London Presentation Transcript

Dave Wall:
Thanks, everyone, for coming. I'm Dave Wall, the managing director of 88 Energy. First, a couple of thanks. Firstly, to Chris up in the back there for helping us get everything organized and some of the logistics on the ground, and to Tim and Brian again for helping collate some questions for us, and the lovely girls on the registration desk. The format for tonight will be similar to what we did last time. There's a few new faces here, so I'll just run through that very briefly and then quickly, just for our safety, the rally point is in the courtyard near the entrance.

We're just going to run through the presentation quite briefly. I'll say a bit. Paul will come and talk a little bit about the background of the project. Steve's going to talk about the conventional side of things. Then, we'll have quite a lot of time as the last time for the questions, because I think that's what a lot of you are here for, is try to get that one-on-one or many on several time with us which we don't obviously get to do very often, and that's why this type of events are really invaluable for us.

Here, we see Doyon Arctic Fox. This is the rig that we contracted last week. This was actually the rig that we're trying to contract for Icewine-1, and someone else got in under us and took the rig away for another job. This is our preferred rig for this type of well at this depth on the slope because it is an exceptional rig and has a very good crew associated with it. As a plus, it's coming to us one of its kind job which has, as I said in my comment, several significant benefits. I did read one of the blogs. It's like, "What benefits? What are you talking about?" I saw someone actually on the blog answer some of the stuff what that guy said.

The rigs will be in good operating condition. The crew is ready to go. They'll just have to finish the job. They're not coming in from holiday or anything and their mind is still in neutral or whatever. We get a chance to inspect the rig when it's still operating rather than coming out of it cold-stacked and you always get teething issues, right, in that situation. So we should have good operational performance from this rig this time. It can't be guaranteed. Obviously, last time, you guys will remember there was quite a few mechanical issues with that rig, which wasn't anyone's fault. It's just the fact of how the industry works. It's something sitting there in minus 40 degrees for 18 months, things start to corrode and break and all the rest.

Typical disclaimer. This is the contextual slide which I'll talk to you just for a little bit, because this does set the scene for where we currently are and we can figure out where we came from as well to get to this point. It also shows you what's going on in Alaska. We've had a couple of years which has been pretty average for the oil and gas sector in general. Things are smoothly moving forward in Alaska and so are we, obviously.

You can see us down here in the red. There's some pastelly bits there. The pastelly bits are stuff that we bid on recently, so another 400,000 acres in the December bid round. Those should be granted just after the middle of the year, hopefully around the same time as the well results so we'll be able to make a strategic decision on whether to pick those acres up and pay the balance for those at that point in time.

On the conventional side, the green stuff, so obviously, Prudhoe Bay here to the north of us, the largest conventional oil pool in North America. The reason why they've built an 800-mile pipeline that traverses our acreage as does an all year round operational access road. That infrastructure is a key part of this story. The subsurface and the above ground, they have to go hand in hand. Otherwise, projects like what we're targeting cannot work. Then, also, in the conventional side, there's other green blobs or boxes over on the left-hand side there for you, guys. Recent discoveries in the conventional side. That gives us some confidence. It's not exactly the same geology as us, but there are similarities. Steve will talk to that a little bit as we go through.

I guess, in summary, we now have rights to over 690,000 acres on the slope, about 400,000 of those are net to 88, and the remainder 290,000 to Paul's company, Burgundy. We drilled Icewine-1, as you guys will mostly know, to test a theory that Paul had about oil phase, porosity, permeability, pressure. We're able to tick the boxes, so we know that the resource is in the ground. Now, we just have to figure out whether we can flow it at commercial rates. That's what Icewine-2 is all about.

This is just the Corporate Snapshot. I'll let you guys read that at your leisure. Then, this is some of the highlights which we've mainly talked to. Obviously, a very big potential prize here. DeGolyer and MacNaughton gave us a billion barrels. We internally are slightly more optimistic than that and have different assumptions. We think there's 2.6 billion barrels. It's important to note that whilst those are very large numbers. They're only on the 271,000 original acres that we had prior to the lease sales. Now, we've got two-and-a-half times more acreage. You don't have to be a rocket science to do the math, but there's a much bigger prize at stake that we're going to be testing with this upcoming drilling of Icewine-2.

We've contracted the rig. Whilst the rig is coming to us warm off its current job, it means that we can't get it until it finishes that job. That's the reason why we're going to be a few weeks behind what we had originally planned in terms of schedule. We could have spud the well with a different rig. However, it's much better for us to take the rig that we've got. As we said, that's our preferred rig for the slope. Just in very general terms, the ways the timing will work is spud the well in April sometime, most likely in 30 to 45 days to drill. Probably one to two weeks to fine-tune the final stimulation based on some micro-stimulations that we do which will give us very definitive pressure analysis in the well. Then, we'll execute the main stimulation and then we should be flowing back, doing clean up sometime in late June, early July, and then the proper flow test starts.

Then, on the conventional side, we've also got a lazy one-and-a-half billion barrels. They are leads. They're not drilling candidates yet. The work that's going on there is to mature one or more of those into a drilling candidate so that we can plan to potentially drill that as early as winter next year, because they are not on the road so they cannot be drilled in summer as our current well, the Icewine-2 well, will be. It could be drilled as early as first or second quarter of next year, all depending on the results of Icewine-2.

This, again, is mostly backwards looking. You guys know most of this, and then the forward-looking stuff we've already talked about. This is a pretty significant diagram. It's fine-tuned and looks like a bit of throwaway. If you understood the amount of time and years that Paul has put into this little bow, or whatever you want to call it, to determine where the sweet spot of this play is, which really is finding a needle in a haystack because this volatile oil phase that we've shown that we have in this project is not something that you find very commonly. It really is crucial to the story understanding that, which is ironic because volatile oil itself is not very well understood in the industry. I will get Paul up here in a minute to start to talk about some of the background of the project, and he'll touch on this volatile oil story.

Just talking very quickly to the well, so there's been a couple of changes here. Obviously, the timeframe, there's a new information in relation to the cost, so $17.7 million with 15% contingency. Fully stimulated and production tested. Our share just a little under 14 million in US, and we've got 20 in the bank. We are well-funded for the drilling. Then, obviously, when you look at the frack design, one of the things that we had been looking at was a multi-stage frack because what we're trying to figure out is what the most productive part of this interval will be for locating future horizontal wells.

