Tamboran Resources Q3 2025 TU Earnings Call Transcript

Quartr
Provided by Quartr
May 14, 2025

There are 6 speakers on the call.

Operator

As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Joel Riddle, Chief Executive Officer.

Operator

Thank you, Joel. You may begin.

Speaker 1

Thank you, and welcome to Tanborn Resources third quarter fiscal year twenty twenty five result presentation. I'm Joe Riddle. I'm the Chief Executive Officer for the company. And joining with me this afternoon is Eric Dyer, Chief Financial Officer. Before we get into the material, I'd like to refer everyone to the disclaimer statement on slide two associated with forward looking statements.

Speaker 1

Starting on Slide three with the key highlights from the quarter. The company successfully completed 35 stages and this is Shenandoah South 2H well and following an extended sixty two day soaking period, the well has commenced a flow test in which we plan to report an IP30 flow test to the market by the June. Overall, we plan to flow the well a full ninety days and we'll be reporting an IP90 to the market by the August. Following the completion of a capital raise that we announced to the market, yesterday, we are fully funded to complete the drilling of three follow-up pilot wells Shenandoah FFEL 45 And 6. Those wells will be drilled in second half of twenty twenty five targeting spud of the SS4H well in early July.

Speaker 1

Following review of the previous two wells that we have drilled off the same well pad Shenandoah South 2 And 3, we will be targeting a twenty five day spud to TD timing and demonstrating an increased cost effectiveness for the 10,000 foot horizontal wells that we plan to drill. Once the drilling is completed for these three wells, we will be pumping two forty stages with a batch completion across the three new wells plus the Shenandoah South 3 well and these completions will take place later this year moving into first half of twenty twenty six ahead of establishing first production of our Shenandoah South pilot project. First Gas remains on track to deliver initial 40,000,000 cubic feet a day to the local Northern Territory gas market by middle part of twenty twenty six. And also following the completion of a checkerboard negotiation with our partner Daily Waters Energy, we are now targeting the initiation of a farm out process of 400,000 acre block, an area we call the Phase two development area. That farm out process has initiated and we plan to provide further updates on that farm out process through the balance of this year.

Speaker 1

The company ended the quarter with a cash balance of $25,600,000 and following the completion of our capital raise yesterday, the company has a pro form a cash balance of $96,000,000 and most importantly, will be fully funded to deliver our Shenandoah South pilot project in middle part of twenty twenty six. Moving to Slide four and a further update on our Shenandoah South pilot project. As I mentioned in my opening statement, Shenandoah South 2H was successfully completed across 35 stages last quarter and following a sixty two day soaking period, the well was opened up and we have commenced flow testing of this well. We plan to report IP30 flow test results in June and we plan to test this well a full ninety day period. In parallel with the Shenandoah South 2H flow test, we will be spudding the first of three wells starting in July Shenandoah South '4, '5 and '6 with the intention to test a minimum of one of those wells over a thirty day period later this year ahead of first gas for the Shenandoah South pilot project in mid-twenty twenty six.

Speaker 1

Moving to slide five to provide additional color and detail around our flowback strategy for our Shenandoah South 2H well. First, one of the key learnings that we've seen from recent Beetaloo wells, particularly our Shenandoah South 1H well is that we've seen productivity improvement after initial gas breakthrough to have an extended cut in period otherwise known as soaking. For Shenandoah South 1H, we had a twenty one day soak period in which we saw a material productivity improvement from pre soak to post soak and moving into our thirty day well test. We believe this is due to the highly desiccated nature of the Midvocari shale in which we're looking to develop. The shale is five to 10 times more desiccated on average versus U.

Speaker 1

S. Shale basins. The company has taken an extensive modeling review with Core Lab in which has resulted in guiding the company to perform an extensive stoking across the SS2 well. That study has indicated an optimal soaking greater than sixty days. We left the well shut in for sixty two total days and we believe that will enhance the overall productivity given this longer soak period.

