IVZ - General Discussion, page-1468

Hey Butcher – this is a good post playing devil’sadvocate – asking the right questions. This is the type of discussion we need -breaking things down and not continually perpetuating confirmation bias.However, I think many are being affected by recency bias atm – that is theshare price has been smashed recently and a lot of holders are seeing this ashow things will remain and that it means the stock is fundamentally flawed. Itis not.

I’ll hit on your main points first and then hit upyour sub-points. (Apologies if this is rough, I’m just going to machine guntype this. You folks not in subsurface might have to google some terms I usehere, I’ll try to add detail where I remember. This might also need to bespread across multiple posts).

1. Poor reservoir quality and low permeability inUpper and Lower Angwa at Mukuyu

Ok – let me start with Mobilstudy and circle back. They had rock samples from the Upper Angwa where itoutcrops at surface in the basin. They did porosity and permeability (‘poroperm’)testing on these. Now I’m assuming the samples were tested at ambientconditions, not an assumed overburden pressure (basically the rocks were testedat surface pressures so the poro and perm measurements will be higher than atsubsurface pressures – with a km of rock lying on top of them). So the resultswould be optimistic but still indicative* (I’ve asterixed this because I’llhave further detail for anyone who can be f**ked reading at base of post).

The poroperm values got up to~20% and permeabilites up to 1.2 darcies (1200md) [see figures 1 & 2 below].

I’m definitely not saying they’llbe these values at Mukuyu reservoir depth, but given the porosities encounteredin M-2 (of which Scott has clearly mentioned the UA quality at the Mukuyu-2location was poorer than M-1, and whose to say M-1 is the best example in thefield – that may not have even been in a channel proper – 3D seismic is the wayforward on that one), in my experience I’d say a permeability average of 20mdto 200md would be fair to assume. Lets go more conservative and say the perm wehave for M-2 averages between 20md and 100md. I’ve seen plenty of gas fieldsget good flows for these sort of permeability levels, and I’ll throw someexamples out when I answer your point 3.

The other point to note is theMobil work interpreted the UA system as having some braided systems present (aswell as meandering). If this is accurate, and holds to the Mukuyu location,braided systems are generally more laterally extensive, thicker and higher NTG thanmeandering systems (google braided vs meandering, or ask ChatGPT, maybe she canspit out something decent). It may be the case that in M-1 & M-2 we’ve hitmeander prone areas (and overbank equivalent to the braided stratigraphiclevels), and missed the better sands. Translation: we may have hit the poorerstuff with our wells relative to what’s present elsewhere in structure. You’veput 2 pinpricks in a 200km2 structure (4 including ST but they hardly countspatially), it’s not statistically plausible to think we’ve hit the best stuff anduntil we get 3D seismic, we’re not going to know better. But I still think whatwe’ve already hit is producible, and again I’ll go into more detail on dot point3.

Figure 1: excerptfrom Mobil report – present in 2019 IVZ pres (IVZMarch 2019 Investor Presentation (invictusenergy.com))

Fig. 2: surface mapping, outcrop examples, seismic constraint example relationship between surface outcrop of UA & subsurface (source: IVZAustralia Roadshow Presentation Sept 2019 (invictusenergy.com))

I’ll just also note here – we don’thave porosity info for the overpressured lower angwa sands (no quad combocoverage hence no porosity interp). When SM says these are looking betterquality (I’m assuming they had LWD GR & Resistivity cover them so that willgive an indication of quality), I definitely believe that. I’m going to soundlike a broken record but overpressure is fantastic for maintaining higherporosity than normally-pressured reservoir as the rocks are buried.

I’m not going to bother goingfurther into all the ways that what is currently called non-net may shift intonet pay in the future for Mukuyu-2. It just wouldn’t surprise me if we get somedecent surprise flow contributions in the flow test, especially if they try toisolate multiple zones, including those currently classed as non-net to seewhat they can get out of them.

To circle back around, let’s carryforward an assumption 20 to 100md permeability for Mukuyu-2. For gas thisworks, I wouldn’t be sh*tting the bed over this, but we’ll come back to it.

2. Significant downgrade to prospectiverecoverable resources in the Mukuyu structure due to net pay well belowpre-drill estimates

I think I’ve already partiallyaddressed this in the above. Porosity cut-offs in basins I’ve worked FOR CONVENTIONALS (at a supermajor) have been as low as 4% porosity. I don’t think they’ve gone this low of a cut-off here. Nonetheless, there could be a heap of rock currently sitting under the porosity cut-off by 1% maybe 0.5%. You either have evidence to support lowering your porosity cut-off (if you prove a given section can flow at this porosity), or your core calibration tells you your petrophysics/log-based porosity is too conservative and you adjust your porosity interp up, you suddenly potentially have a sh*tload of non-net suddenly become net.

