Member Info for KeithOz

I can't be bothered writing anything new on timing to counter the nonsense posted here, so here's a cut & paste.

The Lonny tweet on 8th August showed surface testing of equipment - it also showed that the CT injector was not yet connected to the Christmas tree, meaning that no subsurface work could have begun at that time.

Once connection was completed, the borehole would need to be checked for debris, and if necessary, cleaned out. The bore would then be re-logged to ensure that the horizons to be perforated were in exact depth alignment. This needs to be done since the coefficients of elasticity and thermal expansion of drill pipe and coiled tubing are different, so you will see different depth readings with each.

Only then can you start perforation and testing. Pressure, nozzle size and abrasive content will all need to be optimised, this may require several CT runs for the first couple of horizons. Unlike in Phase 1, which took 10 days for 4 horizons across 2 boreholes, pressure and flow testing will be carried out, assuming perforation is successful. This will most likely be performed using intermittent flow testing. An initial pressure reading is taken, and the horizon under test will be allowed to flow for a period of perhaps 4-6 hours, with any declines in pressure and flow rates recorded. The well is then shut in for a few hours, opened again and the tests repeated. The well is then shut in again, and opened once more for a third set of measurements. These data sets can then be used to project both long term flow rates and the volume of connected reservoir.

It was quite clear in the RNS of 7th August that results would be reported at the end of MOU-3 testing, and no intermediate information would be released. "A further operations update will follow once the MOU-3 rigless testing programme is completed. The Company does not intend to provide an operations schedule for testing at present as plans remain flexible and may be modified depending on initial test results and operational efficiencies." I would not be at all surprised, in a success case, if additional horizons were also tested, including the high-pressure 11m shallow sands currently behind two layers of casing.

My guess for the estimate of 'Extensive operations at MOU-3 are anticipated to last for at least five weeks' is based on two days for perforation & testing of each interval, plus a few days for preparatory work.

Now, @ Beancounting, would you kindly enlighten this bulletin board with your detailed explanation as to why you think this should all have been finished by now.

@MEM and I think others had asked my opinion on MOU-2. I have an opinion, but of course it may not coincide with reality. Can it be easily re-entered and taken to originally planned TD? Yes, no doubt.

MOU-1 was drilled with Ultradrill drilling mud, but this caused some difficulties with the plastic clay formations that were encountered. Because of this, the decision was taken to drill MOU-2 with a different mud, PureBore Silicate. This worked very well until the drill hit the infamous debris slump. The slump consisted of unexpected material derived from eroded volcanic products - think a mix of lava fragments, volcanic sand, maybe some pumice, plus fine-grained volcanic ash, all unconsolidated and rich in potassium feldspar minerals. This reacted with the PureBore Silicate mud to form a thick, sticky mess that prevented the drill bit from gaining traction, hence the well being suspended. You can see from the Figure 5 on p.17 of the ITR, that this same debris slump was encountered by both MOU-3 & -4, and successfully penetrated. This was achieved after lab studies recommended reverting to Ultradrill. So it shouldn't be more than a few days' work to re-enter and drill a further 200m or so.

Will they do this imminently? If the drill rig and sufficient spare cash was available most would say yes. However, I don't see it as a priority. MOU-2 will be part of the CNG operation, because of its geographical location in close proximity to the other related wells, and its exploitation of the same geological strata. I expect that the current testing programme will reveal more gas than can be used by industry at present, or even in the near future, i.e. 50+mmcfgd. So why spend time & money proving up even more CNG gas at this stage? Better to get the CNG operation up and running and producing a positive cash flow, then think about proving up more before selling the whole lot. Meanwhile, use the money to evaluate the parallel opportunity of G2P - this will also require more money in the future for additional appraisal, my preference would be to finance it from CNG profits.

Again, just my thoughts, I'm sure others will have different opinions.

I have refrained from making comparisons between PRD and other companies, but since the subject has been raised, I think it only fair to add some balance to that comment.

