88E Long Term Investors Group- London Presentation 9th Sept 2016

Hosted By: 88E Long Term Investors Group (Graham McHardy / Tim Ashdown)

Presented By:
Dave Wall - CEO - 88 Energy
Paul Basinski - CEO - Burgundy Xploration
Stephen Staley - Director - 88 Energy

See transcript below video.

Video:

Transcript
Tim Ashdown
Welcoming remarks


Dave Wall:
Thanks everyone for coming and a special thanks to Graeme and Tim for putting this together.

You know I’m not going to talk for very long, I’m not going to go through the whole presentation because most of you guys do understand it and we do have a long period of time for Q&A afterwards, so I’ll speak for about 10 minutes, then Paul will speak for about 10 or 15 minutes and then we’ll get stuck into the Q&A ‘cause that’s where I think we can really create the most value - by us understanding where we’re not communicating effectively with you guys and managing your expectations and things like that.

Let’s just flick through this quite quickly… so… standard disclaimer…

You guys know all about this. Where we are… down here in the red… 271,000 acres it’s obviously a very big parcel of land particularly for a relatively small joint venture. Typically this type of acreage position you would be seeing in a much larger company. And it’s fair to say that, in the lower 48 states we wouldn’t be able to do this because you would only have 3 years to drill out every 640 acres to hold the acreage by production. So this is kind of unique just in that sense, and then obviously the project has a lot of other unique aspects to it.

So just running through… you guys know all this stuff

Some of the highlights… obviously we’ve got an above-ground story here as well as the below-ground story.

The above-ground story:

  • Incentives from the State of Alaska allowed us to drill our first well relatively cheaply;
  • We were able to do a deal with Bank of America who co-funded the well, and now we have debt, which is offset by a receivable:- debt with Bank of America and the receivable from - it’s now AAA+ - State of Alaska;
  • Our acreage is bisected by the Dalton Highway, which is the only all-year-round operational access road in Alaska, and,
  • We have the Trans-Alaska-Pipeline System (TAPS) running through the acreage, which is running out of oil - and that’s the reason why the incentives were put in place in the first instance.

So that’s just a couple of the above-ground stories.
Obviously - we’re on the infrastructure - we can get to market - we have some all-year-round drilling locations, whereas the rest of Alaska on the tundra you can only drill in winter when the ground freezes - so there are some other advantages there as well.

And then if we get to the below-ground story and we’ll talk about the well now…

So… we drilled the first well and that was designed to mitigate risk.
So it wasn’t designed to tell us if this play was definitely going to work. But we’re trying to figure out if the things that would make it definitely NOT work were NOT present.

So - that’s kind of a slightly different way of looking at things.
If we were going to fail, we wanted to fail as fast as possible - which sounds kind of funny - but that’s the best way to stop all of us from wasting our time and money. We wanted to do it in as efficient a manner as possible from a cost perspective as well.

And we think we were able to do that - and obviously the result was very good.

All of the things that Paul (Basinski) knows, and we now know as well that are required for this vapour-phase, which is like the “holy grail” for these shale plays - we know that all these elements exist.

It doesn’t mean that it’s definitely going to work though. It means that we’re about 50% Chance of Success (CoS) is our internal estimate.

So the next well, which we had originally designed as a lateral, was designed to test the productive potential of the HRZ.

We know the reservoir is amazing.

But can we frack it efficiently, keep the fractures open, maintain good conductivity through the fractures, which means you get a high flow rate?

The reservoir can flow at high rates, but you need to be able to design an effective fracture simulation.

We think we have enough information on hand to be able to do that, but there’s always uncertainty.

So typically in these plays what you’ll do is you’ll have a geological theory, which Paul spent many years putting together; you test that theory which was Icewine #1, and then you move to the evaluation on the flow potential - which in every other play is done with a vertical well with a multi-stage stimulation.

We thought we might be able to skip that step and go to the next step, which is lateral wells - but what ultimately ended up happening once we spent the last nine months analysing the results from Icewine #1 - we couldn’t get to a point where the uncertainty was low enough for us to be able to take that next step.

So the objective of the well - and this well (Icewine #2V), or the lateral (Icewine #2H as originally proposed) - is to prove the productive potential of the HRZ.

So our job is to maximise our chance of achieving that objective.

And this (Icewine #2V) is the design that does that and that is the main reason why this design was chosen.

Things like cost-reduction… it’s a by-product.
Things like being able to test the HUE… that’s a cherry on the top.

But they’re not the drivers. The real driver is reducing risk, mitigating uncertainty and increasing the chances of achieving the objective which is flow-testing the HRZ.

So this is the design that does that, and Paul will talk a little bit more about that as well.

And this (table) we thought spelled it out pretty clearly but I guess it is hard to put in a table, which is kind of a sterile way of disseminating information, really what we’re thinking.

Are we less bullish on the potential of the HRZ?
Nothing could be further from the truth!

Do we want to maximise our chances of achieving success?
Hell yeah!

So how do we do that?
And really it's this strategic going back, re-assessing the strategy, again and again and again, until we’re comfortable that we’ve got it right. And now we are, which is why we’ve come out and said we’ve finalised the design.

So that’s that - and obviously Q&A - I’m sure there’ll be a few more questions.

In terms of the seismic, I think people probably expected to see something a little bit more mature, or maybe we mis-managed expectations there - but what we tried to communicate was that the first look, which we’ve come out with in this presentation was always going to be a bit of a tease.

So this green area here, this was the 3D seismic that was shot in 2015 using dynamite. And we’ve just purchased some 2D extracts - lines from within that box.

And that was obviously done last year so the processing was finalised earlier this year, only a few weeks ago really.

And then we obviously acquired the big blue box.

So… what we’ve seen is extremely good quality of data.

That’s obviously important. Investors just kind of assume that that’s going to be the case, but there’s actually quite a bit of work that goes into that - and it is possible for that not to occur if you haven’t done the planning right.

So having seen that - it’s very important for us.

You know - some of these images… it’s just squiggly lines and all the rest… and to me, to be honest… they are a little bit too… and Stephen (Staley) is here who is a geophysicist and a director - so if there’s anyone who wants to ask questions about the squiggly lines in a more technical fashion, he’s well equipped to answer those questions.

But what you can see quite obviously here - is, you can see these clinoforms which are really just all beach-fronts. So when you talk about pro-gradational - it just means that what we have is an inland seaway and eventually it was closed in over time - and you had all these beach-fronts that formed.

And what these are is they’re very ideal kind of geological setting for deposition of sand and reservoir. it’s obviously what you need for conventional oil and gas - and also the source rock as well - which is obviously important for both the conventional and the unconventional.

Something like this - it’s probably a little bit hard to see - but this is quite significant for us in that this tiny little green blob - we’re already seeing something that we had hoped to see - but we didn’t know whether we would see or not - especially not in such a small area.

And we can see this on a number of seismic lines which means that it could be of significant size. We’re not at a point where we can say how big and what does “significant" mean and all that - I won’t be able to answer that question - but you won’t have long to wait.

This here again - you can kind of see this mound of sand which is effectively what it is.

So that’s kind of it… and this is the recap of stuff that you guys already know about - so I’m going to leave it at that… you understand all of this stuff…

I’ll maybe just touch on this one just briefly (Cost Analysis slide), so this is something that we put out which we thought was pretty exciting as well - and then Brexit happened so we got caught out a little bit with that one - but ultimately, when we look at the parameters in the HRZ, the quality of the reservoir is exceptional.

Like I said - it doesn’t mean that we can fracture stimulate it effectively - but if we can get it to flow at its potential and you overlay a bunch of different cost assumptions and the fiscal regime in Alaska, what you come up with is a breakeven in our mid-case of less than $40 a barrel - and that’s very significant particularly in a low oil price environment that we’re finding us in at the moment… although hopefully that will change one day in the not-too-distant future.

And then just one last thing in terms of upcoming news flow…
- seismic results… the interpretation of the larger piece of acreage.
- the finalisation of the interpretation of the smaller piece (around Icewine #2V location)
That’s the kind of stuff into the end of the year… over the next 4-8 weeks

And then also we are in commercial negotiations with a number of parties about different deals to lower the cost of the well in some way. We are funded for the well now that we’ve changed the design but as I said - it’s a by-product. So we don’t need to come back to the market. Really what that does - it puts us in a very strong negotiating position and means that we can opportunistically take advantage of investments - whether they be from a strategic source - which might be somebody who wants to take equity in the company - but not at a discount, at market price, and committing to fund us on an ongoing basis.

So I think some people have questioned what I mean when I say “strategic” - but that’s pretty much it in a nutshell.

And then obviously on the industry side - bringing in parties on that front as well.

But as I said - we don’t need to raise money so we’re in a very good position.

