Tamboran Resources - Earnings Call - Q3 2025 TU

Executive Summary

• Pre-revenue operator delivered operational progress in Q3 FY25: completed 35‑stage SS‑2H ST1 stimulation, initiated a 90‑day flow test after a 62‑day “soak,” and reinforced funding through a US$70.4M raise, lifting pro forma cash to US$96.0M.
• First gas from the ~40 MMcf/d gross Shenandoah South (SS) Pilot remains on track for mid‑2026; compression and pipeline long‑lead items were delivered to Australia, and construction is slated to start after FID in mid‑2025.
• Guidance cadence tightened: SS‑2H ST1 IP30 now planned for June (from April in prior quarter), IP90 by August; drilling of SS‑4H/5H/6H targeted for <25 days spud‑to‑TD each in 2H 2025 to drive cost efficiencies.
• Strategic positioning advanced: LOI signed with Arafura Rare Earths for 18–26 MMcf/d potential demand, and RBC engaged to lead farm‑out of ~400k acres in the Phase 2 Development Area; APA progressing pipeline licensing and construction plans.
• EPS modestly beat S&P Global consensus; revenue remains nil as the company is pre‑revenue, with management reiterating no material revenue expected until 2026. See Estimates Context below.

What Went Well and What Went Wrong

What Went Well

• SS‑2H ST1 stimulation completed across 35 stages over 5,483 ft with record Beetaloo proppant intensity (~2,706 lb/ft); flow test commenced post a 62‑day soak as part of an optimized flowback strategy.
• Midstream readiness improved: Sturt Plateau Pipeline pipe delivered into Darwin and compressor units arrived in Brisbane, supporting schedule integrity for mid‑2026 first gas.
• Funding strength: US$55.4M PIPE and US$15M acreage sale raised ~US$70.4M, fully funding drilling/completions of the remaining three SS wells; pro forma cash ~US$96.0M.
• Management quote: “We are fully funded to complete the drilling of three follow-up pilot wells… First Gas remains on track… by the middle part of 2026” — Joel Riddle, CEO.

What Went Wrong

• Timing slippage on IP30 disclosure: SS‑2H ST1 IP30 moved to June from prior guidance of April; SS‑3H IP30 shifted to mid‑2025 after precautionary casing reinforcement.
• Continued negative cash flow and net losses typical of pre‑revenue stage, with CFO and net income remaining negative in Q3 FY25.
• Operational risk reminders: company reiterates early‑stage development and “no material revenue expected until 2026,” highlighting execution, permitting, and infrastructure risks inherent in the plan.

Transcript

Operator (participant)

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

Joel Riddle (CEO)

Thank you and welcome to Tamboran Resources' third quarter fiscal year 2025 result presentation. I'm Joel Riddle. I'm the Chief Executive Officer for the company. 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. Starting on slide three with the key highlights from the quarter, the company successfully completed 35 stages, and this is Shenandoah South 2H well. Following an extended 62-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 end of June. Overall, we plan to flow the well a full 90 days and will be reporting an IP90 to the market by the end of 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 South 4, 5, and 6. Those wells will be drilled in the second half of 2025, targeting spud of the SS4H well in early July. Following a 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 25-day spud to TD timing and demonstrating an increased cost-effectiveness for the 10,000 ft horizontal wells that we plan to drill. Once the drilling is completed for these three wells, we will be pumping 240 stages with a batch completion across the three new wells, plus the Shenandoah South 3 well.

These completions will take place later this year, moving into the first half of 2026, ahead of establishing the first production of our Shenandoah South Pilot Project. First Gas remains on track to deliver initial 40 million cubic feet a day to the local Northern Territory gas market by the middle part of 2026. 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 a 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. The company ended the quarter with a cash balance of $25.6 million. Following the completion of our capital raise yesterday, the company has a pro forma cash balance of $96 million.

Most importantly, we'll be fully funded to deliver our Shenandoah South Pilot Project in the middle part of 2026. 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. Following a 62-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 90-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 30-day period later this year ahead of first gas for the Shenandoah South Pilot Project in mid-2026. 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 shut-in period, otherwise known as soaking. For Shenandoah South 1H, we had a 21-day soak period in which we saw a material productivity improvement from pre-soak to post-soak and moving into our 30-day well test.

