Greetings, and welcome to the Tamboran Resources Shenandoah South 2H ST1 IP30 Flow Test Results Conference Call and Webcast. At this time, all participants are in listen-only mode. If anyone should require operator assistance, please press star zero on your telephone keypad. A question-and-answer session will follow the formal presentation. You may be placed into question queue at any time by pressing star one on your telephone keypad. As a reminder, this conference is being recorded. It's now my pleasure to turn the call over to your host, CEO Joel Riddle. Please go ahead, sir. Thank you, and welcome to Tamboran Resources' special webcast to discuss the Shenandoah South 2H IP30 Flow Test Results. My name is Joel Riddle. I'm the Managing Director and Chief Executive Officer for the company. Before we get into the materials, I'd like to refer everyone to the disclaimer statement on slide two associated with forward-looking statements. Starting out on slide three, I'm very pleased to report this morning that Shenandoah South 2 well has been flowing for the full 30 days and has achieved a Beetaloo Basin record, delivering an IP30 flow test of 7.2 million cu ft a day over approximately a 5,500-ft horizontal section. That would be equivalent to a 13.2 million cu ft a day well normalized to a 10,000-ft horizontal. This IP30 well performance from Shenandoah South 2 is largely in line with the average performance over 11,000 wells in the Marcellus Shale dry gas window and is on the P50 EUR distribution curve among all the wells that have been drilled in the Marcellus dry gas area. In addition, I'm very encouraged with the strong correlation of a very limited decline rate that was seen in Shenandoah South 2 in relation to the previously drilled Shenandoah South 1 well. This well has demonstrated very shallow well decline and a sustained reservoir pressure over the full 30 days. Moving forward, the company will be taking lessons learned from Shenandoah South 2 and integrating those learnings into the completion design for Shenandoah South 3, 4, 5, and 6. Again, each of these four wells, along with Shenandoah South 2, will be hooked up to our Shenandoah South Pilot Project, where we're looking to commence first production of 40 million cu ft a day from this pilot project by middle part of 2026. Moving to slide four in the overview of the Shenandoah South 1 drilling and completion portion of the well. First, you can see by the map on the left the location of the Shenandoah South 2 well being approximately three mi north of the Shenandoah South 1 well. This is a well that was drilled to a measured depth of around 16,180 ft with approximately a 5,500-ft horizontal section. The company was able to steer within a 55-ft interval in the Mid Velkerri B section, where we saw very high-quality contiguous scale along the full 5,500 ft, and we observed no faulting throughout the full section. In addition, through the well testing of the last 30 days, we were able to confirm an overpressure regime of greater than 0.55 PSI per ft. Over the full 5,500-ft horizontal section, we completed a total of 35 stages with our new Liberty frac equipment that we imported from the U.S. into the Beetaloo last year, where we achieved an average proppant intensity of greater than 2,700 lbs per ft, which represents 26% higher proppant intensity than was pumped at Shenandoah South 1. In addition, we achieved five stages a day for our single well operation, which was largely in line with U.S. operational standards. Moving to slide five and a brief overview of the completion design that was implemented in Shenandoah South 2. One of the things that the company has been very focused on is continuing to learn from previous horizontal wells that have been drilled in the Beetaloo over the last few years and apply those learnings in every incremental step as we drill more and more wells. Starting out with the Santos-operated Tanumbirini 3 well that was drilled in the deeper section of the Beetaloo Basin on the east side of the basin in 2021. This was a well that was drilled with four-and-a-half in casing, and 10 stages were pumped over approximately 2,000 ft at around 1,600 lbs per ft and 60 barrels a minute. Over a 30-day period, that well averaged 3.1 million cu ft a day. Tamboran, as a 25% operating interest in this well, were able to take those learnings and deploy those learnings along with a U.S.-style completion design that we pumped in the Shenandoah South 1 well, again, a well that we drilled in the first half of last year. We drilled this well with a five-and-a-half in casing, pumping 2,200 lbs per ft and 90 barrels a minute over a 1,600-ft section. Over that 1,600-ft section, we delivered over a 30-day period around 3.2 million cu ft a day. One of the opportunities that we have as a company is to take the learnings from Tanumbirini 3 and Shenandoah South 1 and deploy those learnings into Shenandoah South 2 in what we've called a Tamboran v2 design. We drilled the well with a five-and-a-half in casing, pumping 2,700 lbs per ft at 95 barrels a minute over 35 completion stages. You can see this well over a 30-day period has now exhibited increased flow rates from the increased stimulation intensity and, obviously, the increase in horizontal section, delivering 7.2 million cu ft a day over a 30-day period. Moving to slide six, you can see the full 30 days from Shenandoah South 2 in red as compared to the Shenandoah South 1 and the Tanumbirini 3 well. Again, this is