Member Info for KeithOz

I have already made my position crystal clear on Trinidad revenues, and an attempt is being made to subvert that. The matter of the percentage royalty attributable to PRD was discussed on this board a while ago, with the consensus appearing to be that WIEGL was entitled to 49% of PRD's revenue stream from the NABI agreement. I used that consensus as the basis of a forecast. Last week, I had the time & inclination to look into this in more detail, and made my views clear in across several posts that the consensus view was incorrect, and revised my forecasts accordingly.

The PAFSMA is between NABI and T-Rex (100% owned by Predator ), so the 30% / 15% revenue stream flows directly to Predator's wholly-owned entity, bypassing Steeldrum Ventures Group entirely. WIEGL, as a 49% shareholder only in SVG, would have no contractual entitlement to that revenue stream.

SVG's role is primarily the legal vehicle that holds the field licences and production subsidiaries — not the entity that contracted the PAFSMA. Steeldrum Ventures Group is the holding company for CEG Bonasse Limited, CEG Goudron Limited, CEG Inniss-Trinity Limited and CEG Icacos Limited, facilitating potential consolidation of tax losses. That is an asset-holding and tax consolidation function, not a revenue-receiving function under the PAFSMA. In the event that these entities or licences were to be sold, then SVG would be entitled to 49% of the sale proceeds.

The consistent legal language of "the Company" and "the Group" (both capitalised) receiving revenues, combined with the emphasis on T-Rex as the wholly owned operating subsidiary, demonstrates quite clearly that PRD is the sole recipient of the 30% / 15% income stream. If SVG or WIEGL were contractually entitled to any of this revenue, that would have to be mentioned in the Company Accounts and RNS announcements. It is not.

In summary, believe what you want to believe, I have no interest in further argument with people who do not understand what they are arguing about. Unlike them, I have more constructive uses for my time.

@RR1970. You could also put the case that the Middle East & Asian entities being targeted as potential buyers in the flexible divestment plan are now in a position of weakness. Reliable industry contacts in mid-2023 were saying that PRD were in talks with NewMed of Israel, backed by cash coming from a $2 billion deal between NewMed and ADNOC (Abu Dhabi National Oil Co.). Talks for both deals were apparently terminated in October 2023, days after the Hamas attack on Israel, since any agreement would have become politically unacceptable. Currently, both NewMed and ADNOC gas production is zero, due to the ongoing crisis. I would expect NewMed to remain untouchable, but ADNOC must be looking a little bewildered by their current position.

p.s, I don't give a monkey's rectum what the market thinks, it will be industry players that determine Predator's value. The market only matters if you are a share trader, which I am not.

The average of WTI/Brent/Murban at open was $124 per Bbl. So far this month, with seven trading days remaining, WTI is +42%, Brent +46%, and Murban +110%. I repeat my view that Murban, being for physical delivery, acts as a leading indicator for other prices. Paul's estimate of 25-35% increase from February to March may be on the conservative side. It looks like the market expects that Trump's bluff, expiring around 10pm tomorrow UK time, will be called.

@Champs. Not worth bothering. Either:

* Trolls don't understand the difference between production & sales, can't do basic maths, and don't understand legal documents.

or

* They can do all the above, but are amused by kicking up trouble, or are paid to do so.

Note the RNS said "Forecast March oil sales PRICE expected to be 25 to 35% higher". [my caps]. Multiply that by the increased VOLUME that will be gained from the March work as detailed, and you are looking at a sales value perhaps 60% higher than february (20% volume increase in March x 30% price increase). Nice.

“On the 1 September 2025 the Company announced the Completion of the acquisition of Challenger Energy Group Plc's business and operations in Trinidad and Tobago with an effective date of 29 August 2025. A Production and Field Services Management Agreement with NABI Construction (Trinidad and Tobago) Limited was executed under which the Company receives 30% of gross revenues less taxes and royalties from existing production of 285 bopd and 15% of gross revenues for enhanced production until 100% recovery of NABI cost.”

Interim Financial Statements, 19 Sept 2025.

Wherever Company appears capitalised in any official communication, it is the invariable legal interpretation that this refers to Predator. There is no mention anywhere of Steeldrum Ventures or WIEGL, as there would need to be if the agreement was with them.

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 to 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 the 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 or indirect entitlement or payment under the NABI PAFSMA, and does not receive any such payment from PRD— which is why it is never mentioned in Predator’s RNS or reports.

