Prospex Energy Plc (PXEN) Earnings Call Transcript & Summary

Good afternoon, and welcome to the Prospex Energy Plc Investor Update. [Operator Instructions] Before we begin, I would like to submit the following poll. And I would now like to hand you over to CEO, Tom Reynolds. Good afternoon.

Thanks, Alex, and good afternoon, everyone. Welcome to the first in a series of asset-focused deep dives that we're planning to run here at Prospex. Today's presentation is focused on our Polish assets and specifically the Mniszow oil discovery in our Dunajec license. I'm going to take you through some of it. I'm joined by my colleagues, Alecos Stavrou and Tomasz Rosowski, both of whom are in our geology team, and they have been working on this since the license award and indeed before the license was awarded during the application process. So without much ado, I'm going to crack on. I'll be making reference back into this photo as I think some of our viewers will know, we made a field trip to the location last week, and this is actually the Vistula River, which runs over the top of the mapped [indiscernible] field. We'll be referring to that later. So introduction to Prospex Energy. I'm going to run through that very quickly. Just this marker slide here, which is a separator just going to draw your attention to like a spot-the-well competition, but there are 3 wells, existing wells. This is an overview of the Grobla field 1, 2, 3 existing well sites on what is a fairly typical landscape in this part of the world. You can see it's broadly agricultural and good road access to the well sites that you can see here. So a very brief introduction to Prospex in general for those joining the story new today. Prospex has a broad asset portfolio across Europe, multi-jurisdictional assets. So we have assets in Spain, Italy and Poland. In Spain -- sorry, excuse me, in Italy, we own 37% of the Selva Malvezzi concession in Northern Italy, operated by Co Valley Energy. That's a producing asset and currently producing from gas from the PM1 well, and we have a 4-well program that we're looking forward to in 2027. Moving to Spain. We have two assets, one in the North, Viura in the Rioja region, where we own 7.24% non-operated interest in a very high potential asset, also gas, that's held through a 7.5% share interest in HEYCO Energy Iberia. That's also a producing asset and producing gas today. And El Romeral, Tesorillo & Ruedalabola licenses, Andalucia of Spain down in the South. Prospex owns 100% of Tarba Energia, the company which owns those concessions, and therefore, we have 100% exposure to each of those assets. El Romeral is a historically producing gas field and continues to produce relatively low amounts by gas to wire. So it generates and sells electricity at a dedicated plant that we own in South Spain. Tesorillo licenses are exploration concessions. And then finally, San and Dunajec exploration licenses that were awarded in Q2 of this year in Southern Poland. Prospex has a 100% ownership position and the Dunajec license includes the Mniszow oil discovery that we're going to talk about today. So in summary, Prospex has a diversified portfolio across Europe in some of the most historically productive basins onshore in Europe. And we're very excited about all of these assets for slightly different reasons, going to shelf today. Just to finish off the introduction to Prospex, what's the corporate investment case. I always look at this as external factors which set you up for success. So that's the extrinsic points that I've listed here. And then also what are the internal specific things to the company in question that offer investment positives. So from an external point of view, we're looking in Prospex at real assets. So these are commodities which hold their value in currency terms during periods of inflation, which I personally think is quite important in today's potentially stagflationary environment. Period of growing energy demand driven by a number of factors, but digital infrastructure growth is one, but also some of the signs we can see in international supply chains at the moment show that homegrown energy resources inside your borders are particularly important, which leads us to the final point there, energy sovereignty. As free access to imported energy becomes less guaranteed, local energy resources will be more valuable. There will be a strategic premium in my opinion. And then when you look at the internal factors that support value growth in the company, each one of our assets, and we're going to talk about Mniszow and really show this in a great deal of detail today is we have an identified pathway to grow value for our investors through the process of derisking and development in this case. What's our goal when you bring all of this together at the portfolio level is to create a cash compounding machine. So cash flow from asset 1, invest in asset 2 to grow and become a cash flowing asset, which then both of those invest in asset 3. And that compounds investor value over multiple investment cycles fundamentally growing value. And if we're doing our job making sure we're communicating appropriately to the market, that should be reflected in the price that all of you see on the screen. And one real flag, and I'm sure we'll touch on this later when we get into Q&A. But at each stage, every investment that we make is assessed rigorously against the value added per Prospex share. That has to be our guiding light and