Tamboran Resources Corporation (TBN) Earnings Call Transcript & Summary

Greetings. [Audio Gap] [Operator Instructions] As a reminder, this conference is being recorded. [Operator Instructions]. It's now my pleasure to turn the call over to Todd Abbott, Chief Executive Officer. Todd, please go ahead.

Hello, everyone, and welcome to Tamboran Resources Financial Year 2026 Fourth Quarter Earnings Presentation. My name is Todd Abbott, and I'm the Chief Executive Officer of Tamboran Resources. I'm joined here today by Chief Financial Officer, Eric Dyer and VP, Investor Relations and Corporate Development, Chris Morbey. I'll start by reviewing delivery against the commitments we made 12 months ago, then cover production and commissioning as we build towards plateau rates and contracted [indiscernible]. I will also discuss what our latest well results and operating improvements mean for performance and cost as we continue to derisk our assets. I will then review our funding position and close with the next development milestones before we take your questions. Moving to Slide 2, you can see our disclaimer, which relates to forward-looking statements within the presentation. I encourage you to review those at your convenience. On Slide 3. The last few months have been a pivotal period for Tamboran and the Betaloo Basin, as we have delivered on a key commitment and provided the next step in derisking the basin. We have delivered first gas sales from the Betaloo to the Northern Territory Gas market. Homes and businesses in Darwin are now being powered by a local onshore resource. These gas sales also bring royalties to the Northern Territory government and native titleholders alongside job opportunities for Territorians. Tamboran already employs a significant local workforce, which we expect to grow as activity increases over the coming years. Moving to Slide 4. Gas has now been flowing into the market for 20 days. Volumes are currently limited to market demand with the Northern Territory Government nominating 25 tera-joules per day as the territory comes out of its lower demand season. We expect demand and therefore, nominations to keep growing through the Northern Territory's peak demand period. We are currently in the commissioning period of the gas sales agreement. Once the agreement moves into the supply period, take-or-pay provisions will apply to the 40 tera-joules per day contract quantity, and we will be getting revenue based on that 40 tera-joules per day. Any guess the offtaker does not take will be banked for future potential delivery. This gives us downside protection in the event of lower nominations during the contracted period. Regarding our flowback strategy, we will prioritize 2 wells to ensure that we're generating long-term production and well performance data to further derisk the basin. The remaining wells will be managed as needed to recover flowback water and to close any gap to the allowable nominations. In achieving this first gas milestone, our operations team have been working deliberately across multiple work streams. They successfully completed the stimulation campaign on the SS-2 pad in the Betaloo Basin. The program utilizes the Liberty Energy stimulation fleet that was imported into the basin in 2023. During the program, we completed 178 stages across 30,000 lateral feet. It was the largest stimulation campaign conducted in basin. And the Zipper Frac approach allowed us to achieve 3 hours of operations and the Betaloo Basin record 12 stages completed in a day. This gives us and the market early evidence that we can execute completions more efficiently. The next measure of success is sustaining an improved pace across a full campaign, reducing downtime and bringing down completion costs per well. We have also entered into a nonbinding Memorandum of Understanding with Liberty Energy, setting out the intent to extend the hydraulic fracture stimulation of wireline services agreement covering Tamborn's operations in the Betaloo Basin. Liberty intends to begin phasing lower-emission pumping equipment into the Betaloo fleet from 2027. Importantly, the campaign included 10 stages using the locally supplied Betaloo Red Sand across various locations with the SS2-5H well. The pumping and placement of the local sand was an identified risk going into the program. However, given we experienced no impact to pump pressures or fracture initiation during these stages, we are confident on our ability to place local sand and future campaigns. [indiscernible] across the horizontal length have shown the stages of producing in line with [indiscernible] wells, but these are still early days, and the true test will be the longer-term flow rates and recoveries. We plan to further test our Betaloo Red Sand during the upcoming stimulation program in the SS1 pad. The success of that local sand is a key step in delivering near-term cost reduction for well completions. It is expected that, that sand could save USD 4 million per well with a 10,000-foot horizontal section compared to the sand to import it from overseas. Those long-term flow rates and recoveries from those stages will help us assess how widely we can apply those savings. In conjunction with the upstream activity, the operations team successfully completed construction of the Sturt Plateau compression facility. On time and approximately USD 9 million below the forecasted budget. This allowed us to meet our commitment to the supply of the Northern Territory Gas market during the quarter. The commissioning of the facility remains ongoing as we fine-tune control systems and refine equipment settings. During the commissioning period, we will be receiving 75% of the gas price. This is due to the interruptible nature of the supply. Once commissioning and production testing requirements are complete, we will commence delivery into the take-or-pay contract with the Northern Territory Government. During the quarter, the operations team also commenced drilling the 3-well campaign on the SS-1 pad with the H&P Flex 3 Rig. Drilling of the first 2 wells has been completed with the third well currently drilling ahead. We continue to incorporate lessons from previous campaigns. This program includes first wells drilled with our improved drill bit design and anti-vibration tools. This resulted in record speeds through the Moroak formation. Modifications to the rig have resulted in reduced mud temps, allowing increased average ROP in the lateral sections. We continue to work with our contract partners to improve efficiencies and reduce down, especially within the lateral section, and we believe these are addressable as we ramp up activity. In the East, drilling of the 2-well appraisal program with Santos on EP 161 has also commenced, with the Jibera South 1H age and New Castle South 1H wells in that depocenters. During the quarter, we significantly strengthened our balance sheet. In April, we raised USD 186 million net of fees via an underwritten public offer and in institutional and retail entitlement. The funds from the raise solidify the balance sheet and provide us financial flexibility. At the end of the quarter, Tamboran had USD 225 million in cash and USD 31 million in undrawn debt for funding of the SPCF, including the USD 15 million that we expect to receive from Daly Waters Energy, the pro forma cash position is USD 240 million, receipt of that $15 million remains subject to certain conditions precedent. Over the next 2 quarters, we expect that under U.S. GAAP, some revenue and cost related to the Pilot Project will be capitalized to the balance sheet during commissioning, rather than flowing through the income statement. This is to avoid reporting volatility and means that the income statement will not reflect cash movements during the period. We expect to announce first quarterly GAAP sales and revenue in our 1Q fiscal '27 earnings in November. The next phase of our development plan is to further delineate our gas resources across both depocenters in the Betaloo Basin. This will be the focus of our '27 and '28 campaigns. We are working with our joint venture partners, Daly Waters Energy and INPEX in the West and Santos in the East to drill and stimulate at least 6 step-out wells over the next 18 months. We are progressing discussions with multiple parties to bring in a strategic partner. These strategic discussions and the upcoming appraisal work aimed to align on resource delineation and commercialization pathways that will support a large-scale development and underpin new pipeline infrastructure. That infrastructure is expected to connect the Betaloo Basin to multiple high-value markets. To close, we have delivered the first gas sales that we committed to you 12 months ago and completed the compression facility on time and below the forecasted budget. Our latest drilling and stimulation work is showing where we can improve efficiency, while local sand offers a potential source of completing cost savings. The equity raise has strengthened our balance sheet for the next phase in development. The priority now is to turn those achievements into sustained operating performance. That means completing commissioning and production testing, building towards plateau production and contracted supply and demonstrating that the gains in well delivery can be repeated. Those are the measures I will use to judge our progress as we advance our development plans and partner discussions. As we close, I want to thank all Tamboran employees for their commitment, their performance and their support for one another as we continue to grow, evolve and deliver for our customers and shareholders. Thank you.

