Hello everyone, and welcome to Tamboran Resources financial year 2026 second quarter earnings presentation. My name is Todd Abbott and I'm the Chief Executive Officer of Tamboran Resources, and I'm joined here today by Chief Financial Officer Eric Dyer and VP, Investor Relations and Corporate Development Chris Morbey.

In January '26, following an external process, the board appointed me as the new CEO, and I'm truly excited for this opportunity to lead Tamboran and the Beetaloo Basin into the next phase. We have a great management team with deep experience and a board of directors with a track record of creating large value over their careers.

I have long relationships and deep trust with the board, and I'm confident in our path. I look forward to working closely with all stakeholders, including native title holders, Northern Territory Government, pastoralists, and shareholders to deliver what I believe has the potential to be a world-class unconventional gas project.

Before I start the review of the second quarter earnings, I'd like to acknowledge the great work done by Dick Stoneburner as interim CEO. Dick guided the company through some critical milestones, including the Falcon merger and the largest drilling campaign in the Beetaloo Basin.

He is one of the best in the business and we couldn't have a better chairman, thank you, Dick. With that, let's get started.

Moving to slide two, you can see our disclaimer which relates to forward-looking statements within the presentation. I encourage you to review that at your leisure.

Then on to slide three. The second quarter of fiscal '26 has been another period of progress for Tamboran, as we delivered on key milestones and approached first gas sales from the Beetaloo Basin during the third quarter of this calendar year.

Following the completion of the drilling of the two-well program in October '25 using the H&P FlexRig 3, the team successfully delivered the largest stimulation program to date in the Beetaloo Basin, achieving 58 stages across a 10,009-foot horizontal section within the Mid-Velkerri B shale. The stimulation activities were completed using the Liberty Energy frac fleet, which Tamboran mobilized to the basin in 2024.

We conducted an initial flowback, and now the well is currently shut in and undertaking a 60-day soaking period. We had originally planned a 30-day soak period, but after further consideration, we'll undertake a soak duration in line with the SS-2H ST1 well.

Construction activities on the Sturt Plateau compression facility continued during the quarter, with the project approximately 80% complete at the end of January. During the quarter, key contracts were awarded for the electrical work.

The project remains on P50 budget and on track for first gas in third quarter '26. The Australian Pipeline or APA Group continued construction of the Sturt Plateau Pipeline.

The line is now in the ground, with strength and hydrotesting activities successfully conducted in January, and the pipeline now ready to take gas. I want to thank APA for their tremendous effort in delivering the SPP on schedule and below budget, and look forward to continuing to build the relationship.

We're now gearing up to commence our '26 Beetaloo Basin operations, which will be our most active year to date. The program includes stimulation of the remaining three wells required to deliver the 40 million a day plateau rate ahead of the commencement of initial gas sales later this year.

We're also planning to drill two wells with our partner, Daly Waters Energy, on the SS-1 well pad to the south of the SPCF. Tamboran will be acting as operator on behalf of DWE, and the wells are planned to be stimulated in second half of '26, subject to performance of the initial wells.

We'll also be participating in two wells in the Beetaloo East acreage, EP 161, via our 25% non-operating partnership with Australian E&P Santos. The two wells, Jibira South 1H and Newcastle South 1H, are both 10,000-foot commitment wells and are positioned to delineate additional gas resources in the eastern depocenter.

Santos has contracted the Ensign Rig 971 to undertake these activities. Additionally, we are continuing to progress the farm-out process, but we will not go into much detail on the call just given the commercial sensitivities and the phase that we're at.

Finally, we ended 2025 with cash balance of $91 million US and a drawn debt of $16 million US associated with the construction of the SPCF. Since the end of the year, Tamboran received $32 million US following completion of the pipe in January, and expects to receive another US$15 million related to the acreage sale to DWE.

Moving to slide four, I want to touch on the investment highlights, which is a key reason I'm so excited to take on the CEO opportunity. First, scale.

