Member Info for KeithOz

Good morning, genuine Predators,

Does anyone else feel really excited about the potentially high reward period we are entering?

Success at either MOU-6 or SC-3 would be transformative for the company. Both wells have been expertly planned, and are being drilled into known geology. SC-3 is in fact drilling a 'Known Accumulation' that has previously flowed, even with old-fashioned drilling technology, in several nearby historic wells. MOU-6 is only 600m away from MOU-3, so the exact geology - strata to be penetrated, depth of reservoirs, gas pressures of the reservoirs (note the plural) - is already known. SLB, who were involved in the testing of MOU-3 thus know the geology, have overseen the well design. Both wells can de-risk very large prospects, and are being drilled at a time of sustained high oil & gas prices - both will benefit from exceptionally benign tax treatment in Trinidad & Morocco.

The market will surely start to price in these exceptional opportunities.

It's available through the Telegram group, another reason you should join.

Fracking and shale gas extraction is currently in legal limbo in Morocco. Here's an interesting vacancy being advertised by ONHYM - "Chef de Département Non Conventionnel". They are clearly looking to start work on onshore shale gas - now, who has a few TCF of that stuff?

Here's the job description: https://www.onhym.com/sites/default/files/fiche%20poste%20gestion/fiche_de_poste_chef_departement_non_conventionnel_21-04-2026.pdf

Hi Joblot, sorry that you are currently unable to access the Telegram group - keep trying.

PRD has a contractual right to enter the 2nd Extension Period; if they wish to do so ONHYM does not have a legal right to stop them. However, PRD will have to agree to a work programme that must be completed within that period - it is my understanding that this will most likely be to complete 2 - 400km² of 3D seismic and drill one borehole (MOU-7) into either the Jurassic or Triassic.

PRD are intending to do this either in partnership with a farminee, or else (preferably) fully paid for by a complete or partial buyer of the licence. Funds raised in the recent placing have been allocated for EIA for both the seismic and MOU-7, so that they are ready to go in November.

The model ONHYM Petroleum Agreement should be here:

https://hydrocarbons.onhym.com/sites/all/themes/hydrocarbure/images/node/Petroleum_Agreement_Model_2021.pdf

but it is v-e-r-y slow to load, you may have a better connection from the UK

you will of course need to have telegram installed on your device first!

https://x.com/kquick20704342/status/2057026019215937649

or direct:

*************+aps7dv1nm802njg0

Here's a thought. PRD seem very confident about the Morocco licence extension: "Commission an Environmental Impact Assessment for potential 3D seismic and a well to the Triassic TAGI in 2027". There must already be agreement with ONHYM to go ahead with this. I am now wondering if "whilst third party technical and legal due diligence is being completed" translates to "waiting for the King to sign the ONHYM commercial entity document."

Dear Gudin/Troll. Learn to read. The $95K quoted in the RNS was just from the NABI operation in April alone. In my posts I clearly stated that the $1.8M free cash flow would be produced from the legacy oil flows from end February to end May. This amount from Nabi will be added to that. How about foing back under the clippety-clappety bridge?

So what would you do?

* Ireland is now back on the front burner - do you ignore it, or do you polish up the years-old data ready for auction during a time of geopolitical turmoil and high gas prices ?

* You have the opportunity during a period of high oil prices to maximise the returns on a drill due to start next month (SC-3). Would you not bother?

* You have also accumulated recent data showing that the older Cory-Moruga drills are viable - so do you hand them over to NABI, or keep 100% for yourself?

* You see the opportunity to capitalise on your CO2EOR experience - are you going to ignore it or apply it?

* The partnering process in Morocco is proving slower than hoped for - do you sit and wait and risk licence expiry, or do you hoist two fingers and go ahead yourself, thus both forcing the hand of the acquiror/partner and raising the price?

All seem like good investments to me.

So Ireland is a go. That alone is worth the current market cap.

Guercif is proceeding to CNG with just PRD running things - this will add value to a future farm out.

Good to see an acceleration and augmentation of the programme in Trinidad, with $100/Bbl oil likely to continue for the rest of the year.

Conclusion - this is probably potentially the most accretive raise that PRD have ever done.

Tough luck, I'm still here. WTI back above $100 today. Based on NY daily closing prices, that gives an average of $91.05 for March, $97.87 for April, and $99.87 so far this month. Based on Trinidad legacy flows of 300 bopd, with a (guess) cost of $30/Bbl, that gives over $1.8M free cash flow over the last 3 months, probably over $2M so far this year. Should the decision be made to go it alone on MOU-6, there will be enough to cover it by the planned spud date. Just sayin'.