that has to be what supports our decision-making in any investment we make. To move now on to specifically San and Dunajec licenses situated in Southern Poland, starting with the San license, which you can see here. Map on the right shows you the location in Poland. So it's in the southeast of Poland, not far from the Ukrainian border to the Southeast. And the map on the left shows the historic trend of gas discoveries and commercial production running from Southeast up to Northwest. You can see these red oligons effectively show the existence and location of historic fields and the text in here shows the historic size. So we're in a very good neighborhood, proven petroleum system, proven prospectivity. The target here is Miocene age, so shallow gas accumulations. And we already have a head start in the license, which is shown by the three leads that are identified here, which are sitting on our block. These were identified by the Polish Geological Institute, and they are the first place we're going to start investigating on this license. Moving to the Dunajec license, slightly to the southwest of San. You can see its location on the right-hand map. So the Dunajec license has two viable geological plays. First is the Cretaceous and Jurassic fracture reservoir oil play, which we're going to talk about in great detail today on the shore. And it also has the Miocene turbidites gas play, very similar to San. You can see just looking at the license map on the left that historically there has been gas and oil discoveries found and developed on the block. And you can see that immediately to the south, the very active gas zones that has obviously moved into the block with this prospect here. What we're going to focus on is Mniszow, which is situated here. So a brief introduction to Mniszow. And you can see for the first time the outline of the field shown on a depth contour map on the left and its location within the block and the sort of highlighted map on the right. Mniszow is a historic oil discovery, multiple wells with oil shows or oil to surface within the field contour that we're showing on the left. It also sits between the Plawowice field to the north and the Grobla field to the south, both of which were commercially developed during 60s, 70s and onwards using vertical well, which was state-of-the-art of available technology at the time. Mniszow was not developed and resources were effectively preferentially allocated to Grobla and Mniszow at the time due to their production performance. But what we have is a great deal of historic data, has allowed us to map the field and really examine what we have here and look at the potential effect and impact of applying modern technology. And being able to review that historical database and an example of a well log is shown here, which shows clear oil saturation over fracture carbonate. We've taken all of that data and used it to estimate the oil in-place figure, which we got about 13 million barrels is our central estimate. And the recoverable reserves that, that potentially delivers is 3.7 million barrels. So what we've done, and we're going to talk in more detail today is designed an 8-well program using modern drilling and completion techniques. We've used that to construct a pathway, construct a capital estimate based on engagement with suppliers in the territory and run economics on a full field development basis, which we'll be sharing. So to talk about geological setting, I'm going to hand over to Alecos in the first instance to talk us through that.

Thank you, Tom, and hi, everyone. Today, I'm going to spend a few minutes to walk you through the oil geological sitting in gas. And then we're going to touch a little bit upon the gas play. So the reservoirs for the oil play are predominantly Jurassic limestones, which are typically deposited in shallow seas. And in the slide, you can see what Europe looked like in the late Jurassic and the area of interest, South Poland is indicated with the red circle here. The takeaway point here is that we understand the reservoir depositional environment, and we can use that knowledge to inform our production strategy. Further to the oil play in Dunajec, we have the Miocene gas play. And following the deposition of the limestones that we mentioned in the previous slide, the Carpathians continue to emerge. So in the late Cretaceous and tertiary, the basin changes into a foreland basin. The mountains load the underlying plane causing it to flex. This creates sedimentary basin and the subsequent erosion for the surrounding area fills the basin, creating reservoirs. This is the foundation of the Miocene play, which is the basis for the gas reservoirs in both blocks. And the key point here is that is worth keeping in mind, there is more in Dunajec than just the oil play and more than just the rehabilitation of Mniszow. And my last slide before I hand over to my colleague, Tomasz, is a complete review of the petroleum system chart here, and we're not going to really go into the detail. I just want to bring your attention to the two depositional events of the reservoir. We have the limestone in the Jurassic, followed by the sandstones in the Cenomanian. Again, key point here is that Mniszow has all the elements of a working petroleum system, and we can go into more detail when you look at the cross-sections. With that, I'm going to hand over to my colleague, Tomasz, who will walk you through the more specifics of the reservoir.

