Member Info for KeithOz

Off topic. In the interests of full disclosure, Al Ghazali (b.1058 d.1111), reported this as being written by Abu ‘Abd ar-Raḥmān al-Khalīl ibn Aḥmad ibn ‘Amr ibn Tammām al-Farāhīdī al-Azdī al-Yaḥmadī, also known simply as al-Farahidi' (b.718 d.786 or 791). Ironically, since this originally related to trolls, al-Farahadi', like someone else we know and love, lived in Basra. No, this isn't from AI.

There seems to be some confusion as to the purpose of MOU-6. This well is to be 900m deep, appraising the already declared discoveries of the A-Sands at 339-350m (2C resource 21.1 BCF) and the Ma & TGB sands at 815-895m (2C resource 61.9 BCF). These alone would be able to supply gas for over 20 years at the same rate as the Tendrara LNG outfit I referenced earlier today. At a conservative NPV10 of $2M per BCF (around half the implied valuation of the Tendrara Phase 1 project), this would be valued at roughly six times the current company market capitalisation.

Over the weekend, I highlighted that during the last presentation Paul suggested that substantial upgrades to the current resources are likely as a result of more recent log data analysis. I have not seen the unpublished June 2025 ITR, nor of course have I had sight of any raw data, so am unable to know if such upgrades will also apply to the reservoirs to be appraised by MOU-6. Potential upgrades could relate to one or more of reservoir thickness, net:gross, areal extent, porosity, permeability, gas pressure and gas charge.

Tendrara is close to producing commercial gas. Here's some details from today's SOU RNS that may give some indications as to what could be in PRD's proposed LNG agreement with Vivo.

"The micro-LNG Plant has been designed, is being constructed and will be operated and maintained by Italfluid Geoenergy S.r.l. ("ITF") with guarantees for plant operability and delivery of LNG to the off-taker, Afriquia Gaz, a leading energy distributor in Morocco. A binding gas sales agreement and associated funding are in place with Afriquia Gaz, with a ten-year commitment from first gas to purchase a contractual quantity of one hundred million normal cubic metres per annum. [That's 3.5 BCF per year]. This is in the context of a take or pay agreement priced in the range of $6-$8.346 per MMBtu [1MMBtu roughly equals 1MMcf, so $21-29M per year] which will be determined using an indexed formula which applies a combination of the European TTF and US Henry Hub benchmark indices. The development will use existing wells TE-6 and TE-7, and one new well to deliver the required raw gas volumes into the plant for the Phase 1 development and maintain a ten-year production plateau under the gas sales agreement. Construction of the micro-LNG plant continues at site, with revenue generating LNG sales forecast by the contractor, ITF, to commence late Q1 or Q2 2026".

https://www.londonstockexchange.com/news-article/SOU/first-commissioning-gas-at-the-tendrara/17362033

PRD are employing an additional world-class outfit, Italfluid. They were not involved in prior well testing, only the most recent attempt. They are in agreement with Paul that the prevention of gas flow is the result of formation damage. More importantly, they have been able to identify and quantify the exact cause of the problem and thus propose an overall well design and completion that will not cause formation damage, and allow gas to flow freely from the extremely fine grained and unconsolidated reservoirs.

These factors are being incorporated into MOU-6, which process Paul told us seven weeks ago was almost complete. The MOU-6 design details, rationale and supporting data will all be part of the package presented to a potential acquirer. The acquirer's technical team will perform their own due diligence in addition to any independent CPR. The involvement and endorsement of Italfluid and SLB will give them reassurance that gas can readily be flowed to surface.

Conventional logs often show suppressed gas readings due to "formation damage" (where drilling mud invades the formation and masks the true readings), while NuTech analysis is able to look beyond this damage and indicate the true scale of the gas presence. This is done by employing proprietary algorithms to synthetically generate more advanced information. This approach allows for a more detailed characterization of reservoir properties, leading to revised resource estimates.

