Tamboran Resources Corporation (TBN) Earnings Call Transcript

Hello, and welcome to the Tamboran Resources conference call on the earnings release for the second quarter of fiscal year 2025. <<operator_script>> Please be aware that this call is being recorded. At this point I'm glad to hand things over to Joel Riddle, Chief Executive Officer. Thank you, sir. The floor is yours.

Thanks, and welcome everyone to the Tamboran Resources presentation of results for the second quarter of fiscal year 2025. I'm Joel Riddle, and I serve as Chief Executive Officer of Tamboran Resources. Eric Dyer, our Chief Financial Officer, is with me this morning. Before we dive into the materials, I want to point everyone to the disclaimer on Slide 2 regarding forward-looking statements. Turning to Slide 3 and the highlights from the last quarter. First, the company drilled and cased the SS-3 well successfully. That well featured a horizontal section spanning a full 10,000 feet and was drilled at 840 feet per day, a Beetaloo Basin record. Second, we finished the SS-2H well, pumping more than 35 frac stages and achieving record proppant intensity across those 35 stages. The company will aim for an IP30 flow test in April of this year. After the 30-day flow test on SS-2, we'll move to SS-3 to wrap up completion operations and target an IP30 flow test for SS-3 in June of this year. The company keeps advancing toward a final investment decision on the Shenandoah South pilot development project. During the quarter, we signed binding agreements with the APA Group to support building and constructing a 12-inch pipeline that links the SS pilot to the local 12-inch pipeline, moving gas from our pilot project into the local Northern Territory gas market, where we'll produce 40 million cubic feet a day across the next 15 years.

Initial gas from this project is still scheduled to begin in the first half of 2026. During the quarter, the company kept making solid headway on business development opportunities, including advancing a data center strategy that we would see as part of an expansion to our Phase 1 development. I'll go into more detail on this later in the presentation. And lastly, the company signed a nonbinding MOU with Santos, an ASX-listed E&P company, concerning progressing technical studies tied to the expansion of the Darwin LNG project. The company closed the quarter with a cash balance of $59.4 million. That follows receipt of an R&D grant of $6.2 million, and the company remains fully funded to deliver the IP30 flow test from SS-2 and SS-3 through the end of June of this year. Turning to Slide 4 and more detail on the progression of our Shenandoah South pilot development. As you can see from the map in the middle of the page, the company remains very focused on the 1-million-acre development area highlighted in yellow in the structure map on the left. As you zoom down into the middle of that 1-million-acre development area is our 6-well pad, where we've now drilled 2 horizontal wells.

These represent the initial 2 of 6 wells through which we expect to build out our 40 million cubic feet per day for this pilot development. As the image on the right shows, you're looking at a snapshot of the new Liberty equipment now sitting on site, which has been advancing completion work on our SS-2 and SS-3 wells. Once more, during the quarter, the company drilled the SS-3H well successfully to 21,169 feet, and that drilling was finished in 25 days. That works out to more than 840 feet per day in drilling performance, and it still stands as the fastest well drilled in the Beetaloo Basin to date. We geosteered the entire 10,000-foot horizontal section inside a 65-foot target. What we observed across that 10,000-foot horizontal well was a high-quality, contiguous Middle-Velkerri B shale and, most importantly, no faulting. The company began stimulation operations on SS-2 and SS-3 in January of this year. At SS-2, we completed 35 frac stages over the 5,500-foot horizontal section and set Beetaloo Basin records for average proppant intensity across those 35 stages. At SS-3, the company took precautionary, proactive steps to pause completion operations after detecting stress in a casing connection.

Work to remediate SS-3 is still underway, and our goal is to keep the stimulation program going into this year's second quarter. Broadly speaking, we're aiming for IP30 flow rates from SS-2 in April of this year and an IP30 from the SS-3 well in June of this year, weather permitting. Turning to Slide 5. Our drilling performance has kept improving substantially versus the last well we drilled during the quarter at SS-3. That well took 25 days to drill, averaging 843 feet per day. That is 43% faster than the SS-2H well. Referring to the table at the bottom of the slide, you can see the performance gains we've achieved at SS-3, mainly driven by the top hole through to the Moroak section, which historically took between 10 and 11 days to drill. At SS-3, we now drilled that section in under 5 days. And in the horizontal section, which took 17 days at SS-2, we managed to drill it in 12.5 days. Total drilling cost at SS-3 came to roughly $10 million, and the company has identified considerable cost savings that will drive additional reductions and boost drilling performance in our follow-on pilot development wells being drilled in this year's second half.