There's also another objective, which is to prove the producibility and also to maximize the flow rate from this well because if you don't maximize the flow rate, and we get 50 or 60 barrels and only one stage is working, but we understand that that's very significant because we can go and drill horizontal, the market is not going to give us the love that we need to take the project forward. We change the priority to be equal flowability and locating the right zones to be primarily maximizing the flow rate, because that will be the thing that helps us move the project forward in the most meaningful way for everyone in this room.

Then, second, but only about a small amount is determining where to put horizontal wells in the future basins. What we're doing is we've changed the
logging program to help us with that second part, so run information, the image logs and a more sophisticated logging suite which will be run before and after we do the fracture stimulation, and putting traces in the fracture stimulation so that we can understand better where the productivity is coming from. We will be able to answer that question as well.

This is the best of both worlds and it's also really utilizing some of the changes that have happened in the industry over the last couple of years, where we've had this very depressed oil process and that has caused innovation particularly in Lower 48 in the US where people are being able to effectively stimulate rock in a much more efficient manner in a lower cost and with higher or better flow results. That's the best of both worlds in terms of higher rates and lower cost. This is very similar and an emulation of what is being executed now based on those recent innovations.

I think that's probably a good time actually to get Paul up to talk about some of the background of the story. Then, we'll run through a bit more of this stuff - expectations around flow rates, why we think is the guidance of what measure of success is. Then, Steve will talk about the conventional and then we'll wrap it up and we'll answer the questions.

Paul Basinski:
Thank you, all. The time has gone by. It just seems like we were up here a couple of weeks ago. A lot has happened since. In addition to materially increasing our position at this last sale, we now control the entire sweet spot for this play, which after the Eagle Ford experience that we had, we could have also done the same. The idea was, if we're going to do this, let's this time not leave money on the table. Right now, as we believe it, we've basically leased the entire thing up. Now, we're really ready to rumble after all these years.

Dave pointed out a little cartoon map. There it is. Like Dave said, this represents a lot of different information. Effectively, what this represents is the integration of not only all of the core data, but then we've come up with some new IP that we are able to, with very high probability, be able to tell where these wings are. To make it real simple, what we came up with, the essence of it is that we have a number of wells that are drilled on trend with us, around eight or so.

What we were able to do, again to make this real simple, we looked at where, when you drill a well, when you put a solvent on the cuttings, you get what's called a fluorescent flowing cut. If you know what the last cut is, the depth, and you know what the color of that is, with our thermal models, we can then predict the other parameters that we are able to do in the first well. By doing that, we see now that we have an continuous feature that actually gets wider on the sides. As it turns out, the peening distribution or thickness of this is exactly what it is up in the Vaca Muerta, and Point Pleasant, and Eagle Ford, and Duvernay. The distance or the width of it is pretty profound. Then, the other thing that happened at the sale was we're not only able to pick up additional acres, but we're able to increase the net effective footage because the shale gets thicker in some places that we just picked up.

The big move since we last talked is nailing this down, but then the other thing was really improving our model and this volatile oil. As Dave said, it's one of those things that you can talk to a lot of people about and they all nod their head. These are the experts. When you actually talk to them about it, it's more of a theory and being able to predict it because it's very complicated. What we've been able to do is to reduce those assumptions. Now, we have a model which is pretty robust. Effectively, what we're seeing is the volatile oil, if you use what the oil business uses to figure out the amount of oil, they'll use this thing called the formation volume factor, the B-sub-O, which basically is just the ratio of the amount of reservoir barrels per stack tank. In other words, the ratio of how many barrels in the ground versus how many you get out of the top, at the surface.

What we were to do was, using all the information from the well, quantify the volatile oil side of it. We talk about volatile oil, but volatile oil is a different type of oil that you add on to this other calculation. In other words, what we were able to find is rather than having 45% oil, then another 20% or so, and what this is, is this is oil that's in the gas that comes to the surface that's actually richer than the other oil. That's what the driver in this play is. That's the reason why the sweet spot in the Eagle Ford works and you get two miles away is not nearly as good. We were able to see this phenomenon in the well. Then, with the offset wells and this last cut, we're able to take that.

Now, we have, this is a simplified version, but this is based on quite a bit of work. We now have very high confidence that we've taken the entire sweet spot out. That's the update for right now. We're very excited by it. The question moving forward is, as Dave said, we brought in the top frack guys that we're aware of. One guy he’s 80 some years old. He's done personally his company about 100,000 frack jobs and shales, a guy who's done more than anyone on the planet. He is the prospective in order to see what we have. Basically, this is not going to be a cookbook thing. He's seen all the data and so we're very closely aligned with him. That's why we're going to have a very sophisticated program. That's really been a big step for us, too, bringing in that expertise. With that, I'd like to hand it over to Steve, or Dave.

Dave Wall:
I'll just mention one last thing. Thanks for that, Paul. It's just this one slide that I think I'll just talk to very, very briefly. What we see here is … There's quite a lot of different ways to represent this data, but this is one of the more, I guess, powerful, easy to understand ways, which is the evolution of how these plays develop over time. What you can see on the left is really the start of a couple of the plays, so vertical appraisal wells from the place where they started out. Then, as you go towards the right, over time, the technology has advanced and people have perfected the completions in horizontals and had moved predominantly all of these plays to horizontal development. You're seeing 15 to 25 times uplift.

If you reverse calculate that back to what we need, and we think a horizontal well needs to flow two to two-and-a-half thousand barrels a day on IP for the economics of this project to work. As you'll see in the appendix and as we've released before with this breakeven less than 40 bucks, it's about 100 to 150 barrels. That's the measure of success. We get a 100 or 150 around that range and we understand why we've got that number. It's not because it's a fluke or because we've failed for the wrong reasons or whatever, and get a low number. Then, that, for us, is the measure of success. That's the guidance.

That's something important for people to understand and that's something we'll expanding upon in the future. If you do your own research, you can go back and quite easily find data to support this. On that note, I'll hand it over to Steve. He's going to talk about the conventional stuff. Then, we'll touch a little bit on some of the stuff in the appendix which is a recap. Then, we'll open up for questions.