If you have too much time on your hands, the following 111-page study may be of interest. It looks at 110 European boreholes and compares the results of historic conventional wireline logs with re-evaluation by NuTech analysis.

https://www.ebn.nl/wp-content/uploads/2022/10/MSc-Thesis-Manuel-Bussmann-Identifying-overlooked-exploration-opportunities-and-Brabant-Formation-prospectivity-2014.pdf [This loads rather slowly, and some of the English is a little dodgy]

"Hydrocarbons can still be present, even if they are not, or poorly, recorded during drilling. Reasons for this may be drilling with heavy mud weights or mud cake formation in the borehole"

"NuTech modelling results are generally best in sand-prone formations, where abundant input logs are available and predominantly gas shows are found."

"Overall Insights from the Study: NuTech excels in sand/shale-gas prone formations NuTech's enhanced resolution (10–15 cm scale) uncovered stacked net pay in grabens missed by low-resolution vintage logs". [which would typically be 1m scale].

Guercif has:

* been drilled with heavy mud weights.

* mud cake formation in the boreholes

* sand/shale formations

* gas-prone rather than oil-prone intervals

* abundant conventional wireline log data available for re-analysis.

* drill cuttings & Rockwash analysis showing huge thicknesses of thin interleaved reservoir sands that are unlikely to be properly represented on conventional logs.

When these factors are taken into account, it would seem that Guercif has an excellent chance of NuTech demonstrating the full reservoir potential. This is particularly the case since the quoted study is ten years old - since then the NuTech process has been further refined, and the borehole database on which it is based has increased by an order of magnitude.

The October presentation ran for 2½ hours, so I'm sure it was difficult to take everything in. I thought one section was of particular importance. Paul states that the now-proven formation damage has suppressed gas readings on the conventional logs. This resulted in only (!) 441 BCF of 2C resource net to Predator for MOU-1 to -4. The NuTech analysis is able to look beyond the formation damage and demonstrate the true scale of the opportunity. I have edited it slightly to improve clarity, and given the relevant timings:

48m26s - "In MOU-3, we can prove that a few psi, 20 or 25 psi, is enough to shut off the gas inflow into the well..."

49m37s - "[because of formation damage] so when these [conventional] logs were run... were interpreted time and time again,...everything that was in there was under-representing what was there...along came the NuTech logs...

50m12s - "our knowledge of the formation damage and how it's transformed our understanding of what MOU-3 and MOU-1 recovered. So we now have two separate fan systems that can be targeted in MOU-3 which we believe all are gas-bearing. We have not seen any water on the logs in these intervals and the attractive thing for us is - yes there's the proven gas , 2C gas - but there is now an upside way beyond our what initial expectations were, that we will address in the divestment process. We will update all that as part of that divestment process with an updated technical ITR/CPR designed for the incoming suitor. We will effectively put together everything we have achieved in the last five years." 51m10s.

Btw, @Jimmy, why do you consistently refer to "jurrasic" rather than "Jurassic"?

Oh dear, just finished cleaning the cr@p out of the pool before it gets too hot, now it looks like the same is needed here. Thank you for starting the refutation of the nonsense about hydrocarbon source rocks, @Teardrop, looks like I can take a week off now.

Paul, the ITRs/CPRs and ONHYM have always made it clear that there are multiple source rocks beneath the Guercif licences. Source rocks have been identified at the base of the Jurassic, and these have always been stated to be the source of the Jurassic hydrocarbon charge - both by migration upwards into the immediately overlying Domerian, and also laterally from Jurassic strata that have been juxtaposed lower due to extensive faulting. Slide 14 of the January 2025 presentation shows this well:

https://wp-predatoroilandgas-2024.s3.eu-west-2.amazonaws.com/media/2025/01/Corporate-Presentation-21-JANUARY-2025.pdf

The location in the Jurassic carbonate penetrated by MOU-5 was not gas charged, since salt mobilisation has blocked lateral and vertical migration, as can be seen in the top middle diagram on p.33 of the October 2025 presentation:

https://wp-predatoroilandgas-2024.s3.eu-west-2.amazonaws.com/media/2025/10/New-corporate-presentation-14-10-2025.pdf

That is why future evaluation of the Titanosaurus structure will be to the northeast, where salt mobilisation is less likely, so gas charge will be more likely.

