AXP Energy Limited (AXP) Earnings Call Transcript

Good morning, everyone, and welcome to today's webinar. My name is Alex Paull from Investor Stream, and I'll be your host today. This morning, we have AXP Energy Managing Director, Dan Lanskey, who will provide a company update on recent activities, including the company's expansion into Oklahoma as well as the recent funding support to drive growth across the company's operations. Following the briefing, Dan will address any questions you may have. We'll attempt to get through as many questions as time permits. Please feel free to send in your questions via the Zoom platform or also e-mail them to me alex@investorstream.com.au. A copy of the webinar will also be available on AXP's social media platforms later today. But for now, I'd like to throw it over to Dan to kick things off for us. Dan, the floor is yours.

Thanks, Alex. Good morning, everyone, in Australia. Greetings from Oklahoma, where it's 8:00 p.m. So thank you, everyone, for attending. I can see we've got a good audience here. I'm going to jump into the presentation, run through some facts figures. And as Alex said, we'll come back to some questions. So my name is Dan Lanskey. I'm the Managing Director and CEO of AXP Energy. The photo you see in front of you on the cover of this presentation is our live and active site in Colorado. We're located in the foothills of the Colorado Mountain, southwest of Colorado Springs inside what's called the Florence oil field. It's the second oldest oil field in the U.S.A. west of the Mississippi, and it was actually discovered before Spindletop in Texas. So we're in an old field, well-known formations. What you can see here is a pump jack. In the middle, we've got oil tanks. The pump is pumping into the oil tanks. Gas is separated behind here. Gas is pushed into the generators, which are creating electricity. And on the right-hand side, you'll see 2 containers that contain active crypto miners. And over here on the top of our little demountable building, you can see a dish, which is our Starlink Internet. So I'm going to talk about where this has happened, how it's happening and the next steps we're going to undertake. There's a disclaimer here about forward-looking facts. All care has been taken to make sure we're correct. Please read at your leisure. It will be part of the PowerPoint that's released later today to the ASX. So one of the things about being in the U.S., I came over in February this year, I had the opportunity to visit with the Crypto 2025 Bitcoin Mining Conference in Las Vegas. The big theme at the moment is everything is booming, data centers, AI, cryptocurrency; where are we going to get the power? That is the big question. So what we've done is we've taken our off-grid natural gas power, and we've delivered a prototype, a modular trial, let's call it that, a modular trial of a theme that is in much demand. What we want to do now is expand that out across on to multiple sites. But about the company, you'll see the directors, Sam Jarvis, a petroleum engineer. We've got Stuart Middleton, who's also an engineer. We've got James Dack, who recently joined us since Christmas time, a real estate investor and a very successful Sydney-based businessman, has joined us as a nonexecutive. My background, myself, I've got over 20 years in oil and gas in the U.S., mostly in Oklahoma, Kansas and a little bit in Texas. And of course, the last 6 months, I've been running the operations in Colorado since I joined as Managing Director in February. As you're aware, we have successfully tested our trial up in Colorado. This is a happy snap of the team from BitFuFu, NASDAQ-listed Bitcoin miner. And myself thumbs it up, let's get on with it. We've got a large contingent resource up in Colorado of 750 billion cubic feet. And our discussions following our successful trial with BitFuFu was to grow the footprint as fast as we could to 25 megawatts by December and 100 megawatts by Christmas of 2026. So as we went through the process in Colorado of getting this up and running properly, you can see our footprint there. We've got a number of wells tied in. So what we did was we went to the Colorado state and said we want to drill some more wells. We want to deepen some wells. We got some aggressive targets. They're very welcoming and said, no problem at all. However, it will take 9 to 12 months to get the permits in place to go and develop your 750 billion cubic feet of gas by deepening some wells and drilling some new ones. So I spoke with the Board and I said, look, we've been over in Oklahoma since 2010 drilling out a well-known oil field now. Let's get into Oklahoma where the process can be run in parallel whilst we wait for Colorado to give us our permits for next year.