Stephen Staley:
Is this working? Can you hear me? It is working. Very good. I'm just going to go back a few slides, folks, to that one. I'm going to talk about the conventional. I'm the one who's got a tie on, so that's what you'd expect, I suppose. We're down here. Obviously, we've seen this slide before. Dave mentioned the green blobs here. Now, back in 2013, the US Geological Survey estimated that there was about 2.1 billion barrels to come out of what's called Brookian or the Brookian system, which is the conventional here. It extends into our acreage. Since then in those very few years with these three discoveries. Caelus there in the northwest, Armstrong and Repsol here, and ConocoPhillips earlier this year, they've already almost doubled that estimate. There's an awful lot of potential here. They haven't, by any means, found everything there is to find.

Way down here, the system extends down here. Tarm/Meltwater here. It's an existing field. That's one of our analogs for what we've got out here and across our acreage in terms of potential conventional play. Very exciting on the conventional side as well. I'll take it forward to where we were before. This now is a map of the acreage. The green blobs are, and you've probably seen these, they've been released. These are the conventional leads that we found. We can't call them prospects yet. We have more work to do on them before we can call them prospects. Very exciting.

You saw Alpha. If you came to the last one of these, we show you a little graphic of Alpha. We've moved further west. This is based on the 2D seismic that we acquired early last year, and processed and interpreted and we continued to work on. As you can probably see from this, we've got stacked plays. Here, we've got India/Juliet, et cetera. Over in the west, picked out just Bravo. We've also got Charlie. Charlie and Bravo overlap. Each of those is quite significant. We got well control over in the west here with Malbec, Smilodon, and Wolfbutton wells.

What do we think we've got? In broad terms, we've done an initial pass on this. Net to us, net to 88, probably about 1.14 billion, about one-and-a-half altogether billion barrels. Very significant. It's not quite as big as the unconventional, but by anybody's terms, that's a very large number to have sitting in your acreage. Now, this requires more work. We need to build in to our analysis, the data from the wells that we've got already over in the west there. We'll be working up what's the right way to approach this, where do we want to drill this.

If we have a look at this list here, then from east to west and we group them, you can see the size of what we've got. Alpha, we estimate in total about 118 million barrels. Then, through the center, so pretty big ones as well. There's Golf and India. As we get to the west, if you look at Bravo and Charlie, the size of those both net to 88 Energy, over 200 million barrels each. There's a potential there to drill both with one well. Also in the west, one can keep going deeper with a single well and also get down to the HRZ. You got a lot of potential for getting a lot value out of a single well. We can start to do more things with the data. We can pull out seismic attributes and start to work on that, especially in the east where we've got access already to some of the 3D data. I think in summary, I'd say very exciting and watch the space. Dave?

Dave Wall:
Thanks, Steve. Just wrapping up, this is a bit of a recap. Paul has talked about this a little bit before. These were the objectives in the first well and this is why we were confident in increasing our acreage size and moving to the next phase of the project. Really, it boils down to the viscosity. You need a hydrocarbon that can flow more easily through these tight rocks which means it can flow at higher rates. You need hydrocarbon pore volume or resource concentration, which is the amount of oil in place per acre per foot, which means that a single well can access more oil and therefore can flow at higher rates again and have better ultimate recoveries.

These, you've all seen these before. Very good parameters for a shale. Obviously, the next test is whether we can get them up to fracture stimulate effectively and flow. Then, these are just the resource numbers which I think everyone is familiar with, which is the DeGolyer & McNaughton numbers, and then obviously our internal estimate which is slightly higher. That's pretty much it. The breakeven, we talked about that as well. This is really just silver lining all our cost assumptions which are fairly well understood on the slope. Hopefully at the time as we have seen in the Lower 48, we've seen very good cost efficiency increases, especially over the last two years. We'll be able to improve upon these numbers potentially. That will be a key goal of the joint venture post-success. Then, this was just a couple of the conventional prospects. That's pretty much it.

What we'll do is now open it up for questions. If you can just raise your hand and then I'll get one of the ladies to come around with a microphone, and we'll bang out a few questions. We've got a fair bit of time for this. I guess when my jet lag starts to really kick in, that's when we'll call it quits, or if Mickey starts getting too rambunctious. Down here, we've got to start with the troublemaker. Hold on mate, there's a microphone coming. There you go.

Questioner:
Going back to the previous-

Dave Wall:
I don't know if that's on. Is it going through there? It is okay.

Questioner:
It is on.

Dave Wall:
That's better.

Questioner:
The picture before.

Dave Wall:
Which one?

Questioner:
No. Keep going. That one. There you go.

Dave Wall:
I'm sensing this is a Paul question.

Questioner:
Southwest. Migration from north to southwest which goes straight from middle down southwest.

Paul Basinski:
This is a continuation of last year's question. We must have done a very poor job answering.

Questioner:
So far. How much is that going to increase by the 3.6 million barrels?

Paul Basinski:
I want to get the first part of your question right about going from-

Questioner:
North to southwest.

Paul Basinski:
Yeah. If we can flip that around, we're starting to get in the ballpark of what we're doing here.

Questioner:
Southwest to north?

Paul Basinski:
Yeah. Oil is lighter than water and it goes upslope. I know last year, it was a problem, right?

Questioner:
Yeah, but then that means all the oil is going to be up in Great Bear territory, not down where we are.

Paul Basinski:
Now, that's a different question. Here's the thing. The calculations have been done on how much oil has been generated by this rock. Approximately 2% left the rock. That means most of the oil is still there down in the kitchen. The key for these plays is that, if you have what people consider to be the ideal source rock for a conventional play, that's usually a pretty lousy shale play, because it means it's leaky. Now, our shale, the HRZ, where we are isn't leaky, but then why is all of the HRZ oil up north and why are all the people finding HRZ oil if it didn't leak from where we're at?

This is the real question. The way it leaks is that we're near a thrust belt. What happens is this dives underneath the thrust belt. When it does, rocks get all busted up and they don't have a seal anymore. All the oil went up this way, updip, meaning from low to high. It went up structure. When it got under the Barrow Arch, it just charged the whole thing. That's the reason why we have a reservoir, a play that's got a great seal because where we do, it does but it just gets 1000-foot thick when it gets into the thrust belt. That's the part that sourced everything, but where we are never got there. We still have 98% of the oil. Where we are, the oil, basically almost none of it ever left. It's still mostly there.