PRD does indeed have a different approach to onshore drilling than does CHAR. PRD has spent several years carefully evaluating their licence area, and has successfully drilled 3 holes into high-value prospects, with a 4th (MOU-2) requiring just a further 200m through a slump, and a 5th (MOU-5) targeting a prospect with a P50 of 8 TCF, 6 TCF net to PRD. All bores have used standard drilling techniques, overweight drilling mud has been necessitated in anticipation (proven correct) that overpressured gas would be encountered.

In contrast, despite the availability of 3D seismic, the first of CHAR's bores did not encounter gas, while the 2nd has rather oddly been declared a discovery based on "an approximate 70m gross interval of primary interest has been identified containing elevated resistivities coincident with elevated mud gas readings, indicating potential gas pays," (RNS 28 May 2024).

Contrast this statement with that of PRD re MOU-3: "Mud weight was gradually increased to 1.25 S.G., above that required to balance hydrostatic pressure, to reduce the inflow of gas into the well. This gas zone is therefore significantly overpressured (122 psi overpressured) and likely to be supported by connectivity to gas volume to provide pressure support." (RNS 13 June 2023). Followed by "Multiple zones of interest from 339 to 1435 metres TVD MD...Ma Sand gas trap potentially could cover 58km²". (RNS 27 June 2023)

The comparison would not be complete without looking at future drilling plans. Last week saw the spud of Anchois-3. Anchois-1 was drilled way back in March 2009, Anchois-2 in January 2022 - neither have been flow tested, despite various experts here claiming that PRD have made a fatal error in not flow testing their wells until now. It's worth taking a look at the description & diagram in the CHAR RNS of 20th August 2024 - this is one complicated operation, I would not know where to start in calculating the cost, they are targeting several horizons totalling just under 1 TCF. Interestingly, in the same RNS, is stated " Anchois-3 drilling and flow testing operations are expected to take approximately two months, with Chariot expected to be fully carried for the anticipated costs of the drilling campaign." Please note the use of "expected" and "anticipated". In reality, CHAR is only carried up to a net $78M for this operation - if costs exceed those "anticipated / expected" or if anything goes wrong, CHAR is liable for their share of any excess (CHAR RNS 07 September 2023). Oh, did I mention that CHAR are only left with a 30% share, giving them around 300BCF?

PRD's MOU-5 will cost around $3M, minus about $1M for gear already in stock. The prospect has a P50 of 8 TCF, and with PRD retaining their full field equity, that gives 6 TCF net to PRD.

@Jimmy. With the proviso that my qualifications are in geology, and not linguistics analysis 😁, I assume that this is the order of events:

1. Finish rigless testing of MOU-3

2. Rigless testing of MOU-4, starting at the bottom to evaluate the all-important Jurassic carbonate interval.

3. MOU-4 gas will also be analysed for Helium, in the same way that Helium was detected in MOU-3.

4. MOU-5 will be drilled.

5. Helium presence will be evaluated in MOU-5 at the same time as hydrocarbons, utilising the onsite PVT lab that comes with the SV-101. This will provide more comprehensive data than the simple sampling of MOU-3 & -4.

6. Catain Kirk will do the Helium MSSI from the Enterprise, now converted by Scotty to run on Guercif methane rather than di-lithium crystals.

@MEM - I suspect the overall shape of the prospect is now believed to be different from that illustrated in Fig 22, p.38 of the ITR - in particular the ITR does not show it extending to the East of the Moulouya River. I would think that a 30m net pay interval in a near 300m structure is very much on the low side - I would expect a carbonate reef to be largely reservoir, albeit with significant variations in porosity & permeability. These local variations (both vertical & horizontal) would depend upon periods of subaerial exposure and weathering, presence of dolomitisation, and fracturing as a result of the two periods of inversion (uplift/compression/tension). To get to a P50 of 8 TCF (only 6 net to PRD), most of the prospect as currently defined would need to be gas-charged.

