Hurricane Energy (HUR)

[PeterGray]

<i>With wells placed high in the structure, hundreds of meters away from the OWC, and a modest drawdown applied, is it realistic that early water breakthrough could occur?</I>

I'm certainly not qualified to make a any technical response. However, it's quite clear that the view of HUR's mgmt, who should know more about issues like this in relation in particular to Lancaster than anyone else, take the view that water breakthrough is very unlikely. I doubt anyone can provide a better answer at this stage, but it's clearly one of the key issues that the EPS is designed to test, and on of the risk factors.

Peter

[NigWit]

@Fabian

I wonder if you’ve come across this presentation by David Craig of Novus, who are Crystal Amber’s geologists, in the course of your research. It’s a year old but subsequent to all the drilling and provides some information about the fracture network. I hope it helps.

https://vimeo.com/223760753

[dspp]

Fabian,
Welcome. Comments in red in your text.
regards,
dspp

I work as a reservoir engineer, but have no experience working with fractured basement reservoirs. I was initially intrigued by Hurricane simply because of the volumes involved. Me too, it/they seem very large indeed.

After doing some studying this winter, I found the project to be both technically fascinating as well as potentially profitable, and decided to take on a moderate (for me) position. I've done some economic analysis which doesn't go much further than to sense check the Edison analysis from last year. I've been impressed by the quality of discussions on this board and the level of civility on display.

Other posters have highlighted the OIP estimates as a major uncertainty, as it depends on the fracture connectivity, density and sizes. The estimates from Hurricane are as I understand it based on wireline coring and log data (Neutron porosity, bulk density, spectroscopy), as well as the distribution of Fault Zones to Fractured Basement, which is based on well log data, drilling parameters and seismic. My question would be whether the EPS will actually limit the solutions space much, as pressure transient analysis solutions are very often non-unique? I would be very interested to hear someone with experience working fractured basement plays (hi dspp) comment on this.

Firstly I am a production engineer in oilpatch terms, not a reservoir engineer. (Actually I am a systems engineer, but hey ho). So I am most used to near wellbore onwards, and therefore I am very interested to hear the story from deeper into the reservoir as it was not my normal playpen. Secondly I have never worked in FB. However I have worked in deep carbonate fields where all the available volume was fracture volume as the pore volume was either negligible or not connected, and therefore the fracture network (at all scales, from large joints, down to microfractures) contained the hydrocarbons. It seems to me that this is not dissimilar to an FB field.

If so my experiences may have some relevance, and they were mixed. I am drawing from personal experience of two (or three) such reservoirs but if you read the literature they seem typical of many.
1. Loss control in drilling was an issue, so too was ability to successfully clean up or not. HUR have definitely encountered this problem, and I am not convinced it is solved. However they are handicapped by drilling exploration wells with greater safety margins required and so this situation may improve when they can drill closer to balance, and against less time/budget pressure. Anyway one to watch.
2. Prolific production was often seen. Again this is HUR's observation.
3. So too sometimes was very rapid decline rates in individual wells, depending on how much volume was connected and through what sort of network. So far HUR haven't really produced long enough to see this.
4. Rapid onset of water was an issue on occasions, and very difficult to control as the fractures bypass the normal controls. HUR have yet to see this. It entirely killed the economics of one field I worked on. After the first phase of the money had been spent

I don't think any of the above will be new to you, my points are really that only time (and production data) will tell. I fully agree with your description of the situation. Slide 26 of the roadshow presentation
https://www.hurricaneenergy.com/~/media ... red-v2.pdf
is the key one for me in respect of your questions. It sets out three analyses that they can conduct with the EPS, and it seems reasonable to me that a combination of all three will give meaningful results to many of these questions. At least sufficient to be able to narrow down the valuation & reserves questions sufficient for acquisition teams to have rational data-driven discussions with each other. It then becomes a function of deal structure to try and resolve the remaining differences of opinion.

Rapidly increasing GOR has also been identified as a risk / potential production constraint. Wouldn't this be closely tied to the risk of fractures closing during extended production? The well tests produced at the same rates planned for the EPS at very low constant drawdowns and above the bubble point pressure. As long as the drainage area is sufficiently large and the well stays connected to it, I would expect the producing pressure to stay above the bubble point.