Questioner:
Really, what you're saying is-

Paul Basinski:
It went updip.

Questioner:
No, it still goes north. Where it should be, going back to Steve now, is 1.4 conventional down there. There could be hell a lot more. That could be more conventional than unconventional.

Paul Basinski:
On the north slope, everything that's got a seal is filled to spill. The question is, do you have seals? The best way to make a big field on the conventional is called Prudhoe Bay, is to have a stratigraphic trap. If you're going to have a stratigraphic trap, it will be as full as the trap is, as far as the trap can trap. That's what we're working on with the seismic, to see the size of these. How much oil is in? There'll still be a lot more oil in the shale because most of it never left.

Questioner:
Thank you, Paul.

Paul Basinski:
You bet.

Questioner:
Good afternoon. Probably more a question for Dave. You've mentioned that we are fully funded for Icewine-2. We've got plenty of money in the bank. What consideration on funding are there - you've said we can go to banks? What are the options available after in terms of [inaudible - dilution, industry banks], whatever?

Dave Wall:
This is something we've touched on before in the last meeting. Like I've said, slightly glibly back then and the same applies here, is that we just do whatever is the most accretive option that we can do. Certain things you cannot do depending on the circumstances which might be the best thing ever, but if you can't do it, then they're not so good, right? The vanilla-type things that we know we could do if we have success is we can come to the market and raise money, or we can go into a deal with the industry.

When you think about that, it's like, "Okay." Say the market can't go to half a billion pounds or something like that on the success of Icewine-2, but someone in the industry thinks the project is worth a billion pounds based on that point in time. Would you take money from the market at half a billion pounds or would you deal with the guy that says it's worth a billion? It's pretty simple answer, right? I don't know what that answer would be in the future because I don't have a crystal ball. I don't know what the oil price is going to be. I don't know what the flow rate is going to be. I don't know what the share price is going to be.

There's too many moving parts for us to be able to make meaningful predictions on what we're actually going to do. We know that there will be multiple pads available to us. I guess you guys just have to trust us to try to do the right thing because we're shareholders, too, and we want to make money like you guys do.

Questioner:
You said the options are open and it's a question of finding the best options at the time.

Dave Wall:
100% correct. Yeah.

Questioner:
Thank you very much.

Dave Wall:
I guess just in terms of there's an unspoken question in there is like, "What happens if we had success operationally?" We did touch up on this. Really, the plan would be to try to accelerate the appraisal of the project as quickly as we could. We had started permitting additional wells in this project which could be drilled as soon as the first quarter or second quarter of next year. That would likely be another follow-up well to Icewine-2 as a horizontal well from the pad to show that here's a vertical well that flowed at 150 barrels. Here's a horizontal well that flowed at two-and-a-half thousand barrels. Therefore, theory proven and we've shown that that relationship is real. Even though empirical evidence shows it works in other plays, it doesn't mean it's going to work for us, but we can prove that, so we'd aim to do that.

Then, we look to drill out to the east and the west, or east and west, and hopefully tag a couple of these conventional prospects on the way down. Then, we look to build out something on the road which will have more wells that would show that you can get significant production out of this as a test case for developing a starter kit unconventional shale play on the north slope. At that point in time, which is two-and-a-half to three years away, our estimate, you would have a delineated resource across the entire acreage position. You would have proven flow rates from four or five horizontal wells. That point in time, the project is eminently saleable. We can retain our leverage to the project without diluting too much until then, that is the best way for us all to make the most money. Like I said, it depends on what options are available to us at that time.

Questioner:
One question. Why is it taking so long for someone to come along here and start drilling there?

Dave Wall:
What do you mean? I don't know understand the question.

Questioner:
Historically, we know a lot of other fields are there, but why wasn't this done five, 10 years ago?

Dave Wall:
I'm going to leave that one for Paul.

Paul Basinski:
Thanks a lot for that, Dave.

Dave Wall:
Paul loves these questions.

Paul Basinski:
Is that right, Dave? A big part of it was something outside of my field which was the above ground situation. While the shale gale was going in Lower 48, Alaska put a very punitive tax structure in place. What happened was the only people that remained up there were the majors. What drove the shale gale and the revolution in Lower 48 were the independents. Because of the fiscal regime, it didn't make any sense at all because of the takes that the state was putting on at that time. Probably as much as anything else, that's the story.

Then, what happened was the price got really low. It was at that point, and then the state put enhancements in the fiscal regime in order to encourage exploration and the outcome of that on the conventional side has been pretty profound because Armstrong has gotten a billion barrels. ConocoPhillips has just got the Greater Mooses Tooth. Caelus has announced a couple billion barrels in Smith Bay. All this has happened in a very short period of time.

On the unconventional side of the story, the issue was that people were thinking about this play with a conventional oil model. They probably were making the right decision because if this is just conventional oil and not volatile oil, it probably wouldn't be successful. The volatile oil model is a relatively new model that we developed during the Eagle Ford and it wasn't until around 2011 and '12 when it actually got out. By that time, the state was starting to pivot to this tax regime and then we had the low oil price. In a nutshell, I think that's 20,000-foot overview.

Dave Wall:
I thought Paul was going to give us some more profound rhetoric about the formation of ideas and how flugelbinders were invented and things like that.

Paul Basinski:
God, I wanted to.

Dave Wall:
There's one up in the back there if we can … All right, here.

Questioner:
Just building on Mickey's questions a little bit. First of all, you mentioned in your initial talk that you acquired additional acreage based on what you believe is the extent of the shale play. Can you give us some idea? You mentioned thicker zones, so higher net pay. You must have an idea on what you think is recoverable or potentially what is in place.

Paul Basinski:
Right now, we're sticking with the guidance of DeGolyer and MacNaughton.

Dave Wall:
I think what we're saying is that, at this juncture, there's a big number on the table already. We need to prove that first. Then, we can think about the next step.

Questioner:
Are you intending to acquire more seismic information?

Dave Wall:
At some point in time, but it's all a question of when the right time is. For example, if the HRZ play works, then we would immediately potentially buy the 3D seismic that exists around the well pad there which was shot using the dynamite. That's there to be bought. It doesn't have to be acquired. If it doesn't work, then do we need more seismic for us to have the confidence to go and drill one of these prospects? Really, that becomes partly a strategic decision but also a commercial decision.