So that’s kind of it from me - and I think Paul’s going to come up and say a few words…


Paul: Thanks Dave

Question:
Q: So your little bit just there about… (without being cheeky…) not needing to raise money… are you 100% sure about that?
‘Cause you said that last time Dave… (DaveW: There’s “needs” and “wants”) …and a few weeks later we had a Capital Raising

Dave: So I think people do get a little bit confused by some of this which is - there is a difference between a “need” - so “is your forward program covered by your current cash position?" - and the answer at that point in time was “yes" - but then if we wanted to drill another well, which everyone knew we did - and it was obvious that we didn’t have the money for that - so, how are you going to do that?

You have to raise money, or do a farm-out.
Q: I agree

DaveW: And what happened was… we had demand to raise that money… and so we did - and it was kind of opportunistic - the share price had gone up and that’s what we did.

Q: It put us in a very good position so I’m not complaining…

(Organiser: Q&A will be at the end and there is plenty of time for questions…)

DaveW: There will be plenty of time and we’ll answer all the questions.

[Applause]

Paul Basinski
Well thank you all this is quite an honour for me and thank you Tim and Graeme… it’s extraordinary what’s happened since this group sitting at the front, we met at the Globe, had more than a few cocktails, and it’s astounding what the Long Term Investors Group (have done) - it’s been extraordinary.

And the impact that it’s had on the company that Dave and I share and private(ly) I want to thank each and every one of you for your support and for actually being here. We would like to make this a fun opportunity as well as an educational one.

So I remember last year when we were visiting at the Globe…

…one of the questions that came up is… this project is quite a long time in the making… and the question was… how do you come up with it?

How does this happen? Because basically… this is a representation of using a toolbox that we put together, that we established in 2004 and 2005.

Anyway, people ask… what is this about? What is this thing? How did we get to this point?

And what I wanted to do first off - a number of people asked “tell me about this ACB thing” - and I just wanted to touch briefly on that - we’re gonna hit a few of the other high points - I don’t wanna be up here a belabour all of this stuff - I just wanna give you a feeling of the contexts for how we got here in the first place.

So - how was Icewine identified?

Well, we used the same technique that we used in the Eagleford in 2005 - and it’s kind of ironic because the workflow we’ve come up with now that we have all of the data is basically a page out of that same book.

The first well we drilled was called the Kundi (sp?). It looks almost exactly the same as the Eagleford - all of the characteristics - other than our reservoir’s quite much better. And we ended up doing a completion and that was for deeper objective and it ended up being the discovery at Eagleford. And we’ve taken kind of a page out of that - it’s a “best practises”. And so we’ll have plenty of time to be able to explain what that’s all about - but effectively the way we do this is… that I’m a big fan of studying history. And about the science of innovation and thought. Because - you know - you don’t find billion barrel fields all the time.

I was taught by John Masters - a gentleman that took me under his wing a long time ago - and effectively the approach that I’ve taken - and I think this approach works in all of life - is that, if you can become proficient in many different spheres then it allows you to be able to recombine things in ways that they haven’t been recombined before - to see things - to imagine outcomes that haven’t happened.

So when you do that - I call that “A” - then you get to “C” - that’s the “wow” - we have this idea, now it’s a crazy idea generally, it horrifies everyone - right - how can you get oil out of a shale? - that was the situation at Eagleford… well, real simple, you just had to get it into the right properties and make it a gas in the sub-surface and the rock wouldn’t know the difference, and when you bring it to the surface it’s mostly oil.

But like Dave said - the secret is… you can have a bunch of ideas - but most of them don’t work. So the ideal is, to fail fast, fail frequently, and fail smart. Cycling. Thomas Edison said “I didn’t fail 10,000 times discovering the incandescent light-bulb - I just eliminated 9,999 things that couldn’t work”.

So the point is, that the whole idea is once you get to this “a-ha” moment, that doesn’t mean anything. Now what you have to do is bring in subject matter experts - and now it’s not about knowing the answer. The problem with the regular scientific method. This is the original scientific method that happened before the scientific method. This method is the empirical method.

So what you do is when you have this idea you would [combine and recombine it with fundamentals] (?) who are the subject matter experts and these (Why? Why Not? What If?) are the “three W’s” in the Harvard Business Review - this is what they teach in business school - “Why?" "Why Not?" and "What If?” - and this is the basis of disruptive innovation. (Clayton) Christensen came up with this in 1997.

So the point is that, then what happens is - you start to “ping” - you ask questions - you “flesh it out” - and when you get to a certain point and it looks like it’s not going to work you learn from it, and you move on to the next one.

So what you are seeing here is the results of a zillion failures - but every once in a while the meteor hits - and this happened to be one of those after the Eagleford when we were using the same techniques.

I love quotes - another Edison quote: “I failed my way to success”
(I’m the living embodiment of that)

Thomas Jefferson: “The harder I work, the luckier I get”
(and guess what - that’s the secret!)

Winston Churchill: “If you’re going through hell, keep going”
(Churchill was right! We’ve been doing plenty of this talking about the stock price)

So - we are moving forward with this, and we are very very excited - and we’re really looking forward to clarifying some of the questions and uncertainty you have.

So we all know this - I think you’ve been picking it up as we go forward - but “what are the characteristics of a World Class Resource Play?”

These things don’t grow on trees - they’re very rare.

The first thing is - you have to have Resource Concentration. You have to have the oil in the ground. You have to have a lot of oil in the ground per acre/foot. If you don’t have that - you’re dead.

So that’s Porosity, Oil Saturation and Net Pay.

And that’s something that we have. And we had a searchers(?) company - name’s gonna go unsaid - who took a look at this and said this is the best shale reservoir they’ve seen in the world. I don’t know about that - but it’s the best one I’ve seen.

We have the resource concentration - we have an extraordinary reservoir.

As Dave said - that doesn’t mean anything about getting it out of the ground - that means we have the oil there.

The next thing is that you have the oil - but it has to be in this volatile phase.

And the reason why the volatile phase is so important - it’s very rare oil.

If you go out and ping the internet and look for the oil production of volatile oil - you won’t see any numbers. Because it’s only recently understood even what it was. It’s always gone with either black oil or wet gas. But the point is that it has extraordinarily different properties.

So in the sub-surface it’s in what they call super-critical phase.

And what we’ve learned at the EagleFord is when you produce it - it flows like a gas. When it gets to the surface, most of the gas is very, very rich oil. But - as it leaves the pores, and the pressure goes down and then gas forms in the pores - the gas in the pores creates another energy system in order to increase the recovery factor. That’s the reason why you get recovery factors because you basically have another artificial assist. And that’s the reason why EOG and ConocoPhillips have such extraordinary wells.

So this is an unusual phase and it provides it’s own energy in order to be able to get recovery factors that are like 15%, 20%, 25%. So this is extraordinarily important.

Once we have the Volatile Oil Phase - this is where we are now… do we have the right Rock & Fluid Mechanics?

Because at the end of the day it’s about the stimulated rock volume and the amount of hydrocarbon in the stimulated rock volume we can keep propped open?

So - we can frack this thing, but how high does it go? Is there propane embedment? How will it last as you bring down the pore pressure, because then effective stress goes up?

So these are the important questions. And right now - we are on the edge of this.

But the first thing we’ve got to be able to understand is - we have to collect the data so that we can understand these things - ‘cause if we just get a flow rate, that doesn’t tell us. Because the only thing you’ll know if you get a flow rate like in the Eagleford which was 320 wells - they were lousy wells - took them a long time to figure out how to do it. But we don’t have 320 wells.

So what we’re going to do is we’re going to use a vertical well and we’re going to do these injection followup tests and these neat little tools we’re going to be able to characterise a lot of these parameters so we can take the well flow that we get out of the vertical and scale it up because industry is very well aware of what the scaling factor from a vertical to a horizontal well is. Like in the biggest shale play going on in the Bakken (/ Latin ?) America, it’s mostly vertical wells - only now that they’re starting to convert over.

There’s a lot of stuff going on under the hood we don’t talk about - and I just wanted to give you a feel for it. We’re looking at kerogen - comparing the visual kerogen to the pyrolysis - we’re being able to identify what the nature of the kerogen is, what it’s kinetics are, that tells you whether it’s going to be… how much oil it’s going to produce, what phases it’s going to have. Everything we do is mathematics… everything’s based on physics. Everything’s based on these relationships - and if we don’t have an R-squared of at least 85, we don’t use it.

And so, that’s why it takes such a long time in order to be able to figure out - there’s a lot of IP that goes into this, in order to be able to find these relationships. Because if you have a return-reflectance of say 1.1, what does that mean? Is that oil? Is that gas? What is it? It can be all kinds of different things, and unless you understand these transforms you’re just guessing. We can’t afford to guess in Alaska - it’s too damn expensive!

We have these unbelievable spreadsheets - we have zillions of numbers - we have all this IP where we’re doing these maturation profiles. We’ve got thermal gradients all the way from Tierra to Fuego up to where we are - these are all constraining parameters. It’s easy to take a look and say “well yeah” - but that’s not how you get there. We have one well and 500 square miles. If you take the conventional approach, with the wave with the technique that we came up with in the Eagleford - we had actually less control in the Eagleford when we put that together than this.