a record 30-day flow test from any well that's been drilled in the Beetaloo Basin, Shenandoah South 2, with 7.2 million cu ft a day is the highest flow rate that we've seen in the Beetaloo. The thing I'm incredibly encouraged on is the steady low decline that has been exhibited over the full 30 days. This very much is in line with a similar decline rate that we saw at Shenandoah South 1. When you see this very steady low decline, this is what you see when you have enhanced fracture connectivity. In addition, the flowing tubing pressure remains very stable at around 900 pounds at the wellhead, and we currently are operating the flow on a 40 choke. One of the things that we did differently in Shenandoah South 2 versus Shenandoah South 1 is that we performed a less aggressive choke schedule on this well to protect early flow-back fracture connectivity and maintain higher flowing wellhead pressure. You can see this choke schedule that we performed on Shenandoah South 2 in the first 10 days of well performance as compared to the Shenandoah South 1 and Tanumbirini 3 wells. We believe this less aggressive choke schedule will have a very positive effect on the ultimate type curve that we look to demonstrate beyond the 30-day flow test for Shenandoah South 2H. Moving to slide seven. As mentioned previously, one of the key analogs to the Beetaloo Basin is the Marcellus Shale. Naturally, as we get additional well tests from each of our Beetaloo wells, we use the Marcellus type curves as a benchmark to measure our levels of success. As you see on the chart on the left, these are the top 10 type curves from all the main operators in the Marcellus, matched in color to their acreage position on the map on the right. You can see from the Shenandoah South 2 latest result of 13.2 million cu ft a day normalized for a 10,000-ft lateral compares quite favorably to the average rates from over 11,000 Marcellus producers, again, for a 12-month type curve. I'm very encouraged from the latest results from the Shenandoah South 2 well, again, in line with the average Marcellus type curve after one month of production, but most importantly, sits on the upper end of the majority of the peloton of type curves that's seen on the chart on the left. Moving to slide eight. As I mentioned in my opening comments, we are currently in the process of mobilizing our H&P Rig 469 to site, where we'll be spudding the first of three development wells on our Shenandoah South pilot pad. This will involve the drilling of Shenandoah South 4, 5, and 6, where we'll take the spud of Shenandoah South 4H in July. These are all wells that Tamboran will hold a 50% working interest, and our partner, Daly Waters Energy, will hold the balance 50% in each of these three wells. The target for each one of these wells will be drilling a total measured depth of 21,000 ft, including a 10,000 ft horizontal section, and we'll be looking to deploy learnings from our latest series of wells that we've drilled in the Shenandoah South area, where we'll target less than 25 days. One of the things that the company has done in the last few months is a comprehensive review with our partner, H&P, on the drilling performance of Shenandoah South 2 and 3, and we have identified increased efficiencies that we look to gain in each of these three upcoming wells, including implementing batch drilling on the top hole sections. We will be looking to implement an optimized bit design and new directional tools with advanced anti-vibration technology that we believe will translate into improved drilling performance in the horizontal section. In addition, we have identified multiple improved systems to limit non-productive time for each of these three upcoming wells. Moving to slide nine, one of the opportunities that the company has in taking this latest Shenandoah South 2 well and looking to optimize the completion design for each of the four upcoming wells. Again, that's the three new wells that the company will drill starting in July and also the existing Shenandoah South 3H well that has already been drilled. Our plan is to complete one of those wells by the end of this year with up to 60 stages that we're going to pump over the 10,000-ft horizontal section and flow test that single well for 30 days by the end of this year. The remaining wells will be completed in the first half of 2026 ahead of our first production commencement date that we'll be targeting from the Shenandoah South pilot project in the middle part of 2026. As I mentioned previously, just like we've been working with our partner, H&P, on the drilling side, we also have been working with our partner, Liberty Energy, to identify optimized completion design to enhance the flow test performance for these upcoming three wells, including targeting optimized proppant placement at greater than 100 barrels a minute for each of the four horizontal sections that we'll be stimulating. In addition, we have the opportunity to use local supply of sand to deliver greater than five stages a day using Zipper technology with our new Liberty frac equipment. Finally, on slide 10, I'm very pleased to report that we have secured local sand for these upcoming completions for Shenandoah South 3, 4, 5, and 6. The sand has been secured at $0.07 a pound. You can see that's roughly 70% reduction in cost compared to our 2024 program in which we used imported sand in bags for Shenandoah South 1. This local sand will be delivered in bulk, and we believe that will translate