Tamboran Resources Corporation (TBN) Earnings Call Transcript & Summary

Hello, everyone, and thanks for joining us for the Tamboran Resources earnings presentation covering the first quarter of Financial Year 2027. I'm Todd Abbott, and I serve as Managing Director and Chief Executive Officer of Tamboran Resources. Joining me on the call are Eric Dyer, our Chief Financial Officer, and Chris Morbey, VP of Investor Relations and Corporate Development. To start things off, I'll walk you through the investment highlights for Tamboran and describe where we sit on the path toward a critical, disciplined approach to de-risking our Beetaloo Basin development. Following that, I'll go over the highlights from the quarter, recent performance from the pilot project wells, and upstream activities across our acreage in the Beetaloo Basin. I'll then take you through our strong balance sheet and wrap up with the upcoming development milestones before we open the line for questions. On slide two, there's a disclaimer about forward-looking statements contained in the presentation, and I'd suggest reviewing it when you have a chance. Then on slide three, I'll begin by explaining why we see Tamboran as a compelling investment. We're methodically reducing risk across one of the biggest undeveloped gas projects anywhere in the world. It all begins with the rock. Our latest flow test results keep reinforcing the strong performance and deliverability we've shown throughout the Beetaloo Basin so far. I'll go into more detail in a moment. Tamboran's acreage position in the Beetaloo Basin is the largest, at 2.8 million net prospective acres, which accounts for most of the basin's prospective area. Multiple stack benches sit on our acreage in two main depocenters, which provides us with a number of targets to delineate in the years ahead; no other operator in the basin has our level of experience. Our team has worked in the Beetaloo Basin for more than ten years and has supervised the drilling and stimulation of 11 horizontal wells, far more than any other operator; we have now become a production company. Initial gas sales began in September 2026, which fulfilled the promise we made 12 months earlier. Beetaloo Gas is now helping to keep the lights on in Darwin. On a take-or-pay basis, the pilot project has 40 TJs per day of gross volumes contracted to the Northern Territory Government at a fixed price that escalates with CPI; this provides us a stable revenue base as we grow the resource. Lessons from the U.S. shale industry are being brought to the Beetaloo by our partners. All three — Helmerich & Payne, Liberty Energy, and Baker Hughes — are strategic partners. Specialized equipment and expertise to support basin development are what they bring. Each of these companies is also a shareholder in Tamboran, and that alignment matters; the scale of the opportunity is something they see, and they have backed it with their own capital. You can't develop any basin without a market, and we have three attractive markets available to us, and each one trades at a premium to the U.S. Henry Hub price. We're committed to supporting the nation's energy security. Outside of Australia, we're well-positioned to serve growing Asia-Pacific energy demand through potential future international LNG exposure. Beetaloo Gas sidesteps the pinch points. That gives certainty of supply to Australia's largest trading partners, while also delivering royalties and jobs to Australians. And finally, we have a team with a proven record. The experience our board and management bring in operations and commercialization runs deep, and they have a track record of unlocking large-scale shale developments. I've had ties with the board going back many years, and those ties rest on trust, and I feel confident about where we're headed. If you move to slide four, I'd like to pull back from the quarter and explain our view of how the Beetaloo Basin gets de-risked across the coming years. Our plan consists of four phases, and the design of each is to de-risk the one after