Speaker 1

Moving to Slide six, the other extensive review that the company has done following the results of Shenandoah South 2 And 3, We have identified multiple opportunities to further progress cost efficiencies across the next three wells. We've identified three major areas in which we believe can be implemented in these upcoming wells. First, there's an opportunity to batch drill the top hole sections over these three wells. We've also reviewed an optimized bit design and directional tools that we believe will result in material reduction in days across our wells. In addition, we've identified improved systems that will limit nonproductive time.

Speaker 1

And combined, we believe we will be in position to target a spud to TD timing of less than twenty five days for our Shenandoah South 4, 5 And 6 wells. Moving to slide seven to provide further detail around the completion of our Shenandoah South pilot wells for later this year. Once our Shenandoah South 4, 5 And 6 wells are drilled, we will move into completing each of those three wells in addition to the Shenandoah South 3H well that is currently docked on the well pad. On these four wells, we will be pumping a 60 total stages over a 10,000 foot horizontal section, and we will have the opportunity to implement key learnings from our Shenandoah South 2H flow test performance and also the tracers that we pumped over across 35 stages. These learnings will inform our proppant placement strategy for pumping each of our two forty stages on our four upcoming wells.

Speaker 1

In addition, we have the opportunity to use local sand in these four completions and the company will be targeting pumping greater than five stages a day using zipper fracking techniques with our Liberty Energy equipment on-site. Moving to Slide 8, the company continues to make excellent progress around maintaining its schedule to deliver first gas from our Cinaduwa South pilot project by mid-twenty twenty six. You can see we've now have the pipe that has arrived in the Port Of Darwin. That pipe will be tied to our Stuart Plateau pipeline. That is roughly 23 miles that will be built by our partner APA and connected to the existing Amadeus gas pipeline feeding gas into the local NT market.

Speaker 1

In addition, we took receipt of a compressor unit in Brisbane, in April of this year. That facility will be mobilized to site and this, Stewart Plateau compression facility will be looking to commission later in the year ahead of our first production date in mid-twenty twenty six. Moving to Slide 9, the company also in parallel continues to evaluate expansion opportunities for our Phase one business plan. We've identified, again, working with our partner, APA, up to $90,000,000 a day of additional capacity that we could look to develop through existing pipeline infrastructure. Over the quarter, the company signed an LOI with Arafura Rare Urs, which is a critical minerals project in the Northern Territory to deliver up to 26,000,000 cubic feet a day for ten years.

Speaker 1

The company will be looking to convert that LOI to a binding agreement by the end of the year. In addition to the Erafura opportunity, the company will continue to progress discussions with various gas buyers in the Northern Territory and the area in Queensland of Mount Isa, where we see up to 90,000,000 cubic feet a day of demand occurring in the next few years. Moving to Slide 10. Over the quarter, the company also completed a checkerboard process with its partner Daily Waters Energy. The results of that checkerboard process is included by the map shown on the right in which Tamboran operated acreage is included in blue.

Speaker 1

One block I'd like to highlight as part of this checkerboard process is the Phase two development area, which is approximately 400,000 gross prospective acres in which Tamborn approximately owns 58% and operates. The development strategy for this Phase two development area will be to supply the East Coast domestic gas market by twenty twenty nine, two thousand and thirty to address anticipated shortfalls that could exceed a Bcf in May later this decade. The company has appointed RBC Capital Markets to lead a formal process to farm out Tamborn's working interest in the Phase two development area. RBC has now commenced this farm out process and will be providing further updates on this process throughout the course of this year. Moving to Slide 11, company ended the quarter with a cash balance of $25,600,000 and following the completion of the $70,000,000 capital raise that we announced to market yesterday, The company currently owns pro form a of this deal and adjusted cash balance of $96,000,000 This cash will be directed primarily for drilling and stimulation activities for our upcoming three well program and also the SS3 completion that we will be performing in the next twelve months.