We should expect a Trinidad update at the end of the month - late next week, or early the week after. We have not been updated on total volumes of oil produced since the RNS of 4th January. At that time, legacy production (30% revenue) was at 285 bopd, new NABI production (15% revenue) was 82 bopd. Since then, there have been several new wells on Bonasse, notably BON-20 should have been finished by now, which is the replacement well for BON-18, which ended up as two shallow wells. In passing, it should be pointed out that the 5 bopd, much mocked by the usual ignorami, was the natural flow rate to be expected from a shallow low-pressure horizon, with the RNS clearly indicating that modern pumping had yet to be applied. I would expect the pumped rate from the two wells that had penetrated a previously unknown, bonus, reservoir to be a multiple of that figure. There have also been at least two workovers completed on Goudron, one of which had an initial flow rate way above expectations.

Let's make a conservative forecast of just an additional 150 bopd of NABI production since January 4th. I expect oil to open at $120+ per Bbl on Monday, but let's assume just $100. That would give a current daily net profits rate of $12,030. Plus, of course, SC-3 is likely to be spudded within the next month. At the same $100 per Bbl, the net profit from a stabilised flow rate of 500 bopd would give an additional $33,800 per day to the bottom line. As I have shown previously, and confirmed by the ITR, to get a stabilised flow of 500 bopd, you need to have an initial flow rate of 1000 bopd. You can do the sums.

Not only does the increase in oil price have a geared effect on PRD's bottom line, but it is also accelerating the return of NABI's capital expenditure, moving an ever-increasing slice of revenue back to the $30 per Bbl royalty tier, thus doubling PRD profit per barrel.

Yet there are still the same foolish people here smirking that Trinidad oil sales would not even cover the Country Manager's salary.

A bit more on Cretaceous possibilities - Touchstone recently made almost the same announcement as PRD did in the SC-3 ITR:

"The company...said it has identified several seismically defined Cretaceous anomalies that could unlock an onshore play comparable to major offshore discoveries in Guyana and Suriname."

"Target depths range from about 7,000 feet to 13,500 feet...Touchstone said six Cretaceous exploration prospects have been identified in total, forming the basis of the proposed multi-well campaign. The company is seeking a partner to share risk and capital as it advances the drilling program, positioning the effort as a potential new phase in Trinidad’s onshore exploration landscape".

https://oilnow.gy/news/touchstone-seeks-partner-for-onshore-cretaceous-drilling-campaign-in-trinidad/

OK. Don't hold your breath.

I commented on the implications of the Murban crude price rise on X on 6th March, it might be of interest to those not familiar with the industry to expand on that. I have always viewed the Murban price as a lead indicator for other quoted prices, and today Murban closed for the weekend at $146.20, well ahead of the more well-known oil benchmarks.

WTI & Brent are futures contracts - the prices you see in March are what you have to pay now for delivery of physical oil in April. A purchaser of a WTI or Brent contract does not have to take delivery of the oil - you can if you wish sell the contract to someone else, much like any other future or option. On the other hand, Murban is a contract for physical delivery of actual oil from the DNOC terminal at Fujairah, which is the main oil terminal outside of the Strait of Hormuz. Therefore, the Murban price is what oil end users are actually paying for oil today.

WTI is mostly US domestic, Brent is international, but both represent huge market size and have considerable pricing elasticity because of the buffering effects of the sheer volume of oil represented, the lack of requirement for immediate physical delivery, and the ability to sell the contract on. The result is that changes in Murban tend to occur a few weeks in advance of changes in WTI or Brent. The conclusion of many market analysts is that things would not return to normal for months even if hostilities ceased today. Brent is now expected to top $150 by early April, and even with the most favourable scenario will stay above $80 for the rest of the year. A risk premium of at least $10 is now being added to previous oil price forecasts, suggesting that $70 per barrel will be the floor throughout 2027.

I see that some are now suggesting that up to 20% of Ras Laffan output will be out for several years. This will take some 4% of LNG and 10% of Helium off the world markets.

Bad news for the world economy and inflation, but a silver lining for those who hold producing oil & gas (and helium) assets.

Not quite sure why speculation has started about 500mm Bbls in our Trinidad licences. The SC-3 ITR mentioned the possibility of hydrocarbons at depth in the Cretaceous levels of the Cory-Moruga block. Offshore, there are a number of Cretaceous prospects in the Guyana-Suriname Basin that have been discovered, and some are 500+ MM Bbls. The Starbroek (Guyana) block is estimated to total 11 billion Bbls, with Block 58 (Suriname) not far behind. These prospects are mostly deep water turbidite systems.

Onshore there has been little Cretaceous activity to date, and even less success, with oil shows but nothing commercial. The limited seismic charts that have been made public do appear to show what are likely to be turbidite channels within the Cretaceous in Cory-Moruga. However, it will be difficult & expensive to appraise, hence PG's statement that a deep-pocketed partner would be required. Problems include the lack of detailed subsurface data, drilling depths of perhaps 3-5000m, high pressures if oil is present, complex geological structure, and the failure so far to find good reservoir quality within the onshore prospects that have been drilled.