@Nevermined & MEM: HSSI - my reading of the last RNS was that HSSI was to be run in the near future, and was to appraise the area for Helium. This contrasts with the clear statement in the same RNS that the new MOU-5 position is already defined and approved. My partially cryptic comments earlier today were relating to a different type of satellite imagery, RSDD-H, which is specifically for hydrocarbons. This is already in existence for the Guercif area, and as mentioned by @Teardrop yesterday, has been reviewed favourably by the late Adnan Samarrai, the renowned discoverer of giant fields. You can find information about this data generation here:

https://www.scotforth.com/index.php/exploration-methodology

It is well recognised that the combination of seismjc data and RSDD-H can result in greatly optimised drill positioning.

Ok, Colon, an additional dot to join up to see the picture. Yes, a big change that would only be made for a very good reason - that being that the additional data and analysis has indicated a better point to drill the prospect. Since this involves time & money in *evaluating *agreeing access with local owners *getting ONHYM buy-in * gaining a new Environmental Impact Assessment approved, it would not be done lightly.

If the drill had arrived at the time originally planned, it would be before everything was ready at the new site. I recall

certain person saying several times that they hoped that PRD would get the drill last. Now why could that be, and how could they know that a delay was actually favourable?

Until just under a month ago, we thought we had all the info we needed about the Jurassic carbonate prospect, and where it was to be drilled.

RNS 13th July 2023:

🦖 "As previously announced the culmination of the Jurassic carbonate target lies 2.6 kilometres to the southeast of the MOU-4 well location and significantly higher than at the MOU-4 well location".

ITR 24th January 2024:

🦖 p.29. "A more optimistic 50m pay interval is used to generate an upside high-case", and 177km² prospect area.

🦖 p.46. "The Jurassic prospects noted in this report are deemed to represent Prospective Resources with greater uncertainty regarding charge and reservoir quality that will be resolved by drilling at least one additional well (“MOU-5”) in a preferentially located region of the mapped prospect where reservoir, charge and trap potential are likely to be optimal."

🦖 p.38. "Scorpion Geoscience understands PRD intend to drill a potential MOU-5 well to test the full potential of the Jurassic Carbonate play contingent on the findings of scheduled Phase 1 and Phase 2 testing in one of the preferential optional drilling locations identified in Figure 22". [Fig 22 shows one location, MOU-SE, as being 2.6km ESE of MOU-4, along seismic line 03-ML-06].

🦖 p.42 P50 (50% chance of gross gas initially in place) 426.87 BCF; 75% = 320 BCF of this is net to PRD.

2U (50% chance of gross unrisked recoverable) 186.23BCF; 75% = 140 BCF of this is net to PRD.

Then in the last couple of months, several things had changed:

💥Prospect area increased to 187km² (RNS 6th June).

💥289M maximum vertical extent (RNS 6th June).

💥Prospect resource P50 was 5,916 BCF net to PRD, previously 320 BCF net to PRD, an 18.5-fold increase (RNS 8th August).

💥"The new [MOU-5] location is also located in an area just east of the Moulouya River floodplain", with a deviated borehole targeting a further 277m southeast. That is some 3km further southeast from the previously mentioned location.

Previous positioning was based on some rather widely spaced 2D seismic lines, one drill (MOU-4) through the structure's edge, and some petrographic studies of similar strata outcropping in the nearby region.

So why such a significant change, especially with regard to the MOU-5 borehole location? Clearly some important additional information has been incorporated into the calculations & planning. Hmm, now what could that be?

Answers on a postcard, but not to me, by the time it arrives in Oz we will probably all know anyway.

I obviously have too much time on my hands, since I have been looking daily for signs of flaring. I am a member of the Earth Observation Group platform, using NightFire v3.0 & 4.0 software to analyse IR radiation in the M7, M8 & M10 spectral bands as observed by the SNPP and NOAA - JO1 & JO2 satellites. This is available about 6-8 hours after observation, and can be projected on to Google Earth Pro. The same data is used by Skytruth, which I know some here are familiar with, but Skytruth is delayed by at least a week.