Turning to Slide 6. Among the most encouraging aspects of this year's 2-well drilling program is how consistent the geology has been in our 2 wells, SS-2 and SS-3, when compared with the SS-1 pilot hole located roughly 3 miles to the south of these 2 horizontal wells. Across the entire horizontal section, we have observed very consistent quality along with a very gentle, undulating structure, and no faulting has been observed. Beyond that, very strong gas shows appear across both horizontal sections, and we believe this will translate into very good productivity in our well test on both wells. Now on Slide 7, a summary of the stimulation campaign at SS-2 and SS-3. At our SS-2 well, we completed 35 stages using our new Liberty equipment that is currently on site. That was carried out across a 5,500-foot section, and we pumped a proppant intensity of approximately 2,700 pounds per foot. That is a 26% higher proppant intensity than what we pumped at SS-1H. And most encouragingly, in 18 of the 35 stages, we successfully executed the full Tamboran v2 design, pumping greater than 2,800 pounds per foot and pumping in at 90 to 100 barrels a minute. We also managed to achieve 5 stages a day for the single well operation on multiple days, and this is in line with U.S.

On the operational efficiency front, we are in the process of cleaning up the SS-2H well right now, before we start an IP30, and we will have a result from that to report to the market in April of this year. As for the SS-3 well, we took proactive, precautionary measures to carry out a remediation of a stress that was observed in a casing connection. We expect that remediation to be completed within the next 30 days, ahead of stimulation activities restarting in the second quarter of this year. We view this as a chance to take the lessons from the SS-2H well and apply them to raise efficiencies and place a higher proppant intensity across the 60 stages we intend to pump in SS-3. Our target is an SS-3 IP30 flow test result in June of this year. Turning to Slide 8, which summarizes the completion designs across Shenandoah South 1H, Shenandoah South 2H and Shenandoah South 3H. As you can see, we have had the opportunity to apply what we learned from the SS-1H well to our recent SS-2H well, which we refer to as our Tamboran v2 design. In this design, we pumped 35 stages at a little over 2,700 pounds per foot, and we pumped 90 to 100 barrels a minute. We are anticipating -- targeting IP30 flow test results of greater than 10.7 million cubic feet a day.

Once more, our goal is to hit that IP30 flow rate by April this year. The learnings from the SS-2H well can be applied to our SS-3H well, and that gives us a chance to fine-tune the Tamboran v2 design, where we expect to pump 60 stages at over 2,800 pounds per foot and over 100 barrels a minute. For the Shenandoah South 3H well test we expect in June, we're aiming at IP30 flow rates above 19 million cubic feet a day. Turning to Slide 9. We're still on schedule to deliver our SS pilot project in the first half of 2026. What we learn from our 2 wells, Shenandoah South 2H and Shenandoah South 3H, will determine how many wells we drill as follow-ups later this year, and those will feed into a binding gas sales agreement of 40 million a day for 15.5 years with the Northern Territory Government. During the quarter, we signed binding agreements with APA Group for a 12-inch pipeline connecting the pilot project to the local Northern Territory pipeline known as the Amadeus Gas Pipeline, which will bring this 40 million cubic feet a day to the local Northern Territory gas market.