For example, seismic acquisition on the slope is quite expensive because it can only be done in winter. That also makes it quite time-consuming. Could we instead go and drill Bravo and Charlie? That might be a $10 million post-hole as we call it in the industry, which would be relatively inexpensive compared to the cost of a 3D shoot. If our major risk here is seal and reservoir quality because we're deeper in the section than these other discoveries to the north, the seismic can't answer those questions for us. The seismic can answer other questions like if we did find decent reservoir quality with a decent seal, how big is it.

We know that if we're going to find something here, the definition that we can see on the 2D means that these things are big, but they still have quite a high risk associated with them. 3D could potentially, we might say the chance of success on drilling one of these, just one of the conventional not the stacked leads, is maybe in the order of 10%, 15%. With 3D, we could probably improve that to maybe 35% or 40% where we are. Do we spend two years acquiring seismic and then planning for that well, or do we just go and take a little bit more risk for lower costs? We don't know the answer to that yet. It does depend on some of the ongoing work that Steve alluded to in terms of maturing these prospects.

Questioner:
Thanks, Dave. I have one final question for you then. Last year, when you presented in September, you've mentioned the 50% success. You've changed the well design. You're obviously looking to get a good flow result. Is there any further upgrade on your expectation?

Dave Wall:
No. I know that people want us to say yes but, really, the 50% is based on our calculation of risk and also our estimation of uncertainty which is not actually very hard to estimate. Changing the design doesn't actually change any of that. What it does is increases the potential to maximize the flow rate, but it doesn't tell us whether it is going to flow and whether the fracture is going to remain open and how the rock is going to behave and all those things that we will never understand until we actually drill the well.

Until we get new information, we can't change our assessment of the risk or uncertainty. 50-50 on a few billion barrels, so pretty good in my book. Obviously, if it doesn't come in, we'll still be villains even though we do try to highlight the risk to everyone and make sure people understand. That's one of the reasons why we're to here, to say that if you flip a coin, and this is not a coin flip because this isn't a chance because there's a lot of work that has gone into this. When it boils down to it, it might not work. There's a 50% chance that it's going to be a lot of value destruction here.
Don't worry, the next answer will be more optimistic.

Paul Basinski:
It sounded like a morgue. It didn't sound like much quiet.

Dave Wall:
I could hear the crickets chirping. Yup?

Questioner:
Firstly, thank you for coming over again. Fantastic. Two questions. Sorry. My name is Martin, private investor. First question, if we are looking to raise more money, obviously, it'd help if our share price was higher. Is there any thought about doing some sort of PR campaign to let people know the news we have? To me, it's nearly all positive. Yes, there's risk, but it is positive news. The first question, for a relatively small amount of money, you could do a very positive PR campaign on 88's behalf. Second question, your pay package has gone up, which I think is well-justified. Are you looking to spend any of that on buying shares because that would be good PR?

Dave Wall:
It's funny when you talk about PR and also directors investing in companies. It doesn't always send the best signal. One of the things that it tells you is that if I'm buying stock, it means that everything that I know is in the market and everything is complete and fully formed. That's very rarely the case. For example, when this story where things are constantly changing and evolving, it's very rare for me to have the opportunity to invest and buy shares. That's part one. Then, in terms of PR, we do probably more PR than any other oil and gas company in our peer group. I think it's been pretty effective today. For us to be able to have all of you guys on the register, it just doesn't happen by accident. That is something that we do put a lot of time and thought into, and that is something that we'll continue to do in the future.

Questioner:
Thank you.

Questioner:
Hi, guys. My question is somewhat similar to the previous questions. Insomuch that the intent to grow the shareholder's wealth and indeed the wealth of the company and its capitalization, the shares itself, the price is stagnant. What do you see in your way as trying to move that share price forward? Is it your intention to remain in the ASX and AIM markets, or do you intend to go into further markets?

Dave Wall:
The question of moving on to another exchange is one that is really right time and right place. At the moment in time, it's not right. Once we have success, God willing, we do have success in our next well, then we'll start to push that agenda forward. We've already made a forays into the US with the capital raising that we did towards the end of last year. We have some relationships there that are improving and evolving, but we need success before we'd really consider seriously moving on to another exchange because it's quite a lot overhead and effort to do that.

Say we did it now, then the share price shoots up, and then it's not successful, then we've basically created unsustainable situation for the company moving forward. We have to think about oil situations, short-term, median term, and long-term. The timing is just not right for that right now. Definitely, it's something that we are looking at and that is continuing to move forward albeit in the background and contingent upon success.

Questioner:
Could I just ask one other question? That is in relation to the ability to be able to draw down reserves from the Bank of America. Is it your intention to draw any more down on this, and for what purpose would you use it?

Dave Wall:
The Bank of America approves those drawdowns on a project-by-project basis. The situation in Alaska, and this is something that we should talk about a little bit actually, is that we borrowed money from the bank, $17.7 million. Today, it's been drawn down. The state owes us about $18.5 million and that will obviously increase when we file our credits for the calendar '16 year for money that we didn't secure lending from the bank. We've got a big buffer in between what is owed to us and what we owe to the bank.

However, the side of Alaska has payed out much less in terms of percentage of the credits over the last couple of years as there had been running budget deficits due to the oil price being so low and then being so dependent on oil revenues, which means that the bank has basically said, "Look, until something changes and we get some of that money back, we don't really want to lend you guys or anyone else any money for that matter." We're quite happy with that situation because we … If you're managing you're balance sheet prudently, you're taking on only so much even though you've got a receivable that outweighs it, we're probably in that zone where I think we feel pretty comfortable about where that's at.

Taking on more money at this stage when we've got an uncertain outcome in our future, probably not appropriate. We've got the money in the bank to fund the well. Why take on that debt risk when you don't really need to? The short answer is no, we're not looking to borrow any money from them at this stage. I know that if we had success, they would be quite interested in having our business but more on a reserves borrowing basis, which would be sometime in the future.

Questioner:
Thank you for your honesty and open opinion on that question. Thank you.

Dave Wall:
No worries.

Questioner:
Hi.

Dave Wall:
Sorry. There's a guy in the middle here who's … There's a lot of microphone over there. I'll get to you next.