[Operator Instructions] Our first question today is coming from Scott Hanold from RBC Capital Markets.

Congrats on all the milestones that you guys have achieved and plenty head. I want to start maybe focusing on the SS1-6H well. It sounds like it was a pretty successful drill. And could you give us a sense of what specifically you're changing in your drilling operations to see that success? And what other knobs and dials are you looking forward to doing it? And I'm sorry, I'm going to layer on one more thing on this. What kind of cost -- what is that kind of pro forma cost on that now that you've seen some good improvement?

Yes, Scott. Good to hear from you. Good question. On the 6H and maybe even more broadly kind of on the total drilling program, like the recent changes you'll see there, and I referenced it in the remarks there, the bit designed on some of the kind of upper level zones there that we're going through. The vibration dampener was actually a pretty big change for us. So that's helped us quite a bit. I'll also add, like one of the things that isn't really a tool change, but the directional plans on those wells and that the way we attack that Moroak Sandstone, which is just a really hard zone, just hard rock to get through. So that's been one of the areas where we saw the biggest opportunities. And in that last well we got through it with one [indiscernible], which was a big win for us. Earlier wells [indiscernible] had many more bits trying to get through that zone. So that's been a key improvement for us. When we look at the kind of opportunities going ahead, we think improving time on our downhole tools is going to help us a lot. We do see opportunities eventually to go to a synthetic oil based system, which will help our drilling times as well the ROPs. And then this is going to be a lot of little things. I mean, I think you've heard me say this before ultimately to really get the drilling times and those costs [indiscernible] than where we need them to be. We need two things. We need repeatability. So just doing the same thing, same crews, doing it again and again and again. And then the other is scale across the basin, this is all operators, but having enough critical mass of activity in the basin so that service companies have their center of operations and can be efficient in the way they set up their operations. So that we have readily available tools, readily available people, skill sets, logistics all work better. Everything we've seen in these large shale plays in the U.S. will eventually happen here. But those are the two things to really get it down into those kind of U.S. level cost structures.

Good to hear that. My follow-up question is and correct me if I'm wrong. So it sounds like there's 2 of the wells that are producing online at this point in time? And could you give us a sense of what you've seen? I know it's still early, but what are you seeing on the pressure data on those wells? And are those wells kind of -- have you opened the [indiscernible] fully on those? Or are they still choke back here at this point?