We've also kicked off procurement for the 40 million a day facility. Approvals for our Shenandoah South pilot project will be wrapped up over the next few months, and that comes before a final investment decision we expect to make in mid-2025. Once again, the project is still on schedule to produce first gas at 40 million cubic feet a day during the first half of 2026. Turning to Slide 10. As I noted in my opening remarks, the company is examining a chance to grow our Phase 1 development by adding more gas supply that could support a data center strategy. The map on the left shows that Australia is turning into a major hub for data centers. Right now there are more than 200 data centers in Australia, and we think the Northern Territory can be a growth area for new data centers, thanks to the fiber optic cables already linking the Northern Territory with other parts of Australia and, even more importantly, with Asia Pacific. Those fiber optic cables pass roughly 30 miles from our Shenandoah South pilot project, and in our view that opens up an opportunity to pair gas from the Beetaloo Basin with energy for new data centers being built in the Northern Territory.

We’ve begun commercial talks with prospective partners about building several data centers in the Northern Territory, and as we keep advancing this strategy, we’ll provide further updates to the market. Turning to Slide 11. During the quarter, we also signed a nonbinding MOU with Santos to assess expanding the existing Darwin LNG plant that Santos operates. Under this nonbinding MOU, technical studies will be considered to examine developing new supply from the EP 161 permit we hold jointly and linking it to the Darwin LNG expansion, where we expect as much as 6 million tonnes of new LNG capacity to be constructed at Darwin LNG through brownfield expansion. We think this presents a really strong opportunity to potentially integrate that Darwin LNG expansion with our Phase 3 NTLNG development. Turning to Slide 12. The company finished the quarter with a cash position of $59.4 million. That figure includes $6.2 million the company received through an R&D credit during the quarter. The company is still fully funded to deliver IP30 flow rates for our SS-2 and SS-3 wells. In addition, Tamboran is assessing a range of options for funding the remaining wells in our SS pilot development and the associated infrastructure as well.

Beyond that, the company keeps looking at possible farm-out opportunities as a way to speed up our Phase 2 and Phase 3 developments. Such farm-out opportunities might involve drilling extra wells to help mature reserves that would support infrastructure connected to Phase 2 and Phase 3 of our business plan. Turning to Slide 13, you can see the upcoming catalyst beginning in March, when we'll start flow testing on our SS-2H well and aim for an announcement in April on our IP30 from this SS-2 well. After the SS-2 well test, we'll proceed to stimulate and flow test our SS-3 well, with a target of announcing the IP30 flow test results from SS-3 in June. In mid-2025, we'll aim to make a final investment decision on our SS pilot program, which will again target first gas from this pilot project in the first half of 2026. Thanks very much, and I'll hand the call back to the operator for our question-and-answer session. Thank you.

<<operator_script>> Kalei Akamine from Bank of America has our first question.

I suppose, to start, with the pipeline lateral, the pilot, the MOU, and this data center news, you all have been quite busy, and we like seeing that. My first question concerns the upcoming flow test, and maybe it has 2 parts. So for the first part, could you remind us why a gap exists between completion and the flow test? And second, could you remind us what the normalized flow test was for SS-1? And I guess what I'm getting at is when you consider your target for SS-3 at 19 million cubic feet per day, to us, that seems a touch conservative.

Much appreciated for that question, Kalei. To start with the first one, regarding the interval between when stimulation wraps up on SS-2 and when we conduct the SS-2 flow test: once more, we're currently cleaning up that well. We'll be running 2-7/8 inch tubing in the hole, and over the coming few weeks we'll be unloading the well. As soon as gas breakthrough occurs, our IP30 will get underway in early March. That schedule also incorporates a 10-day soak period, and we've included that soak because of what we learned at SS-1 — specifically, the extended shut-in that lets our completion keep generating super high <<inaudible>> inside the shale, which stems from the heavily desiccated mid-Velkerri shale into which our completion was pumped. And so that additional 10 days has demonstrated a direct benefit, based on our SS-1 well. That's why we're taking the extra time prior to kicking off our IP30 flow test. On the conservatism that's embedded in this, you're exactly right. If you take the productivity observed at SS-1 and extrapolate it across the full 10,000 foot of horizontal in SS-3, you get roughly about 19 million cubic feet a day.

That's really the direction we're pointing to. Clearly, since we're achieving greater stimulated rock volume by boosting proppant intensity — which we've been pumping for SS-2 and anticipate continuing to pump in SS-3 — there's a possibility we'll see rates higher than that.