it prior to our committing capital at scale. Phase one—showing subsurface deliverability and putting U.S. learnings into practice—spanned 2023 through 2026, and that is what we have accomplished so far. Extended flow testing is now underway at the Shenandoah South pilot project, and with initial gas sales flowing into the Northern Territory market, we're already seeing early cash flow that helps support our balance sheet. At the same time, we're assessing nearby markets for additional output and revenue, drawing on what we've learned in the U.S. to show how well deliverability works, and testing locally sourced sand as a way to cut costs down the road. Phase two, spanning 2027 and 2028, centers on delineating the resource and identifying commercial pathways. Expanding the resource is the foundation for building out infrastructure from the Beetaloo Basin, and we'll pursue that through disciplined capital allocation. Together with our key partners, we'll concentrate on our core acreage across both the western and eastern depocenters. There's also an opportunity, in our view, to apply what we've learned from EP 161 across the Andromeda and Maverick acreage we operate. We're looking at adding production in stages to serve the NT and Mount Isa markets. On top of that, we expect to gain more certainty about how local sand performs, and if that pans out, it may help us achieve reduced development costs over the long term. At the same time, we intend to push forward with commercial negotiations covering LNG gas sales as well as transportation agreements. Phase three — development and efficiencies — spans 2029 through the early part of the 2030s. Once the project is sanctioned, activity will expand substantially as we construct production capacity and transition to continuous operations; reaching those continuous operations is essential if we are to cut costs down to the levels we've targeted. Starting in the mid-2030s, the fourth phase focuses entirely on how we allocate capital. We'll optimize operations throughout our producing assets as we work toward becoming the basin's lowest-cost producer. Every phase comes with clear success measures, and I'll rely on those to update you on our progress as we work through this plan. Turning to slide five. This quarter, Tamboran achieved a first: no other company in the Beetaloo Basin has produced and sold gas, and ours now serves the domestic Northern Territory market. We sold 310 million cu ft of net gas to the NT government, which works out to Tamboran's net share of 24.8 million cu ft per day. Production was constrained because of Northern Territory nominations along with anticipated downtime for commissioning. Revenue from gas sales totaled $1.8 million, and the realized price came in at 75% of the level set by the gas sales agreement. Tamboran expects to enter the take-or-pay period under that contract and to realize its full price during the first quarter of 2027. Work on commissioning the Sturt Plateau compression facility continues, and the facility has performed very well. As of the end of October, it had met 98% of the nominations we received from the Northern Territory Government. That gives us confidence in how the plant is operating. Results from the wells continue to confirm what our earlier testing showed. I am pleased to report that the SS2 wells are demonstrating better deliverability and limited decline as they clean up. The following test is whether those rates persist across a longer stretch, and slide six contains a fuller walkthrough of these results; the three-well drilling program on the SS1 pad has also been completed. Gas for backfill at the Sturt Plateau compression facility is to be supplied by these wells. That provides additional backing for the 40 TJ per day contracted to the Northern Territory Government through 2027, and slide seven will address that program. A two-well appraisal program on EP 161 in the Beetaloo East depocenter has been commissioned by Santos. Our interest is 25% and non-operated, and Santos serves as operator.