Tamboran sits on 2.9 million net prospective acres across one of the largest unconventional shale projects in the world, including large positions over both the Beetaloo East and West depocenters. The acreage position includes up to four high-quality benches across the basin, with over 16,000 drill locations.

Second, well results are showing that initial flow rates indicate comparison to the Marcellus shale in the US, and what we are starting to see is the Velkerri B is showing its own distinct character, indicating shallower declines as the well continues to clean up over the 90-day flow testing. The Beetaloo Basin is also connected to three highly attractive gas markets: the NT local gas market, which we will be producing into later this year; the Australian East Coast gas network, which is trading at multiples to the long-term Henry Hub price; and the Asia LNG market, which is the largest growing demand center for gas in the world.

Tamboran is nearing production, which is going to be a huge milestone not only for the company, but for the stakeholders in the Northern Territory. Our first production from the Beetaloo Basin will provide local supply of energy to the NT, which is powered predominantly by gas, and it will also deliver royalties to the native title holders and to the Northern Territory Government.

We are nearing completion of the acquisition of subsidiaries of Falcon Oil & Gas, which will consolidate Tamboran's interests across the entire Beetaloo Basin, and further de-risk the execution of our development plan. Moving to slide five, '26 is just the first step in Tamboran delivering significant production growth into the three markets I highlighted earlier.

This year, we will be focused on stimulating the three remaining wells and completing the construction of the SPCF to deliver first gas sales to the Northern Territory Government. We will be drilling two backfill wells on the DWE-operated Southern Pilot Area during the first half of 2026.

The reason for drilling these wells ahead of production is a risk mitigation strategy and provides viable gas behind the pipe that will be used to increase volumes over the 40 million a day. We'll also look to progress our Phase 1 expansion project via the commencement of concept select studies.

The project will evaluate the potential for an expansion of the SPCF to approximately 100 million a day, and deliver additional volumes through the Northern Territory Government gas market and Mount Isa. We will also be participating in two commitment wells with Santos on EP 161, where Tamboran is a 25% non-operating owner.

The two wells are planned to delineate additional resources in the Beetaloo East depocenter, as Santos are evaluating delivering to the East Coast gas market and into the Gladstone LNG project in Queensland. Finally, we're progressing the farm-out on our Phase 2 development area, targeting carried wells during the '26-'27 drilling campaigns to delineate resource and to underpin a new pipeline.

As I said, this will be a year to lay the foundations for growth, including a material step-up in drilling activity that aims to deliver reinvestment and accelerating a range of production opportunities. Moving to slide six, during the quarter, Tamboran completed the stimulation of the SS-6H with 58 stages across 10,009 feet within the Mid-Velkerri B shale.

During flowback, an impediment was identified at approximately 8,600 feet along the horizontal section. We're evaluating if the impediment has the potential to block any of the flow from the last 14% of the section.

We are all interested in the local in-basin sand opportunity, which is a material initiative to reduce well costs long term. We did not get to effectively deploy the local sand during the '25 campaign due to being unable to wash and dry the quantities required.

We do plan to test stages during the '26 campaign. Moving to slide seven, as I highlighted earlier, DWE are planning to drill two wells on their operated Southern Pilot Area acreage during the first half of '26.

Tamboran will act as the agent operator during the period, undertaking the activities on DWE's behalf. The two wells are planned to be tied back to the SPCF on the SS-2 well pad and backfilled into the NT Government gas contract.

Both Tamboran and DWE expect to be equal equity partners on the South Pilot Area at 50%, following the completion of the Falcon transaction and acreage swap with DWE. Now moving to slide eight, construction activity on the SPCF continues along our P50 schedule and within the forecasted budget.

At the end of January, the project was 78% complete and is on track for commissioning during the third quarter of 2026. Just a reminder that the remaining capital spend is being funded from a US$118 million facility with a consortium of lenders.