Questioner:
Thanks. Private shareholder. I'm relatively new to the company. Can you just explain the black dots on this chart. Are they existing wells?

Dave Wall:
Correct.

Questioner:
Two of them seem to be in an area on your conventional prospective portfolio in the western play Fairway.

Dave Wall:
That's right.

Questioner:
I presume you've got the data from those wells. When you describe these prospective plays as, I forgot the word you used, but not even prospective yet.

Dave Wall:
Not prospects. A prospect is basically something that is matured to the point that you believe you have confidence that you would just go and drill it tomorrow if you could. A lead is something that you think is more risky and less defined. It is a good question. The answer to this is, there's several aspects to it. One of which is that Prudhoe Bay was discovered in the '60s. People went searching for oil all over Alaska and had found quite a few big discoveries, but they'd left a lot behind, right?

Part of the reason why a lot has been left behind is because the drilling, or more the logging technology at the time was good, but it's much better today. Also, our understanding of the reservoir composition and what impact that has on the logs, and this a big part of our story, actually, all this volcanic material that's mixed in with a lot of the sediment in Alaska, it does play havoc with the logs and gives you some counterintuitive ratings. When you look at something like Tam, if you look at the logs on Tam, it doesn't look like an oil discovery.

Questioner:
Looks wet.

Dave Wall:
It looks wet. That's because the volcanics changed the log response. On a lot of the logs that we see, and if you look at what Great Bear has done with the pipeline state's well which is the black dot just above the peak of the bow, they're saying that that's a discovery because they've gone back and done some forensic analysis on the logs and calculated the impact that these other materials in the reservoir have on the logs and say, "Look, we can now see based on what these other discoveries that have been made that this looks the same and therefore, simplistically, this has oil in it." Whereas before, people would have thought it was wet.

We've started doing similar work, and Steve alluded to that. We need to do more of that work. One of the challenges is that some of the log quality is quite poor in some of these wells. They've had what's called wellbore washout where the shape of the hole expands and gets quite rugose. When that happens here, your logs become ratty and not very reliable. Reconstructing them sometimes is just not possible. When we go back and look at Malbec and Smilodon that Steve talked about, in the interval where we see this reservoir, hopefully it's a reservoir coming through those wells, we can't see a lot on the logs. When you look at the mud log, they've got oil shows throughout the ascensions.

Unfortunately, and this is a funny way to say it, there's a lot of oil shows on the slope. That's obviously a good thing. However, it doesn't make it differential for us to say that is definitely something. We know the oil is there. You can't tell from the logs whether there's actually bypassed prior reservoir there. I assume that we currently know it, but we're going to do more work to try to improve upon that. If we can, that's the maturation that could lead us to say, "Bang, we're going to go and drill Bravo and Charlie."

Questioner:
I have one more question. You described volatile oil as the liquids that come with gas. Is that correct?

Paul Basinski:
It's the volatilized oil fraction in the gas.

Questioner:
One thing you haven't mentioned is the gas. What are you going to do with the gas?

Dave Wall:
That's a very good question as well. There's quite a lot of gas on the slope. One other thing is that they have been pushing for in the government there is to try to get some of that gas to market through an LNG project. That's had various levels of momentum over the years. That have waxed and waned, but it's still a big focus for them but it's still a long way away. Until then, the gas would need to be re-injected or sequestered on a large-scale basis. They do currently inject a very significant portion of gas into Prudhoe Bay. They have a couple of other fields that they could bring into development if they had more gas to inject into them.

They're not going to produce gas in order to develop those fields, but if someone was already producing gas, like co-produced gas, because we have liquids which makes the project economic, then it would make sense to pipe their gas out of these projects and inject them into that. That's more of a medium term thing. They would have the infrastructure associated with doing all of that. In the first instance, that pad that we talked about during those first four horizontal wells, one of the wells that we drill on, that would be a gas injection well.

Questioner:
Thank you.

Dave Wall:
Ready to go.

Paul Basinski:
It's awful quiet in here. I guess that's why.

Dave Wall:
Thank God.

Questioner:
This is a question for Paul. Basically, you've both bought a lot more land and you've thought it's still 50-50. In my mind, I keep thinking why. Why have they bought all that extra land if it's just 50-50, or is it just my ignorance? In other words, people just gamble that way with that sort of money. To me, it's extraordinarily mad. Is that the way that it works? You just take a huge gamble in our terms, but maybe for a big institution, your friends in America, it's not a lot. Why? There's a dichotomy here which I can't get my head around. We all want to believe Paul's optimism and your caution. Somewhere in between, actually we're hoping it's all going to go towards Paul's optimism.

Paul Basinski:
You haven’t seen a fraction and my optimism.

Questioner:
No.

Paul Basinski:
Effectively, what we're talking about here is risk expected monetary value. We do these Bayesian analysis that we did at Conoco, we did elsewhere. Effectively, when you're dealing with a two-to-one on an investment or a three-to-one on the outcome, then the question is different about what the probability is. When you have the potential uplift of a reward which is in the multiples that we're talking about, and then you look at what the value left on the table at $35 or $40 an acre, and the expected monetary value, the project basically only has to have about a half of 1% probability in order for it to be screamingly commercial because of the risk expected monetary value.

Dave Wall:
The simple way of saying that is because the upside is so big.

Questioner:
I was trying to get it. I thought it was just me.

Dave Wall:
It's basically like-

Paul Basinski:
I told you. I was trying to be good.

Dave Wall:
If you got 1% of 10 billion, that's a big number. If that's your risk and that's your reward, that's still a big number. If you got 1% of 10 or 100, it's a small number and you wouldn't bother chasing it. If we can increase an upside and we've got a 50% chance of achieving it, that's a no-brainer for us. Would you rather have 50% of a small number or a big number?

Questioner:
No. I'm quite happy with that.

Dave Wall:
That's it, simplistically.

Paul Basinski:
The denominator is a wonderful thing.

Dave Wall:
Just behind you, there's a gentleman.

Questioner:
Thank you.

Questioner:
Hi. A private investor as well. You've mentioned that there is a two-and-a-half year further away point of which if everything works out well, it's where things could get very interesting. I guess I'm cautious as well and I'm quite interested in how say after the summer, after July or August, when there's more data and more results, if those results prove to be average, how does that two-and-a-half year-

Dave Wall:
It pushes it out.