Unfortunately, even this best-in-class data has significant limitations. It only works for the short duration while the satellite is passing overhead, and only at night. The heat signatures that can be picked up fall into two categories - low temperature (up to 1200°K, indicative of wildfires) and high temperature (1250 - 2400°K, indicative of methane flaring). All the flaring signatures can be identified (by zooming in on GE) as flaring stacks associated with refineries or major oilfields, and appear to be continuous rather than transient.

There have been no observable heat signatures at MOU-3. This could be because 1. There has been no flaring. 2. Flaring has been during the daytime. 3. Flaring at MOU-3 is likely to be of only a few hours duration, making it unlikely to be picked up during a brief satellite transit. 4. Flaring is in a pit, making it far less visible than is a flare stack.

I can guess who will proclaim it to be reason #1.

The same 'they are late, so it must be bad news' is being posted here as on the other bulletin board. This was my reply there (2 merged into 1 & slightly edited for brevity):

There is clearly some misunderstanding of the process here by some folks. The Lonny tweet on 8th August showed surface testing of equipment - it also showed that the CT injector was not yet connected to the Christmas tree, meaning that no subsurface work could have begun at that time.

Once connection was completed, the borehole would need to be checked for debris, and if necessary, cleaned out. The bore would then be re-logged to ensure that the horizons to be perforated were in exact depth alignment. This needs to be done since the coefficients of elasticity and thermal expansion of drill pipe and coiled tubing are different, so you will see different depth readings with each.

Only then can you start perforation and testing. PRD are testing 17 intervals this time round, as opposed to 4 previously. Perforation to the depth of formation damage probably necessary will take a lot longer than 30 minutes [as was claimed by the o.p.] - for you to say "Sandjet only takes 30 minutes, so it must be finished by now" is bizarre. You could equally say that conventional perforation only takes 2 milliseconds, since that is how long the explosion takes. Pressure and nozzle size will need to be optimised, this may require several CT runs for the first couple of horizons.

Unlike in Phase 1, pressure and flow testing will be performed, assuming perforation is successful. This will most likely be performed using intermittent flow testing. An initial pressure reading is taken, and the horizon under test will be allowed to flow for a period of perhaps 4-6 hours, with any declines in pressure and flow rates recorded. The well is then shut in for a few hours, opened again and the tests repeated. The well is then shut in again, and opened once more for a third set of measurements. These data sets can then be used to project both long term flow rates and the volume of connected reservoir.

To think that all this could have been done by now is misguided. It was quite clear in the RNS of 7th August that results would be reported at the end of MOU-3 testing, and no intermediate information would be released. "A further operations update will follow once the MOU-3 rigless testing programme is completed. The Company does not intend to provide an operations schedule for testing at present as plans remain flexible and may be modified depending on initial test results and operational efficiencies." I would not be at all surprised, in a success case, if additional horizons were also tested, including the high-pressure 11m shallow sands currently behind two layers of casing.

My guess for the estimate of 'Extensive operations at MOU-3 are anticipated to last for at least five weeks' is based on two days for perforation & testing of each interval, plus a few for preliminary work.

"Sound Energy announces that the planned work over operations on the gas well TE-7 in preparation for long term gas production into the micro-LNG plant currently under construction at site have resumed following the arrival of additional wellhead equipment. The operation to run new completion tubing into TE-7, will utilize the Star Valley Rig 101 currently located on the Tendrara Production Concession. The rig had been stacked on site at no additional cost to the Group awaiting the arrival of the additional wellhead equipment."

If you click on my name, you will see I joined lse on 19th July 2021. There is a good reason for that. Based only on my own opinions, I had been invested in PRD for two years, and was expecting MOU-1 to be an 'interesting' drill. The RNS on 6th July I saw as very positive, and confirmation that there was a potentially large, overpressured system in place - exactly as per Wacky's post today at 18.31. I was perplexed that the share price halved, instead of doubling as would be expected.

