Please note that this conference is being recorded. I will now turn the conference over to our host, Todd Abbott, Chief Executive Officer for Tamboran Resources. Thank you. You may begin. Hello, everyone, and welcome to Tamboran Resources Financial Year 2026 second quarter earnings presentation. My name is Todd Abbott, and I'm the Chief Executive Officer of Tamboran Resources, and I'm joined here today by Chief Financial Officer, Eric Dyer, and V.P., Investor Relations and Corporate Development, Chris Morbey. In January 2026, following an external process, the board appointed me as the new CEO, and I'm truly excited for this opportunity to lead Tamboran and the Beetaloo Basin into the next phase. We have a great management team with deep experience and a board of directors with a track record of creating large value over their careers. I have long relationships and deep trust with the board, and I'm confident in our path. I look forward to working closely with all stakeholders, including native title holders, Northern Territory Government, pastoralists, and shareholders, to deliver what I believe has the potential to be a world-class unconventional gas project. But before I start the review of the second quarter earnings, I'd like to acknowledge the great work done by Dick Stoneburner as interim CEO. Dick guided the company through some critical milestones, including the Falcon merger and the largest drilling campaign in the Beetaloo Basin. He is one of the best in the business, and we couldn't have a better chairman. So, thank you, Dick. And with that, let's get started. So, moving to slide 2, you can see our disclaimer, which relates to forward-looking statements within the presentation. I encourage you to review that at your leisure. And then on to slide 3. The second quarter of fiscal 2026 has been another period of progress for Tamboran as we delivered on key milestones and approached first gas sales from the Beetaloo Basin during the third quarter of this calendar year. Following the completion of the drilling of the two-well program in October 2025, using the H&P FlexRig 3, the team successfully delivered the largest stimulation program to date in the Beetaloo Basin, achieving 58 stages across a 10,009-foot horizontal section within the Mid-Velkerri B Shale. The stimulation activities were completed using the Liberty Energy frac fleet, which Tamboran mobilized to the basin in 2024. We conducted an initial flow back, and now the well is currently shut in and undertaking a 60-day soaking period. We had originally planned a 30-day soak period, but after further consideration, we'll undertake a soak duration in line with the SS-2H ST-1 well. Construction activities on the Sturt Plateau Compression Facility continued during the quarter, with the project approximately 80% complete at the end of January. During the quarter, key contracts were awarded for the electrical work. The project remains on P50 budget and on track for first gas in third quarter 2026. The Australian Pipeline, or APA Group, continued construction of the Sturt Plateau Pipeline. The line is now in the ground, with strength and hydro testing activities successfully conducted in January and the pipeline now ready to take gas. I want to thank APA for their tremendous effort in delivering the SPP on schedule and below budget and look forward to continuing to build the relationship. We're now gearing up to commence our 2026 Beetaloo Basin operations, which will be our most active year to date. The program includes stimulation of the remaining three wells required to deliver the 40 million a day plateau rate ahead of the commencement of initial gas sales later this year. We're also planning to drill two wells with our partner, Daly Waters Energy, on the SS-1 well pad to the south of the SPCF. Tamboran will be acting as operator on behalf of DWE, and the wells are planned to be stimulated in second half of 2026, subject to performance of the initial wells. We'll also be participating in two wells in the Beetaloo East acreage, EP-161, via our 25% non-operating partnership with Australian E&P Santos. The two wells, Jabiru South 1H and Newcastle South 1H, are both 10,000-foot commitment wells and are positioned to delineate additional gas resources in the Eastern Depocenter. Santos has contracted the Ensign Rig 971 to undertake these activities. Additionally, we are continuing to progress the farm out process, but we will not go into much detail on the call, just given the commercially sensitive activities and the phase that we're at. Finally, we ended 2025 with a cash balance of $91 million and a drawn debt of $16 million associated with the construction of the SPCF. Since the end of the year, Tamboran received $32 million following completion of the PIPE in January and expects to receive another $15 million related to the acreage sale to DWE. Moving to slide 4, I want to touch on the investment highlights, which is a key reason I'm so excited to take on the CEO opportunity. First, scale. Tamboran sits on 2.9 million net prospective acres across one of the largest unconventional shale projects in the world, including large positions over both the Beetaloo East and West Depocenters. The acreage position includes up to four high-quality benches across the basin with over 16,000 locations. Second, well results are showing that