Speaker 1

The company is in advanced discussions around finalizing terms for potential financing of our SPCF and we will look to provide further details on the results of that financing in the months ahead. As mentioned previously, RBC Capital has been engaged to commence a farm down process for our Phase two development area that we believe will result with a successful farm out, potential for additional cash and well carry to support additional delineation ahead of our project sanction decision on our Phase two development. Moving to Slide 12. Over the next twelve months, there will be multiple catalysts that the company will be reporting to market, starting with the results of our IT-thirty flow test that we'll be reporting to market in June. In July, we will commence the drilling of our three well program that being Shenandoah South 45 And 6.

Speaker 1

Following the final investment decision for our SS pilot project, we will commence construction for the SPCF and the SPP later this year. And in parallel, following the drilling of SS4, five and six, we will stimulate all three of those wells combined with SS3 and take a thirty day flow test on a single well by first half of next year. Again, remain on track toward delivering first gas from our SS pilot project by middle of twenty twenty six. With that, I will turn it back over to the operator for Q and A.

Operator

Thank you. We will now be conducting a question and answer session. Our first question comes from the line of Jeff Grampp with Northland Capital Markets. Please proceed.

Speaker 2

Hey guys, thanks for the time. I was curious given all these efficiency gains and opportunities you guys have identified for the 4H36A12 that will start drilling in a few months here. Do you guys have kind of a targeted well cost or AFE for those that you could share that's been penciled out yet?

Speaker 1

Yes, sure. So the AFE for these wells will be approximately US28 million dollars That is what we're AFE ing. However, we believe there's material cost efficiencies that we'll see with multiple wells going down. We long term believe that we can get well costs down both drilling and completing down to about $16,000,000 That's where we've guided the market to. So over these next three wells, we'll be looking to demonstrate gains toward getting to that $16,000,000 number.

Speaker 1

There's really three main areas that I think will come from the cost savings. One is improved ROP. We've already mentioned the optimized mud system that we implemented after the SS2 well. We continue to make progress around refining both the mud system and bit design. I mentioned in my comments improved directional tools.

Speaker 1

We think that's going to generate potential for the horizontal section to be drilled in a more efficient way. The last SS3 well we took twelve point five days. We think that horizontal section can be reduced less than twelve point five days. And then on the completion side, I think the biggest opportunity to reduce well cost over the two forty stages that we're going to be pumping is really sourcing local sand. That's something the team has been very focused on in the last quarter.

Speaker 1

We've confirmed that we have sand frac quality sand that we've identified very close to the pilot pad. And we have a real opportunity across the two forty stages to use some of that local sand. To give a sense of the impact, right now our sand cost in the previous two wells have been $4,000,000 With a local sand solution, we can drop that $4,000,000 cost to about $500,000 So $3,500,000 come off those well costs with sand sourcing local sand alone. So we're very excited to have a three well program. I think it sets us up to really make a lot of progress around reducing cost as something company has been focused on.

Speaker 1

And now I think we have a plan now to get these well costs down pretty dramatically as we move forward.

Speaker 2

Perfect. I appreciate that. All. It's helpful. For my follow-up on the first gas target for mid-twenty six here.

Speaker 2

Can you touch on kind of the I guess the long lead items from a supply chain or regulatory standpoint that present potential risks to that timeline? Or do you guys feel like that's in pretty good shape given you got the pipe and things seem to be progressing on the development front as well?

Speaker 1

Yes, absolutely. Really good question. I think first, we've been planning for this second half drilling program for many months. So we've taken the opportunity to put a lot of the long leads under option. And so I would say there's very limited supply chain issues around getting necessary equipment out to site.

Speaker 1

The facility the pipe that APA has sourced has right on schedule. So there's really no hang ups around timeline around the facility or the pipeline or any of the long leads that tied to wells. So I'm really comfortable around maintaining the timeline. And we're very fortunate to be in a position where Australia is not in the middle of this trade war that many countries are facing. We're trying to take advantage of that being in Australia and sourcing steel that's on the market at competitive prices.

Speaker 2

Great. That's really helpful. I appreciate that Joel. Ultimately I'll stop on. Thanks for the time.

