Tamboran Resources Corporation (TBN) Earnings Call Transcript & Summary

Good morning, everyone, and thanks for joining us for Tamboran Resources' presentation of results for the fourth quarter of financial year 2026. I'm Todd Abbott, and I serve as Chief Executive Officer of Tamboran Resources. With me today are our Chief Financial Officer, Eric Dyer, and Chris Morbey, who is VP of Investor Relations and Corporate Development. To begin, I'll go over how we performed relative to the promises made 12 months back, and then I'll talk about production and commissioning as we progress toward plateau rates and contracted < >. I'll also explain what the newest well results and operational gains signify for both performance and cost as we keep derisking our assets. After that, I'll go through our funding position and wrap up with upcoming development milestones, and then we'll open things up for your questions. If you turn to Slide 2, our disclaimer is there, covering forward-looking statements contained in this presentation. I'd encourage you to look those over whenever it's convenient. Now on Slide 3. Recent months have marked a critical stretch for Tamboran and the Betaloo Basin, since we've fulfilled a major commitment and taken the next step toward derisking the basin; we achieved first gas sales from the Betaloo into the Northern Territory Gas market. Darwin's homes and businesses are now receiving power from a local onshore resource. These gas sales additionally generate royalties for the Northern Territory government and native titleholders, as well as job opportunities for Territorians. Tamboran currently has a sizable local workforce, and we anticipate it will expand as activity ramps up in the years ahead. Turning to Slide 4. Gas has been flowing to the market for 20 days now. At present, volumes are constrained by market demand, with the Northern Territory Government nominating 25 tera-joules per day as the territory exits its lower demand season. We anticipate demand, and consequently nominations, will continue rising throughout the Northern Territory's peak demand period. Right now we are in the commissioning phase of the gas sales agreement. When the agreement enters the supply period, take-or-pay provisions will kick in for the 40 tera-joules per day contract quantity, and our revenue will be based on that 40 tera-joules per day. Whatever volume the offtaker doesn't take will be banked for possible future delivery. That provides us with downside protection should nominations come in lower during the contracted period. As for our flowback strategy, we'll prioritize 2 wells so that we're producing long-term production and well performance data to further derisk the basin. The other wells will be managed as required to recover flowback water and to close any gap to the allowable nominations; in reaching this first gas milestone, our operations team has worked deliberately across multiple work streams. They successfully finished the stimulation campaign on the SS-2 pad in the Betaloo Basin. The program uses the Liberty Energy stimulation fleet that was brought into the basin in 2023. Over the course of the program, we completed 178 stages across 30,000 lateral feet. That represented the largest stimulation campaign ever conducted in basin. With the Zipper Frac method, we managed 3 hours of operations, plus a Betaloo Basin record of 12 stages finished in one day. That provides us and the market with early proof that completions can be executed more efficiently. Sustaining a better pace over an entire campaign, cutting downtime, and lowering completion costs per well is the next success measure. We've also signed a nonbinding Memorandum of Understanding with Liberty Energy, outlining the intent to extend the hydraulic fracture stimulation of wireline services agreement covering Tamborn's Betaloo Basin operations. From 2027, Liberty plans to start phasing lower-emission pumping equipment into the Betaloo fleet. Notably, the campaign featured 10 stages using locally supplied Betaloo Red Sand at various locations with the SS2 to 5H well. Going into the program, pumping and placement of the local sand was a recognized risk. Since we saw no impact to pump pressures or fracture initiation across those stages, though, we're confident in our ability to place local sand and in future campaigns. < > along the horizontal length have shown the stages of producing in line with < > wells, but it's still early days, and longer-term flow rates and recoveries will be the true test. We intend to test our Betaloo Red Sand further during the upcoming stimulation program at the SS1 pad. Delivering near-term cost reduction for well completions hinges on that local sand succeeding. Compared with importing sand from overseas, it's expected that this sand could save USD 4 million per well for a 10,000-foot horizontal section. Those long-term flow rates and recoveries from those stages will help us gauge how broadly those savings can be applied; alongside the upstream activity, the operations team successfully finished construction of the Sturt Plateau compression facility. On time and roughly USD 9 million under the forecasted budget. That let us meet our commitment to supplying the Northern Territory Gas market during the quarter. Commissioning of the facility is still ongoing while we fine-tune control systems and refine equipment settings. Throughout the commissioning period, we'll receive 75% of the gas price; this reflects the interruptible nature of the supply. After commissioning and production testing requirements are done, we'll begin delivery into the take-or-pay contract with the Northern Territory Government. During the quarter, the operations team also started drilling the 3-well campaign on the SS-1 pad with the H&P Flex 3 Rig. Drilling of the first 2 wells is finished, with the third well currently drilling ahead. We keep incorporating lessons from earlier campaigns. This program includes first wells drilled with our improved drill bit design and anti-vibration tools. That produced record speeds through the Moroak formation. Changes made to the rig have brought down mud temperatures, which has let us boost average ROP in the lateral sections; we keep collaborating with our contract partners on efficiency gains and cutting down time, particularly in the lateral section, and we think these issues can be addressed as activity ramps up. Over in the East, the 2-well appraisal program with Santos on EP 161 has kicked off as well, with the Jibera South 1H and New Castle South 1H wells located in that depocenters. During the quarter, we made our balance sheet considerably stronger. In April, we brought in USD 186 million net of fees through an underwritten public offer plus an institutional and retail entitlement. The money from this raise firms up the balance sheet and gives us financial flexibility. At quarter end, Tamboran held USD 225 million in cash along with USD 31 million in undrawn debt to fund the SPCF, and counting the USD 15 million we anticipate getting from Daly Waters Energy, the pro forma cash position comes to USD 240 million, though receipt of that $15 million is still subject to certain conditions precedent. Across the coming 2 quarters, we anticipate that under U.S. GAAP, certain revenue and cost tied to the Pilot Project will be capitalized onto the balance sheet while commissioning is underway, instead of running through the income statement. This is meant to avoid reporting volatility and means the income statement won't reflect cash movements during that period. We expect to report first quarterly GAAP sales and revenue with our 1Q fiscal '27 earnings in November. The following phase of our development plan involves further delineating our gas resources across both depocenters in the Betaloo Basin. That will be the focus for our '27 and '28 campaigns. We're working alongside our joint venture partners, Daly Waters Energy and INPEX in the West and Santos in the East, to drill and stimulate no fewer than 6 step-out wells across the next 18 months. We're advancing talks with several parties about bringing in a strategic partner. These strategic discussions and the forthcoming appraisal work are intended to align on resource delineation and commercialization pathways that will back a large-scale development and underpin new pipeline infrastructure. That infrastructure should link the Betaloo Basin to multiple high-value markets. To wrap up, we've delivered the first gas sales we promised you 12 months ago and finished the compression facility on time and under the forecasted budget. Our most recent drilling and stimulation work is revealing where we can improve efficiency, while local sand provides a possible source of completing cost savings. The equity raise has bolstered our balance sheet for the next phase in development. The priority now is turning 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. That's the standard I'll apply when evaluating how far we've come while moving forward with our development plans and conversations with partners. Before I finish, I'd like to express gratitude to everyone at Tamboran for their dedication, the results they deliver, and the way they back each other up as we keep expanding, changing, and producing results for our customers and shareholders. Thank you.