My personal view is that making predictions about something with so many unknowns, and so far in the future, is not very helpful. We already have plenty of near-term good things to focus on without the need for a crystal ball.

Right now, the average of WTI/Brent/Murban (can't get a current Platts Dubai quote) is $115 per barrel and rising. If we can sell at that price in Trinidad, PRD would get over $81 per barrel profit. If digits are extracted and SC-3 could be drilled earlier to capture this price, at the 'most likely sustained flow rate' of 500 bopd (ITR, p.19), the well would pay for itself after just 72 days. Snowcap-4 could then be drilled at no additional cost. Of course, the ITR has suggested an upside of initial flow rate of up to 2000 bopd (ITR, p.19) for SC-3, but let's not get ahead of events.

Pt.2

In order of likely deal completion, these are:

1. Biogenic gas from just the A-Sands & Ma-Sands to supply CNG and/or LNG. So maybe two deals here, Vivo (LNG), and Afriquia Gaz (CNG). ONHYM may or may not be involved as an additional commercial party. An announcement should include the MOU-1 & MOU-3 ITR, funding for MOU-6 and drilling schedule, and any lump-sum payment. I think that PG is a little hopeful on getting all historic costs returned, maybe it will be in the form of 6 months advance gas sales. The share price will not fully reflect the value until MOU-6 has flowed successfully. This deal needs to be completed asap since it is my understanding that MOU-6 needs to have been tested successfully in order to apply for an Exploitation Concession by the deadline of August 5th. Unless ONHYM increase their current 25%, I do not see any of the licence being farmed out with these deals.

2. Biogenic gas from TGB-6 Sands. This could be an option to extend the above agreements, or a separate arrangement. It has a lot more gas, extends to 85km², and has been penetrated by MOU-1, -2, -3 and -4. The field development will cost a lot more. I assume this is why a separate ITR is being worked up for TGB-6.

3. Maybe? Farmout of the large unconventional biogenic gas around MOU-1 to a company with fracking expertise. Might be part of a larger farmout.

4. Maybe? Farmout of thermogenic gas from the deeper MOU-Fan. This was the original big MOU target until it was realised how much biogenic gas is there. It might get rolled up as part of the following, especially if Helium content is as hoped.

5. Jurassic / Triassic / Helium. Considerable investment and appraisal work required, so will require a big player to farm in. They would want operatorship and more than 50% of the licence. They would have existing customers from deals 1 & 2. Such a comprehensive deal may be further down the track, outside the originally-stated 6 months - although the current geopolitical situation may have accelerated the usually slow decision making typical of the majors. I expect that long-term value (royalties from production) will be worth a lot more than any upfront payment, which I realise is contrary to the expectations of many.

Pt 1.

It's 7 years ago today that the Guercif licence was signed, and I first invested in PRD. Paul Griffiths has been working in Morocco for 20 years, first defining Tendrara, then starting evaluation of Guercif. In the early 2010's I was told of the government interest in the Guercif Basin by a former ONAREP manager (precursor of ONHYM). I did some research, and unearthed scores of technical papers indicating a unique geological history indicating extraordinary potential for hydrocarbons. Oil was actually flowed 100 years ago. Oil & gas seeps were known at multiple surface locations, and early wells looking for oil had hit gas, which at that time was not of commercial interest. I suspected that this was a major opportunity, a view that has only been reinforced as work has progressed over the last few years and new information has come to light.

Yes, it has been frustratingly slow, not helped by a worldwide pandemic and a European war screwing up supply chains and timelines. The unconsolidated nature of the sand beds, that make for such excellent reservoirs, also make them problematic to drill & complete. I am confident that SLB well design & Italfluid flow assurance will be able to resolve these issues. However, we should remember that it has taken 10 years for Tendrara to flow commercial gas, 16 years since contract signature to first oil in Saudi, 9 years from discovery to commercial production for Leviathan, and 17 years for Anchois to produce nothing.

Matters now appear to be coming to a head in Morocco, I would not be surprised to see initial news this month, certainly next. I suspect, but of course do not know, that there are several different deals being discussed.

This Financial Times article on the near future of oil prices is worth a read, and can be accessed here free of charge:

https://www.linkedin.com/posts/robin-wigglesworth-17101722_the-oil-market-mess-is-much-worse-than-you-activity-7440099183686037504-LFrv/

The orientation & interaction of folding, faulting and salt diapirs governs the migration & trapping of hydrocarbons. Seabright, Wacky & GRH have all quoted from this paper:

https://www.scribd.com/document/692505888/Article-1#:~:text=Geologic%20structural%20map%20of%20the,It%20shows%20the%20Scale%201%3A50%2C000.

I will set a test next week...