Thanks, Alecos. So now we are looking at North South cross-section across Plawowice fields north of Mniszow, discovered in '63, containing 12 million barrels of oil, produced just under 5 million barrels to date. It produces from on average 6.6 meters average Jurassic fracture limestone and 2 meters of Cenomanian sand and conglomerates. When you compare this to what we have over Mniszow, we have 10 meters stick average fracture carbonate and 12 meters thick Cenomanian sand and conglomerates. That's another field south of Mniszow, Grobla, gas discovered in '62. It's an oil field with a gas cap, small gas cap contained 48 million barrels of oil and 9 Bcf of gas, produced over 20 million barrels to date and 5 Bcf of gas. The fracture carbonates are much thicker hit 20 meters and Cenomanian on average 9 meters stick. It produces both those fields produced from vertical wells. We believe that applying modern technology to what we have over Mniszow will significantly increase EUR and flow rates from wells drilled over Mniszow structure. So how we mapped Mniszow. We've assessed over 30 wells from the area of interest. We've integrated data from final well reports, open holes, formation tops and well test and core information available from historical wells. We've adopted some structural features. You can see east-west faults, Mniszow South and North. That's those faults were adopted from historical maps. No seismic was used for mapping of Mniszow. There are a few poor quality, poor coverage legacy lines that were not incorporated in mapping exercise. You can see 2 oil water contacts, 505 from Mniszow South and 430 meters from Mniszow North. That's proven by existing information from well tests. So we have high confidence in the structural interpretation of faults presence. Based on our mapping, we calculated at 13 million barrels oil in place. So if we dive into subsurface, that's West East correlation panel. You can see the correlation on the map on the left-hand side, how it runs through the field. It dips to the east. We can -- as mentioned before, we can clearly see oil water contact being mapped by well test. We have good well control over this field, just well down deep oil water contact flowing oil and water and well test just above the mapped oil water contact flowing oil. Another correlation panel north-south this time. You can see on the correlation panel, those two major falls bonding the field, number of wells with well test above oil water contact testing oil to surface all shows wide drilling or oil in core. You can also see the outlines of the field. Those are the vertical lines that you can read on the correlation banner field outlines. Yes, over to you, Tom.

Thanks, Tomasz. Okay. So what we're going to try and do is put this in context by considering analogs that we can see, and we're taking two types of analog. The first is direct analogs, and we've just heard about Grobla and Plawowice. So these are adjacent oil and gas fields that have commercially produced large quantities of oil, 20 million barrels and 5 million barrels, respectively. And in both of those fields, the hydrocarbon bearing formations are exactly what we see in the Mniszow, but slightly different thicknesses, and they've had slightly different production performance with vertical wells, as you've seen. The key point that we're taking away from this, and I would want people to be hear loud and clear is that we have a viable reservoir rock that in nearby fields produced commercial quantities and commercial flow rates of oil by natural production from vertical wells. And a number of those vertical completions delivered over 200,000 barrels of oil from a single well, vertical well completions. That's the key point. What we've then done is look at offset analogs in other parts of the world where you've got shallow fractured carbonate, may have been developed historically using vertical wells and then being tested with modern completion technology. There's a couple of very strong analogs that we're going to mention here. First is Mississippi Lime or Mississippi Chat limestone. A good example is the one that's operated in Oklahoma by Sandridge, 900 to 1,800, so slightly deeper than we're looking here and also relatively high water saturation compared to what we're looking at here. But the key point about talking about this is that the development of horizontal wells led to very high ultimate recovery figures that you can see here, 300,000 to 500,000 barrels of oil well, even with higher water saturation. Even though the reservoir was of a similar thickness to what we see here. So very interesting, strong analog to show that the such a fractured limestone, even in the presence of some water saturation can be highly economic with modern technology. And then the second analog, and I'm going to click on here is the salt flat field in Texas. So this is a field very similar to Mniszow. It's a naturally tight limestone reservoir. It relies on fracture networks within the reservoir to provide permeability and the flow of oil. This field has been producing in the U.S. in Texas. since the 1930s and was developed by vertical wells. And you can see that well to well, it depends whether they hit a hotspot or a kind of fracture, a natural fracture within the reservoir that delivered more or less production. By the time we got to the late '90s -- early '90s, the field is very mature and production had dropped off to the chart says, around 6 barrels a day. What happened then and what you can see on the chart here is the impact of horizontal drilling that was placed using modern seismic. And you can see a massive increase in production from 6 barrels a day to 3,000 barrels a day. And this is in a mature field location that had been produced significantly for 70 years at that point. So we're taking a great deal of information from this sort of historical analog and applying it to Mniszow, and we