He's the one that's driving the slide.

Yes. Is there a problem? I can hear people talking. Sorry, what's that, Alex?

I just wanted to -- no, that's fine, Dan. You continue? You continue with the slide deck.

Okay. Thank you. Back to Oklahoma. So the Board gave me the opportunity to go back to Oklahoma, where over the last 6 to 8 weeks, we've been putting together a pretty exciting opportunity. We've leased up 1,400 acres inside an oilfield, which has got 30-plus drilling locations, right offsetting the previous oil field that I was involved in over a 10-year period. So we've got an opportunity here to network our contractor base, and we've had a very successful time here with 95% drilling success rate inside an oil field. We've got a time period here to get active where it's not -- the lead time to get drilling is weeks, not months. So we're not waiting until next year. We're ready to go now. The reason we raised the funds was to look at initially drilling a number of wells in Oklahoma and expanding our footprint whilst we wait for Colorado regulatory approvals in the background. A little bit about this area here. We're just in the photo here, you'll see the oil refinery at Ponca City, Oklahoma, the Phillips 66 refinery can do 210,000 barrels a day. Each one of these squares is 1 mile. So if you count down, we're within 5 miles of the oil refinery where we're drilling out. The yellow highlighted area and the red highlighted area are the initial leases. And these are a group of wells, including this more along, you can see them offsetting the road, all the wells here that we drilled previously when I was Managing Director, CEO of AusTex Oil. From the annual report, we pulled some data about the IP rates or initial production and looking at where we are, we're in the middle of an oilfield. There's development to the south of us, there's development to the west of us, east of us and to the north of us. So my previous Chairman was a PhD geologist and his comment was always best place to drill an oil well is in an oil field. So we're in an oil field. It's development drilling. We look at the time line and the costing. We closed our offer and the funding will come in early next week. We will be moving quickly to get a drilling permit and get drilling here. Cost per well is $550,000. Our lifting costs are less than $6 a barrel, and we get an 81.25% net revenue interest. So because we're so close to the refinery, it's a perfectly located, low-cost, low-risk vertical well development program. So a little bit of background. Between 2011, we first got into this field by happenstance through a colleague of ours that was a contractor, and we drilled over 70 wells in a period of time. And as you can see, the gross revenue from this field was $33 million with an EBITDAX of $15.75 million in 2014. Oil price at that time was north of $80. Of course, it ran up higher than that, $110, $120, and then it went back to $27. So there's a volatility problem sometimes with the oil price. But normally, we're stabilizing north of $60. And as I speak, it's gone back to nearly $70. So this was a very successful business operation, utilizing local contractors, and we delivered some pretty good results in a short period of time. It wasn't ConocoPhillips, but it was a good effort for a small capital company out of the Australian Stock Exchange. When we drill out here, what we like is we go from 0 surface down to about 5,000 feet, and we drill vertically because as we go vertical, we pass all of these other yellow highlighted pay zones. So our target is the Mississippian down the bottom here. And above that, you can see there's a -- this is all Mississippian aged rock above that is Pennsylvanian aged rock up here. And the sandstones have been prolific oil producers since 1922 when this oil field was discovered. And despite the drilling over the years, what we're finding is, originally, they recovered about 10% of the original oil in place. Now with modern fracking techniques and high-volume pumps, we're able to go and get at least another 10%. So as I said before, the best place to drill a well is in an oil field, and we're targeting this Mississippian where we've had a lot of success. One of the reasons we go vertical and not spending more money on horizontal wells that historically, we found that in half a mile, there might be an 80-foot variation in the top of the formation. So if you're running a horizontal well out through here, you