Tamboran and DWE also commenced the divestment process of the SPCF during the quarter, with binding agreements for the sale on track for first half. Tamboran and DWE will toll volumes through the SPCF under a long-term gas processing agreement, and on the sale of the SPCF, we expect to release our full $50 million in equity that is currently held in the facility.

Moving to slide nine, APA have done an incredible job in progressing the SPP. With the construction, strength testing, and hydrotesting now complete, the pipeline will shortly be tied into the AGP and be ready to receive gas from the SPCF once complete.

Tamboran and APA have commenced discussions to expand the pipeline to support the SPCF expansion project. Moving on to slide 10, Tamboran's JV partner in EP 161, Santos, are planning to drill two permit commitment wells, Jibira South 1H and Newcastle South 1H, during the third quarter.

The wells will target the Mid-Velkerri B shale as follow-up wells to the Tanumbirini wells drilled and flow tested in '21 and '22, and delineate additional resources in the Beetaloo East depocenter. On to slide 11, you can see that following the completion of the public offer, share purchase plan, and pipe, we are well positioned to fund our pilot project to initial gas sales in third quarter '26.

At the end of the quarter, we had US$91 million in cash on the balance sheet with near-term cash inflows of US$47 million. The company received US$32 million relating to the pipe transaction following the shareholder approval in January '26.

We also expect to receive US$15 million from the acreage sale to DWE once we meet certain conditions precedent on the checkerboarding of the acreage. At the end of '25, we had drawn debt of US$16.3 million relating to the facility to finance the construction of the SPCF.

US$42 million net to Tamboran remains undrawn. As mentioned earlier, we are currently tracking towards the P50 forecast, we have ample capacity within the current facility.

We also continue to progress research and development rebates for fiscal '24, '25, and '26 that could, if approved, provide incremental cash flows. Moving on to slide 12, you can see we have a very busy year ahead of us as we progress towards initial gas sales in mid-2026.

I touched on many of these catalysts already, I will not delve into these again, but I'm truly excited for the future of Tamboran in the Beetaloo Basin. I want to thank all of our stakeholders, from the native title holders, the pastoralists, Territorians, Northern Territory Government, and our shareholders for your support.

I look forward to meeting many of you over the coming months. With that, I'll hand it over to the operator for questions.

Thanks. Good morning, good afternoon.

Todd, my question is, just with regards to your background. Obviously, you've had experience in the US and many of shale.

Can you give us a sense of how did you view this opportunity for working at Tamboran? How is some of the work that you've done in the past applicable to what you see in the Beetaloo?

If you could talk about some of the challenges you might see and some of the upside opportunities you see based on your prior work?

Thanks, Scott, happy to go through it. Look, I would say first I've had the opportunity to work in some really great positions over the course of my career.

Maybe for context, I've spent about half that time in finance, capital markets, and about half that time in operations. If I go back, I'll kind of focus more on the operations side maybe as we talk about the Beetaloo.

I think about my time running the Alaska operations at Pioneer. That kind of teaches you how to work in remote, logistically challenged environments.

Certainly the importance of working alongside native title holders and finding ways to meet true and mutually beneficial outcomes. I think about the time in the Permian.

When I was there, it was when the horizontal shale play was just taking off. Launching kind of a new play, admittedly there, that was in a fairly well-established basin.

When I started there, we were just bringing horizontal wells on production, and when I left, that was certainly the norm, and building a lot of momentum there. Eagle Ford, Marcellus, Utica, all great shale developments.

There, most of those jobs were about capital discipline, efficiency, and really very important for kind of where we are here in the Beetaloo, learning from every data point, learning from every well. When I think about maybe challenges or upside that I look at here, we've got a great team, we have great rock, we certainly believe in all that.

What we've got to do here is drill great wells. Back to what I was talking about with the Eagle Ford and the Marcellus and Utica, it's using every data point we have, making sure that we understand what we're doing, tweaking our processes going forward and drilling great wells.