Operator

Thank you. Our next question comes from the line of Kayla Ackerman with Bank of America. Please proceed.

Speaker 3

Hey, good morning guys. Hi, Joel. Hey. For my first question, I want to ask on the use of proceeds here. Between the pipe and the acreage sale, you've secured about $70,000,000 of funding.

Speaker 3

Our understanding of the original funding path, if you will, was to flow the wells and then market the results for the capital. So why preempt the plan and to get the capital now? And I'm wondering if this has any read through to the productivity of the wells?

Speaker 1

Yes. Good question. Look, we took advantage of where we've gotten to with our strategic partner Formentera. As I mentioned in the opening comments and also in the announcements from yesterday, we had been advancing a negotiation on the checkerboard strategy and part of that negotiation has resulted in a $10,000,000 commitment from Formentera and the pipe and also the acreage deal. And we use that as a catalyst to build a $55,000,000 book on the pipe and that was largely taken up by existing shareholders and that's in the top 10 shareholders of Tamboran.

Speaker 1

So, this was a real opportunistic capital raise that puts the company in a very strong position to be fully funded going into the well test result. And then obviously allows us to drill these next three wells to get into production and cash flow for the business. I wouldn't have any read through I wouldn't suggest there are any read through on where we are on the well test. I think this is all about ensuring that the company gets into a full funding position for our Phase one pilot project. And I'm really excited with the result now to be in a position where we're fully funded.

Speaker 3

Okay. That's really helpful. For my second question, I'd like to address the new acreage map and this one has two parts. First, it looks like the northern and the southern pilot areas are about 20,000 acres each. And am I kind of magic ruler that it looks like you've retained about 160,000 acres in the very best part of Beetaloo West.

Speaker 3

Can you kind of talk about an idealized scenario? And I suppose this parcel contains enough resources both to support multiple Bcf per day of production. Can you kind of talk about the upside case and the full development scenario? And the part two to this question is kind of returning to the map and addressing the white space. I suppose now somebody else operates the other part of the white space here on this map.

Speaker 3

With multiple operators in place, do you see learnings in the basin kind of accelerating here?

Speaker 1

Yes. Yes, great questions. First on the 160,000 gross acres that you referenced, being in the very best part of the Beetaloo West area. Just to give you a sense, over 160,000 acres, we can drill around 04:30 wells. We have three zones, three stacked pay zones there in that area that we can put up to 1,300 wells in.

Speaker 1

When you assume kind of an average EUR per well, you can comfortably fit about 20 Tcf in that 160,000 acre area. So 20 Tcf is enough reserves that we could develop two Bcf a day for twenty years. That's our business plan with some headroom. So if you think about two Bcf a day for twenty years, that's about 15 Tcf. But just within confines of that 160,000 acre area, can produce that two Bcf a day for twenty years plus an additional five Tcf of headroom.

Speaker 1

That's something that I would say we are very comfortable on from a near term development perspective. It's one of the reasons why we call this the Phase two development area is that will be the focus of the company and obviously we want to direct potential farm in partners to that opportunity to work with Tambor and Daily Waters Energy on that. I think the part two to your question, obviously very much understand sort of the additional white space on the map now. I think the short answer to your question is that in the near term and mid term, we are very much aligned with our strategic partner, Full Monterra Partners and Brian Sheffield. So on Phase one in the pilot, we are aligned for that pilot project.

Speaker 1

And this 160,000 acres that you referenced as part of the Phase two development area, part of the deal that we negotiated with Flomentera is they will take a percentage of that block and that creates alignment. And we think that is something that we wanted. I think that alignment creates a lot of opportunity to share learnings. We value, Formentera and Brian's team, and we think that's going to be absolutely critical in our ability to have success in Phase one and Phase two. I think long term, to your point, I think there will be opportunities to bring more operators into the basin, including Formentera will be one of our competitors long term.

Speaker 1

We think that's a good thing because that's going to attract additional wells getting drilled. Service companies will be attracted by those additional delineation. And overall, we see costs coming down long term. So we look at this as a good thing with more operators coming into the basin. And that's really the strategic intent for the checkerboard altogether is to have opportunity for other operators to drill and compete.