can actually miss the targeted pay zone by 80 feet in half a mile. So we've had a lot of success drilling vertical wells. Every well we drilled, we intersected the formations. The only well we lost out of all of our -- was a cracked casing. We had an issue downhole mechanically. We came back up and recompleted it in a shallower zone and still made a producer out of it. We've got documented history of the decline curves for oil and gas over time. As I said, we've been here for many years. We've got a target zone at 4,300 feet below surface. So they're shallow, low-cost, low-risk vertical wells. Our dry hole cost to drill a well and log it before we make the decision to complete the well is less than $100,000 in drilling and logging costs. So this is, as I said, low risk. Target zone, 300-foot thick. It's laterally extensive. In other words, it covers a large area of a marine sequence limestone sitting on top of a geological formation called the Nemaha Ridge, which has caused it to naturally fracture. So when we go in here and we do a small frac with slick water on it, the current natural fractures open up further using hydraulic fracking, and we have very good initial production and paybacks of even at $60 a barrel, we're getting paybacks at about 14 months. If the oil price goes to $80, our payback comes back in less than 12 months. When we were drilling out here and we got to $100 a barrel, our paybacks were 90 days. So that's revenue back from the production from oil and gas to pay for the development. Low cost, $550,000 all in. and up the pipe if we -- in about 15 years' time with the depletion factor tied in, we can come back up to the shallower zones and recomplete for a lot less than a new well, $70,000 per zone. There's a lot of geological work going in here over the last 15 years since I've been involved in this area, and we can talk about that if people have technical questions later. One thing I love about Oklahoma is go and get your permit, it takes about 7 days to build a site. The rig will move in normally on a weekend. And by -- for some reason, it's always at 2:00 or 4:00 on Saturday morning, we'll be out there in a logging truck testing the formations to see what we have downhole. Once the well is cemented and cased, we wait for a few weeks and we come back and we do a frac job. It's a single-day multistage limited entry slickwater frac. So we use local water to do that. We use sand, of course, to prop open the porosity zones once we fracked it. And within 60 days of start, we're tied in and putting oil in the tanks as well as gas produced alongside with the oil. Next 180 days, we're going to be busy. I've just relocated over here. I've got a be to live here for the next few years. And we've already got in place our drilling contractors. We've leased the sites. We're ready to go. We'll get our permitting underway. We're going to drill 2 wells initially. We will be drilling between now and September 30. There will be lots of news flow as usual as we complete each well. And in the meantime, we'll be deploying our generators and Bitcoin mining containers with our partners through BitFuFu, and you'll be getting a lot of news flow about as we increase our footprint and get that generator power up and running. Ponca City, 5, 6 mile away, local refinery, 30-day sales cycle, what's that mean? Whatever we sell by the end of the month, we get a check on the 20th of the following month for everything we sold. So it's a cash flow business. Once you drill a well, some of these wells in this oilfield are still producing 40 years later. So your capital cost upfront is recovered quickly, and then you have a trailing revenue stream with program maintenance for many, many years to come. One of the other sides, as I said about this is how do we get our power, natural gas generators running crypto is our target. Oklahoma is very friendly to the digital asset class. We're seeing a number of sites being rolled out. One that we really like here is, of course, BitFuFu is at Muskogee, which is about 1.5 hours from the oilfield we're developing. And they're very, very proactive and very keen to help us roll out quickly in Oklahoma as their warehousing, technical staff and support staff are only 1.5 hours from the field. They run a 62-megawatt on-grid power system at the moment. and they're looking to get to 100 megawatts off grid in Oklahoma and Colorado over the next 18 months. Depends who you talk about..

