Tamboran Resources - H2 2024

Transcript

Operator (participant)

Hello, and welcome to the Tamboran Resources Q4 and fiscal year 2024 full year 2024 earnings release. At this time, all participants are in listen only mode. If anyone should require operator assistance, please press star zero on your telephone keypad. There'll be a question and answer session following the formal presentation. You may be placed into the 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 Managing Director and CEO, Joel Riddle. Please go ahead, sir.

Joel Riddle (Managing Director and CEO)

Thanks, and welcome to Tamboran Resources' full year two thousand twenty-four earnings call. My name is Joel Riddle. I am the Managing Director and Chief Executive Officer for Tamboran Resources, and joining with me today is Eric Dyer, our Chief Financial Officer. Before we get into the material, I'd like to refer everyone to slide two and associated disclosure statements, associated with forward-looking statements. Starting with slide three, this has been a very exciting twelve months for Tamboran Resources. We've achieved six major milestones, including delivering the largest normalized flow rate from any well that has been drilled in the basin to date with the results of our Shenandoah South one well. Two, we secured $82 million to progress our two thousand and twenty-four drilling program.

This was part of a successful IPO that the company completed in late June as part of our new New York Stock Exchange listing. Three, we entered into a strategic agreement with Liberty Energy. This will bring a modern frack fleet from the U.S. into Australia this year, and we'll be using that frack fleet for the six pilot wells that we have just started drilling. Four, we signed a 15 and a half year binding gas sales agreement with the Northern Territory Government. This will underpin our Shenandoah South pilot project and look to deliver initial cash flow and production as early as Q1 of 2026. Five, we signed LOIs with six of the largest East Coast gas retailers, and that will underpin our phase two of our development plan.

Six, finally, we signed two MOUs with BP and Shell for 2.2 million tons of LNG for 20 years each. That will be tied to Tamboran's operated NTLNG project. In addition, we have a recently awarded pre-FEED studies to Bechtel Corporation, and again, this will be part of our progress that we will be making in the next 12 months on our NTLNG project, and that's what we call phase three. Before getting into the company update on slide 4, I'd like to provide an update on the current East Coast gas market dynamics in Australia. The Australian Competition and Consumer Commission, otherwise known as the ACCC, who is undertaking triennial studies on the East Coast gas market, has recently provided an update in June of this year. The key outcomes from this study, I have highlighted 3 themes.

One is the shortfall that hasn't been anticipated for a number of years, is now projected to occur a full year earlier than the previous forecast. Two, gas prices agreed under contract in 2024 were approximately $8.50 per MMBtu. This is almost three times the price of Henry Hub during the same time period from 2024 to date. And three, the anticipated shortfall on the East Coast is anticipated to grow to 1 BCF a day by 2030 and expanding to 1.5 BCF a day by 2035.

This market provides the appropriate market signal to stimulate a very large new development out of the Beetaloo, that we would look to deliver a minimum of one BCF a day as early as twenty twenty-eight into this market, and we believe this provides a very constructive macro backdrop to accelerate this phase two of our development plan. Moving to slide five, this is our company strategy, which will focus on delivering two BCF a day by 2030. That will involve three main phases. The first phase is delivery of 40 million cubic feet a day of a pilot development project, and we'll target having that 40 million a day delivered to the local into gas market as early as Q1 of 2026.

Off the foundation of our pilot project, we will develop this one BCF a day and target the domestic market on the East Coast of Australia as delivery as early as 2028. And once we have a well-supplied Northern Territory gas market and a well-supplied domestic market on the East Coast, we will progress our LNG strategy, where we'll focus on delivering a minimum of one BCF a day to NTLNG by 2030. In phase four and beyond, we would envision additional trains being built at NTLNG and supplied with additional gas supply from our development area in the Beetaloo Basin. Moving to slide six. One of the key elements of delivering this strategy is importing U.S. technology that has been developed as part of the shale revolution in the last fifteen years.

That's what led us to partner with H&P about twenty-four months ago. We agreed with H&P to bring in up to their five modern FlexRig 3 rigs into the Beetaloo Basin from the US. The first rig arrived about twelve months ago, and that rig is currently on location and drilling the first series of wells on our pilot development. Last year, we also partnered with Liberty Energy to bring in modern frack equipment. That frack equipment has currently arrived in the port of Darwin, and we will be mobilizing that fleet down the site, and that's the frack fleet that we'll be using for the upcoming two wells this year.