With regard to multiple hydrocarbon sources beneath the Jurassic, may I refer you to this very interesting ONHYM document (loads super slow): https://hydrocarbons.onhym.com/sites/all/themes/hydrocarbure/images/pdf_onshore/Hydrocarbon%20Exploration%20Opportunities_Onshore_2023.pdf

Of particular interest is Figure 8 on p.8, which shows a truly humungous Lower Jurassic kitchen that extends beneath the northern part of the Guercif licences, and from p.14 onwards, the Guercif Basin proper is covered in detail. In particular, Figure 15 on p.15 shows source rocks and reservoirs in the Ordovician, Silurian, Carboniferous & Triassic. Although I got my geology degree many years ago, I am pretty sure that it is still the case that all these formations are older than the Jurassic.

So, Jimmy Jimmy, please provide your sources that demonstrate that your assertion is correct, and the above sources are incorrect.

Why is the ask on 3.2p, when the price is supposed to be 2p? I've been meaning to check the assertion made here last month that the PRD share price will be down to 2p because private investors sell their shares as Christmas approaches, so that they can afford a turkey. Here's the real numbers. A Santa Claus rally has occurred in 83% of the years from 1985 to present for the FTSE 100, with an average rise of 2.26% in December. This is mirrored by the AIM index, with a December rise of 1.7% on average, and a rise in 76% of the years from 2000 - 2024. The MSCI Europe Small Cap Index has gained an average of 1.8% in December this century. The S&P 500 has been positive in December 79% of the time since 1950.

It seems like the only turkey is the original poster, someone might remember who it was.

@pv72. Agreed re money. Everyone should read of CHAR's 7/12/23 RNS to understand the good & bad bits of their deal.

BAD. Upfront payment of $15 + $10 = $25M. This in no way covers Anchois prior expenditure, which I estimate to be well in excess of $100M.

BAD. Only free-carried for 10%, with a cap of $85M. If costs exceed that (very likely), they would have to find a lot of money to maintain their %age stake.

BAD. This $85M alleged free-carry would be recovered from CHAR's future revenue.

NEUTRAL. $850M for development paid by Energean. Just the 3 wells would cost $250M, I have seen total capex estimates of $1 billion plus.

Then, post-FID, either:

GOOD. $50M interest-free loan to help cover any over-run of costs.

or:

GOOD. 3 million Energean shares, but with a 3+ year lock-in.

GOOD. 7% royalty on net gas sales above a set hurdle rate. At future peak flow of 100MMcfgd at $8 per MCF, for 360 days, this is a potential gross income of $288M per annum, however, it would be less than that, since there was a base hurdle to pass before the royalty payments kick in, I don't know what that was set at.

GOOD. An increase in free-carry of development costs to $170M

BAD. All $170m free-carry is not actually free-carry at all, but is to be recovered by keeping 50% of CHAR's income, plus

VERY BAD. The allegedly free-carry balance would have interest added at SOFR (Secured Overnight Financing Rate) plus 7%, which would equate to about an 11% interest rate at present.

In summary, Energean was prepared to drop up to $935M to leave CHAR with 30% of the licence. However, they recognised that high upfront costs made this a high-risk deal, hence the payments being heavily loaded contingent upon future successful production. The fact that it took a year for a farm in agreement to be reached tells me that potential investors did not see this as an imperative investment. The market reaction suggested that it did not think this was a good deal.

From the same RNS: the development is to "potentially materially increase the resource base for a development above 1 TCF." [From current 2C of just 476 BCF]. Let's be clear about this - it is not a big project, but the requirement for substantial capex made it high risk, but even so a FTSE 250 company was prepared to drop up to $1 billion on it.

My guess is that even scaled down, capex will still be a major hurdle to getting this project off the ground. I suspect that CHAR management hope to secure funding from the newly-commercial ONHYM. Since ONHYM will have limited investment funds, CHAR may see PRD as a dangerous competitor for that money, hence the concerted anti-PRD campaign by certain individuals with known links to CHAR.