Speaker 1

And much like what's happened in The U. S. That's resulted in a reduction in well cost through efficiencies but also more service companies coming into the basin.

Speaker 3

Joel, if you don't mind, I've got a third here. Can you talk about why the farm down area is shaped the way it is? From my perspective, it basically has exposure to two different geological settings. Why would that be interesting to a partner?

Speaker 1

Yes. No, it's a good question. I think just to take a step back, the checkerboard was part of a 4,000,000 acre area that we split roughly in 20 blocks and those 20 blocks were roughly 200,000 acres each. We performed a checkerboard draft much like the NFL draft. So we had areas that we really liked kind of high on our draft board.

Speaker 1

Probably at the top of that draft board was this Phase two development area. And the reason for that just to give you some color is because of the quality of the geology obviously very close to a derisk pilot project area. We believe that quality of the acreage will extend under this Phase two development area. Obviously very close to existing infrastructure with roads pipeline 20 miles away and also very supportive pastoralists and traditional owners in that area. So this is an area that is development ready and that's what I'm most excited about.

Speaker 1

And that's one of the reasons why we prioritize this as part of the checkerboard draft. To your point beyond 160,000 acres, the northern part extends to Amunji area where there's a number of wells that have gone in. That is a further derisk part of that 400,000 acres we think will be accretive. Obviously, the initial wells that we will look to work with a farm in partner on I think will be closer to the pilot area just because of the derisk nature and the deeper part of that basin. And so the way I see this happening much like what's happened in the Wolfcamp and other areas in The U.

Speaker 1

S. Is you start in the deeper sections and work your way kind of more shallow. And that's why I think this 400,000 acre block will be developed in time. But remember just within the 160,000 acres in this deep section, we can put up to 1,300 wells. We can develop two to three BCF a day.

Speaker 1

And that allows us a pathway to deliver the business plan, through 02/1930. So everything else beyond that will be upside.

Speaker 3

Got it. Thanks, Joel. I'll turn it over.

Operator

Thank you. Our next question comes from the line of Paul Diamond with Citi. Please proceed.

Speaker 4

Thank you. Good morning. Thanks for taking the call. Just a quick one. Wanted to kind of walk through the pathway on well costs.

Speaker 4

Talked about these next few wells expected around $28,000,000 take out 3.5%. Can you walk me through kind of the rest of the process? Is that just multi pad drilling? Or is there how should I think about like other low hanging fruit there?

Speaker 1

Yes, sure. So part of the $28,000,000 is well testing. Obviously, a development scenario, the well testing will come out. Of the other big opportunities that we have by having a multi well program is that we can implement zipper fracking. So you remember Shenandoah South 2, we were pumping five stages a day.

Speaker 1

With multiple wells, we think we can pump up to 10 to 12 stages a day. That's kind of what a Marcellus operator is pumping. We believe we can replicate that. So that's double the amount of stages that get pumped a day versus what the well cost the $28,000,000 well cost is tied to. So there's that combined with the utilization of local sand and I already mentioned the opportunity for improvements on ROP by taking learnings from SS2 and SS3.

Speaker 1

We think the biggest gains will come in the horizontal section. That horizontal section for SS3 for instance we drilled in twelve point five days. We've been working very closely with Baker on having a review of the SS3 well. There's a more there's a better directional tool that we're going to be using for these upcoming wells. We think there's probably two or three days of gains that we can take from there.

Speaker 1

I think it's I mentioned the sand because that's really the biggest needle moving opportunity that we had to reduce well cost. Other elements will come from just having more reps. So the more reps you have, obviously efficiencies on the pumping more stages a day, higher rates of ROP coming from more optimized well plan and tools. And I guess just the fourth one is just drilling off one pad. There's no mobilization cost that we're incurring.