When we do that, we will build the investment rationale for the large-format pipelines to get the gas kind of out to the East Coast. North, for that matter.

Did I answer your question there?

That's helpful. Appreciate that background and concept.

For my second question, and if I heard you right during your prepared comments, you talked about potentially being greater than 60,000 potential wells and testing upwards of four different benches in the Beetaloo. If I'm not mistaken, the prior disclosures you all had talked about 40, greater than 40,000 wells.

Did you guys increase that resource or well location assessment, and could you talk in terms of some of the other zones in the Beetaloo? When might you test those and take a look at something else and in terms of a different zone?

I would say at this point, Scott, there's no change to our strategy. In fact, I'm focusing the team very clearly to, we're going to focus on the Velkerri B shale, and we're going to focus on drilling great wells.

There's a lot of upside beyond that, not just in the different benches, but in other things to do in the basin. The first thing we need to do to enable all that is drill great wells in our targeted zone.

Got it. Was I mistaken when I heard you talk about 60,000 wells now?

That was part of the question. I think the prior disclosures are around 40?

No, I'm not recalling what you're referring to in the remarks, Scott.

Oh, okay. I had thought you mentioned something, there's upwards of 60,000 drilling inventories, the drilling inventories upwards of 60,000 wells in the Beetaloo.

Maybe I misheard you.

We can go and certainly follow up with Chris for

Got it. Thanks.

Yeah.

Thanks. Hi, Todd.

I'll start on the 6H well, and just wanted to get a little more discussion on the soak period decision there. I think you mentioned, Todd, it was originally planned for a 30-day and now looking to a 60-day.

Just curious what led to that tweak or that decision. Thanks.

We flowed that well back for 23 days to clean up the water, it's been soaking since then. Look, that was me.

I guided the team to leave that well shut in for 60 days just so we can be consistent with what we did on the SS-2H. Kind of back to what I was talking about with Scott, we're trying to learn everything from every well, and so minimizing the number of variables helps us do that.

It just creates less noise in the data.

Understood. That's helpful.

For my follow-up, I noticed in the catalyst slide that you guys have in the deck that the farm-out process timeline, which I think was previously a Q1 event, is more of a wider window of a first half event. I know you can't touch too much on the minutiae of discussions and things like that, but does the 6H well result impact that process at all, or just can you touch at a high level on the revised timeline there?

I would say generally speaking, we're still in the same timeline we were. Obviously, I can't talk too much about the specific to the farm-out.

I will only say we've got some really interested, very credible parties in there. If you're sensing a little flex there, that's possibly just a little time as we work through agreements, but the commercial process is no different than it was before.

Understood. Sounds great.

I'll turn it back. Thank you.

Yeah.

Yes, good morning, as it may be down there. Todd, I wanted to ask about the 2H well.

My understanding is you guys did your flow test, you shut it in, and so that's why you don't have any kind of update on the decline curve. I wonder if you could perhaps comment on you did I think make a reference in your prepared remarks about the Mid-Velkerri B kind of has its own idiosyncrasies, its own signatures.

Have you guys seen anything on the pressure build-up since you shut that well in that would encourage you or kind of solve some of the puzzles of some of the relatively flat decline you saw on that well? Just anything incremental there?

I hear what you're asking. Dick can certainly talk about the kind of indicators of flat decline.

We still believe that's there. On this specific well, frankly it's too early to tell.

The data that we've seen on the flowback, as you're unloading the water, it's all in line with what we expected. We haven't really seen anything that deviated from what we expected.

In that type of flowback, we're obviously not getting long-term data. We're not getting kind of full-flow data on it.

To really answer that decline question, we need wells on production for a period of time. Look, I'll tell you this well, everything looks in line.

It's kind of hard to tell much until we really get it on production.

When you say this well, you mean the 6H?

Correct. The 6H.

Okay. Okay.