I haven't heard anyone directly discuss rapidly increasing GOR as a problem. There is discussion of whether there is adequate aquifer support, and so far the working assumption tends to be the aquifer is adequate. Again only production will tell. If it isn't then water injection will be called for is my thought, but that is not too problematic. My real concern is what is the actual GOR and whether it is in the sweet spot or too high or too low. I am expecting that they will have to put in gas reinjection for several years as I don't see a gas export line being available in time. But once they have done sufficient reservoir analysis (without confounding effect of injection) that's OK. It does have a considerable influence of FFD options & economics mind you. The need to drill Whirlwind by 2021 (? or is it 2020 ?) is significant in forcing all the relevant data onto the table in time for gas export planning. It would be nice to have a phase diagram though.

My last question would be on the water cut. With wells placed high in the structure, hundreds of meters away from the OWC, and a modest drawdown applied, is it realistic that early water breakthrough could occur? If all the production originated from a single fracture, I guess I could see it happening (and we've actually seen such an inflow distribution from the vertical well 205/21a-7 DST, but still...). If anyone has seen this occur on basement plays with similar deep OWC, I would be very interested in reading about it.

I've seen it happen, but with a much closer fault that it turned out was not sealing. Here, for the same reasons you discuss, I don't see it as being too significant an issue for a long time. But nonetheless worth doing an EPS to derisk.

Generally, I'm here to get my assumptions corrected and my understanding more informed, so please dissect my post to your pleasure.
I don't think you are missing anything.

Have you any useful public domain papers on the other WoS fields that you can link to ?

regards, dspp

[FabianBjornseth]

@Fabian

I wonder if you’ve come across this presentation by David Craig of Novus, who are Crystal Amber’s geologists, in the course of your research. It’s a year old but subsequent to all the drilling and provides some information about the fracture network. I hope it helps.

Thank you NigWit, this is much appreciated. Mr. Craig's statements reflect what Peter posted earlier, that the risk of water breakthrough is seen as quite small, but the risk is still there it can only be reduced by acquiring extended flow test data. For my part, I would be surprised if it is rapid water cut increase that causes the EPS or even a full field development to fail (knock on wood).

Mr. Craig also discussed the OIP volumes, but primarily related to the depth of the oil-water contact and did not touch on porosity estimates. From the May 2017 CPR, the high case porosity is more than twice that of the low case.

Fault Zone (FZ) Porosity | Fractured Basement (FB) | Porosity | Rationale
Low (%) | 3 | 2 | Estimated from image log work done by Eriksfiord
Best (%) | 4.8 | 3.2 | Based on log analysis both conventional and NMR
High (%) | 7 | 5 | Assumes higher porosity associated with major (sub regional) fault zones

The impact on volumes in place is thus very large, compared to a sandstone reservoir where a porosity range from 25-30% could be expected at this stage of field appraisal. I'm wondering if the EPS will yield sufficient data to constrain the porosity range within 1 percentage point (3.5%-4.5% as an example)?

[NigWit]

You’re most welcome Fabian. I was actually present at David Craik’s talk and seem to recall that he explained, perhaps in the Q and A, that the 3D seismological surveys can only map the fractures nearest the surface layer in detail. I expect you know this anyway and I confess that I am danger of tripping over here since, whilst I’m an engineer by training, it’s not what I’ve done for a long time and I was never in oil or geology.

I’ve come to the possibly lazy view that the best knowledge of FB is in the company so the investment case comes down to a matter of trust. That’s why I’m pleased that there has apparently been at least one corporate approach. That this approach took place speaks to the quality of the data we’ve never seen. Don’t let me put you off though, I’m sure others will value your technical input, as will I.

Since you’ll be able to speak their lingo you may find an email enquiry to David Craik or Hurricane themselves will elicit deeper answers. I have David’s business card somewhere if you’d like to follow this idea up although I’m sure you’ll be able to find him via Crystal Amber (who are also very approachable) or Novus.

[FabianBjornseth]

So too sometimes was very rapid decline rates in individual wells, depending on how much volume was connected and through what sort of network. So far HUR haven't really produced long enough to see this.

That's the tricky bit isn't it... Just out of curiosity, does it mean you have seen wells that would have performed very similar to Hurricanes' wells over an ~18 hour flow test, yet suddenly came to a sharp decline?