In addition, we've also partnered with the largest pipeline company in Australia, APA, and we're actively working with APA on development of a new pipeline from the Beetaloo into the East Coast market, where we'll target initial first gas as early as 2028. And finally, we recently awarded Bechtel as our pre-feed partner, and we are actively, over the next twelve months, we'll be progressing pre-feed with Bechtel to support the initial designs of our NT LNG project. Turning to slide seven. The other key element to executing our two BCF strategy is the high quality, world-class resource that is in the deepest sections of the Beetaloo Basin. This world-class resource was identified from a well that we drilled last year, called Shenandoah South 1H.

You can see the log in the middle of the page of slide seven, where we logged 480 feet of high quality shale that you can see from the spider on the right, spider diagram on the right, in comparison to the Marcellus Shale. The rock properties that we've seen in the deepest sections of the Beetaloo are not only thick, but they're very high quality. Reservoir properties and also the gas in place versus the Marcellus Shale properties are roughly 40% greater here in the Shenandoah South area. In addition, there's a million acres that we feel have been significantly de-risked by this well, and we believe provides a significant runway for our 2 BCF a day development plan. Moving to slide eight.

A little bit more detail around the activities that we have kicked off in our Shenandoah South Pilot Project area. If I refer everyone to the map in the middle of the page, you can see Shenandoah South 1 that was drilled last year is in this small black stick, and directly north, three miles from that well location, we've constructed a new six-well pad, where we have kicked off the drilling of the initial two wells this year, Shenandoah South 2 and Shenandoah South 3. Those will both be designed with 10,000-foot horizontal lateral lengths, and we will be pumping 60 stages in each of the 10,000-foot horizontal wells.

Following the drilling of Shenandoah South 2 and Shenandoah South 3, we will look to take the learnings from each of these two wells and deploy those learnings in four follow-up wells that we will look to drill in 2025, where we will look to take all six wells and commission a facility and hook that facility up to the local Amadeus Gas Pipeline and produce initial volumes of up to 40 million cubic feet a day by early 2026. Again, this project is underpinned by a 15.5-year gas sales agreement that we have signed with the Northern Territory government and provides a significant de-risking for our delivery of this initial phase of our development plan. Turning to slide 9, you can see by the picture on the right, the activities that are ongoing on this roughly 20-acre site.

You can see the well pad, where we're gonna be drilling six of our pilot wells, in addition to our man camp and our Sturt Plateau compression facility that will be positioned on the northwest corner of our pad. Again, we will be targeting IP30 flow rates from each of these two wells, as early as Q1 of 2025. And so we're extremely excited about the opportunity to deliver the first 10,000-foot horizontal wells in the Beetaloo Basin and pumping over 100 up to 120 stages in each of these two wells. This represents the largest single campaign in the Beetaloo Basin to date. Moving to slide 10.

Again, the Liberty frack spread arrived in the port of Darwin about 30 days ago, and we are actively mobilizing this new frack spread down to site as we speak. We should have this frack spread on site by late October, and anticipating pumping our first frack around November first. This equipment also included 400 sandboxes that is gonna be dramatically reducing the cost and also the efficiencies of pumping each of our frac stages. The last well that we drilled, Shenandoah South 1H, we were averaging one frac stage a day. We believe this new frac spread from Liberty Energy will dramatically improve the efficiencies and allow the company to pump up to 5-7 stages per day with our new equipment.

Turn to slide 11, a little bit more details around the well design for each of the six pilot wells that we are planning. Again, the two wells that we'll drill this year, we will incorporate the learnings from Shenandoah South 1H, and this optimized completion design will be pumped over the 60 stages from each of the wells that we have drilled. Again, we will be taking the learnings from our initial two wells and deploying additional learnings into the four follow-up wells that we will be drilling, completing, and flow testing in 2025. Turn to slide 12. You can see the performance from our Shenandoah South 1H well and extrapolated to a 10,000-foot horizontal.

You can see the close, kind of alignment, of the productivity, that we've seen from this initial well, kind of lining up with top quartile type curves in the Marcellus Shale regions, particularly in Northeast Pennsylvania. Our goal is to replicate this curve over our full 10,000-foot horizontal, for Shenandoah South 2 and 3, and again, look to further optimize and potentially see better productivity as we move from well 1 to well 6 in our pilot project, in the next 18 months. Moving to slide 13, what is incredibly exciting, about the opportunity to de-risk further this 1 million gross acres on the west part of the Beetaloo Basin, is the opportunity, for significant runway.