There is likely to be continued good cash flow from Trinidad whatever happens - see the interesting FT article on oil price (free to read via link below). In summary, prices are being kept artificially low due to increased exports from US, and decreased imports from China. However, this is not due to increased production in US, nor to decreased usage by China. Both countries are achieving this by running down their inventories. If inventories reach critical lows before Hormuz reopens, then prices will spike dramatically. If Hormuz reopens first, prices will stay elevated at current levels while everybody rebuilds their inventories.

https://www.ft.com/content/ae621e63-0be6-4818-9bec-eb1188737a1a#:~:text=Why%20are%20oil%20prices%20not,%C2%A9%20Reuters

Two issues have been raised today as "facts".

Problem #1 – not enough oil storage at SC-3, so PRD expect maximum flow will only be 250 bopd.

Securing adequate oil storage was explicitly cited as the key reason SC-3 drilling was deferred from 2025 to 2026. PRD have not disclosed what storage they plan to install at SC-3, but have said that oil will be trucked 1.5km to the Heritage collection point.

In the RNS of 20/Jan/2026, £500,000 ($675,000) of the placement proceeds was allocated for SC-3 "Separator, tanks, water treatment, vacuum truck."

Oil storage tanks of 1000 barrels capacity, built to the required API-650 or API-12F standards, cost new from $45K to $75K in Trinidad, depending upon supplier - such as Supply Solutions in Arima, or PSS in Frederick Settlement. Serviceable 2nd hand tanks cost less than half this amount. I'm sure if PRD felt the need for several 1000-barrel tanks, that would be within the allocated budget. Both PRD and Scorpion have consistently mentioned the potential for initial flow rates of 1500 bopd from the Herrera #1.

Problem #2 – missed payments to CEG are due to missed production targets.

These future payments are NOT contingent upon meeting production targets; they are no longer considered to be due following the takeover of CEG. There is no suggestion anywhere that Trinidad production targets will be missed – this is deliberate fabrication.

RNS 18 Feb 2025 “deferred UNCONDITIONAL consideration payments of $750,000, payable in cash, in three instalments of $250,000, on each of 31 December 2025, 2026, and 2027 “

Modified by RNS 1st Sept 2025 “Challenger will be paid a further US$0.5 million in deferred consideration on 31 August 2026, US$0.25 million on 31 December 2026; and US$0.25 million on 31 December 2027.”

Unconditional means just that - payments are not conditional upon anything such as production levels.

Anymore "facts" that I can debunk for you?

I have reviewed the Snowcap-3 economic model in the recent ITR, with the intention of seeing the effect on first-year profits of the increased oil price. I have now realised that the model presented is not based on initial production rates as suggested elsewhere in the document, but based on an assumed first year total flow of 65,800 Bbl. This number is derived from historical data from the adjoining Moruga West field, not on likely flow rate of our own well. Using the given decline rate of 35% over the year, and assuming a standard hyperbolic decline curve, I have back-calculated this to an initial flow rate of just 224 bopd. Thus the economic model presented is a substantial undervaluation compared to the initial flow rate range of 400 – 1500 bopd suggested elsewhere in the report just for the Herrera #1.

I have put together a spreadsheet giving net profit in the first year assuming four different initial flow rates, and three oil prices. All use the same assumptions:

* 35% hyperbolic decline over Year 1, as per ITR.

* $32.60 profit / bbl @ $60, as per ITR, which is net of royalties and fees per barrel.

* 12.5% royalty deducted from sale price above $60, as per ITR.

* 18% royalty deducted from sale price if flow is over 500 bopd, as per AR.

Net profit for 224 bopd initial flow rate:

@ $60 - $2.15M, @ $70 – $2.72M, @ $80 - $3.3M.

Net profit for 400 bopd initial flow rate:

@ $60 - $3.82M, @ $70 - $4.84M, @ $80 - $5.86M.

Net profit for 1000 bopd initial flow rate:

@60 - $9.54M, @70 - $ 11.94, @80 - $14.33M.

Net profit for 1500 bopd initial flow rate:

@60 - $14.3M, @$70 - $17.9M, @$80 - $21.5M.

fyi, the average price for WTI in March was $91.05, April was $97.87, both based on NY daily closing prices.

This is a theoretical calculation to demonstrate the effects on profitability of changes in flow rates and oil prices, it is not any kind of forecast. I am not going to attempt to forecast future oil prices or SC-3 initial flow rates, you can do that for yourselves to estimate the likely range of SC-3 first year profits.