I had another look at the well test analysis presented in the CPR. At first I didn't understand what they were referring to with storativity ratio, as the textbook definitions is the fracture pore volumed divided by (fracture + matrix pore volume), and the matrix pore volume is approximately zero on Lancaster. Reading a bit more, I think they are referring to the ratio between the pore volume of large, connected fractures to the total fracture system, which includes fine fractures that cannot be identified on logs. It seems like a simplification, but also reasonable - but in the end I don't have the experience to say for sure.

The result from that analysis is that 2/3 of the pore volume connected to the 205/21a-6 well comes from the dynamically compressible fracture set (the "matrix" non-discrete fractures). For sustained production, I would think that means this dynamically compressible fracture set must be very well connected, ideally past the oil-water contact. I'm not sure if this is good, bad or neutral information - would it have been better or worse if most of the volume was residing in the discrete fractures? Or is this pointing towards an upside in the oil-in-place volume beyond the fractures that may be mapped?

As you can probably tell I'm not fully confident that I'm reading the report right, so I appreciate any corrections.

I haven't heard anyone directly discuss rapidly increasing GOR as a problem.

The May 2017 CPR mentions it (section 7.8.5) in the context of having to keep the flowing bottom-hole pressure above the bubble point. A strong aquifer would help with that in the long term, but I think in the mean term fluid expansion in the oil column should be sufficient, as the long as the whole volume is well connected. Actually it would be a great thing to do some sensitivities on with material balance equations.

Unfortunately I have not searched for public/free papers on the surrounding fields. I assume you don't have free access to OnePetro.org? It's essentially public information, but sits behind a prohibitive $25/paper paywall.

I really appreciate the discussion so far, thanks a lot everyone!

[dspp]

So too sometimes was very rapid decline rates in individual wells, depending on how much volume was connected and through what sort of network. So far HUR haven't really produced long enough to see this.

That's the tricky bit isn't it... Just out of curiosity, does it mean you have seen wells that would have performed very similar to Hurricanes' wells over an ~18 hour flow test, yet suddenly came to a sharp decline?

Yes I have seen this sort of thing. 1) For example one deep/HP exploration gas well that did an 18h well test with some very high rates and very little water. Fast forwards a few years, farm-in on the block, install EPS, open up, almost instant high water rates and rapidly declining flow rates over just a few days/weeks. However that was exactly why the EPS was conceived so as to prove or disprove connected volume and nature of that. In this EPS example the working hypothesis after results were reviewed was that the macro-scale fracture 'swarm' that formed the lateral sealing fault plumbed straight to the aquifer. Personally I had put my reservoir/welltest concerns on the table at farm-in stage so felt somewhat vindicated, but still it was $150m or so down the pan. 2) Wasn't there a Shell exploration well in the Med back in the 80s/90s that drilled into a fracture set, amazing rates, then nothing, bang. They concluded that outside the macro-fractures there was nothing connected. 3) A series of wells on a light oil field with GOR not dissimilar to Rona, where some wells would come in at 20kbopd and others at 5-6kbopd, and one could never predict which from seismic fault-picks, or from drilling losses, and nor could one a priori predict decline curves. Again the vast majority was fracture storage at all scales, but the seismic & processing really struggled to interpret it meaningfully and allocate it micro/macro. There are other analogues I could think of, but less directly relevant.

I am pretty sure that RT will have had exposure to learning from these or similar experiences when I read his CV. Likewise I fully understand the caution of the majors in farming in prematurely. The overall Rona FFD analysis I have done is very much the thought process they will have done, that's why they want to bid on the whole quad (or quint) of named fields. Given the scales involved that means sufficient people will be working on this that there will be very little emotion or internal politics involved, but lots of gaming. Then the scale pushes it into a consortium bid, and again that needs manoeuvring into place, and that again means the whole Rona and only after EPS derisk.

I had another look at the well test analysis presented in the CPR. At first I didn't understand what they were referring to with storativity ratio, as the textbook definitions is the fracture pore volumed divided by (fracture + matrix pore volume), and the matrix pore volume is approximately zero on Lancaster. Reading a bit more, I think they are referring to the ratio between the pore volume of large, connected fractures to the total fracture system, which includes fine fractures that cannot be identified on logs. It seems like a simplification, (one I would agree with, as from a physics perspective there is nothing that magic about a 'pore' vs a micro-scale fracture. Yes there are differences, but after you consider the processes a pore may go through before humans get involved, they can end up looking & behaving like almost the same thing.) but also reasonable - but in the end I don't have the experience to say for sure.