Guercif is much lower capex with a potentially larger resource, so I expect a deal weighted more heavily to front end payment to be completed by perhaps Easter next year.

No buyers?

Sorry to bring up CHAR again, but since this was also a competitive Morocco farm out process, there are relevant comparisons to be drawn. Here is a brief summary of the CHAR opportunity at the time of Energean buy in, together with equivalent numbers for Predator.

Twelve gas samples were recovered from seven horizons, but gas was not flowed to surface.

https://www.lse.co.uk/rns/CHAR/post-well-analysis-on-discovery-at-anchois-2-well-5urcujkxzagekt3.html

RNS 21st June 2023 “Societe Generale appointed as financial advisor to project – KEEN INTEREST received from a number of Moroccan, African and European banks in providing future project finance”... “now are in the final stages of a farmout partnering process on Anchois and the Lixus and Rissana licences, which has been a VERY COMPETITIVE process”. [my caps]

https://www.lse.co.uk/rns/CHAR/2022-final-results-2yyjyraql9joji6.html

During a 2023 presentation, Pouroulis claimed that forty enquiries had been received. So apart from Energean, why did they all pull out? Could it have been the cost of $85M per drill, compared to $3M for PRD? Or more likely the $850M development costs for the required 3 offshore wells, subsea infrastructure and pipeline to coast, onshore central processing facility, and then a further overland pipeline to connect with the GME?

https://www.energean.com/media/5612/morocco-country-entry-and-farm-in-to-gas-development.pdf

The same Energean release gave 2C gross resources of 18 BCM = 637 BCF, which is 476 BCF net after accounting for ONHYM's 25%, plus gross 2U of 11 BCM = net 291 BCF. This is very close to PRD's current net 2C of 441M BCF, so this was for a deal with similar scale to the current Guercif opportunity - note that the PRD resource numbers are likely to be revised sharply upwards in the forthcoming CPR.

https://wp-predatoroilandgas-2024.s3.eu-west-2.amazonaws.com/media/2025/10/New-corporate-presentation-14-10-2025.pdf page 4, point 6.

The Energean base case gave only a miserable NPV of 20%, so hardly surprising that the deal terms were not exactly generous, with the majority of the payback contingent upon actual gas production and sales. When you factor in that the capital costs for developing Guercif with three wells and short pipeline are likely to be around one tenth of the CHAR costs, you can see just how attractive this opportunity will be to industry players.

Nothing?

Some are here claiming that I have not provided any information about the viability of a farm out of the Guercif licences. Of course I have, in detail. In particular I quoted numbers from the Wood Mackenzie 2025 Oil & Gas Mergers & Acquisitions Report, showing that outside of the US shale basins, almost all deals were concluded on prospects that not only had no gas flowed to surface, but were undrilled. This means that buyers were primarily relying on just seismic data and 'nearology' - ie a block offshore Guyana was near to or in the same basin as another discovered prospect. This has always been the case, and claims to the contrary are either down to gross ignorance of industry norms, or more likely deliberate mendacity.

Report I quoted: https://www.woodmac.com/news/opinion/whats-been-happening-in-upstream-ma/

Updated two weeks ago: https://www.woodmac.com/reports/upstream-oil-and-gas-global-upstream-manda-in-brief-150350596/

Unlike the vast majority of recently concluded deals, PRD has the highly unusual competitive advantage of highly detailed information from five drilled wells, including gas pressures; gas compositions; wireline logs that have received world-class analysis; likewise drill cuttings; detailed petrographics and stratigraphy; prospect areal definition; and reservoir thicknesses, porosity, permeability and gas charge.

contd...

@dickienicholls. Don't worry about me, if I'm receiving abuse, I'm doing obviously doing something right. With regard to gonads, I have the advantage of having a Mrs Oz to keep things in good order. The poor trolls have only their overworked hands, alternating keyboard abuse of me with abuse of themselves.