And the whole point is that - if you’re looking for volatile oil then you’re looking for thermal gradients and you’re looking for seals. And that’s a very different exercise than what everyone else (is doing) - and that allows you skip a lot of steps and basically weed out huge areas - because you just know that it can’t work. And that’s the secret. It’s not finding it - it’s ruling out everything that can’t work. And that’s the origin of the Achilles Heels. Because if you’re trying to prove it - you can never prove anything - but you can sure prove that it’s impossible - and that’s how we’ve focused on doing this.

And we have core gas - and we’ve been able to convert that into a critical phase and API gravity - now we take the viscosity and these are run in all of our simulators when we talk about the flows we know the viscosity - and the viscosity is an amazing thing. If you go 10 miles to the north of us (Great Bear?) the viscosity is 15 times higher than we are - and when you put that into the flow equation that means 15X the flow rate. That means a (great well?) or something on the North Slope that you’re dead. So viscosity is key.

And on this core we have these ash beds we’ve done a lot of research on those - because it’s something we have to contemplate in our completion plan. We’ve looked at thorin(?) - we’ve looked at all these other characteristics because what we have to understand is the holistic package and how it will frack.

Lastly what I wanted to say is - Dave and I have an unusual relationship - we’re kinda Mars and Venus (Dave: “I’m Mars”) - the thing is we have this really unique relationship and somehow it’s working. It’s amazing - I mean sometimes we wanna kill each other, but that’s ok - we both have skin like an elephant!

The point is - that what we have between us - in these little itsy-bitsy companies - we have this differential expertise. We have proven methods. Dave has got a proven track record. We have proven methods that have worked before. We have the world's leading experts. In Houston we have the world’s leading experts - everything we do is QC’d by all of these guys - and if there’s a flaw we go back - like Dave said, we’re always evaluating.

The bottom line is - people may think we’re pivoting - that maybe we’ve lost interest. I can tell you that the project that we are representing in the HRZ has never looked better. And we are close on the tic-tac-toe board to the last step. But at the end of the day if we can’t stimulate it, we can’t keep it open and we can’t keep it propped then we’ve got a problem. But we have all the pieces in play and frankly I’m not aware of another play in the world that’s got this materiality - ten year term - plenty of time great leases - a state that’s bending over backwards - right next to the pipeline… we’ve got all the fundamentals and now we've just got to execute - do that vertical well and see what happens.

It’s risky. We don’t know what the outcome’s going to be. But we’ve sure come a hell of a long way from where we were even 18 months ago.
—-
Organiser: So we’re going to do a the Question and Answer session now… (remarks on how Q&A will work)

Q&A

1) Paul B mentioned in his presentation who was quality-controlling the data analysis. Can you elaborate on that and tell us who those people are?

PaulB: Well we’ve got a lot of people involved. To the specific point of the question, I’ll give you an example. Like for instance on the geochemistry and the thermal maturity - this is an imperfect science. (We ended up getting a large number) of conflicting pieces of information. None of the data ever actually works perfectly because it’s imperfect.

So what we did was… we bought in, arguably the world’s expert in the thermal maturity of the North Slope, Ken Peters. He’s a professor at Stanford and USGS, he’s the most published guy, he’s an expert on the North Slope - and we had him independently evaluate it and he came back with the same interpretation.

We’ve used StimLab, we’ve used CoreLab, we’ve used the best people that we can find - but at the end of the day on the interpretation too… you’ve got to make sure. You can always find what you’re looking for… but if you can find people that can tear it apart and they still come up with the same answer, that’s the approach and that’s what we’re doing.

This is an example with Ken Peters. And the reason why Ken Peters is important is he’d come out with an analysis in 2007 that Great Bear used - they bought 500,000 acres based on his analysis - he was 25 miles off.

But when we drilled our well, we showed that it was wrong, and if anyone wanted to disprove what we had it would be him.

So that was the point. You've got to make sure - you're testing this with disparate people that are looking at it without an axe to grind - and he kinda did - but the data’s the data and the interpretation’s the interpretation so that’s kinda the philosophy.

2) Now that we’ve decided to go with a vertical well, will we need to follow it up with a horizontal well?

DaveW: The short answer is “yes”, but not to prove the production potential, because we already will have done that, so what the next well, or wells will be - hopefully if we get this well right - it will be wells… (PaulB: Exactly!) … DaveW: What they will do is they will allow us to enter production really. So, there’s a chance that we do this well, and we don’t get the design quite right and we have to tweak where we land the zone a little bit - but this well is designed to try to mitigate that risk as much as possible - but it’s oil and gas, and you’re never going to mitigate it to zero. So, it’s like we’ve gone from 25% to 50% and maybe we want to get up to 85% - and then it will be tweaking to see where the right zone is to land the lateral and maybe tweaking the frack design.

(Moves closer to the mic)

DaveW: So basically the upshot of what I was saying is… yes we will need to drill laterals because that’s how the field’s going to be developed - but this well will tell us how and where to drill the laterals - and to me, in my mind, really, if we get it right - we’ll be drilling development wells.

It’s not another “science well”… still trying to figure out what we’re doing type of well, that’s not going to be the next step, if we get this right.

PaulB: No more “bait-cutting” - we’re going fishing.

3) We’ve got seismic from a very small portion of the whole play and we’re going to drill one well - I just need to know how do we extrapolate that so we get an idea of the total reservoir on the whole play and what the volume’s going to be and how much production we can expect - and where to put the other wells?
How do we extrapolate from one well and a little seismic to the whole thing?

DaveW: Paul will expand on my answer I’m sure… but the seismic is really unrelated to the unconventional play. There is some relationship but it’s quite loose.

So all of the years of work that Paul did putting it together - I might try to get just the initial map up which shows the well control - and really it’s based on that and some of the other legacy data - but the seismic that we’re acquiring now… this is for the conventional - so it’s not really related to the unconventional stuff at all.

So that’s why I said that's complimentary - so we know what the resource potential is for the HRZ - we don’t know what the resource potential is for the conventional - the seismic will tell us that.

PaulB: On trend although we have one well and 500 square miles - Alaska’s a big place, the play’s a big play - just like in the Eagleford - big play… the second well we drilled was 55 miles from the Kundi (sp?). We have effectively six wells and a trend.

And there are very good data wells. And we also have the new wells that Great Bear has drilled in the north. So we have done petri-physics using the best guy that I’m aware of - his company’s called Stimulation Petrophysics - so he’s my favourite type of petri-physicist - he’s a completions engineer. So he doesn’t get tied up in all the gobble-de-gook of petro-physics - this guy’s thinking about “How do you make money? How do you complete a well?”. He’s been in the business forever. He used to run Halliburton’s international group - and anyway he’s come in and he’s spent a long, long time looking at all these wells - and effectively we see during the petro-physics of a much bigger area than where we are, that the play’s not only continuous but in some places it even gets better (than / in?) where we are.

4) You say that after the vertical well we’ll need horizontal well or wells which would effectively take us to production. I thought 88 Energy would not go into production.

DaveW: No. That’s probably a mis-communication. It’s not that we’re not going to go into production - because even this well is going to produce. We’ll be in production If we get this well right.

So - Kundi #1 which is the well that was drilled in the Eagleford which we’re emulating with this play - that flowed about 150 barrels per day. So we can get 100, 150 - that’s possibly a question someone might have asked about our expectations. How that extrapolates into horizontal well performance, it’s 15 to 25 times. So that should give you some idea of what we want to get.

But that would be production.

So there was never an intention to communicate that we’re not going to go into production, because we certainly want to do that - but we will not be the people cutting the cheque for 1000 wells times 15 million dollars.

5) Do you have any projected point you want to get to before the sale?

DaveW: Really it’s about timing to some extent, but also about activity. For this asset to have the value created in the shortest period of time as possible which we always talk about as “creaming the curve” - you want to get those next few horizontal (wells) in as quickly as possible - and the permits that we have for this well would allow us to do that as long as the well’s successful. And then you’d want to drill a few more wells probably along the road. And then drill some delineation wells out to the East and West - and once you’ve done that, you’ve shown it works all over the acreage, you’re getting these fantastic flow rates hopefully (ideal world scenario) - and that could happen within three years. And at that point in time, someone needs to cut a big cheque to drill a number of wells.

PaulB: Or the price of oil goes up quite a bit - there’d be people willing to take that gamble.

DaveW: That’s right - and hopefully at that time we’d be in a more… (higher POO environment?)

6) So, we’d be looking to finance those wells before getting a joint venture / farm-in (partner)?

DaveW: It depends.

So - we’re always looking at what we believe is the most accretive path for shareholders.