initial flow rates indicate a comparison to the Marcellus Shale in the U.S., and what we are starting to see is the Velkerri B is showing its own distinct character, indicating shallower declines as the well continues to clean up over the 90-day flow testing. The Beetaloo Basin is also connected to three highly attractive gas markets: the NT local gas market, which we will be producing into later this year, the Australian East Coast gas network, which is trading at multiples to the long-term Henry Hub price, and the Asia LNG market, which is the largest growing demand center for gas in the world. Tamboran is nearing production, which is going to be a huge milestone, not only for the company, but for the stakeholders in the Northern Territory. Our first production from the Beetaloo Basin will provide local supply of energy to the NT, which is powered predominantly by gas, and it will also deliver royalties to the native title holders and to the Northern Territory Government. We are nearing completion of the acquisition of subsidiaries of Falcon Oil and Gas, which will consolidate Tamboran's interest across the entire Beetaloo Basin and further de-risk the execution of our development plan. Moving to slide 5. 2026 is just the first step in Tamboran delivering significant production growth into the three markets I highlighted earlier. This year, we will be focused on stimulating the three remaining wells and completing the construction of the SPCF to deliver first gas sales to the Northern Territory Government. We will be drilling two backfill wells on the DWE-operated Southern Pilot Area during the first half of 2026. The reason for drilling these wells ahead of production is a risk mitigation strategy and provides valuable gas behind the pipe that will be used to increase volumes over the 40 million a day. We'll also look to progress our Phase One expansion project via the commencement of concept select studies. The project will evaluate the potential for an expansion of the SPCF to approximately 100 million a day and deliver additional volumes to the Northern Territory Government gas market and Mount Isa. We will also be participating in 2 commitment wells with Santos on EP-161, where Tamboran is a 25% non-operating owner. The two wells are planned to delineate additional resources in the Beetaloo East Depocenter, that Santos are evaluating delivering to the East Coast gas market and into the Gladstone LNG project in Queensland. Finally, we're progressing the farm out on our Phase Two Development Area, targeting carried wells during the 2026, 2027 drilling campaigns to delineate resource and to underpin a new pipeline. As I said, this will be a year to lay the foundations for growth, including the material step up in drilling activity that aims to deliver reinvestment and accelerating a range of production opportunities. Moving to slide 6. During the quarter, Tamboran completed the stimulation of the SS-6H, with 58 stages across 10,009 feet within the Mid-Velkerri B Shale. During flow back, an impediment was identified at approximately 8,600 feet along the horizontal section. We're evaluating if the impediment has the potential to block any of the flow from the last 14% of the section. We are all interested in the local in-basin sand opportunity, which is a material initiative to reduce well cost long term. We did not get to effectively deploy the local sand during the 25 campaigns due to being unable to wash and dry the quantities required. We do plan to test stages during the 2026 campaign. Moving to slide 7. As I highlighted earlier, DWE are planning to drill 2 wells on their operated Shenandoah South Pilot Area acreage during the first half of 2026. Tamboran will act as the agent operator during the period, undertaking the activities on DWE's behalf. The 2 wells are planned to be tied back to the SPCF on the SS-2 well pad and backfilled into the NT government gas contract. Both Tamboran and DWE expect to be equal equity partners on the Shenandoah South Pilot Area at 50% following the completion of the Falcon transaction and acreage swap with DWE. Now moving to slide 8. Construction activity on the SPCF continues along our P50 schedule and within the forecasted budget. At the end of January, the project was 78% complete and is on track for commissioning during the third quarter of 2026. Just a reminder that the remaining capital spend is being funded from a $118 million facility with a consortium of lenders. Tamboran and DWE also commenced the divestment process of the SPCF during the quarter, with binding agreements for the sale on track for our first half. Tamboran and DWE will sell volumes through the SPCF under a long-term gas processing agreement, and on the sale of the SPCF, we expect to release our full $15 million in equity that is currently held in the facility. Moving to slide 9. APA have done an incredible job in progressing the SPP. With the construction, strength testing, and hydro testing now complete, the pipeline will shortly be tied into the AGP and be ready to receive gas from the SPCF once complete. Tamboran and APA have commenced discussions to expand the pipeline to support the SPCF expansion project. Moving on to slide 10. Tamboran's JV partner in EP-161, Santos, are planning to drill 2 permit commitment wells, Jabiru South 1H and Newcastle South 1H, during the third