We believe this is due to the highly desiccated nature of the Mid-Velkerri Shale in which we're looking to develop. This shale is 5-10 times more desiccated on average versus U.S. shale basins. The company has taken an extensive modeling review with CoreLab, which has resulted in guiding the company to perform an extensive soaking across the SS2 well. That study has indicated an optimal soaking greater than 60 days. We left the well shut in for 62 total days, and we believe that will enhance the overall productivity given this longer soak period. 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 non-productive time. Combined, we believe we will be in position to target a spud to TD timing of less than 25 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 total of 60 stages over a 10,000-foot horizontal section. 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 240 stages on our four upcoming wells. In addition, we have the opportunity to use local sand in these four completions. 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 eight, the company continues to make excellent progress around maintaining its schedule to deliver first gas from our Shenandoah South Pilot Project by mid-2026. You can see we now have the pipe that has arrived in the Port of Darwin.

That pipe will be tied to our Stewart Plateau pipeline that is roughly 23 mi that will be built by our partner APA and connected to the existing Amadeus gas pipeline feeding gas into the local NT market. 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-2026. Moving to slide nine, 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 million a day of additional capacity that we could look to develop through existing pipeline infrastructure.

Over the quarter, the company signed an LOI with Arupura Rare Earths, which is a critical minerals project in the Northern Territory, to deliver up to 26 million cubic feet a day for 10 years. The company will be looking to convert that LOI to a binding agreement by the end of the year. In addition to the Arupura 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 million 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 are included by the map shown on the right, in which Tamboran operated. Acreage is included in blue.

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 Tamboran 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 2029-2030 to address anticipated shortfalls that could exceed a BCF a day later this decade. The company has appointed RBC Capital Markets to lead a formal process to farm out Tamboran'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, the company ended the quarter with a cash balance of $25.6 million.

Following the completion of the $70 million capital raise that we announced to market yesterday, the company currently owns, pro forma of this deal, an adjusted gas balance of $96 million. 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 12 months. 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 Markets 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 a project sanction decision on our phase two development.

Moving to slide 12, over the next 12 months, there will be multiple catalysts the company will be reporting to market, starting with the results of our IP30 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 4, 5, and 6. Following the final investment decision for our SS pilot project, we will commence construction for the SPCF and the SPP later this year. In parallel, following the drilling of SS4, 5, and 6, we will stimulate all three of those wells combined with SS3 and take a 30-day flow test on a single well by the first half of next year. Again, we remain on track toward delivering first gas from our SS pilot project by the middle of 2026.

With that, I will turn it back over to the operator for Q&A.

Operator (participant)

Thank you. We'll now be conducting a question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we pull for questions. Thank you. Our first question comes from the line of Jeff Grampp with Northland Capital Markets. Please proceed.

Jeff Grampp (Analyst)

Hey, guys. Thanks for the time.

I was curious, given all these efficiency gains and opportunities you guys have identified for the 4H through 6H wells 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?

Joel Riddle (CEO)

Yeah, sure. So the AFE for these wells will be approximately $28 million US. That is what we're AFEing. 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 million. That's what we've guided the market to. Over these next three wells, we'll be looking to demonstrate gains toward getting to that $16 million number. 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. 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 12.5 days. We think that horizontal section can be reduced to less than 12.5 days. On the completion side, I think the biggest opportunity to reduce well cost over the 240 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. We've confirmed that we have frac quality sand that we've identified very close to the pilot pad.

We have a real opportunity across the 240 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 has been $4 million. With a local sand solution, we can drop that $4 million cost to about $500,000. So $3.5 million come off those well costs with sourcing local sand alone. We are very excited to have a three-well program. I think it sets us up to really make a lot of progress around reducing costs. That is something the company has been focused on. I think we have a plan now to get these well costs down pretty dramatically as we move forward. Perfect.

Jeff Grampp (Analyst)

I appreciate that. It is helpful.

For my follow-up on the first gas target for mid-2026 here, 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?

Joel Riddle (CEO)

Yeah. Yeah, 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. The facility, the pipe that APA has sourced has been right on schedule.

There's really no hang-ups around timeline around the facility or the pipeline or any of the long leads tied to the wells. I'm really comfortable around maintaining the timeline. 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.

Jeff Grampp (Analyst)

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

Operator (participant)

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

Kayla Ackerman (Analyst)

Hey, good morning, guys. Hi, Joel. 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 million of funding.

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

Joel Riddle (CEO)

Yeah. 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. Part of that negotiation has resulted in a $10 million commitment from Formentera and the pipe and also the acreage deal. We used that as a catalyst to build a $55 million book on the pipe. That was largely taken up by existing shareholders that's in the top 10 shareholders of Tamboran.