And that’s not to mention thatwhen you deepen this well with the 6” into the overpressured lower angwa that’syour low-hanging fruit for adding more net to this well.

As for the section above the UA(Pebbly, Dande, etc.), yeah you only have residual hc at the M-2 location, butI’ve seen it a bunch of times before – you don’t have hydrocarbons at onelocation in a given unit, and then you do somewhere else in the field – easily doneif there’s valid structural or stratigraphic controlled. It is positive therewere residual hc’s in the Pebbly (& high gas chromotograph readings in theshallower units), it means hydrocarbons have migrated through those units, andif there are any suitable trapping locations you’ll have hydrocarbons present. The3D will definitely help with this – in a)identifying valid structural trap thatcan’t be broken out on 2D, and amplitudes will help with identifying poss. Strattraps or DHI constraint/ extent (watch out for fizz gas though). Also, if thesupra-UA doesn’t have hydrocarbons, based on what I believe are conservativenet pay figures released, you already have multi-Tcf in that alone (from my back-of-the-envelopecalcs).

3. Low flow rates in the upcoming flow test atMK-2

Define low flow rates? For gas? 10MMscf/d?20MMscf/d? 5MMScf/d? (rhetorical question)

If you need more deliverability,you just drill another well. You are onshore, this is relatively cheapdrilling. Especially when the basin gets going. Personally I think 10MMScf/dmay be fine, but I think we’ll get more.

So, let’s quickly look at fewrelatively low perm fields and their flows.

Let’s use Perth Basin seeing asthat’s been referred to a lot. Specific flow test: Waitsia-4. This well had anestimated average perm of 55md for the tested section. It flowed 89MMScf/d.I think that’s probably enough for us. A disclaimer here is that it had aslightly larger net interval (so theoretically a greater kh), but I’d arguethat we’re going to have more contributing than the stated net pay numbers forM-2 (LA not covered by quad combo, UA under current net pay cut-off but thatwill contribute, possibility of barefoot flow of 6” section). If we could get aportion of 89MMscf/d I’d be happy. It just goes to show what you can do with relativelylow perm reservoir. Flow test screengrabs below (Fig 3 & 4), most of theWaitsia wells are open file so you can grab the completion reports, flow testreports if you want.

Fig 3: summary of expectedpermeability for Waitsia-4 flow test (source:W-4 flow test report)

Fig 4: Waitsia-4 flow test summary

Muruk, in PNG, averages around50md (another example). Flow test for Muruk-1 produced an EQUIPMENT-CONSTRAINEDrate (meaning it could’ve done more) of 16MMscf/d at

Another PNG field, Hides,currently producing averages about 40 to 60md perm and flows very well (can’tprovide flow rates that are publicly available – but they are very competitive).Hides is a significant producer for the PNG LNG project.

Where I see reductions in flowrate compared to what Mukuyu could otherwise get – is if it has high CGR and issubject to retrograde condensation / dropout. Dropout can negatively affectflow rates. But you will still flow, and you still get liquids to sell. If thisis the case, there are ways to manage keeping reservoir above the dewpoint andIVZ can explore strategies to maximise recovery. You never 100% pull out allhydrocarbons from a reservoir in any case – that’s why we have recoveryfactors.

Again, even if it is subject todrop out, the well will still flow. So either, you have high CGR (a lot of condensate),and so you will have liquids to sell, but you may have a lower flow rate; oryou have low CGR (little condensate), and you will maximise your gas flow rate. There’s pro’s and cons to everything.

4. Low CGR and minimal liquids content

See above. But Scott has already said they think this is a wet gasdiscovery. They had a lot of heavier ends on the gas chromo readings. They hadheavy C’s on fluid analyser. If in the unlikely case it’s a low CGR, then you’reprobably going to get better flow rates. So again, pros and cons to everything (‘itdepends’ is often the best answer in subsurface).

*Plus these surface samples likelyfrom rocks that have been exhumed to some degree (buried and then brought backto surface via structural processes – think faulting and folding), so there’slikely some diagenetic porosity/permeability reduction that these rocks havebeen subjected to. So at least the diagenetic affects on the rocks may at leastpartly be accounted for.