Speaker 1

We have the rig and the frac spread on location. We're going have a local sand solution hooked up to that. And I think that's what we've been working toward really over the last twelve months is to get into a situation on our pad that has the same look and feel as wells that are being drilled in the Marcellus today. That's what we're trying to replicate. And I think we're very, very close to that.

Speaker 1

We've made a lot of progress in the next twelve months. And what the team needs now is just more reps. So the more reps, think more efficiencies that we're going to gain. And I think what we're trying to accomplish over the next three wells is set our trajectory where we can take these next learnings and then show a trajectory to get down to $16,000,000 well cost.

Speaker 4

Understood. Appreciate the clarity. And just a quick follow-up on the whole SOAP period. So SS1H was twenty one days, increased that for the most recent. I guess how should we think about that from a kind of a run rate basis?

Speaker 4

Is that still kind of poking around seeing where the right level is? Or is it the more the better?

Speaker 1

Yes. Look, we as I mentioned in my opening comments, we did a deep dive study with Core Lab to build a model that we believe will predict kind of the effectiveness of soaking on production enhancements on a flow test. And that was a product of a lot of folks around the table that come from a lot of experiences in the Marcellus. Obviously, we have some experiences here in the Beetaloo. And recognizing this is the most desiccated rock on the planet, this is a shale target that has been buried for 1,200,000,000 years old.

Speaker 1

And it's very unique and we believe that uniqueness in this being a very, very dry shale, how long you soak matters. How you flow back these wells matter. And we've seen kind of a pretty big kick from twenty one day soak on SS1. Kind of where our model comes out is that a sixty day mark is kind of the optimal soaking period to get the best production characteristics out of this highly desiccated shell. So that's what guided the team towards leaving the well shut in sixty days.

Speaker 1

And I'm very encouraged by that model that we built and it'll put another data point on the board to help calibrate our model moving forward. But this is like very highly valuable information to guide kind of how we flow back wells in the Beetaloo and ultimately how we get the optimal type curve. That's what we're looking get out of this pilot and part that is trying to refine our flowback strategy. So hopefully that gives you

Speaker 2

a little color on the rationale.

Speaker 4

Understood. Appreciate the clarity. I'll leave it there.

Operator

Thank you. Our next question comes from the line of Nish Katya with Connum. Please proceed.

Speaker 5

Hi, Joel. I had three questions please. First of all, I was wondering with the 2H well test that's coming up, do you believe that that'll give you enough information to sufficiently derisk the play for Pharmanese, I. So you don't now need to show the performance for a full length lateral. Secondly, I'm just wondering if you could give a couple of updates on the data center opportunity for Phase one and then the MOU with Santos over the Darwin LNG Train two.

Speaker 5

And then finally, just more of a macro question. Can you talk a bit about the political landscape for gas and LNG in Australia, given the new federal government, how that kind of impacts the future gas strategy initiative? And also with regard to the NT government scrapping its renewables target presumably in favor of gas? Thank you.

Speaker 1

Yes. Absolutely. Let me start with your first question on the SS2H well flow test being kind of the adequate amount of information required for a farm in. I think, just to set some context, we have been running a soft process over the last twelve months following the results of the SS-one well. And we've had multiple IOCs and Asian strategics in a data room for the last twelve months.

Speaker 1

We've provided those counterparties a deep dive around the subsurface, obviously the SS1 well performance and also kind of all the key advancements we've made around reducing cost with the H and P rig and Liberty frac spread. We've always believed that the pilot wells as they get drilled and completed and further derisking occurs that will be the opportune time to have a farm down discussion with an IOC counterparty. And this is what's led us to appoint RBC on as our advisor on the farm out. Remember RBC was the bank that ran the original farm out process for Origin Energy, in which we successfully won that bid. So they have a lot of intrinsic knowledge the beetleu.

Speaker 1

They have a lot of intrinsic knowledge on the players that are interested in the beetleu. And all those players we've spoken to and I think SS2 I think will be a big step forward around another derisking point that will provide additional comfort on the extension from 500 meters to 1,700 meters on a horizontal. Being able to replicate that performance of what we saw in SS1, I think is very, very important. Being able to demonstrate kind of the productivity that comes from a modern U. S.

