Pantheon Resources Plc (PANR) Earnings Call Transcript & Summary

Hello, and welcome to Pantheon's third webinar of 2022. I'm Jay Cheatham. I'm the CEO of Pantheon Resources. On the webinar today, we have Justin Hondris, our Financial Director; Bob Rosenthal, our Technical Director; and our 2 presenters, Michael Duncan, our VP of Operations and Engineering; and Ed Duncan, consulting geologist. And we're going to talk about modeling and going from vertical to horizontal wells. I'm assuming if you're tuning in to this webinar, you watched the last one where we reviewed the winter results. Here's our disclaimer. Please read it. In that earlier webinar, we presented flow rates from the various tests from the 2 vertical wells, Talitha-A and Theta West #1. As a reminder, those rates were 42 barrels of oil per day in the Talitha-A Lower Basin Floor Fan and 57 barrels of oil per day from the Lower Basin Floor Fan at Theta West #1. And that second test was cut short because of winter weather. We also tested the Slope Fan System that -- Talitha-A had 45 barrels of oil per day, and we made an assertion that those rates translated into commercial development. After the webinar, we received comments that we hadn't shown adequate reservoir data, meaning porosity and permeability and the analysis to confirm that assertion. As a result, we decided to do this webinar. So in today's webinar, we will show using reservoir engineering analytics from several independent sources that will illustrate reservoir performance parameters. First, you'll hear from Michael Duncan and second from Ed. You'll see it's all about scaling performance from a vertical to horizontal wells. And just a final note before I turn it over to Michael. We wouldn't be here today, Pantheon wouldn't, without the work that originated way back in 2011 on tight booking sandstone reservoirs by Great Bear. On to you, Michael.

Thank you, Jay. As Jay mentioned, we're really looking to understand how vertical completions and vertical tests extrapolate to horizontal completions and what it will mean for our horizontal wells in the future. So we've endeavored through multiple different methods to forecast the horizontal wells and what their production will be. So we've gone through an extensive campaign. I'm going to talk about 3 different methods we used for forecast and predicting horizontal well rate and formation deliverability. All of these methods are industry expected. All of them are commonly used, and I'll discuss the methods in detail. So the 3 that we'll focus on this presentation, first is volumetric bracketing. This is a simple concept of how much oil has been placed around the well that you will contact. So what percentage of that can you get out of the reservoir? The second method we'll discuss is scaling. We have vertical tests, how will those translate into horizontal production. That's been done for decades now, actually. And so we'll look at 2 SPE methods, [indiscernible] prevention methods, and we will walk through the [indiscernible] multistage completions are done [indiscernible]. We can look to analog development. Sure, analog is difficult because this reservoir is better than other reservoirs being developed right now. So when we look to, for example, the Permian Basin as an analog, it's a great analog showing deliverability, but it's not a perfect analog because, to be honest, our reservoir is the best. It's being used as a baseline and go from there. And then last of all, quick note, we saw a third-party assessment on that. We've received validation as such. So we're seeing an associate [indiscernible] in the next sort of report on the deliverability to allocate, and it certainly affirms what we forecast for horizontal deliverability. So with that, I'll dive into the methods. First, we're going to look at volumetric bracketing. Once again, this is just the concept of what does the well contact? How much rock does it contact? How much oil is there? And what percentage of that will you recover? So I use this graphic to display the concept of what a well will really contact once it shows [indiscernible]. For this exercise, I'm using a generic 8,000-foot well. That's a common size well, many vertically -- many horizontal multistage development drill out over that [indiscernible]. It's not an aggressive target. That 8,000-foot horizontal should contact reservoir with a width of about 880 feet. And that's a common space. So common development that will put 6 horizontals in a mile, meaning that each 1 contact width of about 880 feet. And then the vertical contact. We're assuming 200 feet for this example. That's commonplace as well. It's reasonably suggested that actual simulation can certainly achieve that height if not more. And so once again, that's not an aggressive assertion, that 200 feet of reservoir contact is appropriate for a well. But if you take those concepts, that's the volume of rock that a horizontal well in contact, and then you apply some reasonable reservoir properties as we've seen in our wells, 11.5% porosity, 55% oil saturation and a 1.35 feet Bo, which is reasonable and what we've seen thus far. It calculates thusly. And so on the right, we note the calculation of how much rock, 1.4 billion cubic feet of rock. And so 11% porosity. It's 161 million cubic feet across the end. It works out to be about 89 million cubic feet of oil. And so that's the rough number that we use. If you look to recover 10% of that, it's 1.2 million barrels [indiscernible] 1.7 million barrels recovery. And so that certainly affirms our ballpark estimates. In this generic example, rough contact, [indiscernible] 1.7 million barrels of oil [indiscernible]. So the key assumption for that is, of course, recovery. Can you get 10%? Can you get 15%? And for that, we go back to JJ ARPS, who's the engineers of the Arps equation it's based on. So the standard recovery equation, the Arps equation, it's based on this. The original publication go back here, and this is an excerpt from this publication on estimation of primary recovery. And we've highlighted in this case the parameters that are most applicable to a reservoir. So you see on the left-hand side one of the main drivers is the gas oil ratio. 