Have a pleasant long weekend.

Further to whom we are dealing with... we were discussing this elsewhere, it was my recollection that it was an indigenous company. Thanks to Chris for locating this quote for me on p.75 of yesterday's Annual Report:

"Additionally, the Company is progressing a Heads of Agreement with an indigenous Moroccan company to acquire a non-controlling interest in Predator Gas Ventures Limited to facilitate a potential pilot CNG gas development and a potential decision to enter the Second Extension Period of the Guercif Petroleum Agreement at the end of 2026."

The question remains - was this the thinking at Year End 2025, or is it current thinking?

@Rambo. I don't have your address for billing you for my consultancy fees, so I guess a short answer to your many questions will have to do. I am neither the Delphic Oracle nor Mystic Meg, so I don't know what Paul is intending to do. It is uncertain from the Annual Report what was the thinking at year-end 2025, and what is the intention now. Taken at face value, PG seems focused on getting a CNG/LNG operation up and running at no cost to PRD.

It is uncertain to me where the upfront payment is coming from. Is it forward sales of gas? We have (current?) MoUs in place with Afriquia Gaz & Vivo Energy, both have previously agreed terms with other companies involving prepayment or loans. Since they are solely energy distributors, I would not expect them to want to be involved with exploration, appraisal, and development.

Is it in return for a stake in the Guercif licences? Such a partner would need geologists & petro engineers, hence my suggestion of ONHYM or Managem locally, obviously a greater choice elsewhere. At this stage it does not at all look like a complete sale, rather someone taking a minority stake now in return for sharing field development costs. Such a deal may have an additional option for the partner to increase the stake and take over operatorship conditional on certain milestones - such as MOU-6 flowing at a pre-agreed rate.

As for valuation, I would prefer a small discount on Proven Reserves in 12 - 18 months' time, rather than a large discount on Prospective/Contingent Resources today. Yes, there is risk with that route, but the upside is very substantial. I am not here for beer money, even if I did drink beer, which I don't.

apparently someone doesn't like managem as a potential partner because of the price they paid for the bulk of sound's assets. i don't consider them a good fit as a partner, merely mentioned them because they would be interested in guercif. in essence, managem put sound out of their misery. sound had a long history of ****ing people off by declaring wildly inflated expectations of profitability based on apparently dodgy data - including investors, creditors, potential lenders, the moroccan tax ministry, and quite possibly the king. some have even suggested criminal activity by previous management, i do not have details, but am aware of a great deal of criticism. perhaps some here were investors there at the time and may wish to comment.

sound's 2023 annual report and audit indicated 'material uncertainty for the continuation of the business'. they had £33m in debt, and no income to pay the interest; nor repay the capital which was shortly to become due. market cap was around £15m, with a loss of £7.2m in 2023. there was a big question mark over their book valuation of tendrara assets, resulting in an impairment of £122m (!) in the 2024 accounts. an attempt to raise additional debt from that internationally-respected entity attijariwafa bank (that's my attempt at humour) to bridge them to tendrara operation resulted in an offer of a loan on what many would consider credit-shark terms, so did not go ahead.

on the verge of bankruptcy, managem paid them upfront cash of $12m, plus a further $33m for carry. sound retained 20% of tendrara, but still has a large debt overhang.

to suggest that the sound deal is a reasonable comparator for prd is nonsense.

There is a range of possible partners. Just for a GSA with financing of a CNG/LNG project, with or without financing of MOU-6, it could be Afriquiq Gaz, owned by the PM, or Vivo Energy, Shell distributor owned by the massive Vitol Group. For a licence partner sharing appraisal & production, it could either be the newly commercial ONHYM, or else Managem, majority owned by Al Mada, itself owned by the Moroccan Royal family. Managem bailed out Sound, and are now operators of Tendrara. Pick whatever combination you think works best.

Error, para 2, line 2. 'TGB-6 remains same' should read 'TGB-2 remains same'.

Within the Annual Report is some volumetric data for the gas within the Moulouya structure, derived from boreholes MOU-1 to MOU-4. Some of the reservoir horizons have been renamed, following correlation of material recovered from drilling of the four wells with the orientation of geological structures known from seismic. What is immediately noticeable is that the potential for biogenic gas from what is now called TGB-6 is much greater than was previously realised, hence the additional new ITR for this horizon.

Nomenclature, from top to bottom: * A-Sands – remains same. * Ma-Sands & TGB-6 - now renamed TGB-6 (TGB = Taza-Guercif Basin). * TGB-4 – remains same. * TGB-6 remains same. * Moulouya Fan – now renamed TGB-1.