quarter. The wells will target the Mid-Velkerri B Shale and follow-up wells to the Tanami wells drilled and flow tested in 2021 and 2022 and delineate additional resources in the Beetaloo East Depocenter. On to slide 11. You can see that following the completion of the public offer, share purchase plan, and PIPE, we are well positioned to fund our pilot project initial gas sales in third quarter 2026. At the end of the quarter, we had $91 million in cash on the balance sheet, with near-term cash inflows of $47 million. The company received $32 million relating to the PIPE transaction following the shareholder approval in January 2026. We also expect to receive $15 million from the acreage sale to DWE once we meet certain conditions precedent on the check and abiding of the acreage. At the end of 2025, we had drawn debt of $16.3 million relating to the facility to finance the construction of the SPCF. $42 million net to Tamboran remains undrawn. As mentioned earlier, we are currently tracking towards the P50 forecast, so we have ample capacity within the current facility. We also continue to progress research and development rebates for fiscal 2024, 2025, and 2026 that could, if approved, provide incremental cash flow. ...Moving on to slide 12, you can see we have a very busy year ahead of us as we progress towards initial gas sales in mid-2026. I've touched on many of these catalysts already, so I will not delve into these again, but I'm truly excited for the future of Tamboran in the Beetaloo Basin. I want to thank all of our stakeholders, from the native title holders, the pastoralists, Territorians, Northern Territory Government, and our shareholders for your support, and I look forward to meeting many of you over the coming months. And with that, I'll hand it over to the operator for questions. Thank you. At this time, we will conduct our question-and-answer session. If you would like to ask a question, please press * 1 on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Once again, to ask a question, press * 1. We'll pause for a moment while we pull for questions. Your first question comes from Scott Hanold with RBC Capital Markets. Please state your question. Yeah, thanks. Good morning, good afternoon. You know, Todd, my question is, you know, just with regards to your background, obviously, you know, you've had experience in the US and many of the shales. But can you give us a sense of, like, how did you view this, you know, opportunity for, you know, working at Tamboran? And how is some of the work that you've done in the past applicable to what you see in the Beetaloo? And if you could talk about, like, some of the challenges you might see and some of the upside opportunities you see based on, you know, your prior work. Yeah. Thanks, Scott. Happy to go through it. Look, I would say, first, I've had the opportunity to work in some really great positions over the course of my career. Maybe for context, I've spent about half that time in finance, capital markets and about half that time in operations. And if I go back, I'll kind of focus more on the operations side, maybe as we talk about the Beetaloo. I think about my time running the Alaska operations at Pioneer. You know that kind of teaches you how to work in remote, logistically challenged environments. Certainly, the importance of working alongside native title holders and finding ways to meet mutually beneficial outcomes. I think about the time in the Permian. When I was there, it was when the horizontal shale play was just taking off, so launching kind of a new play admittedly there, that was in a, you know, a fairly well-established basin. You know, when I started there, we were just bringing horizontal wells on production, and when I left, that was, you know, certainly the norm and building a lot of momentum there. Eagle Ford, Marcellus, Utica, all great shale developments. There, most of those jobs were about capital discipline, efficiency, and really very important for kind of where we are here in the Beetaloo, learning from every data point, learning from every well. So, you know, when I think about maybe challenges or upside that I look at here, we've got a great team, we have great rock. We certainly believe in all that. What we've got to do here is drill great wells. So back to what I was talking about with the Eagle Ford and the Marcellus and Utica, it's using every data point we have, making sure that we understand what we're doing, you know, tweaking our processes going forward and drilling great wells. And when we do that, we'll build the investment rationale for the large format pipelines to get the gas out to the East Coast and north, for that matter. Does that... Did I answer your question there? Yeah, that's, that's helpful. I appreciate that, that background and concept. You know, for my, my second question, and if, if I heard you right during your prepared comments, you talked about, you know, potentially being greater than 60,000, you know, potential wells and, and testing upwards of 4 different benches in the Beetaloo. If I'm, if I'm not mistaken, the last, the prior disclosure you all had talked about, like, 40, greater than 40,000 wells. Did you guys increase that resource or well location assessment? And, you know, can you talk in terms of like some of the other formations, the other zones in the