We have finished drilling the pilot hole and have logged every Velkerri formation. The results matched what we expected. If this proves successful, it will lower risk further on our nearby Andromeda and Maverick acreage, which we operate and in which we hold a majority interest, and it will support infrastructure build-out in the Beetaloo East depocenter. Our strategic partnership process moved forward during the quarter. It is competitive, with several parties that would be strong, credible JV partners. As I have stressed before, the most important thing is getting the right outcome for long-term shareholder value. At quarter end, we held $180 million in cash, plus capital we expect to bring in soon, including $15 million of near-term inflows tied to the acreage sale to Daly Waters Energy, which is still subject to certain conditions precedent. Turning to slide six. In September, we began long-duration flow testing on the SS2 pad wells, feeding gas into the Northern Territory gas market. The early rates confirm the deliverability observed in earlier tests, and these results strengthen our view that declines stay comparatively modest while the wells continue cleaning up. The first results from the 2H well have us truly excited, because we believe they show what these wells can produce once cleanup is finished. After being shut in for a year, that well has produced considerably better than it did during the initial 90-day flow period. When we reopened it, there was very little water flowback, and it delivered an average rate of 10.2 million cu ft per day across 720 hours of interrupted production. Normalized to 10,000 ft, the 2H well achieved 18.4 million cu ft per day, which aligns with the original SS1H well, and we now have two data points showing considerably higher deliverability once stimulation water has been cleared from a well. The 3H and 5H wells delivered average IP30 rates of 8.8 million and 10.0 million cu ft per day, respectively. Since these wells are longer, cleanup naturally takes more time, as the stimulation program used more water. They were not soaked the way earlier IP tests were. Immediately after stimulation, they were tied directly into the Sturt Plateau compression facility. Each well still produces 300 to 500 bbl of water per day while maintaining fairly high bottom hole pressures. That indicates additional productivity as cleanup continues. In terms of the cleanup phase and pressure, performance is consistent with what we saw before. Our subsurface work suggests that well deliverability rises materially as water from the stimulation program is recovered or imbibes into the formation over time. Although it is early days, the results are encouraging. Using these initial figures, Netherland, Sewell & Associates (NSAI) has calculated a P50 EUR of 17 Bcf for each 10,000-foot lateral. The SS2 5H well, meanwhile, had 10 stages fractured using local Beetaloo Red Sand. So far, deliverability has not suffered from the local sand, and our confidence keeps growing about using it in future wells. With a 10,000-foot lateral, using local sand instead of imported sand could save about $4 million for each well. The real test will come from longer-term flow rates, but every result we get lowers the risk on two economic factors that matter to us: how productive the wells turn out to be and what the completions cost. Moving to slide seven now. Looking at our Shenandoah South pilot project, you'll see meaningful progress both on the facilities side and in our upstream operations. Starting with the Sturt Plateau compression facility, construction is complete and it's running about $10 million under budget. We're in the middle of fine-tuning that facility during commissioning, and we're targeting completion in the fourth quarter of 2026. In the first quarter of 2027, we expect the take-or-pay gas sales agreement with the Northern Territory Government to kick in. That agreement supports revenue of 40 TJs per day regardless of nominated volume. It gives us a steady revenue base as we keep working to build resources across the basin. On stimulation, we finished a record-setting campaign on the SS2 pad. Zipper fracking took place on the SS2, 3H, 4H, and 5H wells, spanning 178 stages over more than 30,000 stimulated feet. That count includes the 10 local-sand stages in the 5H well. The 3H and 5H wells delivered average IP30 rates of 8.8 million and 10.0 million cubic feet per day, respectively. We also completed the three-well drilling program on the SS1 pad. For the SS1 4H and 6H wells, we drilled usable laterals of 9,329 ft and 9,505 ft, respectively. At the SS1 2H well, a downhole problem came up after we'd drilled a 12,631-foot lateral section, and that required a sidetrack. The sidetrack was successful, with a 10,000-foot usable lateral. Drilling results on that pad were strong, but the sidetrack shows we're not yet achieving that level every time. Replicating our best well across all wells is the next benchmark for success. Since earlier wells came in within budget, the three-well program stays within the contingency CapEx budget. Taken together, these outcomes demonstrate that we can deliver facilities on schedule and below budget, run larger completion programs, and handle operational issues while keeping costs in check. We'll need those capabilities as we enter the next development phase. On slide eight, our balance sheet is still solid. We closed the quarter with $165 million in cash. There's also another $15 million that Daly Waters Energy owes us from the acreage sale, and collecting that depends on certain conditions precedent being met. Most of the cash we spent this quarter went toward four items: drilling and stimulation on the SS2 pad, drilling on the SS1 pad, drilling within EP 161, and construction of the Sturt Plateau compression facility. During the quarter we drew an additional $7 million from the SPCF debt facility, bringing total drawings to US $37 million net to Tamboran. One accounting reminder: until we sign the take-or-pay contract, revenue and costs from the pilot project get capitalized on the balance sheet rather than running through the income statement. Doing this means reported numbers don’t jump around, and cash movements in the period don’t show up on the income statement. Turning to slide nine. During the last 12 months, we reached FID on the Shenandoah South pilot projects and wrapped up the purchase of Falcon Oil & Gas; on top of that, the 3H, 4H, and 5H wells on the SS2 pad were drilled and stimulated with no problems. The SPCF was built on schedule and came in under budget. Part of the Pilot Area and the Beetaloo Central Development Area was farmed out to DWE, and we booked our first gas sales. Every one of these milestones has cut risk. What comes next is demonstrating the resource’s scale so it can support the infrastructure build-out. Through 2027, our focus will be on appraising resources across the whole basin. We expect drilling and stimulation activity to increase substantially in both core depocenters. All operators are busy growing the resource base that infrastructure will need. Output results from the pilot project are confirming how we understand the wells, which bolsters the case for new infrastructure. Turning this activity into booked resource is the next measure of success. Growing the resource is what makes new infrastructure viable. The 3H and 5H wells delivered average IP30 rates of 8.8 million and 10.0 million cubic feet per day respectively. Alongside the drilling, we are advancing commercial talks on gas sales and transportation. Those talks are meant to set a path toward new pipeline infrastructure that would link the Beetaloo Basin with multiple markets.