Cheers,

D

I’ve just quickly responded tosome of your more detailed points below. I’ve just deleted the some of yourpoints where I think I’ve already addressed. If response sound snarky ortelling you how to suck eggs – apologies, just rapidly brain dumping. Yourpoints are good and need to be addressed.
1. Reservoir quality

· No comments whatsoever from SM regarding reservoir quality is a concernand leads me to think that this is because they will disappoint the market.I’ve never seen a company stay silent on reservoir quality and permeabilityresults when declaring a discovery and reporting net pay, especially if they’regood.

I think he’s said all he needs to say on poroperm from everything I’veread and heard. I reckon he might be getting a bit exhausted, trying to explainto people that these porosities are workable. It sometimes feels like peopleare expecting 20% phi and 1000md min. If you haven’t worked with conventional gasfields at these poroperm levels, or you’ve only worked Cooper Basin in the last10 years and you’re used to having to frac/stimulate everything, I can see howthose people might want to see more.

· SM is in possession of permeability data from the routine core analysisof samples from MK-1 and is not reporting these results.

It’s around 8 reservoir samples only. In a well that had huge invasionproblems. He has literally said a bunch of these res plugs are unusable due tofracturing. If I had less than 8 reservoir samples covering 200m of section Iwould not want to release them either (it’s just not a statisitically robustdataset). They are probably literally having trouble properly cleaning the fewres plugs they have to get a representative poroperm value out of them.

· He is also in possession of permeability data for the reservoir unitswhich contributed to net pay at MK-2, obtained using the SLB MDT and also frommobility data acquired during cleanup and fluid sampling. Also not reported.

They could report the mobilities in md/cdp, but I can tell you, thetechnical team will be churning away on the data now and they need the time towork through their interpretation of the system. Any good technical team willtake their time to properly work the data before releasing anything to thepublic

· The only comment from SM regarding reservoir quality is that the LA isbetter than the UA at MK-2. But without knowing what the UA quality is, thenthis comment is meaningless.

You have the UA quality 10% to 8.5% porosity in the current net,conservative interp (their words). Also, M-1 appeared better quality than M-2(prob why they were a little pumpy on the gross metres in an M-1 announcementform ages ago – think it was ~200m?). Again 3D seismic…..

· As a minimum we should have heard a qualitative description of reservoirquality - ie. tight, poor, fair, good or excellent.

Covered in rest of my writing. But no, I wouldn’t expect him to say ‘tight,poor, fair, good or excellent’. We have the net porosities, he’s said LA isbetter than UA. Again, I think they’re a bit exasperated

· For investors to be conservative and without any supporting data, weneed to assume that the UA is poor quality and the LA is “better”…or mostlikely fair and at best - good quality?

Tight poor and fair etc just refer to a porosity range, you can see thisfrom the poro already declared. Again I think he would assume this is implied…

· There’s too many red flags to suggest that we’re going to be suprised tothe upside. I think SM is just hoping for decent flow rates when the time comesand has decided not to unnecessarily disappoint shareholders by reporting poorreservoir quality data now and is just rolling the dice on flow test resultsinstead.

See all previous points

2. Prospective recoverable resources

· We know that Mobil was basing their resources on 46m net pay andestimated approx. 3 TCF recoverable in the Upper Angwa.

You need to think about the whole structure. It sounded like M-1 lookedlike it was higher NTG on logs alone. Again 3D seismic and more targeted wellplacement is needed to skin this cat.

· We can only assume that IVZ have used a similar net pay thickness with alarger area of closure to determine 4.1 TCF for the UA.

Need to see details of assessment, but we never will. Its not industrypractice. You’ve got to remember SM is ex-Woodside, so he prob thinks like aMajor

· With only 13.9m net pay vs 46m, there’s a real risk that the prospectiverecoverable resources in the UA is less than 1 TCF (assuming linearrelationship with net pay thickness). And the potential for poor qualityreservoir will only worsen this figure.

Nothing in resource assessment is linear. Again, we need to thinkstructure-wide. This also assumes there is no chance for the net pay within theUA to be revised. Not my experience

· We have no real pre-drill estimate for the Lower Angwa in terms ofreservoir thickness. But given that this has been promoted by the company asthe “Massive Member” with a high net to gross ratios of reservoir sand, thenthe only reasonable assessment on what has been encountered is the net to grossratio. Typical NTG would be at least 25% for a predominantly sandstoneformation. We encountered less than 4% in MK-2. The pre-drill estimate was 2.6TCF over 650m from 3100m to 3750m. If this was based on 25% NTG then our actualresult of 4% puts us at less than 0.5 TCF recoverable from the LA.

Feel like I’ve addressed this throughout post. Don’t agree (know yourplaying devil’s advocate), for all the reasons in the rest of my post. I’llprob just copy and paste this on a few items.