So for example - if we drill this well and get 100 -150 barrels per day and the market goes - “yawn, that’s not commercial" or something like that - and it’s not meant to be commercial. And the market cap doesn’t go up enough for us to think that raising money at that price point is appropriate because it’s too dilutive compared to where we thing the real value is - then we’ll go to industry who DO understand the value - and we’ll try to cut a deal with them who’ll give us a better valuation - and that in theory makes the share price go up because you’ve crystallised the value point.

So it depends what happens.

When we talk about being masters of our own destiny - which we are at the moment - once you do that (cut a deal with industry) - you are giving away control - and that is worth a LOT.

So if can delay that (cutting a deal with industry) by getting an appropriate valuation for the stock and coming back to investors and giving them the opportunity instead of big oil to invest in this project - and we’re still kicking goals and not having failure after failure - we would do that.

And if we can do this organically with you guys and other investors then that’s the ideal way to do this. However it’s very rare that you’re able to do that.

7) Since we’re talking about flow rates can you perhaps expand on the expected flow rates from Icewine #2

DaveW: 100 to 150 barrels is what would be a good result for us.

8) Paul - what do you see as our final price buy-out - is it £30,000 per acre, £35,000 per acre, £40,000 per acre

PaulB: We won’t get to that point on the slope because there’s a lot of history on the slope as far as what transactions have gone on a land-equivalent basis. The Eagleford got up to $72,000 per acre that we bought for $280 an acre. The North Slope will never do that because the costs are always going to be higher, unless we get the well we’re really thinking about - but we never think about that - we think in P50 terms, what’s really probable. The success case (P10?) always takes care of itself. We’re thinking what’s most likely. And in the most likely case we think that the historical precedent on the slope has been - what would you say Dave…?

DaveW: We run a multitude of economic models - and it really depends on what flow rate we can get and the oil price is. So - if we get our P50 case and the oil price is say $85 per barrel - so let’s be a bit optimistic - you’re looking at something in the order of $20 billion.

Would someone buy it off us if it’s not fully developed for that amount?

No. You have to leave something on the table for those guys. And they might come in and extract 6 or 7 billion dollars at 18 percent rate of return per year for ten years - which would be good for their shareholders - but our guys don’t want to be there for that.

So maybe it’s in the order of that 10 to 13 billion dollars that we might be able to realise. And that’s an ideal world scenario.

In reality we look at Aurora which is a peer company in Australia - they got their asset to a point - and it was a much smaller acreage position - 22,000 acres - and they transacted for $2.6 billion and that was the height of the oil horn.

PaulW: Aurora were on the acreage right next to us at Eagleford - they drilled 55 miles away from where we were because they realised what the play really was and they ended up doing really well.

DaveW: So it’s a slightly wishy-washy answer and that’s because I don’t have a crystal ball. The upside is in that over $10B sort of arena - however there’s a range of different outcomes in between.

PaulW: The other thing that could happen though too - along the road, we might be able to get something in the range - an outcome for example of 20 wells per pad. We can put it into the pipeline almost immediately once we get the critical rate - and if we started to have flowing day barrels, now there’s another metric right? Lower 48 it’s a little depressed but back in the day they had hundreds of 20,000-a-day flowing day barrels. In Alaska it’s never been like that - but you get half a dozen, 20 wells flowing, 1500 barrels per day, you look at what flowing day barrel is - you put that into the acreage, it really starts to be a multiplier.

9) One of my questions has always been the migration of oil - from north to south, south to north, etc. What are your the reasons and the geology behind the migration of oil and which way it goes - from Prudhoe Bay down or from down to Prudhoe Bay from the HRZ or the Hue or whatever?

PaulW: This is the most studied petroleum system in the world. We know the oil came from right where we’re at. With isotopes, with phitane/crystine(?) ratios, with all of this stuff - but we also know that the only other place the oil could have come from is the other side on the Beaufort Sea. But there the petroleum system is limited and the timing wasn’t right to be in the kitchen relative to the HRZ migration and they know the timing of the HRZ migration. There were two migration events in Prudhoe - one was the Shublik and one was in the HRZ. We know that from the tar seal and all of that within Prudhoe Bay.

This is the crazy thing - Prudhoe Bay used to be about three times bigger than it is and full of Shublick oil. And it got hit by the Avak Meteorite - and it all drained out. So then it had to recharge itself. What are the chances of a huge fields gonna get hit by a meteorite? I’d like to think that our chances of getting this working are a bit better than that!

If the migration is from South up to Prudhoe Bay, why is there not a whole lot of oil seeps in the sea?

PaulW: Because you have the Beaufort Arch - and when the oil’s migrating up from the elevation we are - once it gets up there, there’s no way for it to go down because there’s a huge fall there - it goes down thousands of meters down into the Beaufort Sea - oil’s lighter than water, it just can’t go down.

So that’s the same as if it’s going South then - once it gets down to the Arch there’s nowhere for it to go?

PaulW: It’s trapped.

DaveW: Or it leeches out. And there’s millions of barrels of oil leeching out every day - because if there’s no seal it just slowly, slowly, slowly over time makes it way up to the surface - and it’s just very small molecules of oil just leeching out all over the place.

PaulW: And that’s why we feel very good about the top seal on our project. Because it’s the same seal as Prudhoe Bay - which seals the largest conventional oil petroleum accumulation in North America. And that’s a huge issue - over 50% of shale plays fail because they don’t have a good top seal. And we’ve got a damn good one!

10) The Alaskan Government - there’s a lot of changes going on there. What are the impacts on 88Energy?

DaveW: Good question. The way it works in Alaska - they are very reliant on the oil industry for their GDP. They haven’t really diversified their economy but they have put a lot of the money away. They have roughly $100B in funds and those funds are doing quite well. So they’re in OK shape. However, when the oil industry has a down-turn (like this) they find it very difficult to balance their budget. So right now they have a $3B hole in their budget. What this means for us is that the timing of the payment of the credits will be delayed.

When we did our deal with Bank of America, they factored this in to the deal and made us pre-pay a significant amount of interest - so it will be quite some time before we have to put our hands in our pockets to service the debt because we’ve prepaid. And the terms of that are confidential so I can’t say exactly how much - but it’s well into next year.

Really if I was going to predict what will happen - general election in November - they’ll have a special session early in the year and appropriate more funds to pay the credits, because they understand that delaying the timing of the payment doesn’t hurt the big guys, and it certainly doesn’t help the independents like us - we’re very well placed, some of the others are not so lucky.

11) Are you treating the non-conventional and conventional completely separately?

DaveW: Yes - and in an ideal world scenario - we’d be able to carve them out from each other and treat them as completely separate projects and also in terms of how they are monetised - because why give away one for free with the other if they’re both really good - so that IS how we are thinking about it.

12) How much of the field can support all-year round production?

DaveW: It’s actually all-year-round exploration from the road locations. There is all year-round production from all the fields in Alaska. What happens is you form a “unit” to go into full-field development - you do an environmental impact statement which has to be accepted by all stakeholders - and then you can build roads to connect up all the pads.

While you’re in the exploration and appraisal phase, before you’ve gone to that step - typically you can’t build gravel roads.

There is a gravel boundary consideration line just to the north of our acreage which in theory may mean that we could - but I don’t that we probably will need to.

PaulB: You ask a great question because the other side of that is about holding it in a unit. Alaska is very liberal on being able to unitise large areas. That’s something that’s impossible in Texas because it’s all fee(d?) - because it’s all owned by the state we believe with certain pilots we’ll be able to unitise large blocks of acreage to give us time to develop it efficiently.

13) Where is the risk exactly? If you’re saying the reservoir is there, where is the risk once you do the vertical drill - and why did you want to go for horizontal in the first place and then change it?

DaveW: This is the difference - understanding the definition of a reservoir - it has very good porosity and permeability - but it could have a bunch of clay or other minerals which stop you from being able to effectively frack it. So that difference between rock mechanics - producibility - and reservoir is an important distinction to understand.

We think that we’ve got both - and that is what this next well will de-risk.

Q: So it’s the rock mechanics?

PaulB: It’s the rock mechanics. We believe from the work we’ve done so far that the closest analogy is the Haynesville which is dry gas - so all the models we’ve done, simulations that are the basis of some of the numbers Dave’s been running the economics on - we’ve taken the PVT properties of the Eagleford and put them in the Rock Mechanics of the Haynesville. And so you have propant embedment and you have stress-sensitive permeability. And one of the things we know about our reservoir - it’s going to be really sensitive to how you bring it on initially. If you bring it on really fast in a near well bore area - put a big delta P on it - you get more proppant embedment - you end up shutting off the effect of trans specific (?) in the reservoir.

You can have the best reservoir and the best rock mechanics and still screw it up. The real key is understanding what all those different drivers are and then optimising what that is. No-one wants to produce a well any slower than it has to be - on the other hand, you need to understand the limits so you can optimise the ultimate value (of the well).

Q: And why did you want to go horizontally and then go vertically?