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. Obviously, it allows us to drill these next three wells to get into production and cash flow for the business. I would not have any read-through. I would not 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. I am really excited with the result now to be in a position where we are fully funded.

Kayla Ackerman (Analyst)

Okay. That is really helpful. For my second question, I would like to address a new acreage map. This one has two parts. First, it looks like the northern and the southern pilot areas are about 20,000 acres each.

If I kind of magic rule over that, it looks like you've retained about 160,000 acres in the very best part of Beetaloo West. Can you kind of talk about an idealized scenario? 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? 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. With multiple operators in place, do you see learnings in the basin kind of accelerating here?

Joel Riddle (CEO)

Yeah. Yeah. 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 430 wells. We have three zones, three stack pay zones. They're in that area that we can put up to 1,300 wells in. When you assume kind of an average EUR per well, you can comfortably fit about 20 TCF in that 160,000-acre area. 20 TCF is enough reserves that we could develop 2 BCF a day for 20 years. That's our business plan with some headroom. If you think about 2 BCF a day for 20 years, that's about 15 TCF. Just within confines of that 160,000-acre area, we can produce that 2 BCF a day for 20 years plus an additional 5 TCF of headroom.

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, as that'll be the focus of the company. Obviously, we want to direct potential farm-in partners to that opportunity to work with Tamboran and Daily Waters Energy on that. I think the part two to your question, I 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 midterm, we are very much aligned with our strategic partner, Formentera Partners, and Brian Sheffield. On phase one in the pilot, we are aligned for that pilot project.

This 160,000 acres that you referenced as part of the phase two development area, part of the deal that we negotiated with Formentera, is they will take a percentage of that block. That creates alignment. 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. 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, there will be opportunities to bring more operators into the basin, including Formentera, which will be one of our competitors long-term. We think that's a good thing because that's going to attract additional wells getting drilled. Service companies will be attracted by this additional delineation. Overall, we see costs coming down long-term.

We look at this as a good thing with more operators coming into the basin. That is really the strategic intent for the checkerboard altogether, to have opportunity for other operators to drill and compete. Much like what has happened in the US, that has resulted in a reduction in well cost through efficiencies, but also more service companies coming into the basin.

Kayla Ackerman (Analyst)

Joel, if you do not mind, I have 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?

Joel Riddle (CEO)

Yeah. No, it is a good question. I think just to take a step back, the checkerboard was part of a 4 million acre area that we split roughly in 20 blocks. Those 20 blocks were roughly 200,000 acres each.

We performed a checkerboard draft much like the NFL draft. We had areas that we really liked kind of high on our draft board. Probably at the top of that draft board was this phase two development area. The reason for that, just to give you some color, is because of the quality of the geology, obviously very close to a de-risk 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 mi away, and also very supportive pastoralist and traditional owners in that area. This is an area that is development ready. That is what I am most excited about. That is one of the reasons why we prioritized this as part of the checkerboard draft.

To your point, beyond 160,000 acres, the northern part extends to a Munchy area where there's a number of wells that have gone in. That is a further de-risked 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 de-risked nature and the deeper part of that basin. The way I see this happening, much like what's happened in the Wolfcamp and other areas in the U.S., is you start in the deeper sections and work your way kind of more shallow. That is why I think this 400,000-acre block will be developed in time. 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. And that allows us a pathway to deliver the business plan through 2030. So everything else beyond that will be upside.

Kayla Ackerman (Analyst)

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

Operator (participant)

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

Paul Diamond (Analyst)

Thank you. Good morning, Alex. Thanks for taking the call. Just a quick one. I wanted to kind of walk through the pathway on well costs. Talked about these next few wells expected around $28 million, take out $3.5 million for sand. Can you walk me through kind of the rest of the process? Is that just multi-pad drilling, or is there—I should think about the other low-hanging fruit there.

Joel Riddle (CEO)

Yeah, sure. So part of the $28 million is well testing. Obviously, in a development scenario, the well testing will come out.

One of the other big opportunities that we have by having a multi-well program is that we can implement zipper fracking. You remember Shenandoah South 2, we were pumping five stages a day. With multiple wells, we think we can pump up to 10-12 stages a day. That is kind of what a Marcellus operator is pumping. We believe we can replicate that. That is double the amount of stages that get pumped a day versus what the well cost, the $28 million well cost, is tied to. That combined with the utilization of local sand. I already mentioned the opportunity for improvements on ROP by taking learnings from SS2 and SS3. We think the biggest gains will come in the horizontal section. That horizontal section for SS3, for instance, we drilled in 12.5 days.