To wrap up, I’d like to express appreciation to every Tamboran employee for the dedication and performance they have shown during the past year. We’re eager to share another update on our next earnings call, and on that note, I’ll turn things over to the operator so we can take questions. Thank you.

Yeah, thanks a lot, guys, and congratulations on the strong results — they look quite impressive. I mean, with the 3H and 5H wells, it seems the pressures are holding their nice declines; they're holding up. So I guess my question would be, what would the next steps be — the commissioning steps — to get to the take-or-pay contract? It seems like at this point you should have confidence in the well performance, but what are those next steps you need to clear in order to reach that full contract price?

Yeah. Hey, Scott, how are you doing? Thanks for the question. I'll kind of cover two things, just to be clear, so we're not mixing terms. When I say commissioning, I tend to use that as a facility term. We're now in the last phases of commissioning; a performance test will be run on it shortly, and at that point the facility will be more or less fully operational. But what I believe you're actually getting at is the timing for the take-or-pay contract; we included it in the presentation, and you likely caught the remarks there, and we're indicating the first quarter of 2027. And the real gating item for that is our desire to have these next three wells completed and tied in, frankly as a belt-and-suspenders approach to redundancy. The Northern Territory Government cares deeply about this, and our goal is to be as dependable as possible in that area.

Understood. Yeah, my apologies for that. Yeah, so the commissioning work on the 200 is underway, which is obviously one of those things where you need confidence, but really it comes down to having confidence that you can meet the take-or-pay contract when asked, and it sounds like those wells would then do that, is what I'm hearing from you. Okay, appreciate that; and then.

Yeah, and sort of having a high level.

My apologies, please continue.

Sorry about that, I didn't intend to speak over you. I was only saying that we simply want a high level of redundancy there, but apologies, I spoke over you. Please go ahead.

No, no, that's fine. Everything's good. For my second question, what have we learned and what does it mean from that Santos well that was drilled? It looks like they were quite encouraged not just by the A and B zone, but it seems they were especially encouraged by the C zone. Could you discuss what that implies and how it might move forward your view of what's possible on your acreage throughout the Beetaloo?

Yeah, good question. I think as we look through both the public information they've released and what they've told us as a non-op there, the logs line up very well with what we anticipated finding there. The B shale is quite strong. We do believe the B shale is still the main target there, and we also think the C shale has a lot of prospectivity, and that came as no real surprise to us either. Look, you've got stacked pay there. Frankly, there's stacked pay on both sides. I don't want to suggest there were just no surprises, but that's genuinely what we expected to encounter there, so it's good to have that confirmation in the data.

Thanks for that. I appreciate it.

Sure thing, Scott. You take care.

Hello Todd, and hello to everyone on the Tamboran team. I'd like to pose a question

Charles, how are things with you?

I'm doing fine, thanks. You gave us what I think was maybe two sentences during your prepared remarks about the JV or the farm-out process, so I was hoping you could revisit that and perhaps flesh it out a bit more. On that point, looking at slide nine, you've laid out these 12-month catalysts, and they're roughly in chronological order. At the top of the list sits progress on the strategic joint venture. Am I right in guessing that's a deliberate signal that this will be the first of these catalysts to materialize?

Scott — sorry, Scott, you're not, I've still got Scott on my brain. Charles, you're not letting me down at all. That's a completely fair question. Let me begin by saying we share and understand the excitement surrounding the JV. Absolutely. I'll pull it up for a moment and perhaps state what's obvious, which is that as the basin de-risks, interest has kept growing across all of this. It won't surprise you that we consider many different kinds of options open to us, and these aren't mutually exclusive. I'd put the JV in there, along with infrastructure partnerships and capital solutions, and we evaluate all of it through the lens of shareholder value. I won't comment on specific counterparties, and I won't comment on a timeline, but what I will tell you is that those conversations are active, and they involve counterparties who are credible, who have significant capital capability; they bring technical expertise and/or market access; that's probably about as much as I can say on it at this point, Charles.

Fair enough. For whatever it's worth, somebody said, "Hey, look." Someone told me, he said, "Hey, look, that's first on the list. Does that mean it comes first?" I was like, "Well, maybe." That's a good question. I want to circle back to the 2H well — honestly, I'd call that the strongest technical item in the release, though it's really just one more turn in this ongoing puzzle over what actually makes these wells perform. I believe you provided a figure of 720 over 30 days of interrupted production, so that one has been among those swing wells. The encouraging part is that this essentially brings you back into the ballpark of 20 million IP from a 10,000-foot lateral, which places you in the A class relative to U.S. onshore and conventional plays. What's your best estimate here? When you shut this well in a year ago, was it still making water, and now that you've reopened it, they're done? How much water? My understanding is that this is a dry formation with no formation water. I'm curious whether, compared with your U.S. onshore experience, Tamboran has been pumping more water into the fracks on this formation, and that's the reason it's taking them longer to unload? That's guesswork on our side and I've gone on too long about it, but could you address it anyway?