Thanks for that context. My second question concerns the Santos MOU. From what we understand, Santos holds an interest in EP 161, where your company is the minority partner, and that differs from EP 98, which is where your pilot work is focused. So what I want to ask is about how broad the study is. Is their aim to de-risk EP 161 before proceeding? Or would de-risking your stake in EP 98 be enough for them to go ahead with the MOU?

Yes, that's a really good question. In the deepest portion of the basin, we observe that the rocks between EP 161 and the pilot area on EP 98 are quite similar. So there are 2 depocenters: one to the east, where the 161 block is concentrated, and the second major depocenter lies in the western part of the basin. We therefore have data from the most recent horizontal wells drilled on EP 161 in 2021, where we flow tested for more than 90 days on both of those wells. That information genuinely pointed us toward the SS-1 stimulation we pumped last year. So we perceive considerable symmetry between what we're doing under the SS pilot program and the number of pilot wells we're drilling this year — very similar to techniques we would be applying with our partner, Santos, on EP 161. In many respects, we can therefore derisk the EP 161 opportunity relative to what we're doing on EP 98. This forms part of cracking the code on the completion design. As for the DLNG expansion we're working on with Santos, I think we're likewise keeping an open mind regarding where gas could be sourced to supply that expansion train.

That will also be included in the study we're completing with Santos during this year.

So how do we go about reducing risk on 161 going forward? Which wells are they planning?

There's a chance for us to put down more horizontal wells during 2026. Right now, we're talking about drilling 2 horizontal wells on EP 161 in 2026. And we're hoping to lock in that work program sometime this year — ideally by midyear.

Thanks, I appreciate that.

The main point I'd like to stress is that getting our partners involved right from the start matters a great deal, so that when we consider a Northern pipeline linking the Beetaloo to Darwin, we pursue it together with every operator in the Beetaloo. That is really part of Tamboran's effort to bring Santos into their expanding LNG development. And clearly, when we look at NTLNG, we see substantial opportunity for integration.

Scott Hanold from RBC Capital Markets has our next question.

Could you give us a bit more detail on some of the stress detection you found in the casing? Just a little background there. Was it mechanical or reservoir related? And from your talks with your service providers, have they come across that in other places? Or is it more a matter of getting to know the Beetaloo?

Yes. Excellent question, Scott. What we're dealing with here is a mechanical problem that the company picked up on as we were exiting the hole in the vertical portion once the fifth stage had been pumped on SS-3. A stress anomaly was detected, so after halting the stimulation work, we went back in with a camera and an acoustic tool to obtain improved detail on the nature of that anomaly. And in the interest of being overly careful, we made the decision to strengthen that section while, at the same time, carrying on with stimulation on SS-2 and proceeding toward a well test there. Once the well test at SS-2 wraps up, our expectation is to return to SS-3, pump the 60 stages still remaining there, and obtain a flow test in June. That's how we intend to proceed. What this gives us, then, is a chance to capture the learnings from SS-2 — on the completion side as well as what the flow test reveals — and apply them to the 60 stages we plan to pump on SS-3. One point I want to emphasize: none of this relates to the reservoir. It's entirely mechanical in nature. Issues of this sort occur every day of the week across the Permian, Marcellus, and Eagle Ford in the U.S.

The service providers advising the company on this matter are extremely experienced and knowledgeable, and we don't think this is a problem we could resolve with high confidence. Once again, we're keeping a sharp eye on safety. We're keeping a sharp eye on attention to detail. And so, when we noticed this slight anomaly, we concentrated on figuring out where it was coming from in the vertical section and sought to remediate it. So that should give you a little bit of color.

All right, and thanks for that added detail. So my follow-up really concerns the stimulation work overall. I realize you may have ramped up activity on the frac side somewhat beyond what you first envisioned, and perhaps pulled back when it came to the final decision. Could you walk us through part of the reasoning behind the differences between a few of the initial plans and the way you intend to frac this? Does it come down to service availability? Is timing the factor? Or is it your view of what the reservoir is able to handle? Just share a bit of detail on how you arrived at that figure and why it has shifted somewhat in both directions?