London Video with 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.