· And the concern is that if the low NTG continues below 3,718m then ourupside is possibly only another 0.5 TCF from deepening the LA down to say4,500m. This isn’t necessarily the unlimited potential that I was hoping forbefore we hit a water contact.

Don’t agree

· In terms of our total resource at Mukuyu, there’s actually a realconcern that we’ve just signed a MOU for 1.4 TCF which is right on the limit ofwhat we’re likely to have encountered and will limit our potential for signingmore agreements without being able to demonstrate that we have enough gassupply to meet these additional commitments. Which is why I’m not even surethat we would be in a position to firm things up with Sable Chemicals as wellas Tatanga prior to demonstrating a higher average net pay figure.

See rest of post. Don’t think itll be an issue. We still have rest of LAto drill as well. Let me re-iterate, taking undrilled LA off the table, it wouldn’tsurprise me if we have more already drilled non-net found to be contributing toflow

· The other thing that I take issue with SM is the fact that post-MK-1 hewas still quoting prospective recoverable resources for the Mukuyu structure of20 TCF, despite the fact that the Dande, Intra Dande, Forest and Pebbly Arkosewere dry at MK-1 (and most likely across the remainder of the structure). Wewere clearly limited to a maximum of 4.1 TCF from the UA and 2.6 TCF from theLA. To promote this post-MK-1 as 20 TCF still was completely dishonest imo andonly serves to set shareholders up for a disappointment.

I discussed this in one of my points above

3. Flow rates

· Key risk is managing investor expectations. And SM has always exceededat disappointed in this space.

I think he has highs and lows, the lows being where I think he mis-readswhat the audience is expecting based on what he’s previously said, and he doesn’tmanage those expectati0ons in SOME instances. Otherwise to me he comes acrossas extremely competent, technically switched on and pragmatic. Nobodies perfect.The CEOs of many of the supermajors are far from perfect, they just have alarge balance sheet and a robust portfolio to cushion them

· I’m not expecting SM to provide guidance on the flow rates that they’reexpecting to achieve prior to the flow rate, despite the fact that they wouldhave a good idea of these numbers right now and could quite easily makereference to their expectations. Would be good if they did, but I’m not gettingmy hopes up.

SM’s conservative, I can’t see him doing that either. I’ve provided justsome analogues of potential flow in lower porosity gas fields.

· So the problem for us is that only a surprisingly large flow rate willexcite the market and re-rate us.

· I think we’ll need a combined 30-40 mmscf/d plus 5k-10k bopd liquids forthis to be considered a catagoric success and send the share price to where itbelongs.

Flow discussed previously

· Anything down at the 10 mmscf/d levels from both UA and LA and lowliquids would be a disappointment imo

Not so sure, but flow discussed previously

· And with the risk of poor quality reservoir and thin net pay intervalsthis is my biggest concern for 2024

Discusse dpreviously

4. Liquids content

· It doesn’t matter whether you use an in-ground resource value or arevenue based valuation - a condensate discovery is worth twice as much as drygas alone. Even in Zimbabwe. The fact that SM doesn’t understand that this ishow investors value a company and hence gets reflected in the shareprice ismind boggling.

Pros and cons for both situations. See my post at top under 3&4 –actually all the rest of the dot points are already covered so I’ll jump a few.

· For over a year this has been touted by SM as a “very liquids rich”field with CGR estimated from MK-1 mud gas data at up to 135 bbls/mmscf whichis well above pre-drill expectations and adds massive value to the economics ofa discovery.

· The language has now suddenly changed to SM wondering why shareholdersare fixated on liquids and moving back to saying this was only ever a gas playand liquids aren’t relevant.

· I’m concerned that there’s negligible liquids in the samples obtainedfrom MK-2 and this will counter any positive news that comes out of the labresults early next year.

Previous answers

· He was confident enough to declare a gas discovery based on down-holedata without blowing down a sample to determine hydrocarbon composition. So ifhe was certain that we have gas, then he should be just as confident that wehave liquids in the samples. And why not make mention of this in the discoveryannouncement?

· Or is it possible that they observed C6+ liquids on the in-situ fluidanalyser but he needs to confirm if this is volatile oil versus condensate? Andif this was the case then why didn’t they blow a sample down on site to verifyprior to the discovery announcement? Even if it meant a voluntary suspensionfor a couple of days. Blowing down a sample on site was the plan all along. Andthey grabbed multiple samples from the same intervals so there was no realissue with “wasting” one of them.

He's a reservoir engineer by background. The right choice is to sendanother sample off for PVT / higher accuracy compositional analysis