Yes. I'd say it fits with our thesis about how we've described the Velkerri B shale — really the entire shale interval there for the Velkerri. First, to answer that question, Charles: there's no formation water present. What we're recovering from this is load water that comes through the frack. If I remember correctly, we produced that well for roughly 90 days. During that stretch it was putting out — Chris actually has some figures pulled up there — between 40 and 70 bbl of water per day. Okay, so there was a bit of water showing up toward the end there, but we were essentially reaching the conclusion of that cleanup phase. I believe this provides additional support for our view of what's going on: while we're still recovering water, that limits how well we can establish connection with the reservoir; however, with time—whether that water gets produced out or the well is shut in, as it migrates into the reservoir and away from the wellbore, and once the well is linked to the reservoir—you can genuinely observe the wells' true capability. What's really encouraging is that an IP can't necessarily reveal that while you're still drawing water off the well. But over time, as these wells produce and as they dry out, you ought to observe a stronger link to the reservoir and better performance. We believe that accounts for the very shallow declines we've observed across those wells. So as we bring these wells online and that water continues to migrate away — that dynamic happens whether we're flowing them or they're shut in — you wind up with a better connection to the reservoir, and you'll see improved production rates. Once again, we think that's consistent with the thesis we've put forward out there. Having two data points now that demonstrate that kind of evidence is a good thing, since it tells us the first one wasn't an anomaly; our expectation is that over time, as we produce these remaining wells, that will help prop up that decline rate, if you will, as we become better connected to the reservoir while that water keeps coming off. Because the two wells we've prioritized, the three and 5H, are still putting out a fair amount of water. One is making 300, and the other is making 500 bbl a day. That has an effect on what we're observing in the reservoir and on the bottom hole pressure down there. We truly can't pull out everything we're capable of; with those wells, we aren't really seeing yet what they can do. But I'm with you — that 2H is exciting.

That's really helpful detail. Thanks for that, Scott.

It's no problem at all. And my apologies for using the name Scott.

No problem at all.

Hello there. I was hoping to get a slightly clearer picture of gross sales volumes. From what I recall in your most recent update, you mentioned being able to sell 25 million a day. Are you still pretty much right around that figure? Has it increased at all? Or do you figure it won't increase until those next three wells come online during the first quarter? I just wanted some sense of the overall volumes you've been selling on a gross basis.

Yes, Leo, the volumes you will see us selling are really set entirely by what the Northern Territory Government nominates. Most of the time, we don't even have all five of our wells running. Typically, checking some of the data Chris Morbey is bringing up here, 39.4 recently. You will see that fluctuate. The Northern Territory Government determines what they require from our wells according to the demand they are forecasting in the Northern Territory for power and any other system constraints they have; so, when that goes up and down, it's the nominations rising and falling, not how much the wells can deliver.

All right, thanks for that. I'd also like to ask about the 3H and 5H wells — have they mostly been producing through this entire period? Since roughly early September, when you got production going, have those essentially been steady wells the whole time? I see only the IP30 shown, but I wasn't sure whether there's more history available on them. And also, if those wells have produced over a longer stretch, perhaps beyond 30 days, has any pressure drawdown occurred, or has the pressure stayed fairly steady?

Yes, so those wells came online — as you'd expect, when we first bring wells on, we're cleaning them up and bleeding off initial pressure on quite a few of them. The 3H well's IP30 began on September 13th, and the 5H well's began on September 18th, just so you have a sense of how long they've produced; so more data is coming in now. Yes, look, those are the two wells we prioritized there. The most valuable part — apart from production and cash flow, which always matters greatly to a business — the most technically valuable part is simply obtaining that long-term production history. So for us, we chose those two wells to prioritize above the others and let the remaining wells come on and off as nominations shift. Those two we prioritized to stay online continuously so we can build this production history. So they've flowed the vast majority of that time. Yes, as with any well, while producing them you'll see pressures decline. We're still not at bottom hole pressure, where we'd really be drawing on the reservoir yet. That was the point made with Charles; we're still making substantial water from those wells. So we need to remove more water from them before we can truly reach bottom hole pressure and really see what the reservoir can do once we're connected to it.

All right. So, I suppose — have you — I mean, I take it you've essentially been telling us those wells are nearer to 60 days, even if certain days saw somewhat lighter curtailment or something like that. Has there been any meaningful drawdown on the rate, or has it held fairly steady across that approximately 60 days for these 2 wells?

The short answer is that the data is fairly steady; we have kept those wells online, and the data is fairly steady.

Alright, the last question from me concerns your CapEx. It looks as though it came in perhaps somewhat hotter than folks had anticipated this quarter. Would you expect that CapEx to keep going at a roughly similar run rate as we move into Q4, or do you believe that figure will come down?