600 is where we've highlighted it that falls in line with our measurement and our calculations on what was produced roughly. Oil gravity, we've highlighted 30. We're actually getting 35 to 38 API gravity. So there's reason to believe we'll do better than what's highlighted there. So the big conclusion, looking back to the guy who literally wrote the book on recovery calculation. His estimate is a range between 8.4% to 24.3% with an average 15.1%. So going back to our volumetrics. Can we get 10%? Very likely, yes, we'll get 15%. That's right about where JJ Arps estimated the average [ back win ]. And then to this day, he's still the guy we go to and his equation for estimating oil recovery. The second method we've talked about is scaling. We have vertical tests, but what does that translate to in the horizontal? So once again, I looked to predecessors in engineering and looked at publications. And so the 2 methods I'm highlighting here are a gentlemen named Joshi and a gentleman named Babu. And they have published methods of extrapolating from vertical to horizontal production. This is a spreadsheet that calculates based on their methods and duplicating [indiscernible]. Some of the highlights on this that I want to talk to, once again, when we look to the last horizonal well property, same assumptions, an 8,000-foot horizontal. That's what we're scaling to, very reasonable. A lot of reason to think we could exceed that. Drainage width, once again 880, very reasonable, commonplace. And we look up, highlighted above, permeability as the main driver in this as well. We, in this case, estimate 0.16 millidarcies permeability. That's been validated by the core measurement, and that's been validated by our interaction with the [indiscernible] via tracking via drawdowns. But we have a lot of evidence that these permeabilities are quite real. And then we looked at the results on the right, their calculations with appropriate production drawdown. These estimates put it about 108 barrels of oil a day for vertical. And so it does correlate, and it's calibrated to what we got in the past [indiscernible]. And then they scale from that. Joshi scales it up to about 1,659 barrels of oil a day in the well as we've estimated on the left. And Babu calculates up to 2,200 barrels a day. So standard scaling methods that have SPE publication estimates based a long [indiscernible] reservoir and what we look to in our developments, and they're forecasting 1,500 to 2,200 barrels a day scaling from a vertical to horizontal, and that's in an 8,000-foot horizontal. So generic forecasters [indiscernible] use in modeling. And this is based on a 10,000-foot lateral, and we've modeled 1,500 barrels a day production. So below what Joshi and Babue would forecast for it, probably a shorter model. So once again, we're looking at past scaling methods and what it would look like. When we would look to those that have scaled before us, they would estimate 1,600 to 2,200 barrels a day. We're modeling 1,500. So there's reason to think that our beliefs are conservative to think there's a lot of room to outdo what we currently model than what we've called. The third method we've discussed is comparing this to other development, in this case, when you compare it to the Permian Basin. To be clear, the Permian Basin is not a real analog. It's only an analog in the fact that the same development methods are used, but the reservoir is not analogous. When we look to the Permian Basin, we see that this type of well in 10,000-foot horizontal, it's commonplace. And we look at these recoveries, are similar. They're getting, well in this case on [indiscernible], they're getting wells 500,000 barrels a day -- 500,000-barrel EUR of oil or 720,000 barrels of oil equivalent. This complex development is effective in that that's ultimately the point I want to make. But when we look at our reservoir, our reservoir [indiscernible] much, much better. And that's what I'm trying to show to that, that our permeabilities are 100 to 10,000 times. I mean, the deliverability is much, much more. The porosity alone is 20% to 80% more. So the same well contact [indiscernible] just by the amount of rock you're touching, there's 20% to 80% more oil there. And when you look at our permeability, there's 100 to 10,000 times more. There's no moderation to be optimistic that 720,000 barrels of oil a day equivalent you see out of the Bone Spring well is actually a very, very low comparison to what we should be expecting out of [indiscernible]. So there's tons of reasons for optimism. When you look at permeability as the main driver, we're really looking at 100 to 10,000 times permeability. When you're looking at just the amount of oil there, there's a lot more oil there just in the rock. And so it's getting hard to find an analog because reservoir set quality was developed 50, 70, 100 years ago using old methods. Using today's methods that are properly applied in the Permian Basin, there's a lot of reason to say that, not only can we do better than what's on the Permian, we can do much, much better than the Permian. And so once again, a true analog, right now, it's hard to find because this [indiscernible] was long ago developed. But when we look to successful methods used today, we can certainly outdo what's being done out there. To summarize our look at this, it's easy to look at Permian Basin's schedule and pace and say we can do much better. I mean, we're not in nanodarcy rock. We're in millidarcy rock. But also when we look to our quantitative methods of this, when we look at scaling from a vertical towards the horizontal, it estimates that we're exceeding our forecast and that there's a lot of reasons that we'll have great deliverability as we set and a lot of reason that [indiscernible] cornerstone economic development on that. When we look at just the reservoir parameters of what we'll contact volumetrically, there's a lot of reason to see that we delivered very well. And so all of our methods, be it looking to commercial place now and comparing, being quantitatively putting this together, all of our message indicates there's a lot of reason to be optimistic about this, and that we'll deliver good [indiscernible]. And now I'll pass the presentation over to Ed Duncan.