So if you compare the one million acres in our development area in the Beetaloo, and you compare that same one million acres in Northeast Pennsylvania, the one million acres in the Marcellus has been producing 14 BCF a day, and they've held that flat for the last 10 years. So we are talking about developing the first two BCF a day, and we believe we have significant runway beyond two BCF a day moving forward in 2030 and beyond. Moving to slide 14, you can see part of the little bit more detail on phase two and phase three of our business plan.

Again, we are active in working with our partner, APA, on designing the route selection and also the engineering for a new pipeline that will connect our assets in the Beetaloo Basin to the East Coast gas market. This is a market where we have been proactive and have signed letters of intent with six of the largest gas retailers, up to eight hundred and seventy-five million cubic feet a day. Our plan is to convert those letters of intent to a binding gas sales agreement in the next twenty-four months that will go toward underpinning the sanctioning of this new pipeline that we'll be working on with APA, and in parallel to that, we have kicked off our pre-FEED studies for phase three and the Tamboran-operated NTLNG project.

Again, we awarded that pre-FEED to Bechtel, and we couldn't be more excited to be moving forward with one of the premier LNG EPC contractors in the world. Again, we have signed MOUs with BP and Shell for 2.2 million tons of LNG for 20 years each. Over the next 12 months, we will be active in discussions with other parties around looking at additional MOUs to build out our phase three of our business plan. A little bit more detail on slide 15, you can see a bird's-eye view of the Port of Darwin. This is an existing LNG hub. The largest LNG plant, one of the largest LNG plants in Australia, is Ichthys, operated by INPEX. It produces 8.9 million tons of LNG per year.

That represents 10% of Japan's LNG that gets consumed every year. Right to the east of INPEX's Ichthys plant is our 420-acre site that we've been awarded by the NT government in May of last year, and this is a very exciting area called Middle Arm that our 420-acre site resides. On Middle Arm, there's additional projects being planned, including two hydrogen projects. There's a battery and mineral project, two CCS projects, and therefore, there's been a region-wide environmental approval process that's been kicked off and anticipated to complete by the end of 2025, and the Australian Federal Government has contributed AUD 1 billion around common user infrastructure that will feed in to our NT LNG project.

We look forward to providing further updates as we get through pre-FEED in the next 12 months, and look to move into FEED as early as second half of 2025. And finally, on slide 16 are the upcoming catalysts. As I mentioned previously, we are in the process of drilling, stimulating, and we'll be commencing flow testing for Shenandoah South two and three by the end of this year. And in parallel with that, we will be securing our final stakeholder and regulatory approvals for executing our pilot project. In Q1 of next year, we will look to announce our IP-30 flow test results from Shenandoah South two and three. And also by the end of Q2 of next year, we will complete our pre-FEED studies with Bechtel on NTLNG.

Moving into the balance of the year, we will look to commission our pilot project with the view to target initial first gas from our Shenandoah South pilot project in first half of 2026. Finally, Tamboran appreciates the support of the Northern Territory Government and all the people that live in the Northern Territory, and the traditional owners in the regions where we operate. We look forward to working closely with all of our stakeholders, including all of our shareholders listening today, through this exciting, transformative next 24 months with this company in working toward delivering two BCF a day by 2030. With that, I want to hand it back to the operator to conduct questions and answer session of our call. Thank you very much.

Operator (participant)

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. To remove yourself from the queue, you may press star two. Once again, that's star one to be placed in the question queue. One moment, please, while we poll for questions. Our first question is coming from Scott Hanold from RBC Capital Markets. Your line is now live.

Scott Hanold (Managing Director)

Yeah, good morning, and I guess to you all, good afternoon, evening. You know, thanks for this update. And look, Joel, I know it's really early. It's been only a couple of weeks since the drill bit's kind of been in the ground, but if you can give us some color on any early things you're seeing in the drilling and just some idea of like, you know, how far are you into it? Are you into the... I would assume starting to get into that horizontal lateral pretty well at this point.

Joel Riddle (Managing Director and CEO)

Yeah. Hi, Scott. Nice to speak to you. Yeah, drilling is going well. As I mentioned, we spudded the Shenandoah South 2 well in late August. We are drilling ahead. We will be in the horizontal section shortly. But look, all is going to plan to date. We should have TD on both wells in Q4, and we'll be, as I mentioned in my opening comments, we'll be bringing the Liberty frack spread down to site and have that site, that completion spread ready to pump our first frack around November first. But, you know, we'll keep the market updated both on well drilling and performance in due course.

