefore also the terms of the commercial agreement(s). Once this permit is issued, ONHYM become responsible for development costs proportional to their (current) 25% share of the licence. They also have a contractual right to increase their share should the newly-commercial organisation wish to do so. Therefore, they are intimately involved with commercial negotiations, not merely offering an opinion. The current geopolitical situation will be weighing upon these discussions; it was already a top priority that Morocco should reduce their gas imports.

The confidentiality of these discussions means that the ITR content will also remain confidential. We should expect publication of the ITR at the same time as the conclusion of commercial agreements(s). Last week of March should give everyone enough time to agree.

Should have added that Fujairah is just about the only sizeable oil terminal that does NOT require ships to pass through Hormuz - hence the scramble for supply from there.

Murban Crude Oil Future is the main Middle East price, equivalent to WTI in US & Brent in EU. It's a physically delivered contract, basis FOB Fujairah (ADNOC) loading terminal, UAE. This morning (Oz time) it is up 16% to $94.51. No one seems to believe the US navy will be able to ensure safe passage through the Strait of Hormuz.

https://x.com/KQuick20704342/status/2029714547570036852/photo/1

Sorry - typo. H#6 should be 54%, not 15%

The following is publicly available information on gcos for each of the stacked Herrera formations. Where did it come from? As the Scotsman said to the girl who asked what he wore under his kilt "Lassie - it's for me to know, and for you to find out". In short, do your own research, it's not that difficult.

H#1 - 24%

H#2 - 21%

H#3 - 16%

H#4 - 19%

H#5 - 24%

H#6 - 15%

H#7 - 86%

H#8 Known accumulation (100%)

The chances of not hitting recoverable oil in such a stacked formation must be considered very low, especially considering its proven presence in contiguous formations in so many nearby wells. If you intend to publish your disagreement with this statement, please give full details as to why you have come to this conclusion.

The PIIP (Petroleum Initially In Place) numbers look very enticing compared to the Recoverable oil numbers. The ITR is assuming a 15% recovery rate. This is about right for the average oilfield where oil is extracted by natural pressure. However, imo there is substantial potential to perhaps increase from 15% to 30% recoverable, by using modern pumping methods combined with re-injection of all that gas (9 BCF!) that is going to bubble out from the oil. So, double the volume produced using standard methods. That could potentially be increased further by using CO2 EOR tech that PRD has already successfully trialled at Innis-Trinity.

I repeat, an ITR with conservative numbers.

Missed this! " Very few faults are noted within the Snowcap structure suggesting fewer, larger compartments which could benefit production efficiency and reduce the total number of development wells required to produce reserves". This should mean higher flow rates and total volumes per well for Cory-Moruga, compared to the adjoining Moruga West, for which some well data is given in the middle of p.19.