@Miidas. Yes, this is a viable option. Sidetracking can be performed with a well that is already cased, and SLB, Baker-Hughes etc do this routinely, usually with a one-trip system with anchor, whipstock, and mill, which cuts a window in the casing in one run. While you are correct that a single sidetrack will cost substantially less than a new well, the issue then becomes how you would sidetrack into multiple reservoirs at different depths and pressures. While this could be done, someone would need to do a detailed cost: benefit analysis compared to a completely new well.

Any potential acquirer of the Guercif assets will have the technical competence to assess the existing data, and would be examining these options as part of their proposed field development plan. What some here are conveniently forgetting is that only shallow, onshore wells are required. Side track or new, this is cheap work compared to most O & G drilling. Analysis of the wireline logs by NuTech, and cuttings by Rockwash, have indicated exactly what needs to be done, and now we are at the stage of deciding what is the most cost-effective solution.

I should perhaps point out that both NuTech and Rockwash have comparative data on literally thousands of wells, not just the five MOU's, and use machine learning / AI to support their detailed interpretations.

There are still prunes on here responding negatively to my suggestion that correct geology takes millions of years, but getting the engineering right is a matter of months. They should read the small print on all offerings of financial products: "Past performance is not an indication of future performance".

We have two factors at Guercif that are simultaneously both a fantastic geological opportunity and a pain in the engineering backside.

These are 1). highly friable and unconsolidated gas reservoirs that allow storage and flow of high volumes of gas, and 2). high gas pressure. Both obviously opportunities. However, the high gas pressure resulted in drilling with high pressure mud to avoid the risk of a blowout. As always, it is usual to err on the side of caution. This caution resulted in the use of a higher mud weight than was actually needed, causing the drilling mud to be forced deep into the loose reservoir sands, making deep enough perforation and gas flow to surface very difficult.

Yes, there were a couple of attempts that did not work, but being engineering problems each took a few months to try a new approach. PRD management have now sought input from the top consulting firms, and agreed that the drilling mud pressure would only need to be reduced by 8% to achieve the right result - suppression of blowout without excess drilling mud migration. So, on to the next, and hopefully final solution - MOU-6 is being designed from scratch with input from external expertise, using the substantial data that has been generated from drilling all the Guercif wells. We will learn of the design when it is no longer commercially sensitive to reveal details. I strongly suspect it will be designed not to involve the need for perforation.

Several possibilities that do not involve perforation most common in unconsolidated gas sands: * Slotted liner (cut slots in pipe)-

* Stand-alone screens (wire-wrapped, premium mesh)

* Open-hole gravel pack

* Cased-hole gravel pack (with internal screen + slotted casing)

* Pre-packed screens (resin-coated gravel around screen)

These methods are not “work-arounds” for avoiding perforation – they are often the preferred completion technique for high-deliverability gas reservoirs. Once installed across a gas zone, the well behaves exactly like a perforated completion from a flow-measurement standpoint. Flow rates are measured exactly the same way as in perforated wells, but if there are multiple reservoirs at different pressures, then downhole flowmeters run on wireline/coiled tubing can be used, blocking off all but one section at a time. These completions are very common in gas wells where sand production must be controlled, or very high rates are expected - exactly as we have at Guercif.

It's an illusion. There was a UT (uncrossing trade) at 2.7p just after market close yesterday. lse has taken that as yesterday's share price, then taken today's mid-price of 2.8p as a price rise. In reality the price has been flat all this week, with a consistent spread of 2.7 - 2.9p.

I now fully expect to get three trolls appearing in the space of five minutes claiming that I am wrong, but without explaining why. At least one of them will be unable to spell correctly, or express themselves using normal grammar.

Great analogy. I have said several times, if the geology is wrong, it's going to take tens of millions of years to put it right, whereas engineering problems can be fixed in a matter of months. I bought into PRD for the geological potential, not their engineering skill.

There are many T&T oilfields in private hands that have received little investment and are now only producing marginal amounts of oil. Unlike almost anywhere else, oilfields change hands valued on a daily production rate, rather than $ value per in-ground barrel. This means you can buy high reserves but low production fields cheaply, restore them to decent production rates, then sell for a tidy profit. Currently PRD has five T&T oilfields and is looking for more. How are they intending to go about the crucial step of increasing daily production?