The RNS of 19th July was a firecracker, re-confirming what was said a fortnight previously, extending the structural closure to 60KM², and raising funds to get on with the next well in the structure. While a placing can be expected to dampen things, there was again a sharp negative reaction. Perhaps I had completely misinterpreted what I saw as a highly positive result?

I started looking around for additional viewpoints, and found this bulletin board among other sources of comment. Many of the comments here were highly negative, brief, and lacking in facts or apparently deliberately misinterpreting what the company had presented. A very small number of posters contributed lengthy, factually oriented material that confirmed my own positive views. This trend seems to have continued for a further three years.

I remain puzzled why there is a hard core of commentary that is consistently negative about the company and its management. This small group of people claim to be shareholders, but never acknowledge the substantial advances that this company is making, and make ad hominem attacks on those that do supply positive opinions based on facts - not the behaviour of someone who has an actual investment.

So what is going on? Some possibilities:

* They genuinely believe PRD is a poor investment, and out of a saintly sense of altruism are hoping that us poor ignorant fools will not lose our money.

* They are traders who believe their pronouncements will cause short-term price movements from which they can profit - but this cannot be easy pickings for a share that usually has a very wide dealing spread.

* They are working with an external entity that knows there is a huge sum of money at stake, and wish to derail the progress that the company is making. They will call me paranoid, but O & G is a dirty business, always has been.

Linked to the third option, I find it suspicious that equipment availability has been impeded by other entities within Morocco, and regulatory approvals seem to have been delayed to a greater extent than for other companies. I have referred previously to the Moroccan way of doing business, a small company with management that plays a straight bat is likely to run into issues of this nature.

The location I suggested for the actual pad is 34.816, -3.286. I haven't seen any changes within a few hundred metres of that position, nor would I expect them if the revised EIA has only just been issued.

Sold to Chiesi in 2023. not 2013.

NH frequently raises a slur about Fastnet becoming a pharmaceutical company, implying this was some kind of failure by Paul Griffiths. Here's some facts. Fastnet were the holders of the Guercif licence in 2015. Paul was MD, but not a major shareholder. The company was financed by a group of Irish investors, who already had pharmaceutical interests in both wholesaling and product manufacturing and marketing. I have in the past personally had dealings with two of the investors, who I considered to be very sharp cookies - unfortunately the discussions did not lead to the conclusions that I hoped for. The investors were offered the chance to acquire Amryt, this required significant investment in clinical trials which the then owners could not afford. The Irish group did their sums as to which of the two opportunities - Amryt orphan drugs or Guercif gas - was likely to produce the better return on their funds over a five-year period. At that stage there was limited data available on Guercif, and it was considered at that time easier to raise funds for a pharma project, so the decision was made to go the pharma route - Paul was obviously opposed to this, but he was not in control of the purse strings.

Based on my knowledge of the Irish directors, I invested in Amryt in 2016, and held until the sale to Chiesi in 2013, making a very healthy profit. Perhaps controversial, but from a purely financial risk/reward viewpoint, I think they made the correct decision at the time.

I also was aware of the potential of Guercif - Moroccan onshore gas was a frequent topic of discussion, and I have been assured that Paul maintained a personal obsession with the project, including investing some of his own money in further research. A little over five years ago, PRD was able to acquire the licences for Guercif, and I made a small investment - only small because I was not happy with the CLN used for finance. When this was redeemed, I bought more, and have continued to do so as the project has further derisked.

With regard to NH's comments on time schedules, he does not seem to be aware that there have been consequences to a worldwide pandemic, and an even greater effect on supply chains and logistics caused by a major war. The Moroccan way of doing business (I will not enlarge upon this) is also causing substantial delays.

But of course, if you have some kind of personal grievance against Mr Griffiths, then everything is his fault.