Beetaloo? Like, when, when might you test those and take a look at something else in, in terms of a different zone? Yeah, I would say at this point, Scott, there's no change to our strategy. In fact, I'm focusing the team very clearly to we're going to focus on the Mid-Velkerri B Shale, and we're going to focus on drilling great wells. There's a lot of upside beyond that, you know, not just in the different benches, but in other things to do with the basin. But the first thing we need to do to enable all that is drill great wells in our targeted zone. Yeah. Got it. Was I mistaken when I heard you talk about 60,000 wells now? And that was part of the question, like, I think the prior disclosures were around 40. Yeah. No, I'm sorry. I'm not recalling what you're referring to in the remarks, Scott. Oh, okay. Okay. I thought you mentioned something. There's upwards of 60,000, you know, drilling inventories. The drilling inventories upwards of 60,000 wells in the Beetaloo. Maybe I misheard you. We can go and certainly follow up with Chris. Got it. Thanks. Uh, yeah. Thank you. Your next question comes from Jeff Gramp with Northland Capital Markets. Please state your question. Thanks, Todd. Was curious to... I'll start on the 6H well, and just wanted to get a little more discussion on the soak period decision there. I think you mentioned, Todd, it was originally planned for a 30-day and now looking to a 60-day. Just curious what led to that tweak or that decision. Thanks. ... Yeah, so that was, we pulled that well back for 23 days to clean up the water, so it's been soaking since then. Look, that was me. I guided the team to leave that well shut in for 60 days just so we can be consistent with what we did on the SS-2H. Kind of back to what I was talking about with Scott, it's we're trying to learn everything from every well, and so minimizing the number of variables helps us do that. It just creates less noise in the data. Understood. Okay, that's helpful. And for my follow-up, I noticed in the capital slide that you guys have in the deck, that the farm-out process timeline, which I think was previously a Q1 event, is more of a wider window of a first half event. I know you can't touch too much on, you know, the minutia of discussions and things like that, but does the 6H well result impact that process at all? Or just can you touch at a high level on the revised timeline there? Yeah, I would say generally speaking, we're still on the same timeline we were. Obviously, I can't talk too much about the specific to the farm out. I'll only say we've got some really interested, very credible parties in there. If you're sensing a little flex there, you know, that's possibly just a little time as we work through agreements, but the commercial process is no different than it was before. Understood. Sounds great. I'll turn it back. Thank you. Yeah. Your next question comes from Charles Meade with Johnson Rice. Please state your question. Yes, good morning, as it may be down there. Todd, I wanted to ask about the 2H well, and my understanding is you guys did your flow test, you shut it in, and so that's why, you know, you don't have any kind of update on the decline curve. But I wonder if you could perhaps comment on you did, I think, make a reference in your prepared remarks about the you know the Mid-Velkerri B kind of has its own idiosyncrasies, its own signatures. Have you guys seen anything on the pressure buildup since you shut that well in that would, you know, you know, encourage you or kind of solve some of the puzzles of the relatively flat decline you saw on that well? Just anything incremental there? Yeah, no, I hear what you're asking. You know, Dave can certainly talk about the kind of indicators of flat decline. We still believe that's there. On this specific well, you know, frankly, it's too early to tell. And the data that we've seen on the flow back, you know, as you're unloading the water, it's all in line with what we expected. We haven't really seen anything that deviated from what we expected. And in that type of flow back, it's really hard to, you know, see any... We're obviously not getting long-term data. We're not getting kind of full flow data on it. So, to really answer that decline question, we need wells on production for a period of time. But look, I'll tell you, this well, everything looks in line. It's kind of hard to tell much until we really get it on production. When you say this well, you mean the 6H or the- Correct. Yeah, sorry, the 6H. Okay. Yeah, okay. And then a question on the expansion of the Sturt Plateau compression and the pipeline. Usually those are great projects. Once you know, it's easy—it's a great project to expand it. What's the appetite look like on the other end of the pipeline for more gas sales up in and around Darwin? Sure. Yeah, well, I can tell you about kind of what's clear and certain and kind of what our process will be forward. So we've got, you know, 40 million a day to the NT government there, and that can flex up a little bit, so we have clarity on that. Beyond that, we've got specific conversations going on with other customers that have been out there, and without going into all the specific names, we feel like there's a market there. The pipeline is built to go up to the 100 million a day, and the economics on that expansion are, you