The result from that analysis is that 2/3 of the pore volume connected to the 205/21a-6 well comes from the dynamically compressible fracture set (the "matrix" non-discrete fractures). For sustained production, I would think that means this dynamically compressible fracture set must be very well connected, ideally past the oil-water contact. I'm not sure if this is good, bad or neutral information - would it have been better or worse if most of the volume was residing in the discrete fractures? Or is this pointing towards an upside in the oil-in-place volume beyond the fractures that may be mapped?
I think I have commented that they are regarding the reservoir as almost being a homogenous collection of two bulk rock types, which are identifiable from seismic analysis of the fractures, and I have wondered to what extent that is justifiable. I see no geological reason why the the (?dynamically compressible?) micro-fractures should not extend downwards, but I am not a geologist. However even if they do extend downwards I don't think it makes that much difference (setting aside the jellyfish model) as the fractures below the OWC would remain in the waterleg and never compress. All we want the waterleg fractures to do for us is to deliver aquifer support evenly across the whole of the base of the oil surface so that the sweep is good with as little bypass as possible.

As you can probably tell I'm not fully confident that I'm reading the report right, so I appreciate any corrections.
Nimrod here on TLF has made the very valid point that the data supporting the determination of the OWC is not as firm as one might hope for.

I haven't heard anyone directly discuss rapidly increasing GOR as a problem.

The May 2017 CPR mentions it (section 7.8.5) in the context of having to keep the flowing bottom-hole pressure above the bubble point. Ah yes, now I recall that, but it seemed such an obvious point that I didn't really pursue it. I felt that was a consultant writing it down just because they had to. I cannot imagine anyone doing field development without keeping FBHP above bubble point. My interest is what is the actual GOR as this can make a big difference to development options. A strong aquifer would help with that in the long term, but I think in the mean term fluid expansion in the oil column should be sufficient, as the long as the whole volume is well connected. Actually it would be a great thing to do some sensitivities on with material balance equations.

Unfortunately I have not searched for public/free papers on the surrounding fields. I assume you don't have free access to OnePetro.org? It's essentially public information, but sits behind a prohibitive $25/paper paywall.
Not at work I don't as these days I now work mostly in another area of the energy-space. However if there are good relevant papers then I don't mind paying, but I don't want to go downloading dross, so any particular paper titles/refs are welcome.

I really appreciate the discussion so far, thanks a lot everyone!

[FabianBjornseth]

Yes I have seen this sort of thing. 1) For example one deep/HP exploration gas well that did an 18h well test with some very high rates and very little water. Fast forwards a few years, farm-in on the block, install EPS, open up, almost instant high water rates and rapidly declining flow rates over just a few days/weeks. However that was exactly why the EPS was conceived so as to prove or disprove connected volume and nature of that. In this EPS example the working hypothesis after results were reviewed was that the macro-scale fracture 'swarm' that formed the lateral sealing fault plumbed straight to the aquifer. Personally I had put my reservoir/welltest concerns on the table at farm-in stage so felt somewhat vindicated, but still it was $150m or so down the pan. 2) Wasn't there a Shell exploration well in the Med back in the 80s/90s that drilled into a fracture set, amazing rates, then nothing, bang. They concluded that outside the macro-fractures there was nothing connected. 3) A series of wells on a light oil field with GOR not dissimilar to Rona, where some wells would come in at 20kbopd and others at 5-6kbopd, and one could never predict which from seismic fault-picks, or from drilling losses, and nor could one a priori predict decline curves. Again the vast majority was fracture storage at all scales, but the seismic & processing really struggled to interpret it meaningfully and allocate it micro/macro. There are other analogues I could think of, but less directly relevant.

Thank you for sharing these experiences. It is easy to get carried away and forget that EPS success is far from given. If scenario 1) would play out for the Lancaster EPS, I would expect Hurricane to be left with a lot of questions and no money, and the current shareholders' investments reduced to nothing but a tax deductible loss.

I can appreciate the oil majors' reluctance so far, which can be examplified by BP not having invested in much flow testing on their own basement resource sitting under Clair. I've seen a lot of speculation after their transaction with ConocoPhillips this week that increased their stake in Clair, but I can't see that there's much to read into that concerning Hurricane.