DaveW: We thought we could skip a step in the normal process?

Q: And why did you think you could skip that step and then change your mind?

DaveW: Because we had obtained enough material and log and data that we thought we would be able to get to a point in our interpretation and analysis that we could reduce the uncertainty in where we would land that well, but we can’t at this point in time.

Q: Why not?

PaulB: We had log quality issues. We had washouts in the hole. Because the formation is very over-pressured. Where we had core we have certainty - there’s no uncertainty. But there’s part of the hole that we didn’t get all of the information that we need - and so in this vertical well we're also going to be able to acquire the additional information as well as the induction falloff testing, we’re going to actually to frack into these zones - we’re going to be able to measure the height growth and the embedment and all the other things like that.

14) Can you use Icewine #2 to do the horizontal once you’ve done what you need to as the vertical (well)?

DaveW: Yes

Q: Well that’s good news.

DaveW: It’s a short answer, because it’s on one of the slides. What we said was - increased optionality - micro-seismic monitoring(?) well or used as a lateral well. So - depending on what we think is the best course of action we’ll produce from the well - and if it’s producing, great, we’ll just keep producing from it while we drill the laterals.

But when you do your lateral stimulation, if you want to determine how well a stimulation has performed, you really need a micro-seismic monitoring well.

PaulB: Because you need to know height and the effective prop-type and that wells going to be able to be dual (purpose?) for that - and after that - so when we drill the first couple of horizontals we’ll be able to use that well to monitor the fracks although we’ll have optimised them from the vertical - we’re going to use each one of the stages in those two horizontals to continuously optimise, because we don’t have the time to drill 320 wells. So we’re going to take the learnings - we’re going to learn on the fly as we frack. And that was one of the secrets as the Barnett was first developed because they were doing all this technology that hadn’t happened before - so you have to be able to kind of know how to move on the fly and learn on the fly.

Q: The reason I asked the question, because there’s a lot of confusion on online boards - which must be frustrating for you as well - and I think the communication is the difficult thing. A lot of people don’t understand this industry and the information coming through the RNS doesn’t necessarily give us that information. (Thanks for coming in to explain in more detail).

DaveW: Something conveyed in text doesn’t necessarily convey tone - so there’s a lot of things you just can’t communicate in text. Great to have the opportunity to come here and explain in more detail.

15) When we will know about the rock mechanics? Is it March?

DaveW: So the planned spud date for the well is March. And the reason it’s March - we could start drilling very soon, because permitting is well in hand and all that - but we wanted to reverse engineer back from when it’s easiest to flowback and also a lot cheaper - which is the warmer months so that's June, July, August.

PaulB: You don’t have to warm up all your frack equipment, your sand doesn’t freeze and all that.

DaveW: So if we spud in March, we should be flowing back after cleanup and some of the tests that Paul was talking about in July.

And this is something we probably haven’t talked about too much - but it is important to us - the company to the north of us (Great Bear / Otto) - we thought they were going to drill earlier this year and they delayed their program - and it looks like they are going to be drilling as of January next year - and one of those targets is very big and very close to the border of our acreage - testing the same plays that we’re chasing in the conventional stuff, that we can already start to see a little bit of on our seismic. So, it’s going to be a pretty exciting first 6 or 7 months of the year - but having said that, they could drill two dusters and so could we - and our fallback position being the conventional play could be given no value by the market. So, in some ways it increases the risk - but it also means it could add a significant amount of value quicker - without us having to spend any money. And similarly, if we prove up something, some of their acreage will be good for the shale play.

PaulB: They’re not going to be testing the shale - they’re focusing exclusively on the conventional.

16) You mentioned the mechanics of how the gas in a super-critical phase is released and it has a second energy - can you explain that a bit more and maybe relate that to the recovery rates you mentioned above 25%?

PaulB: If you look at EOG’s reports - and EOG are very clever - if you decompile them, then they’re much higher than what people say. We’re using 17% because that’s well within the range of what’s already been demonstrated. But the recovery factor ultimately is going to be a function of the stress-sensitive permeability. But with respect of the phase itself - it’s a super-critical fluid in other words it’s a gas - but when it gets down to this bubble point, then it starts to release liquids.

People in Eagleford didn’t think Eagleford could work because they thought that as soon as you start producing, the liquids would drop out in a near well-bore area and cause a perm block - and you’d never be able to get the oil out. And that’s a really great theory - but the problem is all that that pressure drop happens within a centimetre of where the fracture is. So that pressure drop is happening within that super-tight rock - and after that you’ve got thousands of psi of flowing pressure and it keeps it in that phase. And so what happens is that drop-out does happen but it happens inside the pore. And when it happens inside the pore, because of the surface chemistry of the pores the gas is adhered to the edges of the pore - and it forces out other things that haven’t gone to gas yet. So what it does is it squeezes it out. Because in volatile oil - which is basically a super-critical gas - there’s actually three different types of oil in volatile oil - there’s condensate, and there’s two types of volatile oil. The only way you can really understand it is if you get into the physics and you’re looking at Feccant(?) curves and all that. But there’s a big difference between our oil and condensate, because our oil has a much higher - it’s C15+. And again, the reason is, because when you get to wet gas, it’s much more mature - all that’s been cracked to the gas. But this hasn’t been cracked, because there hasn't been any cracking done yet. This is all about the kerogen kinetics. It’s just a different base and that’s why it’s been so poorly understood.

17) If the 2D comes in as expected or even better than expected - what’s in your head currently as the time scale for monetising the conventional?

DaveW: Good question - and it does rely somewhat on the results of the wells to be drilled to the north of us.

So there's a lot of permutations here. So for example if they (Great Bear) have successes in those wells and we don’t have success in the HRZ, our share price would go down, and then it depends whether at that point we see the value in conventional being much greater than what our current share price is - and if it is, we wouldn’t raise money to drill a conventional, we’d have to farm it out. And that’s this whole thing of picking the path that’s the most accretive.

Those (conventional) wells will most likely need to be drilled on the tundra, which means that the drilling window for those wells is January to May - so if we get our results this year, the possibility we can build a prospect from the 2D is OK but not fantastic. 2D is usually useful for generating leads, and where you’d need to go back and possibly concentrate and shoot 3D. So we’d need to go back the following winter, shoot 3D and then go back the following winter and drill the wells. So - we’re talking 2.5 to 3 years before we’d be able to drill conventional prospects.

Q: And funding that?

DaveW: As I said, whatever’s the most accretive for shareholders. So, if shareholders think it’s worth close to what we think, we’ll come to them and ask them to help us fund it, if they want to obviously. And if they don’t and we think that industry values it higher than the market does, we’ll go to industry and farm it out.

PaulW: With respect to the conventional play - Stephen could you come up and give an assessment of that play?

Stephen: Obviously most of this here is about the unconventional - that’s “Plan A” - that’s the biggest part. But let’s not forget the conventional potential we’ve got here - because it’s substantial. And I’ll go through a little bit more with you on that.

This is just to remind you what we’ve got in terms of seismic coverage.

The green is 3D - so that’s very intense data - we’ve bought what we call 2D slices out of it. And that enables us to get a very good idea of what’s going on there.

The blue area is the data we acquired ourselves this Spring - that’s 2D - as Dave says, probably not tight enough to be able to produce prospects from, but we can likely find some good leads - the larger leads. So now we’ve got coverage on the acreage.

When we first got this (acreage), there was very few seismic lines here - 1980’s vintage - and you’ve seen - the quality wasn’t great. But that’s all changing now…

I know it’s quite small - down at the bottom here is a seismic line running west to east - if you can see the green blobs - they’re all different types of plays that you get at different depths of water - millions of years ago back in the cretaceous, hundreds of millions of years ago. The great thing about this is that you have land to the west, throwing off over millennia sediment towards east, and continuing to do it. And what it means is you have the potential for what we call “stacked plays” - so if you find the right location you can drill 2,… 3,… 4 independent targets with a single well. So you’ve got potentially 4 "rolls of the dice” from the cost of one well.

See how good the data is now. We can start to see these plays.

Topset play - that’s shallow water. Could be a beach, could be a delta.

Clinoforms - as Dave explained, this is the shelf coming down. And the base of the shelf is where you get sand dumped in great piles.

Geophysicists get quite excited about this. See the strong “red” thing - seismic is a very complicated echo. The vertical axis is time - and along the top is a surface location. And when you see something like this (blue top line) - that sort of structure on one line, you start to get interested. It could represent a deepwater fan - a “pile of sand” - typically a pile of several sets of sand all bunched up together with shale in between them.

This is the same feature - it's a feature we can map over several lines. It’s too early to say anything about volumes yet as Dave said. But the fact you can follow the same events over several (seismic) lines gets us quite excited.