Yes. I'll say it's been variable on that. The wells look good. They're in line with our expectations. What we're really interested to see on those are the long-term decline rates. I won't know that for a bit. And we haven't produced a well out here for more than 90 days. So specifically, we're working under that 25 tera-joule a day nomination limitation. So we're prioritizing 2 well so that we can develop production histories and the well performance data to show what the wells can do. But aside from those 2, we've had the other wells cycling on and off kind of as needed if we need to close a gap to the nomination or as we need to manage getting water off of those wells, kind of helping clean those up. With regard to pressure data, I mean the pressure data looks good. But again, it's kind of all in line with our expectations. We just need to watch that over time.

Next question is coming from Leo Mariani from ROTH.

I was hoping you maybe talk to what you think CapEx is going to be in the rest of the calendar year. So I guess it'd be calendar 3Q and 4Q? Trying to get a sense of that would be helpful.

Yes. And we'll get Chris kind of go through the specific numbers on it. But I'll tell you, at a high level, we've got 4 wells in the Pilot Area that you'll see, 3 this year, 1 next year. We've got the 2 Santos wells over EP 161 with our 25% working interest, drilled this year, stimulating next year. And then we've got the 4 wells in the BCDA with Daly Waters. It's about a 10% working interest there. So I mean, overall, you can expect our capital to be focused on de-risking. And frankly, the full capital program isn't going to be fully locked in until we finalize where our partner is and align those what I would call collective strategic priorities, kind of where we're going to be in both basins. As you can imagine, each potential partner has a little bit different focus either one depocenter or the other or for some both. So as those conversations evolve we'll lock the rest in.

Okay. And can you provide a little bit more color on kind of where you are in the process of securing a partner? Do you think that's likely to happen kind of in the next handful of months, which will let you kind of give a better picture of what that kind of '27 calendar year budget would be?

Yes, it's certainly moving forward. Look, we continue to see strong outside interest. We're having the right conversations with the right potential partners. I mean at the end of the day, we're looking for the right capabilities to fit with the strategy and the right time frame with the operations. So I can sympathize with the kind of desire for certainty on the time line, but just please bear with us. It's all in play. And I'm sure everyone appreciates that deals like these take time and need to be carried out thoughtfully. So we're working through that process. It will -- wherever we land on that, whichever partner we ultimately land with it will be with a defined workflow [indiscernible] and going back to your first question, that will update that capital program.

Next question is coming from Jeff Grampp from Northland Capital Markets.

I was curious with respect to additional in-basin sand testing, you said the upcoming fracs will include at least 1 well. I just wanted to clarify, is that something you guys are comfortable doing across the whole well? Or will this be another partial test? And then maybe just taking a step back, what do you guys view as kind of the scalability of in-basin supply to the extent you have more confidence there? How meaningful of a portion of the program, could that be longer term?

Yes. So first, I'll just kind of talk about the early performance. And I mentioned in the remarks to you, like we had no problems pumping the sand, which that was something we were watching for. We started the frac -- like initiated frac well with it. So we're highly confident in our ability to pump it. When we look at the tracers coming back from those stages, they look identical to the other stages and the other wells. So early results are positive. But just like with the production, we won't know the full answer till we get some production history on this and see how that holds up. So yes, we're optimistic on what it can do. With regard to these X wells, we won't move to full Red Sand program until we are confident in. So we need some of that history. Each well we drill out here is pretty important to help derisk the basins. So we're not going to kind of take outsized risk on any one of them. So we'll do some additional stages on these next completions, but we won't do full wells at this point yet, Jeff. Going forward, like once we get history on it, once we're comfortable that the Betaloo Red Sand does what we expect and hope it will do, I can see us going to a 100% full program at Red Sands or effectively 100%. There could be some settlements here and there. But I think the end goal is to use in-basin sand based on sand in the Betaloo, and from a low cost perspective, it's going to be the obvious right thing to do.

Yes. Understood. That makes sense. And for my follow-up, with respect to the potential to expand the SPCF, I think you had talked about maybe making an investment decision next year. What are the milestones or key, I guess, check boxes, if you will, to get comfortable making that decision? Is that more on comfortability around your own internal producibility volumes, offtake financing all the above, just any kind of, I guess, kind of milestones you can eye out to track that project?

Yes. I think all the things you're mentioning are important in [indiscernible] it, although I feel pretty good about all the ones you mentioned. The one that we really have to look at, and this is probably the key uncertainty on whether we expand it or not, is making sure that the surrounding infrastructure network will allow us to move the incremental volumes to the incremental markets, right. Just having high confidence that we can get that. We don't own the pipelines all around us and understanding how the gases are going to flow and how those are going to be upgraded or modified over time, will help us make the decision. So we're working through that now, kind of getting a better understanding each day on it, but that's something we just need certainty on before we make that kind of investment. We need [indiscernible] that we will be able to...

Next question is coming from Charles Meade from Johnson Rice.

Good morning Todd, to you and Eric and Chris and the rest of the Tamboran team. Todd, I want to go back to the -- your decision to flow these or really, I guess, prioritize these 2 wells in the initial 25 [indiscernible] a day. It seems like getting more production history on more wells is one of the key near-term things that you're looking for. So I'm curious, can you give us an idea when that 25 million a day will go to up to the 40 million. I mean I think you said it's contingent on the full commissioning of the SPCF. Can you just give us a time on on when you're going to be able to start to build more of that production history?