Speaker 1

Style frac with our Liberty Energy frac equipment, I think is very important. And then all the cost efficiencies that I've spoken previously about, I think are very, very important. So we will find out after we get around the table in the months and quarters ahead around kind of how the process is kind of concludes. I'm kind of in a position of a lot of confidence because I think we are having showing a lot of good progress. I think we're significantly derisking this part of the basin.

Speaker 1

And in the backdrop of all this is a structural short gas market, in which molecules need to come online to feed into up to a Bcf a day of shortfall on the East Coast. So, these are all things that I think give us confidence around our ability to attract a high quality partner in the farm down process. Time will tell around if this is the adequate amount of information required to get a very strong farm out deal done. But right now, as I sit today, looking at a lot of the progress we've made and also twelve months of discussions we've had with a lot of counterparties, believe there's I'm operating with high confidence that we will be successful in the process. I think the second question you had was related to data center opportunities.

Speaker 1

We continue to have discussions with a number of parties on our data center strategy. I think just to take a step back, we believe data centers in the Northern Territory are well positioned for being powered with gas from the Beetaloo simply because we have an abundance of gas supply coming online. We have I would say none of the issues that a lot of operators in The U. S. Struggle with around Not in My Backyard.

Speaker 1

We don't have any of that going on in the Northern Territory. In addition,

Speaker 3

there is

Speaker 1

opportunities to feed into an existing fiber network that is 20 miles away from our pad. And so I will hope in the quarters ahead, we will have a few MOUs MOUs to provide the market a little bit more color and definition around this data center strategy. I see this being part of an expanded Phase one opportunity that we would look to build upon the $40,000,000 a day that we're delivering middle of next year. And just to give you a sense of the scale, we need about another $200,000,000 a day to deliver a gigawatt data center. That could be a nice goal for an expanded Phase one in twenty twenty seven-twenty twenty eight.

Speaker 1

Kind of the final question you had is just around the macro environment and political situation both at the federal level and the local level in Australia. I think you'll know that we had an election that occurred on May 3 in Australia. The government, the labor government that we've been working with over the last three years stayed in power. So I look at this as being kind of a status quo and slightly accretive because the Federal Labor Party now has a majority, a very strong majority on the Federal side. That's a positive.

Speaker 1

And we have developed very deep relationships with the federal government and all the key ministers and we'll look to build on that foundation in the next three years into the next election. So, I'm feeling very positive about the outcome. I think on the local side, the Northern Territory government came into power about eight months ago. This is a country liberal party that now is in power. That is the right side of right of center politics in the Northern Territory.

Speaker 1

They also have a very strong majority. And we have a lot of depth in the relationships that we've built. In the last twelve years, I've been in this job locally. We I think the fact that they have rescinded their net zero policy, think, is really not relevant to our ability to get to be working with this local government around permits and approvals for our Phase one and Phase two and ultimately Phase three of our development. I look at it as a real win that the new local government came once they came into power, they appointed a territory coordinator.

Speaker 1

This territory coordinator was put in place to facilitate an accelerated approvals. And I think that's going to be very helpful and as we move forward in these bigger developments to have the opportunity to have someone in place that reports directly to the Chief Minister that can facilitate accelerated approvals. That's something that we've been discussing with the local government for many years. And I really applaud the local Northern Territory government on that to take that step and put in place a way for us to facilitate accelerated approvals.

Speaker 5

Thanks. Appreciate those insights, Joel.

Operator

Thank you. There are no further questions at this time. I'd like to turn the call back over to management for closing remarks.

Speaker 1

Thank you very much. First, I'd like to just thank everyone for joining, especially our existing and new shareholders that supported our capital raise and we look forward to delivering flow test results on Shenandoah South 2H in about thirty days and again, a IP90 that we're working toward in August. Thank you for your time and we look forward to keeping everyone up to date on Tambor and resources in the future. Thank you.

Operator

This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.

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Tamboran Resources Q3 2025 TU
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