All are turbidites, with TGB-1 containing layers of volcaniclastic material (sediment from nearby eroded volcano). This may have given rise to the Helium found in MOU-3, as opposed to that found in MOU-5 which is likely to come from deep magmatic intrusions.

No new information is given regarding shale gas around MOU-1, only repetition of the calculation that up to 7 TCF could be generated in situ.

These are the areas, well occurrences, and P50 volumes for the above formations:

A-Sands, 6km², MOU-3 & ?MOU-4, 21 BCF.

TGB-4, 68.5km², MOU-3, 269 BCF.

TGB-2, ?area, MOU-1 & MOU-3, 16 BCF.

TGB-1, 40+km², MOU-1, -2, -3, & -4, 74 BCF

TGB-6 is under review. It is already known that there is a distinct structural trap penetrated by MOU-3, but also a less well-defined and much larger stratigraphic trap that will be confirmed by MOU-6. There are three reasons for moving the MOU-6 location -definition of the stratigraphic trap, thicker sediments than at MOU-3, and enabling use of both MOU-6 and MOU-3 as production wells – two wells are needed to ensure production continuity. NB – the 3D well location diagram on p.46 incorrectly labels MOU-6 as MOU-5.

P.46 of the AR also gives a very confusing chart with 27 bars, indicating three different TGB-6 areas within the MOU area, each with P10, P50 & P90 estimates, and for each of these, three different scenarios for the extent of the stratigraphic trap, all shown on a logarithmic scale. I have rasterised the scale to come up with comprehensible numbers, my calculations are +/- 10% because of the small scale of the chart. The summary of my summary (!) for TGB-6 horizons is P90 – 350 BCF, P50 – 937 BCF, P10 1835 BCF.

I have added these TGB-6 numbers to the others above. Overall P50 is 1.317 TCF, not including any shale gas. My guestimate of P10 is 2.5 TCF, again no shale gas. To convert this to Reserves, worth $2Bn NPV10 per TCF, it will be necessary to drill MOU-6 ($3M), and sidetrack & frack MOU-3 (?$1-2M). Sidetracking MOU-2 (?$2M) and sidetracking and fracking MOU-4 (?$1-2M) would likely add to the above volumes.

Seems like a viable investment to me. Time for coffee & paracetamol.

Right, I've read all 151 pages, and much of it twice. There is little in here unexpected, I suspect the negative market reaction is because a number of folks were expecting a massive instant payout, as hyped to laughable levels by certain posters. According to the official stock exchange data, only 4.5M shares. have been traded, which puts this morning's drop into perspective. imho, what will move the share price, in likely order are:

1/ In the next month. The announcement of the Moroccan partner and terms. My money is on ONHYM wanting to increase their share of the licence, and funding not only MOU-6, but also the "small-scale frac jobs" on MOU-3 & -4, and side-tracking MOU-2.

2/ July. Snowcap-3. Even using conservative metrics, PRD's current market cap does not reflect the income from this one well.

3/ August. MOU-6 results. Not only will this be enough to run the CNG project with associated cashflows, but will also de-risk the existing clogged-up wells, and trigger the programme to un-clog them. I don't expect the unclogging to start until 2027.

btw, did anyone else notice that none other than our Trinidad country manager Geoffrey Leid, owns the non-PRD 49% share of Steeldrum?

That's a statement, not a question. This is what we all want to know, so this is my summary of today's info.

* No mention of a licence sale, part sale, or farmout.

* Continued reference to a CNG development & partner negotiations structured as we have already been informed.

* (new) The CNG operation will be sourced from what used to be called the Ma Sands & TGB-6 Sands, now lumped together and referred to as the TGB-6 Sands. Areal extent as before, no indication of gas volumes or revisions due to new ITR.

* Dependent upon MOU-6 results, and presumably using the funding by the CNG partner, the existing wells will be re-worked. This includes side-tracking MOU-2, and 'small frack jobs' to MOU-3 and MOU-4.

* MOU-5 is being considered for side tracking to both potential Jurassic reservoirs up dip, and to the Triassic.

My provisional conclusion: Focus is on getting the CNG project up and running. Up front finance from that will be used to get the existing MOU-2 to MOU-5 wells to produce gas. There is no mention of sale of the licence in all or part, nor of commercial discussions about either the shale gas (MOU-1 is not mentioned) or of helium. I therefore assume the intention is to do another year or so of appraisal work in order to increase the final sale value - such a sale would imho difficult to be achieve in 2026, but would be at a greater value than if forced through today.