Sorry, Dan, if I could just stop you there. This slide can't be used at the moment. If we could just skip to the next slide, that would be great.

Sorry. Okay. Right. I'm not allowed to talk to that at all. Okay. So back to what I was saying about, we're very well placed in a very topical situation at the moment, gas to power from natural gas. We've proven a model 1.5 megawatts, Colorado, 260 Mcf of gas a day runs 1.5 megawatts which at an 80% uptime plus or minus, delivers between 9 and 10 Bitcoin per month to our joint venture partner, and we get paid for supplying the electricity in share of that Bitcoin revenue, which we then turn back into cash at the moment. So we've got a strong partner targeting 100 megawatts by December. We've got an identified pathway in parallel with Colorado, where we're waiting for permitting processing. We're going to get after it in Oklahoma, very pro oil and gas opportunity. The regulatory authorities are very on side. A lot of the state revenue is driven from fossil fuels and now, of course, from AI and data centers. So they're very pro the business. One thing about this, we previously ran oil companies that had revenue from oil, natural gas liquids and you would sell your gas down the pipelines to a variety of buyers in Oklahoma and would get paid on a cycle monthly. By layering over the crypto mining on our oil and gas sites, we still get the oil revenue, which we get to keep. 81.25% is our net revenue interest. We strip out our natural gas liquids, another form of income, you sell that out and the gas that's burned to power the electrical generation will go into the data centers and we share in the revenue derived from that operation. So you'll see that we are really well positioned here that we grow this business over the next 12, 18 months, and we hit some targets 15 megawatts would be 10x what we're already doing, which means we need 2,600 Mcf of gas to run 15 megawatts of electricity, which on the modeling would deliver between 9 and 10 Bitcoin a month. And with the price of that commodity above $110,000 a month, we could be in for a fun time coming up over the next 18 months. So I'm going to pause there, and you can see our Colorado operation where we're running our 2 pump jacks a little story. Actually, I'll just finish here. We've got 2 pump jacks on the one location. The one on the right is producing from a well-known shale formation call it the Niobrara and the one on the left is a brand-new well in the Greenhorn formation and is producing hydrocarbons for the first time in this oil field. So we have the Pierre formation at the top. We have got the Niobrara below that. And now we've got the Greenhorn making hydrocarbons. And I've got other operators wanting to know what we did, how we did it, how can they get involved, and that's Colorado. Like I said, in the meantime, we're in Oklahoma, while we wait for regulatory approvals, and we'll start drilling between now and 30 September. Over to you, Alex.

Thanks, Dan. We have had a couple of questions come through. Firstly, Dan, can you compare the cost of drilling wells in Oklahoma to what AXP has traditionally drilled in Colorado?

Yes. Look, this table here outlines Oklahoma. So the well costs up in Colorado to complete a vertical well is between $900,000 and $1.1 million. To go down and drill a horizontal well is higher than that, closer to $2 million by the time you frac and put surface equipment on. So it's a lot more expensive. The other thing that's happening in Colorado is that the workforce has moved northeast of Denver to where all of the activity is on. And where we are, there's only 2 operators. So most of our contractor work contractors in Colorado have to drive 4 to 6 hours to come and be on site with us. So the cost of the wells are $550,000 in Oklahoma and $1 million plus in Colorado.

Thanks, Dan. So I guess in a similar vein, given, as we mentioned, you're significantly experienced in this part of the world, what's the regulatory environment more broadly like in Oklahoma?

It's an oil-friendly business. We are in a very active regulatory environment. There's still a lot of drill bits turning in Oklahoma. The process for getting permitting because we're in a well-known oil field is around 14 days from application and you get a permit, we do not have to -- there are other layers of regulatory environment in Colorado that delay that process to up to 9 months to 12 months. It's a different process. This is faster, efficient. A lot of it is done online now. We're drilling in a well-known oil province with a very friendly state government who is very supportive of the national government's policy of drill baby drill, and that's what they want.

So Dan, besides the Miss Lime formation, can you just talk us through some of the formations that are productive formations that you're looking at?