know, pretty compelling. So look, we'll firm up those markets and make that decision at the time, but that's probably the best way to describe it is, you know, cautiously optimistic. Got it. Thank you. Yep. Your next question comes from Paul Diamond with Citi. Please state your question. Thank you, guys. Good morning, all. Thanks for taking the call. Just wanted to touch quickly on, you mentioned that you and I guess the prior activities hadn't been able to really fully test the local sand solution. Just want to get an understanding of, like, how in these new, whether it's the Daly Waters or the Santos wells, how much progress we can expect over the course of 2026, or is that more of like a 2027, 2028 story? That's a good question. Yeah, look, we really wanted to test it in the last well. It didn't work out that way. We will have limited stages on the upcoming wells that we're going to complete. We think that's something that's important to unlock and unlock early. I can tell you the lab results on that sand look really good, so we're optimistic about it, but we need to get it in, you know, kind of some selected stages underground to confirm that. Got it. Understood. And then the 2 additional wells, you guys talked about drilling kind of for either, you know, backing up the 40 million resource or for potential growth. Just want to get an understanding of, like, how does fit into a longer term cadence. Is that, does that hold you at 40 for 6 months, a year? Just kind of getting your understanding of, I guess, the operational cadence needed to really maintain that 40 and then grow from there. Yeah, at this point, we're gonna be focused on the pilot project. It's, it's hard for me to answer your question on specific timing and frankly, until I get further into it. You know, I'm... That's something I'm not quite fully across, to be frank with you. So, once I get my head into it, you know, we'll, we'll understand the timelines a little bit better there.... Got it. Understood. I appreciate your time. I'll leave it there. Your next question comes from Anish Kapadia with Hannam. Please state your question. Hi, Todd. Yeah, I just wanted to get a little bit of your perspective and insight in terms of the strategic viewpoint for Tamboran going forward. So, you know, coming in from the U.S., seeing, you know, what has been possible in terms of U.S. shale gas production in the U.S., what do you see as the big positives? What do you see as the big negatives? What do you see as the kind of strategic direction going forward? Just like to kind of get your viewpoint on that. Yeah, well, the first thing I'll say is there's no change in our forward strategy, and thanks for the question. It is... We're an upstream gas company, and as I mentioned on one of the other responses, we're going to focus on drilling great gas wells. And so, the way we do that is similar to the way that we would do that in any shale play, U.S. or otherwise, we have really smart people, and that includes the people here at the company. That includes our partners, Baker Hughes, Liberty, H&P, the other operator that we're partnered with in the basin of Santos and Daly Waters Energy. It's about learning from every data point and taking that data and just really, frankly, letting the really smart people dig in and do their work on it. That's the way that the plays in the U.S. have been successful, and that's the way we'll be successful here. Thank you. And a reminder to the audience, to ask a question, press star one on your telephone keypad. To re-remove your question from the queue, press star two. Your next question comes from Kalei Akamine with Bank of America. Please state your question. Hey, good afternoon, guys. Todd, congratulations on the new seat and looking forward to meeting you. My first question is on the backfill commitment, wells number 7 and 8. My understanding is that the North pilot was sufficient to meet your production targets. Just kind of wondering how these plans... how these new wells fit into your plans and what the associated spend is net to Tamboran. Yeah, so those wells are within our agreement with Daly Waters Energy, you know, those are contractual commitments for us. So, we're going to follow through and drill those wells. In that southern block, Daly Waters Energy is the operator, but we will serve as contract operator for them. So, we'll get those wells drilled. There is an added benefit that they just add further resiliency to the gas production that we'll have online. Whether that's extended performance or whether there's, you know, down the road, some unforeseen mechanical challenge, we have further backup to meet our obligations. So that's kind of the upside on it, but that's not why we're drilling in. But that's if that's kind of the question you're asking, if I'm understanding that right. I, I appreciate that, and that does address it. My, my second question is on funding. So, in the second half of last year, Tamboran acted on several opportunities to bolster funding. As you kind of map out your operating plans for 2026, which includes first revenues, do you anticipate having surplus cash at the end of the year without additional fundraisers and also maybe excluding the farm down? Okay, so there's several questions in there. Like, if, if I guess if what you're asking is, do we expect capital markets