believe that the application of lateral drilling, asset stimulation and potentially other techniques that we can use in the completion will give us an ability to connect natural fracture zones in the reservoir that we see and increase production and ultimate recovery from the Mniszow field. So that leads us into the outlined development plan. The graphic you can see here is a close up of one of those wells on Grobla. So you can -- so I think one of the important points here is -- and this is by reference to the broader portfolio. This is active wells, and this is a couple of kilometers from the Mniszow field. So the local population, the agricultural networks in that area are used to seeing this sort of activity, and it's still going on 2 kilometers from where we'll be focusing our efforts. In terms of breaking down the development plan, there's three phases of drilling. The first phase will include acquisition of 2D seismic. We plan to do that early next year, early 2027 to gain structural clarity on field. As Tomasz said, the historical seismic isn't a great quality or particularly relevant structurally. So we think it would be a good investment to acquire some new high-grade seismic that we can use to finalize the well location and targeting. Pilot well targeting Q4 2027 after engaging with local service providers last week across in the country. And the intention there is to both gather information on the reservoir through coding and electrical image logs, case the top reservoir and then drill out a lateral well using coil tubing to deliver initial open hole lateral capable of enhanced production. And that's taking the analog that we were just talking about in south and the Mississippi line, seeing how we can apply it economically and efficiently here in this location at fairly shallow depth. There's two further phases of drilling planned, 4-well program, which would be late 2028. And a key part of the plan here by splitting it into phases, it does two things. It allows you to recycle cash flow from successful earlier wells, offsetting the need to raise cash to perform activity, a key thing, and I'm sure everybody will understand what that means. And then the second point is that any learnings or optimizations that arise from earlier wells can be applied to subsequent wells in the program, so you can make tweaks or redesign changes to boost production and boost ultimate recovery. And then finally, 29 onwards as the slide says, a 3- to 5-well program to basically infill and maximize recovery from the field. So step 1 seismic survey, the map on the left, you can see the field outline of North and South in our license area overlaid on top of the topographical map of the area. You can see here, if you see my cursor, this is the sweep of the river that's in that opening slide. So right in the heart of the Mniszow field area as we've drawn it. The intention of the seismic grid that you can see in blue is listed here. It's to provide the confirmation of reservoir continuity to provide confirmation of the reservoir top and thickness, to detect major faults, both their location and orientation, whether they run across the structure or up and down the structure and to evaluate the updip extent of the reservoir where well control is limited. If we were to go back and look at Tomasz' slide earlier, you can see there's a large number of wells on this structure, but there's very few wells over here that would define where the reservoir map might extend to. So there is possibility for some upside volume over into this area, depending on exactly where the reservoir rock pinches out. We're taking the seismic, and we've designed the seismic rig to support those conclusions. Then we move into the development plan. The seismic should be shot Q1 next year. It gives us some time to analyze it, interpret it and then feed forward into detailed well planning and well targeting. Hopefully, you can see the red line here, which represents top hole and that lateral targeted in the sort of heart of the Mniszow area, where we have good well control from historic wells. And you can see it's very much overlaid on that intersection of the seismic lines. So we get very good local seismic control. The schematic on the right is really just giving you an idea of what this will look like vertical scale, obviously compacted. Otherwise, we have slides. The intention here is to drill a standard vertical well efficiently and quickly down to the reservoir, core through the reservoir and also take in it logs. Go back out, case here down to top reservoir and then reenter the hole with coiled tubing to drill a 400-meter lateral is what we're targeting. If we can get more, then we will drill more. And that's all about intersecting those natural fractures that you can see shown in a diagramatic sense here in the limestone. That's where the permeability comes from. That's where your path to production comes from. The more fractures you can intersect by longer horizontals, then likely to be higher recovery, higher production. At the moment, we're drilling north-south direction to intersect as many of those as possible, and we'll gain information from this test and then be able to roll those learnings forward into subsequent wells. Taking that process and that specified pilot well, and as I said, we have met with a number of suppliers last week cross over in country, and we've got initial budgetary estimates of CapEx that we have incorporated into an economic model, which covers the full field economics. So production profiles are based on very much the local experience seen in Plawowice and Grobla and the analog performance. We've taken what I believe is a conservative view of the potential uplift that can be achieved through horizontal drilling. You can see on the box on the right, we have assumed 300 barrels initial production rate and what I think is a reasonable ultimate recovery per lateral based on other analogs where we've seen that. The pilot well is going to be drilled in Q4 2027. So production isn't expected to start until '28, which you can see the fall production in '27 there. And then 4 further wells drilled in '28, the bulk of which -- the bulk of production from which will be seen in 2029. And then there's a final campaign of three infill wells, which incorporate learnings as well. So the model assumes a conservative oil price average of around EUR 60 a barrel. That's about $70.5 per barrel today. Initial well cost of $4.5 million, that's for the pilot well. We haven't modeled it, but we would expect learnings over time to improve the cost and to get efficiencies out of multiple well programs. 