Questioner:
It pushes it out?

Dave Wall:
It certainly does.

Questioner:
At what point does one decide it was below average and not good enough? Then, with the immediate 6 to 12 months, after that, what sort of things would you be looking at doing?

Dave Wall:
Let's go through a couple of scenarios which I think will help clarify how that will play out if it does get to that. Say we got 75 barrels a day which is okay, not great. If we could understand that the reason why we got 75 barrels a day is because 60% of the stimulated interval had just not worked because there'd been a blockage or something had gone wrong, then, we go, "Okay. Well, if we could frack 100%, then that 75 barrels in that context looks pretty good." The market would be going, "Hmm, I don't know. You guys, we don't trust you so much anymore because you didn't execute properly." That's why things sometimes go wrong.

We would have to drill another well to prove to the market and execute the job again effectively. We probably wouldn't have the information that we needed to drill a horizontal because 60% of the fracture didn't work with stimulation. That would push the timeframe out. We had permanent sites that we can drill additional wells from the pad, so we could fast track that. Obviously, there'd be some dilution associated with that, and possibly at lower prices depending on the market's reaction. That's one scenario.

It's really about understanding why it didn't work. If we effectively fractured 100% of it and it still flowed at 75, that would probably be the end of that for the time being because you probably need much higher oil prices to justify spending more money on something that we think has questionable economic value given what we know about the above ground cost, structures, and everything else on the slope.

Questioner:
Plenty of appetite to get on with it in less than ideal figures going forward into-

Dave Wall:
We quickly focus in more on the conventional and try and prove out something on that front.

Questioner:
Great. Thanks very much.

Dave Wall:
The other thing that can happen as well is, say 75 barrels came. We still got 10 years on most of those leases. We'd go and look at the conventional, and potentially, there'd be a technological advancement which would mean that we'd be able to come back and say, "Well, actually, those guys were only getting 75 barrels and now they're getting 200. Maybe we can apply that technology." That's the thing at the moment, the way that technology is advancing not just in oil and gas but in every field, it's pretty phenomenal. That's something that doesn't mean the project is 100% dead. It might be dormant, so it would push out that timeframe we're talking about.

Paul Basinski:
The real key to Dave's point is that we know we have an extraordinary resource in the ground. We've not shown this to anyone in Houston or anywhere that doesn't agree with that. The point is you got to start with that. If you don't have that, then, really, the rest doesn't make any difference. We have a compelling resource that is very difficult to find anywhere in a western country.

Questioner:
[inaudible - I'll just build on that, partial result you're talking about.]
If you got a partial success, what's the timeframe for getting after another well?

Dave Wall:
It depends. Say if it's partial success which we understand why it failed and we think we can do better, we would fast track the drilling of the next well. We're looking at Q1, Q2 next year, realistically. The way the permit works is that most of the major permits allow us to drill another well pretty much immediately from the pad. Permit to drill is something which takes a couple of months to put together. It's fairly complicated engineering document. It usually only takes two to four weeks to get approved. Theoretically, if we understood everything immediately which isn't going to happen, within three months, we could be drilling another well and also access rigs and all those things, and funding. Realistically, it's going to take longer than that.

Questioner:
To complete your scenarios in the high case, what would you do? What would you expect?

Dave Wall:
I think it said the same thing just earlier. That looks like we'd get after drilling a horizontal well from the pad as a follow-up to Icewine 1 and 2 from the same location and then we look at expanding or building a new gravel pad from which drill the four wells with the one gas injection well. Then, we look to delineate to the eastern west. Not all of those wells, theoretically, if we can line up the ducks, could happen starting from the first quarter of next year. We probably wouldn't be able to execute them all at the same time, so there'd be a priority on which one is going to have the most value. That could probably look like the horizontal well as a low-hanging fruit to follow-up on the vertical success, and also the delineation wells to try to get our arms around the HRZ and our confidence level in the mapping.

Paul Basinski:
To that point, the offset wells on either side are effectively what we did in the Eagle Ford when we drilled the Hookes well which is 55 miles away. The point is that if you do this and then you get the data and you find something that's very similar, then effectively, with your reserve classification, right now, it's 2C, we'll get an elevation across the board just because a major risk factor has been taken out if we show the continuity which is really the first step in order to be able to move a project forward. If you can get your contingent resource evaluated or classified as an elevated contingent or an undeveloped resource, then it becomes much more valuable.

Dave Wall:
Sorry. There's a guy at the back.

Questioner:
Hi. Again, two quick questions. First one, has the Trump administration had any major effects or minor effects? Second question, what is your most optimistic outlook for the whole play?

Dave Wall:
The second question I'm not going to answer, but don't worry I think about it a lot.

Questioner:
Not as much as we do.

Paul Basinski:
Can you see the invisible duct tape?

Dave Wall:
The first question is an interesting one. He's a pretty polarizing guy. When you boil it down for the oil industry, it's pretty positive. If he can't deliver on what he is trying to do, which I believe is to make America the most competitive place to do business in the world, and resources and oil particular. So, what that would mean potentially is there's this double-sided argument. It makes it easier for oil companies to get their projects executed quicker and at lower costs. That means there are going to be more oil, which means there's more supply and the price goes down, right?

However, the other side of that coin is if I can bring this project for the year, and then decrease cost by 30%, the NPV is going to up by 80%. I can absorb a $5 or $10 hit on the oil price and return the same value and margins. I'm just getting the project executed more efficiently. If you talk about efficiency, isn't that what we want? We want a more efficient market in the supply/demand for oil. We are seeing that already in the last couple of years in the Lower 48 because of low oil price.

Then, if you've got someone in the administration that's trying to further enhance that effect, that could be really good for companies that have projects in the US because if I'm more competitive because I'm in the US than somewhere else, our project is going to get up before that one does. It could be very positive, but it all comes down to whether it can be executed, how long that will take, and things like that.

Questioner:
Hi there, guys. A private investor and oil major employee. Just a quick one around oil majors. I know you talked a bit about ConocoPhillips snipping around a bit. Exxon recently paid a large amount of money for Permian acreage. At GC, the Permian, that bubble is becoming unsustainable. Do you anticipate oil majors starting to look north where potentially it's more attractive at this stage?