Scott Hanold (Managing Director)

Okay, that's great. Great to hear. Thanks, thanks for that. And my follow-up question is, you know, look, it looks like you've got a lot of, you know, your strategies laid out pretty well, and it's good to see that agreement with Bechtel, you know, in the play or in the fray right now. But obviously, the next step post-drilling, you know, part of it's gonna be seeing those results. And then to progress forward, how do you think about, like, funding, you know, the pilot project, you know, even further? What, you know, and maybe this is a question for Eric. It's like, what are the options out there you think are most palatable or, you know, top of mind in terms of funding the next step of your journey?

Eric Dyer (CFO)

Yeah, thanks for the question, Scott. So look, you know, we raised $75 million on the IPO, and then post-IPO, the green shoe option was another $7.5 million was exercised. That funds us for the completion of these two wells, long leads on infrastructure, and we've got additional plans and a strategy in the works that's gonna provide us with sufficient liquidity throughout the rest of the financial year. The capital for the 2025 program is highly dependent on the outcome of these two wells. Our current working assumption is that we'll drill four wells during 2025. That'll require up to about $100 million, and we'll evaluate the need for that capital after the results of the current program.

Scott Hanold (Managing Director)

Got it. And as you think about, like, but there are a variety of different funding options I know you all talked about. Is there one that you're in particular leaning towards, or is it really, you know, you need to see the well results, you know, first to determine the next best step?

Eric Dyer (CFO)

Yeah, I mean, look, we went public to—for access to capital and deeper pools of capital there in the United States. We’ve since that process found a lot of traction with banks and potential debt funding supported by our gas sales agreement with the NT government. Remember, that’s a fifteen-year gas sales agreement linked to CPI with an investment grade customer. We’ve been also in discussions with prepays, and then, you know, we’re always cognizant, you know, we’re all... We’re big shareholders here around this table. We’re always cognizant of dilution, and so we’re running all these options down, in parallel with our current program.

Scott Hanold (Managing Director)

Great. That's exactly what I was looking for. I appreciate that. Thanks.

Operator (participant)

Thank you. Next question today is coming from Charles Meade from Johnson Rice. Your line is now live.

Charles Meade (Research Analyst)

Good evening, Joel and Eric. I hope you don't have the whole employee base staying late on the beginning of their weekend. You covered a lot of the questions that I had in your prepared remarks, Joel, so thank you for that. One little data point you gave us, I think in your response to Scott's question, is that, and I wanna make sure I got this right: you plan on starting the frack of, I guess, Shenandoah South two, excuse me, on November one. Did I get that right?

Joel Riddle (Managing Director and CEO)

Yeah, that's correct.

Charles Meade (Research Analyst)

Okay, and so you'll probably still be drilling on the three at that point, is my guess.

Joel Riddle (Managing Director and CEO)

No, no. We will drill number three back to back. So as soon as we finish the drilling of Shenandoah South two, and we case in the five and a half, we will skid the Shenandoah South three, and we will drill and case that well. Then we'll bring on the Liberty frack spread, and lay down the rig on site, and we will pump both of those wells back to back.

Charles Meade (Research Analyst)

Got it. Got it.

Joel Riddle (Managing Director and CEO)

We anticipate to provide a wholesome update on those activities at our next result in November.

Charles Meade (Research Analyst)

Right. When they start. Okay, that makes sense. And then, also, you mentioned or and you had some pictures on the slide about the sandboxes that Liberty has brought along as part of the solution. What can you fill in the picture there? What is your plan? You know, what's your provisioning for sand for these wells? Where is it coming from? And is there any update you can offer us on the? I know you guys were developing some sand mine locations. So you can describe what the plan is for this well, and then what the longer term, how the longer-term picture is evolving.

Joel Riddle (Managing Director and CEO)

Yeah. So the current sort of situation for sand for these two wells, and really all the wells that have been drilled in the Beetaloo to date, is we've been importing sand from various regions of Australia. Actually, the sand that we've gotten for these two wells come from China in bags. It's quite costly, in the order of $4.5 million per well that we spend on sand. So naturally, we have been focused on opportunities to reduce that part of the drill cost, drilling and completion cost. We've picked up some leases in the last twelve months. These are sand leases that we can develop a local sand mine.