The uptick this morning is because it looks as if Kharg Island will be closed down. Normally this ships out around 1.5M bopd of Iranian oil, but they have increased it to 3M bopd this month - 3% of the world's oil supply. This is currently the only oil getting out through the Strait, since even the Iranians are not hitting their own vessels. Not good news for anyone, unless you happen to be producing in Trinidad.

WTI - $101.46

Brent - $106.25

Murban - $114.36

Platts - n/a

I did not make these by rolling dice, please bear with me since this could be a rather long-winded explanation. It is necessary to understand that production rates from all wells decrease over time. About 80 years ago a forerunner of today's reservoir engineers named JJ Arps proposed some formulae which have been used ever since, with subsequent modifications. The most commonly applied is the Arps Hyperbolic Decline Equation. This demonstrates that production decline is not a straight line, but a hyperbolic curve, steep to begin with, then declining more gently over time, until the decline rate is very low. Prime factors affecting decline rates are reservoir initial pressure, volume & permeability, and oil viscosity. Snowcap scores well for all these parameters.

For the SC-3 ITR, SGL have suggested a conservative stabilised rate of 500bopd based on historic wells flow rates, with a high estimate of 1-2000 bopd. (pp18-19). Decline rates used are 35% first year, 20% 2nd year (p.22). To get to a rate of roughly 500bopd by end year 2, it is necessary to start with 1000bopd IP rate (1000-35%=650, 650-20%=520).

All new wells will have these declines. Workovers of existing producers will result in a reset of the decline curve – obviously if the field is substantially depleted, the reset will be from a much lower re-start rate. So, what I have is a spreadsheet of many overlapping declining production curves. The higher the rate of new or workover wells, the higher the overall production growth of the Trinidad assets. I have assumed that the rate of new or reworked wells will be one every two weeks, with average IP of 25 bopd per well, derived from the numbers given in the RNS of 07 & 22 Jan 2026 for the planned work for H1 this year. These numbers exclude future work on the Innis-Trinity and Icacos fields, which will start H2, and of course from Cory-Moruga, where SC-3 will come on stream at the start of H2, and SC-4 a couple of months later. The spreadsheet totals are those I have used in my Trinidad calculations.

I recall someone suggesting that the SC-3 forecasts were unrealistic, based on SC-1 results. It should be recalled that SC-1 suffered from waxing, and that “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.” ITR, p.22.

Eventually (after 2-5 years?) PRD will run out of new locations, and production will plateau, unless gas re-injection, CO2EOR, etc are used. That would be a good point to sell the assets – PG has stated that Trinidad is unusual in that local investors pay according to flow rates rather than reserves. I think it unlikely that multinationals will be interested in a bunch of small mature fields producing perhaps 5000bopd in total. If there is real potential for deep oil in Cory-Moruga, that may change this view.

Infrastructure.

I am in general agreement with @ChesterGreen. Most of the wells have their own collection facility in place, new wells and refurbishment of old well facilities would be covered by the NABI Agreement. For Cory-Moruga, that is PRD's responsibility, as outlined in the Placing RNS, where cash was allocated for this purpose.

Royalty percentage.

I stand by my post yesterday. I concur with those that have pointed out the agreement is clearly with the Company. Wherever Company appears capitalised, it is the invariable legal interpretation that this refers to Predator (including wholly-owned subsidiaries). There is no mention anywhere of Steeldrum Ventures, as there would need to be if the agreement was with them. May I refer you to the Interim Financial Statements, 19 Sept 2025.

For the Bonasse Agreement:

“ A Production and Field Services Management Agreement was executed with NABI Construction (Trinidad and Tobago) Limited ("NABI") whereby the Company was relieved of the burden of funding field operating costs, workover and drilling costs in lieu of receiving 30% of gross sales revenues less tax and royalty and 20% of gross sales revenues less tax and royalty for infill drilling after recovery of NABI's drilling costs.”

and for the other CEG fields:

“On the 1 September 2025 the Company announced the Completion of the acquisition of Challenger Energy Group Plc's business and operations in Trinidad and Tobago with an effective date of 29 August 2025. A Production and Field Services Management Agreement with NABI Construction (Trinidad and Tobago) Limited was executed under which the Company receives 30% of gross revenues less taxes and royalties from existing production of 285 bopd and 15% of gross revenues for enhanced production until 100% recovery of NABI cost.”

@Oldslow. Your sentiments are correct, but I think your share prices are too high - PRD revenues are in USD, shares are GBP, so you need to divide by 1.32. With an average $85 / Bbl in H1 2026, and $70 / Bbl in H2 2026, I get to $10M profit. I know that some will dispute my running rate of 1800 bopd by year end, and say that oil prices will decline more rapidly. Sticking with my numbers, with a current year p/e of 10, and 815M shares in issue, I get 9p per share at end 2026. Of course, that's just Trinidad.