We've been working very closely with Baker on having review of the SS3 well. 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. I think it's—I mentioned the sand because that's really the biggest needle-moving opportunity that we had to reduce well cost. These other elements will come from just having more reps. 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. I guess just the fourth one is just drilling off one pad. There's no mobilization cost that we're incurring. We have the rig and the frac spread on location. We're going to have a local sand solution hooked up to that.

I think that is what we have been working toward really over the last 12 months, 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 is what we are trying to replicate. I think we are very, very close to that. We have made a lot of progress in the last 12 months. What the team needs now is just more reps. The more reps, I think, the more efficiencies that we are going to gain. I think what we are trying to accomplish over the next three wells is set a trajectory where we can take these next learnings and then show a trajectory to get down to $16 million well cost.

Paul Diamond (Analyst)

Understood. Appreciate the clarity. Just a quick follow-up on the whole soak period.

SS1H was 21 days, increased that for the most recent. I guess how should we think about that from a kind of a runway basis? Is that still kind of poking around, seeing where the right level is, or is it the more the better?

Joel Riddle (CEO)

Yeah. Look, as I mentioned in my opening comments, we did a deep dive study with CoreLab to build a model that we believe will predict kind of the effectiveness of soaking on production enhancements on a flow test. 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. Recognizing this is the most desiccated rock on the planet, this is a shale target that has been buried for 1.2 billion years. It is very unique.

We believe that uniqueness in this being a very, very dry shale, how long you soak matters. How you flow back these wells matters. We have seen kind of a pretty big kick from 21-day soak on SS1. Kind of where our model comes out is that a 60-day mark is kind of the optimal soaking period to get the best production characteristics out of this highly desiccated shale. That is what guided the team towards leaving the well shut in 60 days. I am very encouraged by that model that we built. It will put another data point on the board to help calibrate our model moving forward. This is 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 to get out of this pilot. Part of that is trying to refine our flowback strategy. Hopefully, that gives you a little color on the rationale.

Paul Diamond (Analyst)

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

Operator (participant)

Thank you. Our next question comes from the line of Nish Katya with Conam.

Nish Katya (Analyst)

Please proceed. 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 de-risk the play for farming ease, i.e., so you don't now need to show the performance for a full-length lateral? Secondly, I was 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 too.

And then finally, with 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.

Joel Riddle (CEO)

Yeah. 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 12 months following the results of the SS1 well. And we've had multiple IOCs and Asian strategics in a data room for the last 12 months.

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

All those players we've spoken to, and I think SS2, I think, will be a big step forward around another de-risking 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 US-style frac with our Liberty Energy frac equipment, I think, is very important. All the cost efficiencies that I've spoken previously about, I think, are very, very important. We will find out after we get around the table in the months and quarters ahead around kind of how the process kind of concludes. I'm kind of in a position of a lot of confidence because I think we are showing a lot of good progress.

I think we're significantly de-risking this part of the basin. 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 or shortfall on the East Coast. 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 if this is the adequate amount of information required to get a very strong farm out deal done. Right now, as I said today, looking at a lot of the progress we've made and also 12 months of discussions we've had with a lot of counterparties, I believe 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.

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. We do not have any of that going on in the Northern Territory. In addition, there are opportunities to feed into an existing fiber network that is 20 mi away from our pad. I will hope in the quarters ahead we will have a few 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 million a day that we're delivering middle of next year. Just to give you a sense of the scale, we need about another 200 million a day to deliver a gigawatt data center. That could be a nice goal for an expanded phase one in 2027, 2028. 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 Labor government that we've been working with over the last three years stayed in power.

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. We have developed very deep relationships with the federal government and all the key ministers, and we will look to build on that foundation in the next three years into the next election. 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. They also have a very strong majority, and we have a lot of depth in the relationships that we've built.

In the last 12 years, I've been in this job locally. I think the fact that they have rescinded their net zero policy is really not relevant to our ability 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, once they came into power, appointed a territory coordinator. This territory coordinator was put in place to facilitate and accelerate approvals. I think that's going to be very helpful 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.

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.

Nish Katya (Analyst)

Thanks. Appreciate those insights, Joel.

Operator (participant)

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

Joel Riddle (CEO)

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. We look forward to delivering flow test results on Shenandoah South 2H in about 30 days and, again, a IP90 that we're working toward in August. Thank you for your time, and we look forward to keeping everyone updated on Tamboran Resources in the future. Thank you.

Operator (participant)

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