into improved cost efficiencies and removal of waste associated with using imported bagged sand. I'm also pleased to report that the company continues to advance discussions with a potential strategic partner to develop the Beetaloo Basin's first local sand mine. This is a sand mine that we would look to construct on one of the granted sand licenses that the company owns. This is expected to deliver a reduced sand cost to less than $0.05 a pound once we get the local sand mine up and running next year. Finally, on slide 11, to highlight upcoming catalyst, again, we will be sputting the first of three follow-up wells starting in July. In addition, in the second half of this year, we'll be taking a final investment decision on the Shenandoah South Pilot Project and, in parallel, commencing construction for the SPCF compressor unit and the SPP pipeline that we will look to have in place by the end of this year. As I mentioned, we will be stimulating four wells, including Shenandoah South 3, 4, 5, and 6, and have a 30-day IP from one of those wells that we'll report to market by the end of this year. Those four wells, along with the Shenandoah South 2 well, will be hooked up to our pilot project and target delivering first gas sales of 40 million cu ft a day by middle of 2026. With that, I'd like to turn it back over to the operator for the question and answer portion of the call. Thank you very much. Thank you. We'll now be conducting a question and answer session. If you'd like to be placed in the question queue, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two to remove yourself from the queue. Once again, that's star one to be placed in the question queue. Our first question today is coming from Scott Hanold from RBC Capital Markets. Your line is now live. Hey, all. Good afternoon over there. Good morning here. As I look at slide seven, can you help me understand the production flow rate on a normalized basis between the Shenandoah South 1H well to the rate on the 2H ST1? I guess the 1H did show relatively stronger productivity per lateral foot on a normalized basis. What is the difference between the two that you think you're seeing at this point? Yeah, good to hear from you, Scott. I think first, remember that Shenandoah South 2 is the first development well that has been drilled in the Beetaloo. I think the main differences over the 30-day period, as we were flowing back SS2, we put a lot of thought into taking on a less aggressive choke schedule than we took on with the Shenandoah South 1. The first 10 days, we took a lot of care in not being too aggressive with the choke. We did that so that we could preserve reservoir continuity. Hopefully, we think that has a good chance of translating into a higher EUR type curve. Also, just remember that the goal here is to develop 40 million cu ft a day. We are not necessarily chasing rate to post a great IP30 number. We are more kind of getting in a posture of development and more focused on trying to better understand not just what the rate does over a 30-day period, but really over a full 12 months and beyond. As far as the optimizations that could occur around completion design, that is something that the company is looking at with our partner, Liberty, obviously having a lot of conversations with our partner, Daly Waters Energy. We have a lot of smart people around the table that are taking a look at the Frac model. Remember, the whole point of this pilot project is to take each one of these wells and look to optimize further and further as we get through the full pilot program. This is one data point. Again, I would say we took a very mature approach in the first 10 days. We could have opened the choke quite a lot, similar to what we did at SS1. You can see the rate curve back on slide six. The first 10 days were quite stable, and that is just all to do with choke management and just having a lot of care to preserve the connectivity between the wellbore and the reservoir. Okay. That all makes sense, and I appreciate that. Maybe you can give me a sense that I know it's early, but you all obviously have a bit of a tight curve that you're running out here over 12 months on this one. You've got the 90 days on the 1H well. Do you have an idea, or would you be willing to provide a competitive EUR between the two of them, what you expect at this point? As you think about this first project, this 40 million cu ft a day project, is there any change of view? How many wells over the tenor of that commitment do you need to drill? What are you thinking today versus what you'd previously thought? Look, we're right in the bull's eye of where we want to be as it relates to having enough wells to deliver the 40 million cu ft a day. If you just take this 30-day average on SS2 and normalize it to 10,000 ft, for the upcoming four wells, we'll have enough deliverability that would exceed 50 million cu ft a day. We're pretty comfortable that we have enough wells ready to go and that we're fully funded to deliver now to get the pilot project in the first production. As far as where we are on EUR, I think it's a little early to really start making any broad conclusions around kind of the ultimate flow. I mean, that's the whole purpose of our pilot project, is to see a full 12 months out of these wells. I think the good news is that we're on the upper end of the spectrum when you think about we're 11,000 wells that have been drilled and developed in the Marcellus. We're in a really good