Yes, sure. I got to find it. There we go. The oil field we found out here that we got involved with AusTEx was based on the fact that previous life it had produced 7 million barrels of oil in a very small unit out of the Red Fork sandstone, which is Pennsylvanian age formation, which is a system that sits on top of the Mississippi Lime. And you'll see down the bottom is the Woodford Shale right at the bottom. You'll read stories about people drilling the Woodford Shale southwest of this area. It's a well-known source of oil and gas. And as it migrates northeast up dip towards where we are in the Nemaha Ridge, the oil is trying to get to the surface. And over the last 40 million, 300 million, 400 million years, it's found its way into all of these stacked pay zones in the Pennsylvanian age rock. The other thing that's quite interesting is the Cleveland, the Leighton and the Tonkawa sand are all prolific known producers in a sandstone environment with oil and gas present. The Leighton is actually a 300-foot thick laminated sandstone with a water drive in it. Above the Tonkawa, there's actually a Perry sandstone that's shallower than we're showing, and it's known as the Perry gas formation. If we go back down to the big lime and Oswego limestone, hear the word limestone, they're very similar stratigraphic makeup as to the Mississippi Lime. Separately, since leaving AusTex Oil, I have a private company that's been operating here with my previous Chairman, and we actually successfully drilled fracked and completed for production, both the Big Lime and Oswego Lime, comingling those production -- those production formations. So as we sit and look at this stack of pay zones, starting at the bottom, there's so many opportunities to make oil and gas over the next 20 years. And it's unbelievable about you can drill same pad wells, just like we've done in Colorado, where it can be producing from the Mississippi solid on one well and you can come down and hit the Cleveland or the Big Lime and Oswego and another well on the same pad and have double producers there. So that's -- it's a very prolific area. Remembering in historical days, most of the oil that was recovered was only about 10% of the original oil with new techniques, we can now come back and get up to 20%.

So looking at some of the historical IP rates from the wells that AusTex drilled, these were wells that were drilled and completed over 10 years ago. It's now 2025. So how do you know that these formations are not depleted?

As you can see from the map there, this is to the north of the leases that we've hired -- we've leased now. What we found is if you'll see how close those yellow circles are, as we frac that close together, we've never had a connectivity between a well to another well. This rock is this is not a pool of oil. A lot of people think oil just sits in a pool. Oil is trapped in rock, and it's got to come out of that rock and the porosity of that rock determines how far the oil will move through the formation. So as we've drilled north of us here with our -- you can see in that blue circle, there's probably about 20 wells that were drilled, some of them as close as 10-acre spacing. And when they were fracked, it was -- the rock formations did not connect to one another even after fracking. So where we are to the south of that, there has been 2 wells producing out of the Mississippi lime on the leasing we have many years ago, they were producing out of the chat. We've got logs. We've got confirmed stack pays. We've got confirmed oil present and none of this area is being produced. So we would expect similar results to what we got in the square mile to the north. So we're only half a mile from the closest well we drilled at AusTEx. And to the south of us, recent development by another group has drilled 7 wells in the last 6 months, all producing in the square mile to the south of us. So continuity of the reservoirs has been demonstrated, and we also know that the drainage radius of each vertical well appears to be less than 20 acres. So we know the oil is there. It's a matter of getting after it.

So what was the reason behind drilling verticals compared to horizontals in Oklahoma?

We covered that quickly in this slide. With well control of the wells we drilled plus historical drilling across the area, and we had some big brothers like Range Resources shot seismic across the area, we found that because of the natural fractures and the uplift from the Nemaha Ridge, we've got variability in the top of our pay zones. As you can see in that 2 log comparison, half a mile apart, which is only 2,620 feet apart or whatever it is, 5,280 feet, 2,640 feet apart, we've got an 80-foot vertical variation in the pay zone. So if you're trying to stay in the top of that pay zone with a horizontal drill bit that's less than 8 inches around, you have a hard time staying inside the pay zone when you've got such vertical variation. So hence, our previous Chairman, Dr. Peter [ Power ], PhD geologist, suggested that what we do is drill vertical wells. Every time you drill a vertical well, you get every stack pay zone. And by using modern frac techniques, we have shown and demonstrated the economics of the vertical well far outpace those demonstrated by partners in the area that we're drilling horizontal. And all the big horizontal well drillers packed up and went home. smaller companies like ours continue to drill vertical wells because of the variation in the top of formations that are demonstrated from well control.