This is two seismic lines meeting in a corner - hence the chevron effect. You can see the red event. The “blue/black” one here. And you can see these things here just stop. This is other sediments covering up this fan. And you’ve got other things that go right across so it’s covered it up. So you know you’ve had something that’s “stood proud”. And geophysicists get very excited about that.

So what does it all mean?

As Paul pointed out, the USGS outfit (no axe to grind outfit if ever there was one) - has identified the Brookian - and what I’ve been showing you is called the Brookian - as the biggest thing left in North America. They reckon there’s about 2 billion barrels to come out of it. And there’s already been this big discovery to the north. There’s the big discovery by Respol - 1.4 Billion barrels - (PaulW: “Which will be the largest conventional discovery in North America in 40 years”) - so that’s rather large. So that’s an analog to one of the plays we’ve got. And you’ve got other fields that are not shown on here like Tarn field - which we believe is probably a close analog to that fan I just showed you. And that’s smaller - that’s about 100 and something million barrels plus about 165bcf of gas.

So there’s an awful lot of potential. And of course we will be keeping a very close eye on what our neighbours to the north find in those wells. One of those partners is a listed company - Otto (ASX:OEL) - so they will be having to announce things.

We’re excited because they picked these locations after shooting a thousand miles of 3D and one of the locations is within 4 miles of us and we can also see evidence that the play continues into our area so we’re kind of excited.

Q: And when are they drilling?

DaveW: They're drilling between January and May so we expect results will be out within that timeframe.

18) What sort of volume of conventional would you deem is big enough for anyone to be particularly interested in?

DaveW: So, if you’re on the road - so say for example Mother Nature was kind enough to put something close to the road - probably looking at as low as 30 million barrels if oil price was in the mid-60s.

So that would make a bit of money. It wouldn’t be fantastic, but you’d definitely do it.

As you start to get further away from the road and existing infrastructure - so some parts of our acreage up here to the north are close to existing fields and you’d be able to tie back in to existing infrastructure.

But if you were out by yourself and further away from the road / existing infrastructure then you are looking at bigger sizes. So, say on the western border of our acreage you might need 150 million barrels to want to go and do a development and tie it back, because that’s about 35 miles.

Q: So how much are we hopeful of finding?

DaveW: The simple answer is a lot! (laughter)

StephenS: We’re too early at this stage to run volumetrics - that will happen. What we can say is that they are likely mainly stratigraphic plays. They are not necessarily structures that necessarily form a dome or modified dome. They just run up until they are sealed at the top by a different type of rock - a shale essentially. And they sit right on top for the most part, or very close to the HRZ. So getting the charge of hydrocarbons into them is relatively easy.

So it’s relatively low risk. Of all the wells that have been targeting the Brookian over the last few years, as long as they’ve got 3D seismic to base those wells on - they have a 60% chance of success. And for exploration that’s excellent. You don’t find that very often.

PaulB: But at the end of the day when you run the full-field probabilistic, stochastic volumetrics of what could be the ultimate prize, it pales compared to the HRZ, and that’s the reason that’s our primary objective.

19) How would you compare it to Cove (Energy)?

StephenS: In many ways it’s similar but in some ways it’s different. Cove was completely conventional. It was based on really 3D seismic and well controlled to be able to calibrate that 3D response. And when we had that first success, we knew that we’d reduced the risk massively because we could define where to drill the next well just by looking at the seismic response and that’s why we had that stream of successes.

This is obviously mainly unconventional - so the journey that we’re on is a different one - proving it up. You know we talked about proving the different things up is completely different for conventional and unconventional. However - we are equally encouraged at this stage as we were at this stage in Cove with this project. And the beauty here is that Cove we had 8 and a bit percent with Anadarko as the major operator offshore Mozambique. Here - we have 100% of ownership on this stage (88E + BEX). Our ability to make money for shareholders is that much greater.

20) You see your market cap value being possibly $10B - which puts around a £2 share value each - but that’s based on 4.6B shares at the moment. How much more dilution do you see before we get to that value?

DaveW: There will be more dilution of some form because you either have to fund it by raising equity or selling part of the project which is also dilution. So - like I've kind of been belabouring the point - but it’s all about who’s most accretive for shareholders, and what’s the oil price - how much does the share price go up, if we get 100-150 barrels in this well, and how much the flow rate is in the next well - whether we can continue to fund organically in an accretive way.

So - it does really depend. And it also depends whether - say the oil price pops to $80 next year, and we’ve drilled this well and we’ve identified some conventional prospectivity - and Otto’s drilled two successes - and someone comes in and makes us an offer we can’t refuse - there’ll be zero dilution - we’ll be gone!

And it would make sense for us to take something. Say it was 50p or 60p but we're now giving all the risk to someone else, and we can achieve that in 9 months rather than trying to hang on for longer to get a higher target. There’s a whole bunch of things to consider.

But the shorter answer to your question is that we’ve gone through the really dilutionary capital raising events - that’s why we’ve got 4.5 billion shares out there - but if we can maintain a decent value in the stock - future capital raising if we have to do them will be far less dilutionary.

21) There is some more acreage coming up - what’s our chance of getting some more?

DaveW: The way I look at it is - we have 271,000 acres - which is A LOT for a small company. If anyone wants to get acres to the east and west of us, they’re going to have to come through us. Also, any development is going to have to be built out from the road. So, what’s the NPV of that?? It’s probably not going to be that great?

So - are those acres that attractive the further you get away from the road? There’s a question mark there. Will someone else go in there and pick them up? I don’t know the answer. Is it attractive for us to go in there and bid on them given we’ve got 271,000 acres already? Probably not.

The minimum bid is $25 per acre and that’s pretty close to what we bid on the acres we picked up last year.

PaulB: Like Dave said, if someone comes in and picks up those acres, they gotta come through us, which means they’re doing a deal with us.

22) A couple of years ago you offered shareholders the opportunity to participate in a placing. Would that be a possibility in the future?

DaveW: So I guess this is a question about the mechanics and the regulatory environment - so, in Australia, when you do a placement without a full-form prospectus it’s only eligible to sophisticated investors, which is defined as people who make $250,000 per year or a net worth of $2.5M. And that’s not all of us, let’s be frank.

So in Australia, it’s pretty hard, unless you do a rights issue or a share purchase plan.

So we did the share purchase plan at the end of last year to give everyone a go, and guess what? The share price tanked. And we all know why, so I’m not going to belabour that point.

So it’s a question of whether doing that - under that mechanism - is going to actually help the people who want to be involved - when you’re going to get filled in by all the traders - and the answer’s probably not.

If you are a long term investor group - how would you do it?

And it’s not for me to say to you guys what you do - but these are just a couple of ideas - and someone in the room smarter than me will figure out a better idea…

You all get an account with the same broker - I do a placement - I call the broker and say “make sure the 88E Long Term Investor Group” is looked after.

Or someone sets up a unit trust and then they approach me whenever we’re doing a placement - ‘cause we always announce it on the ASX because we go into a trading halt. And then you get looked after that way.

Or probably there’s another way to do it. But it will take a bit of work.

But in terms of being able to look after each individual investor if they approached us individually - I don’t know the answer to that. In Australia you cannot do it. On AIM you may be able to do it. I’ll have to look into it. I think it is possible over here, but I’m not 100% sure.

Graham (organiser): We have about 750 investors in the long term investors group so that’s something we can continue a dialog on and see if there’s any mileage in that.

23) The cash raising you did a few months ago to sophisticated investors and institutional investors at a price around 1.9p - do we know if they are still invested or have they taken their cash and flown?

DaveW: This is another one of the vagaries. In Australia it’s very easy to track the register. In the UK it’s a little bit more difficult. There is a register interrogation underway and I’ve seen the early results from that. So the institutions that came in are still there. I can’t tell about the retail guys because I don’t have the granularity of detail. And in Australia about half of the people that came into the placement have sold. And most of those in recent weeks when the share price was going up towards that 6c mark.

Q: So on reflection was it a good thing to do? I know we needed to raise the cash, but seeing the guys taking the money and run…

DaveW: I will never judge anyone from taking a profit - or for selling the stock when they need to sell the stock. That’s what the market is for, right?

So there’s plenty of facilities, like line of equity facilities where you draw down, the person who takes it just belts the stock into the market and its a never-ending, what we call a “death spiral”. Would I take on one of those facilities? Of course not! Because you know 100% of that stock is coming into the market regardless of whether the share price is going up or not, and regardless of their view of the prospects of the company.

But investors that come in all have different needs. So - after two or three months decided to take a profit because you’ve got 80% profit… and most of the people when I look at the register I can see - they’re not selling out completely, they’re just selling half on average of their holdings. Some people sold completely, some people sold a third, but on average about half have come out - and that would be my guess for the retail guys in the UK here as well.

24) Can you explain a little about the options (ASX:88EO) - particularly for the UK investors?

DaveW: When we did the initial raising for the company - the second round that we did in order to purchase the acreage that we picked up after the deal with Paul - we put down 20% and we had to find the balance.