spot where the SS2 has posted a number, where the SS1 is. I think there's a lot of potential to optimize from here. I feel incredibly encouraged. The biggest thing that I'm encouraged by is just the character of the curve. It's a very shallow decline, and clearly, the rocks are working. I think we've answered a lot of unknowns that was out there even before SS1 was drilled and completed to where we are now. The other thing I'll just make a point on is where we sit relative to the majority of the Marcellus curves, again, on the upper end of that peloton of curves, but we're also in a premium gas market. This is a market that trades three to four times Henry Hub. I think from an economic perspective, again, I feel very encouraged where we're at, where these flow tests are, where we're going on our cost to get our cost curve down, where I think we've made a tremendous amount of progress toward driving commerciality in the basin. That's where this company is laser-focused on delivering, is that by the end of this pilot program, we have the needed data to support a large-scale supply to the East Coast of Australia that's a structural short market. This is an incredibly positive step forward, in my view. Look, as a team, we're going to continue to focus on ways we can optimize, ways we can better understand both completion design and flowback to put ourselves in the best position at the end of this pilot to deliver, one, that 40 million cu ft a day, but most importantly, get the 12 months and more flow test performance to support a larger development decision. Understood. Thank you. Thank you. Next question today is coming from Anish Kapadia from Hannam & Partners line. Is now live. Hi, Joel. A couple of questions. One on the flow test and then one on potential farm out. In terms of the flow test result, I think you've given quite a lot of information. One of the things I was just interested in was the lower IP rate than you've kind of seen previously on a normalized basis. I was just wondering how much that is then kind of offset, balanced out by the lower decline rate, because obviously, those are the two key components in terms of the economics. I just wanted to see how you kind of balance those two things out and how you kind of think about those from a production scenario. The second one was on the farm out. You announced some time ago that you were going to, I suppose, kick off the farm out in earnest once this result was out. I am just wondering if you could give a bit more detail about how you see that playing out in the coming months. Thanks. Yep. Look, as I mentioned before, Anish, it is a little early to make any broad conclusions around decline that we are expecting to see from Shenandoah South 2. We do know from the execution of the 35 stages that we've pumped in the well that stimulated rock volume will be higher, most likely, versus SS1. I think there's a really good chance that we'll see that stimulated rock volume show its face the longer that we flow this well. Again, I know everyone is focused on the IP30, and I understand why. Again, the mindset that I am in is that these are development wells, so we're looking to preserve the stimulated rock volume that we pumped over the 35 stages and not get too excited around throwing open the choke in the first 10 days. If we were to have done that, I think potentially we could have seen a much higher number, but we resisted that. Again, took a more adult approach on how we chose to flow this well back. We are now looking at a well that hardly has any decline. I think as we flow this well more and we get more data, we will ultimately understand kind of what the decline will be, and that will translate to the EUR that we can project. Again, look, we're not chasing rate here. I want to be really clear. We're more interested in kind of better understanding what a type curve is going to be. I think when it's all said and done, when we have all five wells online and we start producing more than 12 months, I think there's a good chance that the type curve will look different than the Marcellus. There's a lot of characteristics that we've even seen in the last 30 days through some of our modeling to suggest that the shallow decline that we're seeing looks quite different than a lot of the early Marcellus wells. Now, we need more data. We're going to continue to flow these wells. We're going to get more data. And then be able to really answer that question, I think, more squarely what you're asking, which is what the ultimate decline is going to look like. I think the early part of this well test is encouraging, as I described. Let's just see how the next few months look. We'll, again, take the information from this well and look to optimize for the completions. That doesn't stop kind of our team looking for ways to optimize given the results of SS1 and SS2. We have two data points on the board now. I would characterize the two data points as being incredibly encouraging. As far as the farm out process, we've been engaged with RBC now for the last few months. As I foreshadowed on the last earnings call, once we had the IP30 well test out, we would be kicking off the farm out process in earnest to look for a partner on our phase two development area, which is approximately 400,000 acres gross. The thing I want to remind everyone is that we've been engaged with a number of strategics and IOCs over the last 18 months. They've been reviewing data. We feel like a lot of the parties