8 wells in total and then, as I said, 300 barrels initial production rate and an ultimate recovery per well of 450,000 barrels per well. So the results, you can see the production profile shown on the left, which pretty healthy, growing on a 100% basis. Economics on the right in the bar chart, those blocks some to -- they're broken down to -- these are NPV-10 numbers in millions of euros. The figure -- the first box is for the first pilot well based on those sets of assumptions, 4-well program in Phase 2, 3 further wells in Phase 4. Total NPV sums to EUR 54 million on an NPV10 basis with that set of assumptions. That equates to around just under EUR 16 per barrel. So it's a very attractive development on those numbers. So what's the path from here? In terms of the time line that we've laid out, we're sitting in Q3, and we're doing an IMC presentation right now. We're now entering a period where we go into well program design and identifying long lead commitments that we need to access whether that's resources equipment on material and consumables. We're also going to instruct advisers to prepare a preliminary competent persons report. So that's an independent ratification of the reserve estimates that we've already produced in-house. Moving into Q1 next year, the acquisition of 2D seismic that I talked about, that will allow the CBR to be updated in light of that better data, tightening those reserve estimates and improving uncertainty on those, then moving into the operational phase through the middle and end of the year. I've flagged key project commitments as we go through here. During Q4, I expect us to commit to that seismic and a design lock on what we are prepared to drill next year. That feeds into the seismic survey, the results of which will then allow us to confirm the well location and trajectory in terms of what we found from that and lock in the drilling equipment. That then moves into Q2 next year permitting and land access, preparing the well site and all equipment into location in Q3 and drilling the first well on the Gulf field in Q4 '27. You can see also what I've included here is the green line of decision bubbles, and that's really just to flag our program that we are expecting to engage with third-party investors to join us in. I expect that to be in a position to confirm partnership investment at some point towards the end of this year. That process at the moment has kicked off, and we're engaged with a number of potential investors. They have to do their own physical, technical and commercial due diligence, and we have to negotiate a fully termed agreement to lock that in. That process takes time. And I really just guiding expectations that confirmation is likely to come towards the end of the year, later in Q4. In line with the hard yellow commitments 2 and 3 that you can see on this that new partnership that would be formed as a result of that investor joining would take a decision to commit all funds and press the big green button to get on with it somewhere around the end of Q1 and then support the program with funds through to first oil. So really just to pull everything together here, this is an unashamedly bullet point list of telling you what we've just heard. But I really just want to join the dots here in terms of just going back through some of the points we've covered in the individual slides. So the first point is that the Minishof oil discovery has been mapped here using a significant body of historical data, which allows us to map contour depth and volume metrics of the reservoir here. with a high degree of confidence. And neighboring field shows that the carbonate reservoir at Minsowz is a viable producer but using vertical wells in the past in 60s and 70s, it was not considered viable. We now have a number of data points, which shows both in local and international analogs that the application of modern production technology dramatically improves the performance of mature limestone plays like Minsowz, and we expect that to have a very similar impact here. The team here has done a fantastic job. I have to say I'm hugely impressed by my colleagues' ability to take raw information at the point of license award back in April to where we are today in less than 6 months where we have an executable development plan. We're engaged with the oilfield service community. And we've got what is a highly deliverable plan through to this time next year being prepared to drill that first well. The base economics very much support strong valuation. I've already mentioned the EUR 54 million NPV10 basis subject to the assumptions we already flagged, 15.6 a barrel. That's highly competitive when you look at the net economics of a number of other onshore developments in Europe. And that we think gives us a very strong basis to engage with potential investment partners. And as I've already said, that process has now kicked off, and we are engaging with a number of counterparties that are both technically and financially competent to join us on this journey. So with that, that's the meat and drink of what we wanted to talk about today. Colleagues will come back and join me, and we're just going to take some questions.