@Ibiza. You are using the price to a retail purchaser for your calculations. That is not the value to a company acquiring the assets in Morocco. You would need to make assumptions concerning capital expenditure to set up the whole project, the ongoing operational expenditure per BCF to produce the gas and get it to the customer, the time period over which how much gas would be sold, taxation, and the time value of money over the period. These should be put into a standard NPV (net present value) calculation spreadsheet. The NPV is the value today of the whole operation. No purchaser will pay the whole of this, since they are taking on the risk of everything going to plan (it never does), and they also need to make a profit.

Previous industry estimates suggest that the NPV of 1 BCF of gas in Morocco range from $1M to $3M, depending on the different sales prices to local industry / power generation / export, etc. and is particularly dependent upon initial capital expenditure. At the stage of a proven set of flow tests from multiple wells connected to large volumes (hundreds+ BCF), expect a purchaser to be offering 25 - 50% of the NPV.

@Jimmy. What you are effectively asking is if I have inside information that the entire 289m thick, 189km² structure is charged with overpressured gas. Unfortunately, I don't have that information, maybe nobody does. If I did know, and it was positive, I would secretly be borrowing every penny I could get to take an insanely leveraged position ahead of the announcement, hoping that the SEC could not get me in Australia 😁 In reality I never borrow to invest, nor use leverage.

"This is a major bearish reversal pattern, which is even more significant than a regular Bearish Harami. The outline again looks like a pregnant woman, as with the Bearish Harami Pattern. However, now the baby is a Doji. Basically, the pattern is characterized by a white body followed by a Doji that is completely inside the range of the prior white body."

...and I get accused of writing rubbish!

@Jimmy - I agree it is very odd, I would very much like to see the revised Scorpion report to see if it offers any clues. I am assuming for now that they have retained the same scoring for gcos as in the ITR. The reason I quoted at length from several RNSs was to demonstrate that some of the weightings in the ITR are very much on the conservative side. I accept that no consultant is going to score any parameter at 100% without indisputable proof. However, 0.5 for reservoir effectiveness looks odd, perhaps they have assumed that this is the same reservoir quality as in TAF-1X, which only had 9% porosity. Sourcing at 0.56 also looks very low, considering source rock studies have shown this to be directly below the carbonate reservoir, and inside the same structure - Scorpion had previously mentioned the likelihood of sourcing laterally from abutting vertically displaced younger strata. Finally, given 175m of overlying claystones plus anhydrite, I feel a seal & trap effectiveness rating of 0.49 is miserly.

Clearly there is still some uncertainty over the accuracy of the NuTech interpretation from the carbonates at the bottom of MOU-4 - does it indicate currently trapped gas under pressure, or just indicates that gas has been there at some time? I do not know if Scorpion are familiar with NuTech methodology, but Paul seems very comfortable with it. I guess in about 6 weeks they will be perforating this bottom interval in MOU-4 - if there is indeed gas under pressure, it will be safe to assume that the whole structure is likely to be charged, and MOU-5 will in effect become upgraded to an appraisal well. If so, expect fireworks as the consequences become understood by the market.

Part 2.

11 July 23 RNS. “The top Jurassic carbonate objective was reached at 1135 metres TVD MD, 253 metres deeper than the estimated depth pre-drill based on no well control. A thick section of 175 metres of claystones capped the Jurassic carbonate section confirming the presence of an excellent seal separating the section from the overlying Moulouya Fan sequence. This has eliminated a significant pre-drill seal risk. The culmination of the Jurassic carbonate target now lies 2.6 kilometres to the southeast of the MOU-4 well location and significantly higher than at the MOU-4 well location.”

13 July 23. “top of the Jurassic carbonates - 2 metres of likely gas reservoir with average porosity 19.9% (maximum 20.6%) and average gas saturation 56% (maximum 73%).” and “The recognition by NuTech of likely good quality thin gas reservoirs at the top of the Jurassic carbonate is particularly significant in the context of the large Jurassic structural closure ... Rigless testing of the Jurassic interval will be an important step in evaluating the significant Jurassic potential within our core area of interest."