Congratulations on everything you've accomplished and the many milestones. I'd like to begin by zooming in on that SS1 to 6H well. From what I can tell, that drill went quite well. Could you walk us through what exactly is different in your drilling operations that produced that result? And what other levers and adjustments are you excited to try next? And apologies, I'll pile one more question on top of these. What does the pro forma cost look like now, given the solid improvement you've seen?

Sure thing, Scott. Great to hear your voice. That's a good question. Regarding the 6H, and perhaps more broadly across the whole drilling program, the changes made recently are visible there, and I touched on this during the remarks, the bit design for a few of those upper zones we're passing through. The vibration dampener was honestly a fairly significant shift for us. It has given us a meaningful boost. I should also mention, one item that isn't truly a tool modification, but the directional plans for those wells and how we approach that Moroak Sandstone, which is simply a very hard zone, just tough rock to drill through; so that ranks among the areas where we identified the greatest opportunities. And on that most recent well we made it through using a single < >, which was a major win for us. In prior wells < > there were far more bits needed to penetrate that zone. So that represents a crucial gain for us. As we consider the opportunities ahead, we believe extending the time on our downhole tools will benefit us considerably. We do anticipate chances down the road to move to a synthetic oil based system, which should improve our drilling times along with the ROPs. And beyond that, this will come down to many small items. I mean, I think you've heard me mention this previously, ultimately to truly bring the drilling times and those costs < > to where we need them to be, two things are required. Repeatability is one. So simply performing the same work, with the same crews, over and over and over. And the second is scale across the basin, this applies to all operators, but having sufficient critical mass of activity in the basin so that service companies base their center of operations here and can operate efficiently in how they organize their work. That way we have tools on hand, people on hand, skill sets, logistics all function better. Everything we've witnessed in those large shale plays in the U.S. will eventually come to pass here. But those two items are what's needed to really push it down into those U.S. level cost structures.

Glad to hear it. For my next question — and tell me if I've got this wrong — it seems like right now there are 2 wells that are online and producing? And might you give us an idea of what you've been observing? I realize it's still early, but what is the pressure data telling you on those wells? And those wells, have you fully opened the < > on them? Or are they still being choked back at this stage?

Yeah. I'd describe it as variable on that front. The wells are looking good; they match what we expected. What really interests us on those is the longer-term decline rates. That won't be clear to me for a while. Also, we haven't had a well out here produce for over 90 days. So specifically, we're operating under that nomination cap of 25 tera-joule a day. That means we're giving priority to 2 wells so we can build up production histories and well performance data showing what these wells are capable of. Beyond those 2, the remaining wells have been cycling on and off roughly as required if we need to close a gap to the nomination, or as we need to handle getting water off those wells, sort of helping clean them up; as for pressure data, I mean the pressure data looks good. But once again, it's all roughly consistent with what we expected. We just have to monitor that as time goes on.