Ah yes, now I recall that, but it seemed such an obvious point that I didn't really pursue it. I felt that was a consultant writing it down just because they had to. I cannot imagine anyone doing field development without keeping FBHP above bubble point. My interest is what is the actual GOR as this can make a big difference to development options.

Between the fluid samples and the well tests already performed, isn't the GOR known with a fairly high degree of confidence? I may be asking out of ignorance here.

SPE-84590 discusses GOR development in fractured reservoirs in general:

The GOR of fractured reservoirs normally remains lower throughout production, if the reservoir is properly managed. This occurs because liberated gas flows preferentially upward towards the fractures to the top of the reservoir, rather than horizontally towards the nearest wellbore as in a conventional reservoir. The liberated gas creates a secondary gas cap, or expands an existing gas cap, and the gas content of produced oil is lowered accordingly.

I didn't think of this dynamic - potentially solution gas drive could be a drive mechanism in the full field development.
SPE-137045, another paper I found discusses the waterflood application in Bach Ho - it seems quite complicated as a large transition zone has been formed between the injectors and producers due to preferential flow through the most permeable fractures. But I'm probably getting way ahead of myself thinking about a potential waterflood at this stage. Also, I'm not recommending to download either of these papers unless you can get them for free.

[dspp]

Yes I have seen this sort of thing. 1) For example one deep/HP exploration gas well that did an 18h well test with some very high rates and very little water. Fast forwards a few years, farm-in on the block, install EPS, open up, almost instant high water rates and rapidly declining flow rates over just a few days/weeks. However that was exactly why the EPS was conceived.

Thank you for sharing these experiences. It is easy to get carried away and forget that EPS success is far from given. If scenario 1) would play out for the Lancaster EPS, I would expect Hurricane to be left with a lot of questions and no money, and the current shareholders' investments reduced to nothing but a tax deductible loss.

Your Norwegian tax code is different than the UK one. Here we only get to offset losses against capital gains, not against income.

If that situation (scenario 1) were to arise then HUR would have no questions to answer. All investors have been fully informed of the situation. If they haven't read the material, or don't understand it, and have chosen to invest nonetheless then they need to go take a good long look in the mirror.

But yes, there are many risks here. Some technical, some project, some commercial, some market, some macro/sovereign. Success cannot be taken for granted and there are a very wide range of possible outcomes here. I have my own views which I have set out but I am very happy to hear other professional views, so yours is welcome. I am also happy to post about downside as most folks with even a bit of oilpatch experience only ever really see the successes, due to survivor bias in the work patterns. Therefore they are unconsciously incompetent in assessing risk, to use the jargon.

I can appreciate the oil majors' reluctance so far, which can be examplified by BP not having invested in much flow testing on their own basement resource sitting under Clair. I've seen a lot of speculation after their transaction with ConocoPhillips this week that increased their stake in Clair, but I can't see that there's much to read into that concerning Hurricane.

I think you are better placed than I am to know what BP are thinking.

I have very little knowledge of Clair, hence my asking about WoS papers. Even if there is a geology read-across between the basement under Clair and the Rona Ridge basement (and I really don't know), then my understanding is that there is NOT a oil/gas read-across. Isn't there a different charge source in Clair and/or hasn't it undergone biodegradation ? It has an API of 22-24 vs the Rona Ridge API of 42. Clair production peaked a t53k bopd and is down to about 23kbopd. If biodegradation is the problem then one would want to target deep basement structures under Clair - but do they exist, did they get charged, is it still there ? Like I say I'd like to read more, ditto for Foinavon and Rosebank and etc.

Ah yes, now I recall that, but it seemed such an obvious point that I didn't really pursue it. I felt that was a consultant writing it down just because they had to. I cannot imagine anyone doing field development without keeping FBHP above bubble point. My interest is what is the actual GOR as this can make a big difference to development options.

Between the fluid samples and the well tests already performed, isn't the GOR known with a fairly high degree of confidence? I may be asking out of ignorance here.

It seems less certain than one might assume. When I read through the public domain data I am unsure if they got fully cleaned up & stabilised flow, or representative samples to surface. Hence my flagging it as a risk very early on in my reading. Then some of the analysts picked up my concern and rebroadcast it, and now the company has acknowledged it.