Thank you, Michael. My name is Ed Duncan. I appreciate your time and interest in joining us today. I'd like to take you back in time, quite some time ago, in the early days of Great Bear when we were starting a review of the Brookian. Jay's already pointed out that we really started our first contract before when we served the company with a 2011 valuation -- regional valuation of Brookian potential by petrol businesses in Alaska and the [ Eastwood ]. We followed that with our first 3D in 2012 when we saw Alkaid. That interest in Alkaid was followed by the 2013 3D where we saw the first -- for the first time Shelf Margin Deltaic. At this point, our working interest partners in the project, Halliburton, recommended that we contract to Larry Britt, who is the principal at NSI Fracturing, LLC, a Tulsa-based group that specializes in planning and executing lateral wells, horizontal wells with multistage frac and modeling those fracs to give you an impression or understanding of what you're likely to achieve from a production perspective. So this work was done in 2013. It's proprietary to us, but we're sharing it with you as part of the driver behind our interest in the working conventional potential. So Larry Britt's model, what he referred to as Brookian Fans. That's on a bucket term that includes the Shelf Margin Deltaic's Slope Fan System, basin for fan reservoirs. Those are the 3 dominant plays in our Brookian portfolio from Alkaid to Talitha to Theta West Lower Basin Floor Fan. The assumption is that the values that you see on the screen are the assumptions. This is directly copied from Larry Brit's report for us in 2013. The depth, 9,000 feet. So about [ 5% ] average for all 3 of those projects. The height of the reservoir [indiscernible] 70 feet. That's way underrepresenting the total reservoir that we have. Reservoir pressure of 4,950. That's probably about writing in as an average across the 3 projects. Water saturation, 40%, not bad. Porosity 12%, again, not bad. Permeability maxed at 0.4 millidarcies. Again, that's not a bad assumption. The Kv or the Kh stacks the vertical permeability over horizontal permeability, just illustrating that horizontal permeability is generally perceived and recognized to be much higher than vertical permeability. Oil API at 26. Now this is where we actually win quite a lot. Our oil is a 35 to 38 API. And API translates through to viscosity, which is the next value. That's the cP, stands for centipoise. 3 centipoise, not bad. It's not a bad level at all, but we have 35 to 38 probably less than 1 centipoise or around 1 centipoise. That means that our oils flow much more readily through the permeability zones in our reservoir. So we gained quite a lot from a production rate perspective in the type of oil that we have. Go to the next slide. The layering model of what we should expect with the vertical completion with the assumptions that we illustrated on the previous slide, 9,000-foot depth with the [ 30 BOPD ] of reservoir. Initial production, the average 30-day production, 49 barrels. That sounds pretty familiar given some of the vertical rates that Michael took us through in his presentation. A first-year average rate of 43 accumulative, oil of 569,000 barrels. Okay, those are not miserable numbers. They're not the type of things that we're looking for on the North Slope of Alaska, for sure. But let's take a look at how Larry translates the vertical model into a horizontal well simulation. The curves that you see displayed illustrate Larry's output modeled for a horizontal well using the functions that we illustrated in the previous slides. You see a first-month rate, that's a 30-day average rate of 1,927 barrels of oil per day, first-year average rate 1,271 barrels of oil per day and a cumulative of 2.5 million barrels of oil. These numbers categorically are similar to the numbers that Michael has modeled with after the hard data, real data from the wells that we have drilled. So I consider this a validation of the work that Michael and the team have done over the last few months translating what we have from Alkaid, Talitha, and Theta West Lower Basin Floor Fan into an expectation for our upcoming horizontal well development program. The horizontal well simulation results, and this is again a 9,000-foot depth. You know Larry's numbers assumption -- based on assumptions that you've already gone through, a 9,000-foot reservoir depth, an IP or 30-day of 1,927 barrels per year, average rate of 1,271, and cumulative oil of 2.5 million barrels. The basis of -- or the basis of our pursuit of conventional plays is really very much built on this type of work. But I think what we're seeing today are Michael's work. We're seeing this completely validating the internal Pantheon model