30 Aug 23. “Three preliminary drilling locations are being selected for inclusion in a new EIA. Well design and sourcing of long lead well inventory has commenced. A field trip is being planned for the autumn to evaluate the reservoir potential of the entire interval of interest in Jurassic surface exposures to the south of the Guercif licence area. Geochemical source rock quality and maturation studies, including evidence for migrated gas, for the Jurassic section penetrated in the MOU-4 well are expected to be completed in September.”

26 Jan 24 RNS & ITR. MOU-NE is now 177km² and up to 249m thick.

06 June 24 RNS. MOU-NE is now 189km² and up to 289m thick.

It should be obvious that as knowledge of this prospect has improved, the optimal drill locations will be changed. Seismic reprocessing has delineated the structure with improved resolution. Key changes have been an increased depth of 250m, confirmed by drilling, and a consequent increase in structural closure. I have a suspicion (but only a suspicion!) that PRD have received a 'free sample' of hyperspectral satellite imagery to help with this location. You might recall that a notable shareholder had expressed the hope that we would be last on the drill schedule – anyone worked out why?

This has resulted in new EIAs - the most recent EIA ran into an issue, but management are now so confident that this is the best location that they are prepared to amend the drill plan to site the pad to one side (but still on the same seismic line) and deviate the drill accordingly, even though this will result in a delay. That sounds like a strong positive to me.

Part 1.

Someone here has twice suggested that moving the drill pad by 277m is a sign of management incompetence. The logic of this conclusion is beyond me. Optimal positioning of a well is an iterative operation – to understand the process, it may help to understand the history of Titanosaurus.

The potential for large hydrocarbon-bearing carbonate structures in the Guercif area has been known for 100 years. The Institute of Petroleum Journal, 1936 : Vol 22, p 239 and Dunstan's 1938 Science of Petrology, p. 186 both mention actual extraction of commercial quantities of oil in 1924, from a prospect that PRD refer to as MOU-NW. I put a photo of this on X a couple of years ago: https://x.com/KQuick20704342/status/1504653923541393408

These old references misidentify the producing horizon, modern mapping shows it to be Lower Jurassic. From Dunstan's: “The productive horizon is a Triassic limestone which appears to be or to have been oil-bearing over an area of at least 16 miles by 12 miles." That's big!

Fast forward to PRD RNS 13 January 2022 – first mention of MOU-NE - “MOU-NE lies updip from an abundant micro-seepage with an oil signature identified by a Geo-Microbial Technologies micro-seepage survey in 2006 and 2007.

08 March 22. 250km seismic to re reprocessed, and EIA (Environmental Impact Assessment) completed.

17 March 22 “The primary target following further desk-top studies is now anticipated to be a Lower Jurassic carbonate platform build-up with potential for leached porosity development covering potentially up to 100 sq. km., albeit within an area that lacks extensive seismic coverage. Dry gas shows were encountered in TFR-1X at the top of this interval. MOU-NE will potentially test the play concept some 1500+ metres higher than the TFR-1X structure in an area favourably located for gas charge.”

12 May 22. “The MOU-NE drilling lead has now been mapped at the base of the forecast reservoir sequence with a structural closure covering 102 km². The next step is to finalise a drilling location based on defining the highest point on the structure with the maximum potential for leached reservoir development (18 metres of reservoir were encountered approximately 2,200 metres downdip in well TRF-1 about 15 kms. to the southeast of the MOU-NE structure beneath a zone of gas shows. MOU-NE well will be targeting a gross reservoir sequence of approximately 200 metres within which the potential for good quality reservoir is increased due to its structurally elevated position relative to TRF-1. MOU-NE is adjacent to the gas-generating basin defined by the MOU-1 well results. Oil and gas shows are present on trend to the west of Guercif in the target reservoirs in the depleted Boudraa and Tselfat oil fields and in the DGR-1 and DGR-3 wells, demonstrating an active petroleum system to the west that will be tested by MOU-NE”.