that are interested in forming a partnership with Tamboran on phase two of our development plan, I think these parties are well advanced. I think this well test provides a bit of wind at our back as it relates to the farm out process. My goal is to finalize a farm out by the end of this year so that we're in position to start drilling additional wells on the phase two development area next year in parallel with getting our pilot project online mid-next year. This is, again, going to be subject to kind of a lot of engagement that we're going to have with a lot of different parties in the next six months ahead. We'll update the market in due course as we make progress on this farm out process. Sounds great. Thanks. Thank you. As a reminder, that star one is to be placed in the question queue. Our next question is a follow-up from Scott Hanold from RBC Capital Markets. Rewind is now live. Yeah. Hey, I know it's going to feel like beating a dead horse, but obviously, we're all trying to learn just like you. If I can, it sounds like this first 30-day IP rate on the 2H well, you all did a very deliberate job of managing the choke. Could you give us some context? If I look at page six in your presentation, you do provide us a good rundown of what these three wells that have been drilled here had for IP rates on a daily basis. When you look at the 2H well versus the 1H well, on day 30, were the chokes open in equivalent amount? I'm just curious because if you do an IP per ft on day 30, it still does seem like the 1H had performed meaningfully stronger than the 2H. Were the chokes relatively similar at that point? Or can you give us some context on sort of that day 30 point? Yeah. Yeah. Great question, Scott. Look, in the first few days of flowing SS1, we were already at a 30 choke. By day 30 on SS1, we were at a 43. On day 30, we had a flowing tubing pressure of around 590 lbs. In comparison, on SS2, we started out in the first couple of days on a 10 choke. Instead of being at a 30 on SS1, we were at a 10. We slowly stepped up the rate with the incremental choke sizes that we did on a planned basis at around 260 force every 48 hours. We ended up at a 40 choke at day 30. You can see at day 30 on SS2, we were at 910 lbs. That compares to SS1, where we had drawn down to 590 lbs. Again, very deliberate strategy to, I would say, be fairly conservative on our choke management on SS2. Again, our intention was to ensure that we maintain strong connectivity between the wellbore and the reservoir. This is based on a lot of work that my team has done and a lot of analysis to support that choke management approach in the first 10 days. Now, if we had gone about opening the choke similar to what we did on SS1 and even dating back to Tanumbirini 3, I think both of those wells that were very aggressive upfront, you can see that on slide six with the rate in the first two to three days kind of spiking there. We think, based on our analysis, that potentially resulted in some damage on the ability to connect from the wellbore into the reservoir. What we wanted to do is just protect that a little bit more. We think there's an opportunity, and we'll see this as we flow the well more. There's an opportunity that we could have a more shallow decline on SS2 versus SS1. Again, this is all part of the pilot to get a good understanding, not just on completion design, but just how you bring these wells on. Part of SS2 was to test that thesis is in the first couple of days, instead of starting out on a 30, we're going to lean into it a little bit. Again, we are taking a very development-type mindset on this. This is not an exploration well where you're trying to chase a high IP30 and post a big number. We wanted to be instead focused on how do we bring this well on a steady way, maintain connectivity with the reservoir. And remember, in the Marcellus, it took hundreds of wells and optimizations and testing and how to work this out. I think the big picture here is that over the last couple of wells, I think we're making some really good progress to better understand how to bring these wells on. And big picture, just to take a big step back, this is clearly a representation on a 30-day IP for SS2 that the rocks are working. And the completion designs that we're pumping are translating into bigger numbers coming out of wells. And again, big picture, this is one of the most promising gas plays in the world. We are on the cutting edge of unlocking commerciality through this pilot project. We are coming down the curve quite dramatically, both on optimizing the completion, optimizing our flow back, but most importantly, coming down the curve on cost. This sand deal that we did is incredibly positive in our ability to get our cost down. That is one of the biggest needle-moving items on getting a well cost down. Obviously, we are focused on kind of getting the best rate as we can out of the wells that we drill, but also simultaneously in parallel focused on how do we get our cost down so that we end up after these five wells in a place where we are locked in around kind of the cost of production out of a Shenandoah South deep development well. Okay. Just to, excuse me, ask another question here. When I think, what is the next step for the 2H well? Are you all, remind me, are you all still flowing that? Will you provide us an IP90 rate? Is that still flowing? Is that still the plan? On the completion and testing of the next well, I guess you talked about it being