activity? Well, I'll answer it a little bit more broadly and just say, look, we're a, we're a, you know, high growth company in a capital-intensive industry. So, there's a reason we're a public company, and from time to time, we'll access the capital markets. You know, early on, that's more likely to be equity. Later on in our maturity, we'll use some debt. But realistically, we have other funding mechanisms. You mentioned the farm out. That's one of them. There are other things we can do to raise equity. What I want you and all the other shareholders to hear is that we'll be very thoughtful in our approach to that and do it in a way that makes the most sense for all our shareholders. Got it. I appreciate it, Todd. Thank you. Thank you. Your next question comes from Scott Hanold with RBC Capital Markets. Please state your question. Yeah, thanks. Hey, Todd, could you talk about some of the learnings that you all have gone through on some of these early wells? I know with the OFS partners, there have been some issues on some of the drilling and completion operations. But can you talk about any kind of learnings or any kind of strategy you guys have moving forward to mitigate some of these things in the future? Sorry, give me more detail on your question, Scott. Are you talking about specific operational issues or performance, or where's your head on that? Yeah. Yeah. Just, you know, for example, like, you, you had, like, tools and stuff you had to fish out of some of the wells, like the 4H well and, and, you know, drilled... had to drill some shorter laterals on, on some of the, you know, initial wells. So, you know, just talk about, like, some of the things that, you know, you'll, you'll take a look at in terms of changing the operational procedures to hopefully mitigate all of that moving forward. Yeah, I see what you're saying. Yeah, look, we, you know, we've got great partners. Baker Hughes, Liberty, H&P are all highly focused on it. They've done a good job for us. You know, I think with any basin or in any situation where you have equipment starting up, you really start hitting your stride when you get more continuous operations, and we will do. The more our activity ramps up, the more consistent those crews will be out there. I can tell you that our team here, and our partners are all highly focused on the exact thing you're talking about. You know, certainly aware, and we're going to get better at it. You know, if you think about the plays that are in full swing in the U.S., you have crews that, you know, they're doing those same things every day, day in and day out. That's a big driver of their performance, and it will be here ultimately as well. Appreciate that. And for my last question, you know, maybe it's a better one for Eric or somebody else, but you know, just talk about just the stakeholders in Australia and any kind of traction or what are the next steps to phase two and other things to get the permits and stuff you need for early work. How's it been working with the government? How has that been? And you know, what are the next things to watch for there? Sure. And I'll let Eric chime on here if there's anything to add. What I'll tell you is, in kind of my brief experience here, the support across the board has been fantastic. And so, that's from the government there in the NT. We've spent time with them this past week, and they've all been extremely supportive. The native title holders have been supportive. Look, the development of this basin is a great outcome for all the stakeholders and all those that we're talking about. So, they'll all benefit from direct royalties. They'll have jobs, they'll have economic development, and they've been very supportive. You can see that in the beneficial use agreement that we have to sell our gas. You can just see that in the support and the way that the basin is being developed. And of course, I can't leave out the pastoralists, you know, as we're kind of working alongside them. It's really a great situation out there, and that everyone kind of wants to see this take off. It benefits the local area, it benefits the nation, and frankly, it ultimately benefits kind of the region of the globe. Eric, anything to add there? Yeah, no, look, I think Todd captured it very well. Where we're sitting today is, you know, we're looking forward to drilling, you know, with our partners and with Santos and DWE, the equivalent of, if not more, horizontal wells that have been drilled in the basin, in the basin's history. You know, this basin's been ten years coming, and even for us, the local support is incredible, because one, the market needs the gas. Two, the local community needs the jobs, and we're setting up a regional office near the Beetaloo in Elliott. We've made some really great hires locally, recently, and we intend to make more. You know, really, everything's all systems go. Our team is working through the Indigenous Land Use Agreement with the government, and everything we're doing is just putting one foot in front of the other to make sure that we're bringing the whole community with us as we open this project. Thank you. Thank you. There are no further questions at this time. With that, we will conclude our Q&A session and also conclude today's meeting. Thank you all for your participation, and all parties may disconnect. Have a good day.