Paul Basinski:
A very good question. I can respond with a partner that we have, Burgundy has. It's a three-generation oil company in Houston. They got started because the original chief geologist for General Crude which became Mobil was the founder of the company. Now, they got production in 15 states. They're selling everything they have in the Permian because they're getting $60,000 plus an acre. They've been in the business a long time. They realized that, I think, people right now are … There's a flight to risk aversion. I think that the odds of being able to not sustain a loss are reasonably high, but the odds of getting much upside when you effectively invest over $2 million at land per well starts to become pretty de minimis when you look at the distribution.

I think that what we're seeing is that there's a flight to the Permian because it is a sure thing and everyone is looking for something to do where you can invest money. Now, with respect to Exxon, I'm quite familiar with that deal. One of the primary drivers for that from the Bass brothers was that was a contiguous acreage position which is basically the last of its kind in the Permian that I'm aware of. What the majors look for is operational efficiency. Even though they pay this ridiculous amount of money, they're looking long-term because they're going to really be able to optimize this. Having a contiguous block is really key.

That's one of the things that we are going to be able to deliver because even when you look at the other shale place like the Vaca Muerta in Argentina, where Exxon and others are getting in, the acreage is very parcellated. What we're going to be able to offer if we show that we have the resource and we got the right classification is an operational efficiency upside which is going to highly leverage a lot of the other conditions that we're currently facing.

Questioner:
Thank you.

Paul Basinski:
Yeah, you bet.

Questioner:
Looking at the end game, is it still to sell or to be a producer or perhaps both?

Dave Wall:
Technically, if we get a flow rate this out of the next well, which we should, it's just a question of how much we'll be a producer. If you're talking about large-scale production, really, I think the first phase of that potential monetization strategy is to get to a point where we have delineated the resource and prove that production is coming from multiple horizontal wells on the acreage.

At that point, really, we've increased the optionality of the project to, I guess, a juncture where we can make a decision, which path we want to go down. Obviously, it will be very tempting to just monetize it and sell it. Ultimately, if this turns into a full field development company, I don't think either Paul or I will be around to see that even if it is still under the 88 Energy and Burgundy banners, and whatever happens to those vehicles, because that's just not our wheelhouse, right? Ultimately, those decisions get driven by the shareholders.

If we've got a bunch of shareholders at that stage, it would probably be, unfortunately, not you guys, but larger institutions driving the strategy in terms of financing and saying to us, we want to take you through. We think that that is path as the board to create more value for shareholders even though by that stage, we're talking about 15%, 20% a year or something like that which is pretty good. It's not going to be the type of uplift that we're in this project for, so we won't be around.

Questioner:
Also, what would it take for a major then to say like, "Well, 88E, we're going to buy you"? Would it need to have just the one well? Would it need to have several wells? Is it-

Dave Wall:
I think it is possible. If we get success in this next well, we could go and lift the skirt, so to speak, to all the majors, and we definitely get offers, but how much will we get, right?

Paul Basinski:
The kilt might be ugly initially.

Dave Wall:
It wouldn't be great. How much would you get in that scenario? I can tell you it wouldn't be a maximized value, or what we refer to the “creaming the curve” which is a common industry term which is creating the most value in the shortest period of time. We would get, say the curve looks like this, we're here, we could get to there with the next well. If we execute the next 10 wells to delineate, we could get up to here, and then we leave something on the table for those guys. We just sell here. You want to execute that delineation program. That's the point that we think is the most appropriate way to move this forward in the success case.

Paul Basinski:
If you're producing four wells or X number of barrels even on the north slope, you're going to be able to get a pretty big realization on the flowing day barrel price which is going to hugely leverage the value of the project. Not only will it reduce the risk, but the upfront money you're going to get on those flowing day barrels is going to be pretty huge.

Questioner:
Dave, back in September, you spoke a little bit about Otto to our north, not very far away, as possibly giving you some guidance when they were intending to start drilling convention, I believe. Could you just recap there what's happening? Maybe say a little bit about other competitors around us who are currently drilling or planning to drill, and what you might be expecting as guidance from some of there if there are any around us.

Dave Wall:
I guess we don't see ourselves in competition with anyone. There's no competitors. We have peer companies. Otto partnered with Great Bear to the north of us, and we don't fully understand what their strategy is. Obviously, Great Bear is the operator and the very large working interest holder in that deal. They're 90%, Otto's 10-ish. We don't know what they're doing is the short answer. We know what had been publicly released, and so we made everyone aware of that saying, "This is what these guys have said they're going to do," but then they've obviously changed their strategy. We don't understand why because we're in their board room when they're talking about it. That's, I guess, the short answer there. In terms of what some of these other guys are doing, they're making big discoveries up here to be a little bit flippant. That's the short story. These guys are aggressively getting after it. These guys have slowed down down a little bit, but we don't really fully understand why.

All right. That is pretty much perfect, spot-on to … Hi. I was just about to call drinks.

Questioner:
Good afternoon, gents. Can I ask you, although we all fully appreciate that this is a step-by-step-by-step, is money the driver or is the data the driver? In other words, could we get another rig in there as an argument? If we had double the money in the bank, what would that do? Is it driven by your log and your data, et cetera?

Dave Wall:
There's certain things that we can do concurrently and there's certain things that we have to do sequentially in the step-by-step process. At the moment, we're still in the step-by-step process. We figure out how much we can buy, which is a lot for us, and we buy it and then we chew like crazy. We don't want to take on too much. Also, we'd have to raise obviously more money at lower prices in order to go and drill two wells when, really, we only need to drill one. Why drill two when you only need one? In order to maximize the value of the project after this well, we've talked about that at length. That's something that we would try to execute as much as possible concurrently. Then, it will be a question of capacity, the number of rigs on the slope. Rigs can be bought in from out of state. All those things, the things that we've looked at, and we'll be trying to execute those.

Paul Basinski:
Effectively, what we'd be looking at when we got to that point, assuming that we the green flag and going forward with the development from the technical and from an above ground, from the location point of view, you get about 10 wells per rig per year.

Dave Wall:
All right. Thanks, everyone, for your questions. I hope you'll join us for some drinks and nibbles downstairs. We'll be there as well so you can come and ask us those private questions you're too embarrassed to ask in front of everyone else. Thank you.

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