We have initiated some review of the quality of the sand that are, you know, reasonably close by our Shenandoah South pilot pad, and the early indications are positive. And so, we have now commenced some discussions with developing a local sand solution with potential partners. And, you know, we look forward to updating the market around that progress at the next call. But big picture, having a local sand solution in place will dramatically reduce cost. You know, again, we're starting at a high base of AUD 4.5 million per well. We think it'll... With a local sand solution, we could see sand costs drop below AUD 1 million.

Charles Meade (Research Analyst)

That is great detail. Thank you, Joel.

Operator (participant)

Thank you. Next question today is coming from Kalei Akamine from Bank of America. Your line is now live.

Kalei Akamine (Analyst)

Hey, good morning, guys.

Joel Riddle (Managing Director and CEO)

Yeah, good morning.

Kalei Akamine (Analyst)

Joel and team, first off, congratulations on your first U.S. quarter, and thank you very much for taking my question. And I've got several here that pertain to the pilot program. I guess, first off, can you sort of address what the baseline expectation is or the pre-drill expectation is for these wells? And I'll caveat by saying that I'm not a reservoir engineer, but if I simply place an Arps curve on top of the performance for Shenandoah number one, it looks like it's running significantly ahead of the seventeen BCF type curve. So maybe, without getting specific, can you say if it's fair to characterize the outperformance that you're seeing as significant? And then can you ground that for us as we think about the higher intensity frack that you're employing on the pilot?

Joel Riddle (Managing Director and CEO)

Yeah, great question. I am a reservoir engineer by background, by the way. You know, I think, you know, going into the last well, Shenandoah South 1H, our pre-drill expectation was seventeen BCF EUR. You know, to your comment, you know, we did see better performance than expected on productivity per stage, and then obviously, when you extrapolate that out to ten thousand feet, you're in the upper quartile of type curves in the Marcellus. You know, kind of where we're grounded is on the performance that we've seen on a per stage basis for Shenandoah South 1H. What we are looking to achieve with these first two wells is to replicate that performance over a full ten thousand foot horizontal, so we're not extrapolating anymore.

We will look to replicate that exact, you know, sort of performance on that Marcellus type curve, slide that I reviewed earlier. And obviously, as we get through these first two wells and, you know, I acknowledge that we are using bigger equipment for that we've imported from Liberty. We have more horsepower. You know, we have up to 32 pumps versus 16 pumps that we used in the last well. That'll allow us to have better redundancy and more consistency in pumping the completion design that we pumped in Shenandoah South 1H. So we're not gonna change the design, but I believe the consistency of pumping our design for each stage will be better because of the equipment we have on site versus the previous equipment we have.

And so the first two wells, again, to set the expectations, we're just looking to replicate the performance that we've seen from Shenandoah South One. And, you know, I think based on what we see, and, you know, we'll report those results in Q1, then we'll take that opportunity to, you know, update the market on our forward projections on what we're seeing for the subsequent four wells. But I think if any of the experience that we've seen here in the U.S. is that, you know, the more wells that you drill, the more stages that you pump, you're gonna get more efficient, you're gonna optimize and hopefully get better performance.

You know, that is the whole point of doing this pilot project, is to get a really good understanding of how many reserves that we can recover from each well, what are the costs of each of our horizontal wells, and then that'll feed into a development model for our two BCF a day plan. That will guide us on the number of wells we need to drill, the cost of those wells. So this is a learning from well one to well six, and at each quarter, we will update the market further on where we sit.

Kalei Akamine (Analyst)

My real quick follow-up there is on the 2025 program. Eric suggested that there is some flexibility in there. Your base case is four wells, but could it actually be fewer if you see outperformance in these first two wells?

Joel Riddle (Managing Director and CEO)

Absolutely.

Kalei Akamine (Analyst)

Great. My follow-up goes to the drilling side of the equation. In a previous conversation that you and I had, you mentioned something that I thought was interesting, that Shenandoah number one went through something like ten drill bits. You've got a new higher-powered rig on site, so I imagine that there's downside to that number, which would indicate faster drilling, lower costs. Can you talk a little bit about the improvements that you hope to see from the new equipment and ultimately what the efficient frontier of the drilling side looks like?