from our vertical well performance and observe reservoir parameters into what our expectation is for the potential of these reservoirs going forward. Lastly, I to put some regional contracts too because we've got much more to do both in the projects that we have in appraisal and development mode. Tremendous amount of rock volume that we have that's oil bearing. On the North Slope of Alaska, there's huge [indiscernible] that done on reservoir performance. Porosity and permeability prediction across a broad range of geological formations that are relevant to what we are doing. Some are good analogs. Some are not good analogs. The Albian, which is the age of rock that includes the [indiscernible] rock formations that [indiscernible] Willow and Pikka and Horseshoe are red dots in this display. We know that mineralogically and texturally, the Campanian Sandstones that we have, that is Alkaid. That's Shelf Margin Deltaic at Talitha, the Slope Fan, the Basin Floor Fan at Theta West and Talitha are similar texturally, mineralogically to the [indiscernible]. So the expectation is, is they often behave similarly in a [indiscernible] permeability space. And the data that we have are illustrating that that's very likely in a broad regional sense. The work that Larry Britt did, okay, for us, plots very well on this display. The yellow-orange dot in the middle of that yellow oval is an application of the assumption of the data -- porosity and permeability data that Larry used in his upscaling from a vertical to horizontal. The yellow oval represents the distribution of major [indiscernible] calculated the common porosities that from all of our projects, a very broad distribution. This is for A. The porosity and permeability that we have on the screen in front of us includes data calculated long porosity data from the Theta West Lower Basin Floor Fan section that we drilled this year. Remember, we cut 950 feet, nearly 300 meters of 80% net to gross section, all of it oil charged with 50% of that gross rock volume better than the input data that Larry Britt used in is upscaling from vertical to horizontal. That's a tremendous result for us. Now interestingly, the Permian Basin, which was mentioned by Michael, is not a [indiscernible] analog but a technology analog. So the technology transfer reservoir for us to lean on, plots them off this display, okay? It's important to recognize C, this is a linear display of porosity from 0 up to 25% or 30%. The permeability display of scale is logarithmic. So each change is a tenfold increase. So [ 1, 10, 100,000 ], for example, our -- all of our reservoirs are climbing inside this yellow oval. All of these can be judged as commercial [indiscernible] to develop the technology that we have access to today. And our approach has always been, and it will continue to be that it's great geological characterization with modern reservoir engineering to guide our volumetric and drilling conclusions. Thank you.

Yes, I'd just like to remind everybody what I said at the last webinar is we're starting to study with Schlumberger to do a 3D visualization of all our reservoirs, the Shelf Margin Deltaic, the Slope in Basin Floor Fan. And what we hope to get out of this is a visualization of the subsurface that will -- integrated all our well data, all our engineering data, all our seismic data, and we will see the reservoir distribution across the entirety of the 3 development projects. All reservoir realizations will include the depositional facies, porosities, permeability. And what we get out of this is a reservoir effectiveness at a performance volume, i.e., oil in place and expected range of recoveries. This will be the fundamental tool that'll help guide our appraisal and development. So this is our way forward. This is where we are today, but our way forward is very much in through this 3D visualization. Over to you, Jay.

Thank you, Bob, and thanks to both Ed and Michael for that great presentation. So what we try and do here at Pantheon with our webinars is give the participants an in-depth access to our engineering and geologic work. The real validation of what you've seen here today will come from the Alkaid #2 well due to spud in July. We'll take a look at the Shelf Margin Deltaic they'll take on the way down through the Alkaid formation, and then we'll drill the horizontal in the Alkaid. We'll be on production in October of 2022. We'll establish a production profile. But as a reminder, our modeling is based on 150 barrels of oil per day per 1,000 foot of lateral. As both Michael and Ed has said, given the analysis that you see here today, we have every reason to be very optimistic about those rates and possibly exceeding them. So thanks to everybody. Thanks to Bob, Michael, Ed, and goodbye.