SPE-84590 discusses GOR development in fractured reservoirs in general:

The GOR of fractured reservoirs normally remains lower throughout production, if the reservoir is properly managed. This occurs because liberated gas flows preferentially upward towards the fractures to the top of the reservoir, rather than horizontally towards the nearest wellbore as in a conventional reservoir. The liberated gas creates a secondary gas cap, or expands an existing gas cap, and the gas content of produced oil is lowered accordingly.

Yes, and these reservoirs are mostly quite shallow at crest. I'd like to see a good phase diagram, but that goes back to the point above. By the way if you read around the Halifax well(s) there is some indication there might even be a small gas cap in situ, but we don't have the data to be sure. I think that played a part in the Hal failure to clean up as they probably had no choice but to be very conservative in mud weight.

I didn't think of this dynamic - potentially solution gas drive could be a drive mechanism in the full field development.
SPE-137045, another paper I found discusses the waterflood application in Bach Ho - it seems quite complicated as a large transition zone has been formed between the injectors and producers due to preferential flow through the most permeable fractures. But I'm probably getting way ahead of myself thinking about a potential waterflood at this stage. Also, I'm not recommending to download either of these papers unless you can get them for free.

Thank you, but I know enough for now about waterflood in fractured reservoirs. What I am after are good survey or field-specific papers on WoS.

regards, dspp

[FabianBjornseth]

Thank you, but I know enough for now about waterflood in fractured reservoirs. What I am after are good survey or field-specific papers on WoS.

I had a look around OnePetro, but most of the papers give a quite brief description of the reservoir before delving into a tangential technical topic. The best one I could find on Clair was SPE-96316-MS, though I'm not sure if it will tell you much that you're not already aware of. Sorry that it's not very helpful, but it seems like it's hard to find something public at the right level of detail.

If that situation (scenario 1) were to arise then HUR would have no questions to answer. All investors have been fully informed of the situation. If they haven't read the material, or don't understand it, and have chosen to invest nonetheless then they need to go take a good long look in the mirror.

Absolutely - I probably came across the wrong way. I meant to underline that it would be very hard to make Lancaster a full field development in such a scenario, and particularly in any way that sees the current shareholders retain value.

[dspp]

Q3 presentation now up
https://www.hurricaneenergy.com/~/media ... Q-2018.pdf

(@ FabianBjornseth: Thank you for looking around the papers, I'll not rush. I think we agree on the main points. )

regards, dspp

[dspp]

RNS out to notify CA sell down from 6.90% to 5.77%.

(this seems to be in line with their aim of not letting any one share become too great a % of the CA portfolio)

https://www.hurricaneenergy.com/communi ... ws-service

regards, dspp

[NigWit]

Yes. If CA sell down faster than necessary then that will be cause for concern but if they buy again (if and when their other holdings rise giving them the latitude to do so) then that would be a positive sign.

[PeterGray]

RB was said to be buying recently. If so he's made a pretty reasonable trade on the ones he's just sold. He's kept his overweight HUR position under a degree of control and made a quick profit. It pains me to say so, but it looks like smart work

Peter

[NigWit]

I’d suggest that CA sold because it’s wise for them not to let their fund get overweight. You can download the articles of association from their website to check their rules, which do give a weighting limit of 30% that will not normally be exceeded but is not rigid. Nonetheless it’s very unusual for any fund to be as heavy in any stock as CA have been in Hurricane and testament to their confidence.

I think that CA’s confidence explains their recent buy, which they may have had little option but to reverse on the rise to 55p. I expect they were able to buy because several of their other holdings have performed well this year, including Ocado (which they have exited) Leaf and FairFX. These rises would have given RB latitude to buy Hurricane, which he did.

Anyhow, I think it’s good to watch what CA do. Not so much for small changes in their holdings but since believe that it would be cause for genuine concern were they to sell more Hurricane than needed to meet their own internal guidance. I haven’t seen or heard rumors of any signs of this yet though.

[FabianBjornseth]

The results from Lundin’s Rolvsnes appraisal well should be coming in soon. This is a fractured basement discovery on the Norwegian side. Although it’s not directly related to Lancaster/HUR, I would think the production test outcome (negative or positive) would impact the sentiment on FB in the region.