That capital raising was done with a 1-for-2 attaching option. And in Australia, if you have enough option-holders, you can list those options so they trade like an ordinary share. So those options are the main class of options that are out there as listed options with a strike price of 2c exercisable in March 2018. So it’s almost like another class of share in Australia. And in that round, no-one in the UK was interested in investing in the company at that point in time that we were able to get in touch with.

So, we had a different broker at the time, and Cenkos is the kind of broker who did a great job for us and they’re institutional, so they don’t have retail clients on their books. So, it was quite difficult for us to tap any retail interest. It may or may not have been there at that point in time for that capital raising.

But we’re endeavouring to try to fix that and that’s one of the things we just touched on here and one of the reasons why we want to talk to you guys so if there is a way for us to look after you if we do raise money - we will do it.

25) Is it possible that the rock mechanics from their wells come from our acreage or vice-versa? How does it stop? I’d rather we nicked their play than they nicked our play!

PaulB: “Fair enough!”

StephenS: (Clarifying) Are you referring to “will they drain our oil across the boundary?”

Q: Yes

StephenS: They are close, but I think it’s likely that what they’re looking at - although it’s very much the same sort of thing as the first thing we’ve seen (Note: I believe he's referring to the green blobs on seismic here) - is probably it’s twin.

PaulW: Piles of sediment

StephenS: Yes. So probably not the same pool of oil. It’s possible, but it’s quite unlikely.

PaulB: If that’s the case, we’ve got a billion barrels.

DaveW: ‘Cause it’d be pretty big

StephenS: Yeah - nice problem.

DaveW: In America, just as a point of interest, typically what happens if you have oil that is shared across different acreage positions, you go into what’s called a pooling arrangement so there are some jurisdictions where you can drain oil from another person’s acreage - so it’s like “first in, first served” basis - but that’s not the case here anyway.

StephenS: In the UK it’s generally called unionisation - and the same applies to North America. You can’t just pinch somebody else’s oil. You’ll get experts in and they’ll adjudicate and decide whose is whose.

26) There’s a lot of space between Icewine and Prudhoe Bay and you’ve mentioned a bit about conventional that people are looking at (in this space) - what are they looking at in terms of the unconventional between Icewine and Prudhoe Bay?

DaveW: Well Great Bear did have a look at the unconventional. They’ve never really come out publicly and said what their real detailed results are but we know that they were focusing mainly on the Shublick which is the source rock that has 70% of its oil in Prudhoe Bay - so from that you can guess that it’s quite “leaky” - for us on our acreage that source rock is buried much deeper and it’s definitely gas. We are not interested in it.

They (Great Bear) said that they had an encouraging result but without the detail you can’t tell what they really think however they have changed their focus to the conventional so maybe you could read something into that.

And no-one else is chasing the unconventional plays and there is no way to access any of the unconventional plays on the road apart from Great Bear who are after mainly the Shublick play - and us, who have the HRZ play. And we both have ALL of the road acreage. And without that, you wouldn’t be able to develop economically an unconventional play on the North Slope.

PaulB: We do have another bit of an advantage and that is the surface topography because one of the issues that Great Bear has had is that they’ve had flooding - Sag River will jam with ice, it’ll flood - they have massive floods - and where we are, what happens is we’re going up to the Brooks Ranges (?) - we’re getting higher. So where we are - our acreage is right at the beginning of where you start to get elevation advantage. This is an important thing with respect to 360 (days per year?) operations and stuff like that. Our acreage right now appears to be all above the flood of the Sag River - and that really can’t be under-estimated with respect to full-cycle development.

Q: So every day, you’d choose our acreage over the north (Great Bear)?

StephenS: [Nods in agreement]

PaulB: Indeed!

DaveW: It’s fair to say that if you could transpose the conventional from the northern acreage into our acreage we would be pretty happy with that [PaulB: nodding] because basically how it works is the further south you go the deeper the sediments are.

As sediments are buried deeper - except for the weird Paul Basinski HRZ shale - typically you get a reduction in porosity and permeability. So we’ve obviously with the shale got this crazy porosity - permeability is still tight - but the sandstones when you get to a depth of the HRZ, they have porosities that are not dissimilar - and that’s ok for a sandstone, amazing for a shale - but you wouldn’t want it to be much less and you still have to frack a sandstone at that depth with the 13% porosity.

But as you go further to the north - so this one (Repsol) that’s just been discovered - 1.4 billion barrels - that’s an average of about 22% porosity at 6,000 feet of depth. So we have that in the shallower sequences, but not in the deeper sequences.

27) Are you able to tell us when you would commission the next Independent Resource Report (IRR) - and how easy is it to find a company that can analyse your data because it’s so unique?

DaveW: So this is a pretty topical question. We do have a difference of opinion between the most recent IRR on the unconventional versus what the independent consultant did.

Would we continue to use them? I guess we’d have to have a little bit of a heart-to-heart and understand the differences better. And last time as with a lot of things we’ve been doing up until this point, we’ve been doing everything on a just-in-time basis, and we were trying to get that out as quickly as possible. So, we didn’t really have time to go back through all the detail, assess the differences, try to make arguments, get them a bit more aligned and possibly educate them on some of the things they may not have picked up that we know they don’t know.

So if we can accomplish that or we think that even they disagree for the right reasons - then we would continue to use them.

Q: So do you have an idea on when you expect that to happen on the seismic?

DaveW: So on the unconventional side of things because we’re drilling in the same area, we’re going to test the production potential probably what would happen is they might not say - because basically what they said was “about 40% of the acreage would be productive in the success case scenario” - even though Paul’s predictions about what we would see in this well were spot on.

Which means that the model for mapping the fairway works.

But they gave us no credit for that - so before we drilled the well it's 40% of the acreage - after it’s 40% and it just got increased, basically because we picked up more acres. And then the Chance of Success (CoS) also went up by 50%.

So, would they then give us credit because we’ve flowed it on more - probably not - if we can’t convince them that our methodology for mapping is really good. So they might just say “look, you’ve decreased the risk again” and we get an upgrade on Chance of Success. So that’s possible.

So if that’s the case, we all know that we’ve de-risked it because the oil’s flowing out of the ground now - would it be worth doing an updated IRR on that basis - it would not.

And I guess, when you think about it - once we start flowing oil out of the ground - the IRR’s on the prospective resource become less meaningful. And then once we get a reserve out of the well bore for production, then that can be extrapolated over all of the acreage and when you do the delineation wells, that’s when you actually get the real value from industry potentially on the prospective resource or the larger resource over all of the acreage.

Q: Just to dig into that a little more, you said “probably not use D&M (DeGolyer and McNaughton)”..

DaveW: (Clarifying) No - I didn’t say that. I said “may not”.

Q: What’s the cost of the IRR?

DaveW: They do vary, and we are bound by confidentiality on what we paid for our one, so I can say that I know of other ones that cost between $30,000 and $70,000 for this type of thing - but I’m not saying that that’s ours.

28) I see the acreage there and I see companies but what I want to understand is - are there any producing companies around our acreage?

DaveW: No there is not. That’s the short answer.

So you can see up here the production areas, they’re all on the northern part of the North Slope.

When Prudhoe Bay was discovered in the 60s they then went out looking for more Prudhoe Bay’s and they found Kuparak which is like the second or third biggest conventional oil pool in North America and they potted a few wells down here but they were drilling a line because they had really crappy seismic and - if you look at Otto’s presentation they’ll say that that this Pipeline State-1 Well (1988) is a discovery - but it’s on the other side, on the edge if you like, of some of the larger features that extend out on the acreage and it wasn’t big enough - because they (in the 60s) were looking for billion barrels.

Now - like I said before - something that close to the road - 30, 40, 50 million barrels would be pretty good.

And that prospect that they’re drilling down there has two stacked horizons - one’s 330 millions barrels (mean recoverable) and the other one’s 100 or so - so that’s like a 450 million barrel prospect that they’re drilling down near our project.

Q: What company is that?

DaveW: The Australian-listed company that has 11% is called Otto Energy (ASX: OEL). And the company that’s the operator is Great Bear.

29) There’s rumour that Alaska may put a gas pipeline in - if we have gas within our acreage, is that of interest to us?

DaveW: It is, but it’s more longer term.

So for example, a scenario in which that could add value for us is in the case where the governor of Alaska as you are rightly saying is really pushing for this Alaska LNG project. So if they can actually push hard enough to get that off the ground - and it’s going to be a multi-year development - and we can show that we’ve got oil and gas on our acreage - which there will be some - then that will increase the value when we monetise the asset.

Are we going to be part of the Alaska LNG project? Probably not.

At the moment, the value of the gas is really for re-injecting into the sub-surface to enhance oil recovery.

30) I read somewhere that the oil we will be producing will gain a benefit when it goes through the pipeline because it’s adding quality?