Then a question on the expansion of the Sturt Plateau compression and the pipeline. Usually those are great projects.

Once you put the infrastructure in, it's a great project to expand it. What's the appetite look like on the other end of the pipeline for more gas sales up in and around Darwin?

Sure, yeah, what I can tell you about kind of what's clear and certain and kind of what our process will be forward. We've got 40 million a day to the NT Government there, and that can flex up a little bit, we have clarity on that.

Beyond that, we've got specific conversations going on with other customers that have been out there, and without going into all the specific names, we feel like there's a market there. The pipeline is built to go up to the 100 million a day, and the economics on that expansion are pretty compelling.

Look, we'll firm up those markets and make that decision at the time, but that's probably the best way to describe it, is cautiously optimistic.

Got it. Thank you.

Yep.

Thank you. Good morning, all.

Thanks for taking the call. Just wanted to touch quickly on, you mentioned that the prior activities hadn't been able to really fully test the local sand solution.

Just wanted to get an understanding of whether it's the Daly Waters or the Santos wells, how much progress we can expect over the course of '26, or is that more of a '27-'28 story?

That's a good question. Look, we really wanted to test it in the last well.

It didn't work out that way. We will have limited stages on the upcoming wells that we're going to complete.

We think that's something that's important to unlock and unlock early. I can tell you the lab results on that sand look really good, we're optimistic about it, but we need to get it in kind of some selected stages in the ground to confirm that.

Got it. Understood.

Then the tradition wells you guys talked about drilling kind of for either backing up the 40 million resource or for potential growth, just wanted to get an understanding of how does fit in to a longer-term cadence? Is that that holds you at 40 for 6 months, a year?

Just kind of getting an understanding of I guess the operational cadence needed to really maintain that 40 and then grow from there.

At this point, we're going to be focused on the pilot project, right? It's hard for me to answer your question on specific timing, and frankly until I get further into it.

That's something I'm not quite fully across, to be frank with you. Once I get my head into it, we'll understand the timelines a little bit better there.

Got it. Understood.

Appreciate the time. I'll leave it there.

Hi, Todd. I just wanted to get a little bit of your perspective and insight in terms of the strategic viewpoint for Tamboran going forward.

Coming in from the US, seeing what has been possible in terms of US shale gas production in the US, what do you see as the big positives, what do you see as the big negatives, what do you see as the kind of the strategic direction going forward? Just like to kind of get your viewpoint on that.

The first thing I'll say is there's no change in our forward strategy, and thanks for the question. We're an upstream gas company, and as I mentioned in one of the other responses, we're going to focus on drilling great gas wells.

The way we do that is similar to the way that we would do that in any shale play, US or otherwise, is we have really smart people, and that includes the people here at the company, that includes our partners, Baker Hughes, Liberty, H&P, the other operator that we're partnered with in the basin, Santos and Daly Waters Energy. It's about learning from every data point, and it's taking that data and just really frankly letting the really smart people dig in and do their work on it.

That's the way that the plays in the US have been successful, and that's the way we'll be successful here.

Hey, good afternoon, guys. Todd, congratulations on the new seat, and looking forward to meeting you.

My first question is on the backfill commitment wells number seven and eight. My understanding is that the North Pilot was sufficient to meet your production targets.

Just kind of wondering how these new wells fit into your plans and what the associated spend is net to Tamboran.

Those wells are in our agreement with Daly Waters Energy is those are contractual commitments for us. We're going to follow through and drill those wells.

In that southern block, Daly Waters Energy is the operator, but we will serve as contract operator for them, we'll get those wells drilled. There is an added benefit that they just add further resiliency to the gas production that we'll have online, whether that's extended performance or whether there's down the road some unforeseen mechanical challenge.

We have further backup to meet our obligations. That's kind of the upside on it, but that's not why we're drilling them.

If that's kind of the question you're asking, if I'm understanding that right.

I appreciate that, and that does address it. My second question is on funding.