Joel Riddle (Managing Director and CEO)

Yeah. The ten bits that I mentioned in our previous meeting were tied to a well that wasn't drilled by Tamboran. It was a well that was drilled on the east part of the basin that we were 25% interested in. So, that wasn't a Tamboran-operated well. But just to clarify, you know. One of the things that our team has done, and part of our strategy, you know, really over the last 10 years, is to participate on non-operated working interest level, you know, to learn from others. So we've had that opportunity. We picked up learnings from early wells that Santos had drilled on the east part of the basin. That helped us really get our head around bit design.

Obviously, after we acquired the Origin acreage in 2022, there was a number of wells that we could pull learnings from. So we took the product of all of that, all of those previous wells, and we used that on all our 2024 drilling program that really began in 2023. Fast forward to where we are today, these two wells we're drilling now are the product of all those learnings. You know, what was previously the bits that were burned out in some of the early wells, up to 10 bits across a very thick, hard rock section, you know, we can get through in one bit on these couple of wells, and that's, you know, helping us really get down the curve even further.

You know, that's part of, you know, having increased ROPs, less days on the well, less cost. You know, again, we've already made a lot of progress. I think the more wells we drill in the pilot, in the six pilot wells, the more efficiencies even we're gonna see beyond this first well. What we're trying to do is refine our design further and further. That laser focus on reducing drill times, reducing the number of stages we can pump a day, and overall, reducing our cost from well one to well six.

Now, that will guide us on how many wells that we feel like we need to drill, in 2025, but most importantly, will guide us the number of wells we need to drill to develop two BCF a day.

Kalei Akamine (Analyst)

Awesome. Thanks for that, Joel. We will watch with interest.

Operator (participant)

Thank you. Next question is coming from Paul Diamond from Citi. Line is now live.

Paul Diamond (Equity Research Analyst)

Thank you. Good evening, all. Thanks for taking my call. Just a quick one to talk about the conversion of the LOI for the gas sales agreement. You mentioned like 12-24 months. How should we think about kind of the pace of that dialogue? Is that, you know, once two and three are up and running, and then that accelerates that? Or how should we think about the timeframe there?

Joel Riddle (Managing Director and CEO)

Yeah. Yeah, I think our goals in the next twelve months is to find, you know, kind of, one of the, you know, largest gas retailers, and start our gas sales agreement, you know, with a, I would say a third of the BCF a day that we would look to bring under a binding GSA. You know, much like a lead in a capital raise, is finding that lead. And once that lead kind of, you know, is identified and we get to a binding gas sales agreement, we will. You know, that from my experience, that will attract others. And so these are, this is very important, because these are long-term commitments.

You know, these gas sales agreements in Australia are 10-15 years, and they're all kind of fixed price tied to CPI. And this will underpin our pipeline infrastructure. So the quicker we can progress a binding gas sales agreement, the quicker our pipeline partner, APA, can get comfortable to accelerate this new pipeline. So, I think the backdrop that we're dealing with in Australia, as I mentioned in my second slide today, is that we are moving into a structurally short market, so we believe the market is very constructive. The dialogue with each of these gas buyers, I would say, is maturing quite rapidly.

You know, that's what's led us to sign these LOIs, which gives me a lot of confidence that we can move forward in the next 12 to 24 months to convert these LOIs to GSAs.

Paul Diamond (Equity Research Analyst)

Understood. I appreciate the clarity. Just one quick follow-up. I know you guys mentioned you're targeting Q1 2025 for the initial IP thirty flow rates on the next two wells. Is the current expectation for that to be, you know, closer to the front half of the quarter, towards the back half, or do you have any clarity on the timing there? Or is it just still dependent on, you know, drill times and such?

Joel Riddle (Managing Director and CEO)

Yeah. Look, we'll provide more clarity around timing at the November call. We'll be through the drilling and, you know, we would've initiated kind of our completions for both wells, and I think we'll have further line of sight around the specific timing around the IP30 announcement. So, you know, right now, I think it's a little early to be guiding towards specific months, but definitely within the Q1 of next year is our target to announce the IP30.

Paul Diamond (Equity Research Analyst)

Understood. I'll leave it there. Thanks for your time.

Operator (participant)

Thank you. We've reached the end of our question and answer session. I'd like to turn the floor back over to management for any further closing comments.

Joel Riddle (Managing Director and CEO)

Thank you very much for everyone joining today, and we look forward to providing further updates on our next quarterly call. Thank you very much.

Operator (participant)

Thank you. That does conclude today's teleconference and webcast. You may disconnect your line at this time, and have a wonderful day. We thank you for your participation today.