later this year. I thought the plan was to be more like mid-year. It sounds like you're kind of, are you holding off on that for a little bit to make other decisions or other evaluations of 2H? Yeah. No, just to be clear, we're flowing 90 days on this SS2 well, and that's consistent with the guidance that we put out with our earnings. That's our plan on SS2. It's flowing today. It's continuing to flow today. We're going to keep flowing that well. We have our rig back on site. We're going to spud SS4 here in July, and we're going to drill those wells back to back. Three wells that we're going to drill. As soon as we finish the drilling campaign, we'll bring in our Liberty frac equipment, and then we'll pump the frac on one of the 10,000-ft horizontals. We'll get the flow back and get the 30-day IP out by the end of the year. Really, the decision's not due to delaying this well, delaying the completion of this well. It's more about just the ability to do simultaneous operations out there. We wanted to first, given that the rig is there and it's stacked on site, we felt like the prudent thing to do is get the wells drilled, drilled and cased, and then have the ability to pump one of the fracs on one of the wells. Then we have a rainy season coming into view probably in November, December. Once the rainy season clears up, we'll pump the other three wells, each of the 10,000-ft horizontals. Part of our thinking, just to be clear, is while we're drilling the three wells, we'll get more data on SS2. Again, the next 60 days will be probably as important as the first 30 days on this well. We're going to be around the table with our partner Liberty, with Daly Waters Energy, with a lot of smart people around our team to look to how we're going to optimize kind of the next 10,000-ft horizontal. We'll pump that 10,000-ft horizontal later this year. That, again, will be a data point that we'll look to learn from. That'll inform a further optimization for the next three wells. Okay. I appreciate that. One last thing. On your last earnings call, you went into a bit of an overview on why you want to soak the wells. Is there anything changed after seeing this IP30 and where it's at now on your view on how to soak and rest these wells prior to bringing them online? Is it still, are you still looking at roughly, what was it, 60 days? Yeah. Yeah. Look, the decision to take a 60-day soak, I think it translated in material uptick in performance. We believe that it largely confirmed our thesis around seeing a material change in rate and potentially type curve. Again, it's early. We only have 30 days of flow. This is one of the reasons we want to flow the well longer is to better understand the effects, not just on the completion design, but also on the ultimate decline curve that will come from the flowback strategy. That is where we're at on the soak bit. I think, again, our team got a positive data point here. Our intention is to continue to have soaking be part of our flowback strategy. Again, we will build that most likely into our development plan. That is a technique that we believe is a quite unique factor that we have to deal with given the extreme desiccation that these shales have. They are incredibly dry. How you flow back the well is part of the IP that we are developing and learning from on every well. That is something that we will continue to do moving forward. Yeah. I guess kind of the point of that question too is you all have a lot of knobs and dials to turn and pull. Obviously, some of it is choke management, some of it is soaking time. I am curious, with the SS1, there was obviously not the soaking period, but you opened the choke, had a more robust IP, 24 on that, for lack of a better term. How do you think about the soaking period? Is it sort of a dial you want to tweak moving forward based on what you learned? Or do you still need more time? I guess that was the point is how much of a variation can that cause, do you think? Look, I think our thesis is that the breakover point for incremental benefit from soaking is around 60 days. I think it's a little early to make any broad conclusions on the difference between, say, 21 days that we use for SS1 and the 60-day soak that we put in place for SS2. That's one of the things that we are evaluating as part of this flow test, quite frankly. The reason we want to see another 60 days of flow is to better understand the knob around the soak benefit. Obviously, the knob on how aggressive you want to open the well initially, that's another knob that we believe, again, taking a more conservative type choke management on SS2, we're going to have to see how that plays out over the next 60 days. We think that's going to, again, set up this well to have a much more attractive decline. That's our current thesis. We clearly see the frac that we pumped, there will be a lot bigger stimulated rock volume down there in the shale. Again, having a less aggressive choke approach in the early step, we want to maintain good connectivity. Again, that's the reason we want to flow the SS2 well for 90 days so we have an apples-to-apples comparison to SS1. Okay. Thanks. All right. Your next question is coming from Charles Meade from Johnson Rice. He's now live. Yes. Good morning, Joel, or good evening as it may be. I hopped on the call a little bit late, so forgive me if I'm asking something you've already covered. I'm looking at slide four and your depiction of the lateral versus the vertical log. I'm