[dspp]

pjoe over on the LSE HUR board has made the very valid point that the BP acquisition of the BHP shale assets may provide a useful bench mark for current valuations. Se 09:44 on 27-July-18 :
http://www.lse.co.uk/ShareChat.asp?ShareTicker=HUR

The various releases I have seen are:
https://www.investegate.co.uk/bhp-billi ... 00039447V/
https://www.investegate.co.uk/bp-plc--b ... 00039448V/
https://seekingalpha.com/news/3374737-b ... 5b-deal-bp
https://otp.investis.com/clients/uk/bp_ ... id=1130194

From this all I can really see is

- Adds 190,000 boe/d production ( 45% of which is liquid hydrocarbons [i.e. oil or condensates, with the rest is gas]) and;
- 4.6 billion boe discovered resources
- Total cash consideration of $10.5 billion

pjoe makes an assumption on the split between 2P reserves, and 2C resources, and comes out with $15/bbl for 2P, and $2/bbl for 2C.

Looking at my tables I hold $15-$5 for 2P depending on whether it is actually connected and in production, or just has a viable plan (i.e. a FFD) in place. For 2C I generally hold $0.50 - $1.0 depending on quality of data and associated timeline for maturation.

Since HUR has a mkt cap of £1bn or so at present, and about 4.8billion boe resources, with about 30,000 bbl/d production about to come onstream, and drilling slots booked for 2-wells which would be expected to give a similar amount of production (if they could be produced ...), then I think pjoe is correct that these are helpful numbers.

Question: does anyone know the 2C/2P split in the BP / BHP shale assets ?

regards, dspp

[Eureka1963]

Question: does anyone know the 2C/2P split in the BP / BHP shale assets ?

regards, dspp

Is the following of use?

https://www.bhp.com/-/media/documents/b ... .pdf?la=en
Table 1: Net BHP Billiton Petroleum Reserves and Contingent Resources as of June 30, 2016. [Onshore US]
(The barrel of oil equivalent conversion is based on 6000 scf of natural gas equals 1 boe).

https://www.bhp.com/investor-centre/-/m ... rt2017.pdf
6.3 Resources and Reserves (pg. 248-254)

[NigWit]

I’ve what I hope may be an interesting thought.

Crystal Amber published their monthly NAV schedule earlier this week. Currently the total NAV of their fund is 252p yet their shares trade at 236p. In other words, ignoring costs and spread, you can buy 252p for 236p.

This is not a great bargain and indeed the discount has been reducing all year but one wonders if CA’s relatively risky position in Hurricane is holding their share price down.

I also see that CA have reduced their exposure to Hurricane to 23% of their total fund, at one time it was almost 40%. I don’t think this is down to lack of confidence, instead I see several of their other holdings doing well and have therefore caught up. Yet, on the other hand they have not added Hurricane for a few weeks.

Anyhow, it occurs that if CA’s shares are being held down by Hurricane, which you can judge for yourselves, then, if all goes well with the EPS, there will be a geared ROI at the same time as downside protection by using Crystal Amber as a proxy play on Hurricane. Indeed this is what Simon Thompson in the Investors’ Chronicle has been suggesting since January.

Whilst this would limit gains relative to a pure play on Hurricane it would also eliminate any prospects of total wipeout if there’s a disaster (remember that Hurricane’s bond holders have first call on any residual cash).

As FOIL approaches I’m considering shifting some of my investment in Hurricane stock to CA but I just thought I’d throw this out there and see if anyone else has a view.

[Sorcery]

Anyhow, it occurs that if CA’s shares are being held down by Hurricane, which you can judge for yourselves, then, if all goes well with the EPS, there will be a geared ROI at the same time as downside protection by using Crystal Amber as a proxy play on Hurricane. Indeed this is what Simon Thompson in the Investors’ Chronicle has been suggesting since

Depends on the size of your position, mine is about 5% of my portfolio. I can afford to lose that. If it was 10% I would be top-slicing.
Don't see the need to involve a 3rd party (Crystal Amber). If you have researched it, thought about all their holdings and think they are good stock pickers then perhaps you should make the case for them and buy them. If it's about being worried about the size of your position in HUR then reduce it imho, For me it's an average purchase price of 28p, now 50p, so good so far, hope to see £1.00 plus though.