I was wondering if you could perhaps share your expectations for CapEx over the remainder of this calendar year. So I suppose that means calendar 3Q and 4Q? Getting some clarity on that would be useful.

Yeah; and we're going to have Chris walk through the particular figures on that. But what I can say is, at a broad level, there are 4 wells in the Pilot Area that you'll see, 3 during this year, 1 during the next. There are the 2 Santos wells over EP 161 where we hold a 25% working interest, drilled this year, with stimulation happening next year; and then there are the 4 wells in the BCDA with Daly Waters. That's roughly a 10% working interest there. So I mean, on the whole, our capital should be expected to center on de-risking. And honestly, the entire capital program won't be completely settled until we work out where our partner stands and get those collective strategic priorities — that's how I'd describe them — aligned, in terms of where we'll be across both basins. As you'd expect, every potential partner has a somewhat different emphasis, whether on one depocenter or the other, or for some, on both. So as those discussions progress, we'll firm up the remainder.

All right. Could you give us a bit more detail about where things stand as far as bringing a partner on board? Is it probable that this will come together within the next several months, so that you can then offer a clearer view of what that '27 calendar year budget might look like?

Yeah, things are definitely progressing. We keep seeing robust interest from outside parties. The conversations we're having are with the appropriate prospective partners. At the end of the day, what we want is the right capabilities that align with the strategy, plus the right timing that fits the operations; so I understand the wish for certainty regarding the time line, but please be patient with us. Everything remains in play. And I'm certain everybody recognizes that transactions such as these require time and must be done carefully; so that process is underway. It will — whatever conclusion we reach on that, whichever partner we end up with, it will involve a defined workflow < > and returning to your first question, that will bring that capital program up to date.

I had a question about the further in-basin sand trials — you mentioned the next fracs are going to involve no fewer than 1 well. I just want to get this straight: are you guys at ease applying that throughout an entire well? Or is this going to be one more partial test? And then, maybe backing up a bit, how do you guys see the scalability of in-basin supply if you wind up with greater confidence there? How big a share of the program might that become over a longer horizon?

Yeah; so to begin, I'll sort of address the early performance. And as I said in the remarks, we had zero trouble pumping that sand, and that was one thing we were keeping an eye on. We kicked off the frac — started a frac well using it. So our confidence in being able to pump it is high. When we look at tracers returning from those stages, they appear the same as the remaining stages and the remaining wells; so the early results are good. But as with the production, we won't have the complete answer until we've got some production history here and can see how it holds up; so yeah, we're hopeful about what it can deliver. As for these X wells, we won't shift to a full Red Sand program before we're confident in it. So we need part of that history. Every well we drill out here matters quite a bit for helping derisk the basins. So we won't take disproportionate risk on any single one of them. So we'll add some stages on these upcoming completions, but full wells aren't happening yet at this point, Jeff. Down the road, once we have history on it, once we're at ease that the Betaloo Red Sand does what we expect and hope it will do, I could see us moving to a 100% full program at Red Sands, or basically 100%. There might be a few settlements here and there. But I think the ultimate aim is to use in-basin sand based on sand in the Betaloo, and from a low cost standpoint, that's clearly the right thing to do.

Yep, got it. That’s clear. As for my follow-up question, regarding the possibility of growing the SPCF, I believe you’d mentioned possibly reaching an investment decision next year. What are the milestones, or the key boxes to tick, so to speak, before you’d feel ready to make that call? Is it mostly about your confidence in your own internal producibility volumes, offtake financing, all of those things, or just any sort of checkpoints you can watch to keep tabs on that project?

Yeah. I’d say everything you just listed matters in < > it, though I actually feel quite good about each of those items you brought up. The thing we truly need to examine, and this is likely the main uncertainty about whether we grow it, is ensuring the infrastructure network nearby will let us transport the added volumes into the added markets, correct. Simply being highly confident that we can achieve that. We don’t own the pipelines surrounding us, and grasping how the gases will move and how those will be enhanced or altered as time goes on, will assist us in reaching the decision. So we’re currently working through that, sort of gaining a clearer picture daily, but that’s something we simply require certainty about prior to committing that sort of capital. We need < > that we’ll be able to...

Morning Todd, and hello to Eric, Chris, and everyone else on the Tamboran side. Todd, I'd like to revisit your choice to bring those 2 wells online first — or rather, I suppose, to give them priority — at an initial rate of 25 < > per day. It appears that accumulating additional production history across more wells ranks among the main near-term items you're after. So I'm wondering, could you tell us roughly when that 25 million a day will climb to the 40 million? I believe you mentioned this hinges on the SPCF being fully commissioned. Could you simply provide a timeline for when you'll be in a position to begin gathering more of that production history?

Yes. And Charles, so I'm certain I've got your question right: you're asking when we can reach — right now it's roughly 25 million, but when can we get up to the 40 take-or-pay?