Sep 25, 2026 earnings call — First gas sales and commissioning progress
Tamboran delivered First Gas Sales; market nominations limited to 25 terajoule per day, with revenue based on the 40-terajoules per day contract once supply period begins.
EPS $-24.00 (est $-25.54)
Key quotes
"We have delivered First Gas Sales from the Betaloo to the Northern Territory Gas market."
"It is expected that, that sand could save USD 4 million per well with a 10,000-foot horizontal section compared to the sand imported from overseas."
"In April, we raised USD 186 million net of fees via an underwritten public offer and an institutional and retail entitlement."
Analyst Q&A 6
drilling changes and well performance
Q (Scott Hanold · RBC): He asked what specific drilling changes led to the SS1-6H success, what other adjustments they plan, and what the pro forma cost is now after the improvements.
A: They changed bit design and added a vibration damper and changed directional plans to better get through the hard Moroak Sandstone. They see more gains from improving downhole tool time and possibly using a synthetic oil-based system, but they need repeatability and larger basin scale to cut costs. They did not give a pro forma cost number in this answer.
"The vibration damper was actually a pretty big change for us." — Todd Abbott (CEO)
capital spending and partner search
Q (Leo Mariani · ROTH): He asked what CapEx will be for the rest of the calendar year (3Q and 4Q) and how far along they are in securing a partner and its likely timing.
A: At a high level, they expect capital focused on derisking with 4 wells in the Pilot Area (3 this year, 1 next year), 2 Santos wells over EP 161 (drill this year, stimulate next year), and 4 BCDA wells with Daly Waters at about 10% working interest. The full capital program will be finalized after they choose a partner and align strategic priorities. They said partner talks are moving forward with strong interest, but deals take time and will be agreed with a defined work program.
"Overall, you can expect our capital to be focused on derisking." — Todd Abbott (CEO)
in-basin sand test and plant decision
Q (Jeffrey Grampp · Northland): He asked if the upcoming fracs will test in-basin sand across the full wellbore or only partially, and how scalable local sand could be long term. He also asked what milestones they need before deciding to expand the SPCF.
A: They had no problems pumping the Betaloo Red Sand and tracers look identical to other stages, but they will wait for production history before moving to full Red Sand wells. They will run more stages on the next wells but will not do full wells now; if history is good they could move to effectively 100% Red Sand. For SPCF expansion, the key uncertainty is the surrounding infrastructure network and certainty that incremental volumes can be moved to markets via pipelines and upgrades.
"But we won't do full wells at this point, Jeff." — Todd Abbott (CEO)
gas nomination increase and well data
Q (Charles Meade · Johnson Rice): He asked when the NTG nomination will rise from 25 terajoules to 40 terajoules so they can build more well production histories, and which shale zones the Santos wells target and which zones were tested vertically in earlier work.
A: The 25 terajoules a day limit is set by the Northern Territory Government and is seasonal; they expect nominations to rise toward the end of the year as power demand increases. They prioritized 2 wells now to build long-term well history; those prioritized wells are full 10,000-foot laterals and include a Betaloo Red sand well. The primary target on the east side is the B shale and Santos did a vertical frac in 2019 that hit most zones.
"So right now, because of just where they are seasonally, those needs are not high." — Todd Abbott (CEO)
sand test criteria and drilling time
Q (Paul Diamond · Citi): He asked what specific results in the tracer and production data would make them go to 100% local sand, and whether 25 days is the right drilling time target for upcoming wells.
A: They want to see that the zones treated with Red Sand hold up on a relative contribution basis over time as reservoir drawdown and stresses change. If those contributions are comparable to other zones, the cost savings make local sand the clear choice. On drilling time, 25 days is a realistic near-term target, they have beaten it with a 24-day well, and they expect further improvement, especially in development mode.
"What we're specifically looking for in this, is to make sure that the zones where we place that Red Sand hold up on a relative contribution basis over time." — Todd Abbott (CEO)
pipeline agreements and East Coast timing
Q (Anish Kapadia · Hannam): He asked what needs to happen to convert non-binding LOIs into binding GSAs for the East Coast pipeline, and the remaining commercial, regulatory and financing milestones and expected timetable to a binding pipeline development agreement and FID.
A: APA is progressing on permitting and right-of-way work and is moving ahead on the East Coast pipeline. The biggest derisking input is upstream production data from the Pilot Area and other wells, which will demonstrate well decline and support infrastructure investment. They said early GSA conversations are happening, but nothing binding will occur until there is a very clear resource.
"GSAs, early conversations are already happening, but there's nothing binding that's going to happen until you have a very clear resource." — Todd Abbott (CEO)