In the second half of last year, Tamboran acted on several opportunities to bolster funding. As you kind of map out your operating plans for 2026, which includes first revenues, do you anticipate having surplus cash at the end of the year without additional fundraises, and also maybe excluding the farm-down?

Several questions in there. If I guess if what you're asking is, do we expect capital markets activity?

I'll answer it a little bit more broadly and just say, look, we're a high-growth company in a capital-intensive industry, there's a reason we're a public company, and from time to time, we'll access the capital markets. Early on that's more likely to be equity, later on in our maturity, we'll use some debt.

Realistically, we have other funding mechanisms. You mentioned the farm-out, that's one of them.

There are other things we can do to raise equity. What I want you and all the other shareholders to hear is that we'll be very thoughtful in our approach to that and do it in a way that makes the most sense for all the shareholders.

Got it. I appreciate it, Todd.

Thank you.

Thanks. Hey, Todd, could you talk about some of the learnings that you all have gone through on some of these early wells with the OFS partners?

There've been some issues on some of the drilling and completion operations, but could you talk about any kind of learnings or any kind of strategy you guys have moving forward to mitigate some of these things in the future? Wait,

sorry. Give me more detail on your question, Scott.

Are you talking about specific operational issues or performance or where's your head on that?

Just, for example, tools and stuff you had to fish out of some of the wells like the 4H well, and had to drill some shorter laterals on some of the initial wells. Just talk about some of the things that you'll take a look at in terms of changing the operational procedures to hopefully mitigate some of that moving forward.

I see what you're saying. Look, we've got great partners.

Baker Hughes, Liberty, H&P are all highly focused on it. They've done a good job for us.

I think with any basin or in any situation where you have equipment starting up, you really start hitting your stride when you get more continuous operations, and we will too. The more our activity ramps up, the more consistent those crews will be out there.

I can tell you that our team here, and our partners are all highly focused on the exact thing you're talking about, certainly aware and look, we're going to get better at it. If you think about the plays that are in full swing in the US, you have crews that they're doing those same things everyday, day in and day out.

That's a big driver of their performance, and it will be here ultimately as well.

Appreciate that. For my last question, maybe it's a better one for Eric or somebody else, but just talk about the stakeholders in Australia and any kind of structure, what are the next steps to Phase 2 and other things to get the permits and stuff you need for early work, cuz how has it been working with the government, how's that been, and what are the next things to watch for there?

Sure, and I'll let Eric chime on here if there's anything to add. What I'll tell you is, in kind of my brief experience here, the support across the board has been fantastic.

That's from the government there in the NT. We've spent time with them this past week and they've all been extremely supportive.

The native title holders have been supportive. Look, the development of this basin is a great outcome for all the stakeholders and all those that we're talking about.

They'll all benefit from direct royalties, they'll have jobs, they'll have economic development, and they've been very supportive. You can see that in the beneficial use agreement that we have to sell our gas, and you can see that in the support in the way that the basin's being developed out.

Of course, I can't leave out the pastoralists, as we're kind of working alongside them. It's really a great situation out there, and that everyone kind of wants to see this take off.

It benefits the local area, it benefits the nation, and frankly it ultimately benefits kind of the region of the globe. Eric, anything to add there?

No, look, I think Todd captured it very well. Where we're sitting today is we're looking forward drilling with our partners and with Santos and DWE the equivalent of, well, if not more, wells that have been drilled horizontal wells that have been drilled in the basin's history.

Now this basin's been 10 years coming, and even for us, the local support is incredible because, one, the market needs the gas, two, the local community needs the jobs. We were setting up a regional office near the Beetaloo in Elliott.

We've made some really great hires locally recently, and we intend to make more. Really everything's all systems go.

Our team is working through the Indigenous Land Use Agreement with the government, and everything we're doing is just putting one foot in front of the other to make sure that we're bringing the whole community with us as we open this project. Thank you.