*Workovers – Old wells are unclogged and cleaned up using a lightweight drilling rig. This is fast and cheap.

*Infill drilling – Has started on Bonasse and will be extended to other fields. A rule of thumb is that a nodding donkey can optimally drain 100,000m² (25 acres), so used where there are gaps between existing bores.

*De-waxing – Much T&T oil is relatively viscous and contains paraffins. As the oil is brought to the surface, it cools and depressurises, the paraffin crystallises, and clumps of crystals form a waxy deposit that clogs up the wellbores and piping. This can be overcome by injecting a chemical that releases nitrogen and heat. The heat liquifies the wax, and the nitrogen helps lift the oil to surface.

*CO2EOR. T&T ammonia companies produce over 300 MMcf of CO2 per day as a by-product, currently released as waste into the atmosphere. Injecting CO2 into an oil reservoir reduces the oil viscosity and increases the reservoir pressure, thus increasing recoverability. PRD has developed an injection process which has been tested on the Innis-Trinity field (now owned by PRD). Paul has mentioned several times recently that this process could be rolled out to our other fields. Depending upon oil viscosity, 1–6 mcf of CO2 is required per barrel. Paul has presented the I-T trial results to MEEI, and he is a member of the T&T Government committee on enhanced oil production.

Pp 17 - 25 of the July 2020 presentation give some interesting estimates of T&T CO2EOR profitability, based on $41 per bbl WTI ($58.50 today). Since both price and operating costs have changed dramatically, and the I-T field is now in PRD hands, I am reluctant publicly to provide an updated forecast, but incremental production from selected wells in the five suitable horizons of just I-T should produce a profit in excess of today's market capitalisation. I will try to obtain some up-to-date numbers in order to firm up my assumptions, but don't hold your breath.

https://wp-predatoroilandgas-2024.s3.eu-west-2.amazonaws.com/media/2024/09/Corporate-Presentation-29-July-2020_FINAL-DRAFT-1.pdf

P.7 of 2020 Annual Report gives for the AT-12 well a pressure increase of 87psi, incremental production of 21bopd, 69% above forecast.

https://wp-predatoroilandgas-2024.s3.eu-west-2.amazonaws.com/media/2024/09/Webinar-Presentation-website-Version-28092021-Corrections-15.40pm.pdf

Just because gas has not been flowed to surface does not mean it's not there. XRF & magnetic susceptibility are just two parameters that a potential acquiror will be looking at closely - note that such data is only available if wells have actually been drilled. Unless the Guercif data package was compelling, Paul Griffiths would not be making it available for industry parties to evaluate.

"Elemental data derived from XRF analysis provide us with the fundamental downhole profiles we need to interpret key changes in depositional environment, sediment provenance and organic matter distribution. With data from every sample, an extremely detailed understanding of these changes can be drawn, whether they are abrupt or gradational. Well-to-well correlations are routinely constructed and combined with wireline logs to gain a deeper perception of both local and regional variation".

"By measuring the extent to which a material will be magnetised in relation to an applied magnetic field (magnetic susceptibility), we are able to add another independently acquired layer of data to the RockSCREEN™ package. With implications for permeability, porosity and lithology, magnetic susceptibility data is a tool used to evaluate detailed reservoir-scale variations in mineralogy and flow characteristics".

Thanks, Taff for linking all these information sources. It's possible that many PRD investors may not know that all the drill cuttings from the Guercif wells are sent to Rockwash Geodata in North Wales. They use proprietary multi-factor analysis of the actual rock recovered from the borehole. This can then be correlated with the high-accuracy NuTech log analysis to provide a detailed picture of all the relevant reservoir characteristics - porosity, permeability, organic content, hydrocarbon charge, etc.

The application of hard science to produce vast amounts of valuable data is far more comprehensive than certain posters on here seem to assume.

https://www.rockwash.co.uk/services/rockscreen

https://www.nutechenergy.com/integrated-solutions/petrophysical-analysis/