curious, I guess this gets to the question of future optimization. Have you detected any difference in contribution of stages that were completed in the upper part of your target section versus the contribution of stages in that lower part of the target section? Yeah. Initial review is that, again, early stages here on the review, but you remember that the 35 stages that we pumped over that 5,500-ft section, the last 19 stages were pumped in a very consistent way. Around stage 19 is where we went from a 40-meter spacing to a 50-meter spacing because we were seeing some stress shadowing as we were reducing down our stage width. I think there is likely a distribution on the effectiveness of every stage. That is part of the review that we are doing as we speak, again, with our partner Liberty, who was on the job. I really cannot add any details around that, given that is part of what the next few months of review will be looking at, to look at on a per-stage basis. I think indicative sort of approach is that the remaining 19 of the 35 stages pumped a lot more efficient than the first 19 stages. As we go forward, again, part of the approach for the next series of wells is to take that same general design that we saw in those 19 stages and apply it over 60 stage per 10,000-ft horizontal. Got it. It is an important question, but just too early to really look for an answer, if I understand you correctly. Yeah, that is correct. That is correct, Charles. Got it. Thank you, Joel. That is it for me. All right. Your next question is coming from Kelley Ackerman from Bank of America. Your line is now live. Hey, good morning, guys. I also want to ask about the rate here. What does this IP30 tell you about the number of wells that you need to meet the needs of the pilot program, the 40 million cu ft per day? Earlier, there was some discussion about drilling fewer wells and perhaps having supplemented by a higher rate. Where does that dialogue kind of stand today? Yeah. Remember, prior to the IPO, we were looking at six wells here on the pilot. We've now shifted that down to really four 10,000-ft horizontals and one 5,500-ft horizontal. So we think based on this last well result on SS2, which would be equivalent to a 13.2 million cu ft a day out of 10,000-ft lateral, we're right in the bull's eye on having, we believe, having enough wells. If we just replicate this SS2 well over the next four wells, we have enough rate here to deliver the 40 million cu ft a day. Again, a linear extrapolation and assuming same completion over the next 240 stages, that would get us to around 52 million cu ft a day on day one. Obviously, as we learn more, there is potential if we do see better productivity out of the next 10,000-ft horizontal that we would look to preserve capital and not drill as many wells. That is, I would characterize that as an upside, not the base plan. The base plan, again, that we're fully funded for is to drill the next three wells plus the SS3 well and the SS2 well. We believe that's more than enough to get us into the 40 million cu ft a day pilot. Thanks for that, Joel. When you kind of look at this well, when you analyze this well, are there any design changes that you plan to implement the next well? Did the higher intensity frac work as you intended, or would you choose to dial back the frac intensity and perhaps save some money on the next well? Look, we're going to look at all variables, including stimulation intensity. I think on the headline, there's obviously differences in SS1, where we pumped around 2,200 lbs per ft versus 2,700 lbs per ft for SS2. This is all the work ahead of us. I mentioned the work that we're doing with Liberty on the frac model and obviously getting 60 days more data on the flow test. I think that's going to inform the company on how we optimize moving forward. That is a variable. One option is to go back to the SS1 design and kind of take some elements of that and improve, look to have the optimization from there. I would just say it's early to not draw any big conclusions. Remember, this is IP that the company has here, and we're going to protect that IP moving forward. We're not going to get into specifics around how we're going to optimize. That will be subject to the folks that are under the tent here, including our partner Liberty. We're going to take those learnings, and then we're going to put those learnings into the next series of wells. Obviously, SS1, it was a great result, but obviously, as I mentioned before, I mean, there was a much more aggressive choke schedule. That's something we're going to look at quite closely as kind of how taking a less aggressive choke schedule is going to impact the decline over the next 60 days. Again, can't get into the details, Kylie, but this is part of my approach is to take each one of these data points and look at all the variables, look at all the variables to better understand how we optimize design moving forward. Got it. I appreciate it, Joel. Thank you. Thank you. We reached the end of our question and answer session. I'd like to turn the floor back over for any further closing comments. Thank you very much for everyone joining this morning, and we look forward to providing further updates on company's progress on our standard OSL pilot program moving forward. Thank you very much. Thank you. That does conclude today's teleconference webcast. Let me disconnect your line at this time and have a wonderful day. We thank you for your participation today.