So we were provided with some questions ahead of the IMC kicking off, and thanks very much to those participants that took the time and thought to provide those questions before. I'm just going to start with those whilst any other questions that people may have flow through. I'm probably going to group them into three spaces rather than trying to answer it because there's some similarities in the question. So the first question is, just reading a question about potentially spreading ourselves too thin. We already have an existing portfolio that at the start. And by adding an additional string of activity, are we spreading ourselves too thin and potentially making ourselves vulnerable. So the way I would answer that question is that Prospex is an investing company. Our job is to find opportunities to deploy our investors' capital where we think we can make very strong returns. We'll do that in a number of different ways. We'll do it by getting involved as we have done in the past with in exploration concessions. And spending money to identify, test, prove resources and then move them into production. Selva Malvezzi is a very good example of that, where it's paid off in the space. And we have to constantly be moving forward and adding new things to be able to grow the business, both in terms of productive and cash flow terms, but also to provide follow-on investment opportunities. I very much see our Polish licenses in that vein. I don't believe that we're spreading ourselves too thin. I believe this is a natural part of our ongoing investment process. The second question that was pre-submitted is one about -- there's another question that has some similarity to this is that obviously in raising capital to fund this activity, how can we be sure that we don't dilute existing shareholders and investors who already own a position in the company. So this is a big subject, one that comes up consistently whenever we engage with shareholders on an informal individual basis or scheme. it's worth spending a little bit of time talking about this because I think it's critical to understand. The way I think about this is to move our assets through that value curve, which is to derisk them, to develop them or to discover resources, capital must be spent. And therefore, Prospex must find access to capital to perform that activity. And that process is necessary because we don't get paid -- our investors don't get paid for assets that have been put on the shelf, hoping that someone just sees the benefit. We have to demonstrate there is more value in these assets by following that process, derisk, discover, develop. Costs money, so we have to find it somewhere. I'm going to run through a few places where we should be seeking money in order of priority. So the first is cash flow. It's the cheapest form of funding that any company has because it's the money that you get on a regular basis. You can either apply it on a monthly basis or save up, and you allocate that. It's the cheapest form of equity you can find. It does not involve in selling anything other than current production. You don't sell out assets, you don't sell out shares in the company. And therefore, it is non-dilutive and it's the cheapest form of capital you can find. The second ranking behind that is to effectively sell forward through raising debt. So debt is raised effectively by selling forward right to future cash flows. You advance that money, and you can then apply it to productive uses like developing more. Again, non-dilutive on the basis that it doesn't involve selling equity and doesn't involve selling anything at the asset level. You then move into equity capital. If debt isn't available because your assets aren't mature enough to support debt of appropriate cost or your cash flow is limited, then you move into equity funding. And I think at the heart of this question about dilution from a Prospex perspective is do we have to sell shares of Prospex, therefore, diluting our interest in the whole across the whole portfolio to fund these activities. And what I'm going to say pretty clearly is no. I believe we have a path to focus on these individual opportunities and bring in people who are focused on just these opportunities and raise capital at a valuation which reflects the value of the asset we are selling a part of, not the current screen price of Prospex Energy Plc. So that allows us to raise capital at a much more favorable valuation. And although we are selling something to raise that money at the asset level, it is non-dilutive for Prospex shareholders. So moving on to the third question. And Alecos and Tomasz, I'll perhaps ask you to fill in here as well. There's a question here about the development strategy for Mniszow. And the question basically asks, given this is a shallow fractured carbonate reservoir, what specific methodologies are we considering to maximize fracture intersection whilst mitigating risk of water production. I think we've covered some of that by talking about the method we're going on. But perhaps I think Tomasz, perhaps you could talk specifically about some of the things because we've talked about it extensively internally.