DaveW: So it’s subject to commercial negotiations that we’re yet to have because we don’t actually have the oil yet, but based on our understanding - and we do understand that based on the quality of the oil you put in, there is a mechanism called the Quality Bank already for which different qualities of oil receive different prices, so the higher the quality the better the prices you’ll get.

So it’s possible that because we’ll be producing a different type of oil again - this volatile oil with this 48 degree API - versus the current highest quality oil that’s going in is 38 to 42 (API) - we could get a bump on top of that. That’s subject to commercial negotiations before we can really firm that guidance up.

31) The “marriage” (between 88E and BEX) seems to be working really well - what happens if a “divorce” happens or we “cream the curve” and we want to exit, or one party wants to exit before the other?

DaveW: Basically what happens - and like Paul said before, we communicate very well - and mainly because it’s a very open communication. So - what he’s thinking, he tells me - what I’m thinking, I tell him. Sometimes we don’t agree, but we always come to an arrangement, depending on what it is.

And usually what happens is, he says something, I’m completely horrified (joking), and then he explains it to me later and I get a better feel for it. Or I say something to him and he’s insulted, and then I say “well, that’s not what I meant” or whatever.

PaulB: (laughing) It’s true!

So that’t the kind of thing that I anticipate if there is a divergence - and this is obviously quite possible, where the needs of our shareholders don’t align with the needs of Paul and his shareholders or wants - we just come to a middle ground somewhere, and I think that we’ve got a relationship that will allow us to do that.

32) How do you stabilise the market cap volatility of the company over the next year?

DaveW: That’s the challenge right? And there is a way to do that - and that is to change the flavour of the structure of the register.

So the last placement that we did we brought institutions in and they’re still there. And as we discussed, the retail folks sold out half but the institutions did not. So they (institutions) become a more stabilising force. But they’re at a pretty small percentage now and we need to grow that to reduce the volatility or find more sticky, high net worth - or somehow drive the traders out of the stock.

So that also becomes a bit of a double-edged sword as well because sometimes you get these overshoots arguably (in the share price) where it just goes out of control - is that good? People love the excitement of the ride I guess - but then you’ve got to take the downside as well.

So ideal world, it just slowly goes up and then we go “pop” and get taken out and we’re all rich.

But the reality is for the next at least year whilst we’ve got three wells being drilled all around us - and our own well - it’s going to be volatile - but you would guess that the trend would be upwards as we get closer to these high risk, high reward events.

It’s a challenge, but it’s something we are thinking about.

If the oil price recovers, we may be able to get some of these guys to buy the stock on market - but at the moment it’s not what’s happening in oil - it’s still a bit unloved.

33) You mentioned volumetrics earlier - when would you put a figure on the conventional - is that in the next announcement in 4 weeks?

DaveW: I don’t think we ever said there would be an announcement in 4 weeks.

What we’re guiding is that over the next 4 to 8 weeks we’ll have finished our interpretation and there will be some initial volumetric work that goes with that.

Q: Would that require 3D to finalise that?

DaveW: No. Basically, what the 3D does is that it upgrades your chance of success and it also can mature a “lead” into a “prospect”. So it’s possible that we can define some prospects off the 2D and people do drill leads as well off 2D data so it’s all about this reduction in risk and the risk-reward and things like that.

So for example, if we were running out of time on a leases - which we’re not - Otto had made discoveries on trend and it looks like that trend came onto our block and we saw something that looked like a fan but it was a lead, we didn’t have 3D seismic on it - and we were running out of time - would we try as hard as we could to drill it? Sure thing.

If we had time up our sleeve, and we had access to capital in an appropriately non-dilutive way would we shoot the 3D to de-risk the prospect? Probably.

So the 3D is very helpful at de-risking and it will turn up additional features that you can’t see on the 2D for sure.

34) If this well is a dud, what’s "Plan B”?

DaveW: So I kind of touched on this earlier. The reality is, if Otto drills two dusters with Great Bear in conventional, even though they might be technically independent of things that we see on our acreage, the value of our conventional “backstop” will be diminished.

And then if we have a duster, you’re going to see a large destruction in value.

It’s not up to me to guesstimate for you what that will be, but it will be significant.

So what that “backstop” is will always be a function of - if our well doesn’t work - what the conventional rating potential is, what the value is deemed to be. And that’s dependent upon our seismic results and the results of the drilling of those (Otto) wells regardless of whether they may be technically independent of the prospects that we see.

So this next 6 months or the first 6 months of next year - very high risk. So it could be disaster in July - there is no doubt that is a potential scenario.

Q: You still think that the chances of success are 50%?

DaveW: That’s right. So the first well we estimated 25% - that came in under our definition of success - it was obviously a really good outcome and this one we think we’ve de-risked to 50%.

35) I understand we’re fully funded for the vertical well (Icewine #2V). If that’s a success and we want to start putting Horizontal wells in, what’s the funding situation for those?

DaveW: This comes back to the funding as per the most value-accretive option available at the time for investors.

There’s a number of different scenarios. The most obvious ones are - if we drill a successful well but the market cap doesn’t go up to a point where we believe the value is appropriate, we’ll go and seek an alternative avenue for funding from someone who we thing can value the assets appropriately, which is usually an oil and gas company, because they understand this better than investors. That’s just a fact of life, they’ve got teams of experts so it’s impossible for us as investors to understand as well as they do.

Sometimes, investors will give appropriate valuations for companies. And then it’s up to us whether it’s better to keep allowing you guys to invest with us, to own 100% of the project and move it forward that way, because you’re going to have dilution either way - money won’t just fall out of a tree and hit me on the head and I can just start paying for the wells without issuing shares or selling a piece of the project.

So it’s just whichever one is better - we give away less or we have one that creates more value for shareholders.

So it could be that someone offers us for 51% of the project an offer we can’t refuse. So we would give away a chunky dilution, but it would make money for you guys, so I daresay you’d be happy. So I hope that answers your question.

36) You read that the technology of fracking is improving all the time - how do you see this impacting on your production?

PaulB: A lot of the technology of fracking is about the landing zone and about making sure that you’re in the right stratigraphy within the reservoir.

At Eagleford, Conoco EOG for instance are taking the 3D volumes and they’re turning them into mechanical properties where they can predict Youngs and Poissons. The key is when you frack the well you want to be able to initiate a stimulation where the channel will remain open. And a lot of the fracking efficiencies that you’re hearing about are about the landing of the well and about the initiation of the fracture stimulation.

The other thing that is making a big difference in the stimulations are some of the proppants that are coming out. These low density, low specific gravity proppants for instance when we frack this reservoir we think it will be a couple of hours before it closes - so in other words you either have to have a very high viscosity gel - and that technology is still going crazy, it’s getting better every day - or - you can reduce the specific gravity in the proppants.

So a lot of the things that you’re hearing about the fracking efficiency, have to do with the inputs to the fracking. The landing zone specifically, and a lot of the fluids - and that’s one of the things that we’re trying to understand in this vertical well - because we’ve got fluid chemistry issues, we’ve got compatibility issues, there’s always Fines Migration and a big part of the fracking is how you manage what happens after the frack and how you then produce the well. Because there’s many many instances - for example in the Paynesville, where they’re actually fracking it very well, they were producing it too hard, so the big revolution in fracking was just the way they were bringing it out.

DaveW: I guess a shorter answer is - it does bring the cost of production on a per barrel basis down.

PaulB: Totally [laughter] - get Basinski out of the weeds.

Before the final question, Dave remarked:
DaveW: The line of communication is open. If there’s a question you want to ask directly to the company there’s an email address. I answer all of the questions that get asked, except when people are being abusive, then you get put on “ignore”. (laughter)

You also can obviously go through these guys [indicating Paul and Stephen] - we have a good line of communication open with these guys as well.

Note that the 88E Long Term Investor Group are putting a mechanism in place to collate questions to save Dave getting asked the same question 20 times. Expect more info on this from Graham and Tim.

37) You’ve outlined the risks that the project will encounter over the next few months and I think we all understand those. I think it’s a very good sign that the three of you are on this stage to talk to us - I feel that somehow you feel the odds are very good in favour of Icewine. Would you agree that it’s really very promising? (audience laughter)

DaveW: (smiling) All of us on this stage have looked at - in my case hundreds - in Paul and Stephen’s case probably thousands of projects. So when we look at these type of opportunities like this one - we all agree that this is - for me it’s a one in ten… fifteen year event that I see one as good as this.

And Paul has obviously seen the Eagleford - and for me that was the Eagleford - the only one that I’ve seen that’s as good as this since then.

But it just doesn’t mean that it’s gonna work.

But if you can get 50% chance of a couple of billion barrels or more - that’s unique. Not many companies get that opportunity - and not small companies. That never happens.

Q: And with 100% ownership as well

DaveW: That’s right.

[Applause]

Tim / Graham: Closing remarks

Unless otherwise stated, the content of this page is licensed under Creative Commons Attribution-ShareAlike 3.0 License