Tamboran Resources Corp. Q4 FY2026 earnings call

• First Gas Delivery: Successfully delivered first gas to the Northern Territory market, powering homes and businesses in Darwin. Volumes are currently capped at 25 terajoules per day (TJ/d) due to seasonal low demand, with expectations to rise toward the contracted 40 TJ/d capacity as peak demand approaches.
• Stimulation Efficiency: Completed the largest stimulation campaign in the basin on the SS2 pad, utilizing the Liberty Energy fleet. Achieved a record of 12 stages in one day using a zipper-frack approach, demonstrating improved operational efficiency.
• Local Sand Testing: Conducted successful tests using locally sourced Beetaloo red sand for 10 stages. No impact on pump pressures or fracture initiation was observed. This local sand could save U.S. $4 million per well compared to imported sand, pending confirmation of long-term production performance.
• Drilling Improvements: Drilled two wells on the SS-1 pad with significant speed improvements due to new drill bit designs and anti-vibration tools, allowing passage through hard rock zones with a single bit. Modifications reduced mud temperatures, increasing average rate of penetration (ROP).
• Capital Raise & Balance Sheet: Strengthened the balance sheet with a U.S. $186 million equity raise. Pro forma cash position is expected to reach U.S. $240 million upon receipt of U.S. $15 million from Daily Waters Energy.
• Strategic Partnerships: Entered a non-binding MOU with Liberty Energy to extend services and phase in lower-emissions equipment from 2027. Engaging in discussions with strategic partners to align resource delineation and commercialization pathways for large-scale development.

The company does not report traditional product segments with distinct revenue contributions. Instead, performance is measured by operational milestones in the Beetaloo Basin. Key financial highlights include: raising U.S. $186 million net of fees via an equity raise; completing the Sturt Plateau Compression Facility (SPCF) approximately U.S. $9 million below budget; and achieving first gas sales with a contract quantity of 40 terajoules per day (currently limited to 25 TJ/d due to market demand). The firm holds U.S. $225 million in cash and U.S. $31 million in undrawn debt at quarter-end.

• Gas Supply Volume: Expect nominations to grow through the Northern Territory's peak demand period. The company anticipates reaching the full 40 TJ/d take-or-pay contract quantity later in the year, contingent on government nominations and commissioning completion.
• Production History: Prioritizing two wells to generate long-term production data. Full decline curves will not be available until wells have produced for over 90 days.
• CapEx Focus: Capital expenditure remains focused on de-risking activities. The full capital program for future years is not yet locked in and depends on finalizing strategic partner agreements.
• Revenue Recognition: Under U.S. GAAP, some pilot project costs may be capitalized during commissioning to avoid income statement volatility. First quarterly gas sales and revenue are expected to be announced in the Q1 FY27 earnings release in November.

• Market Demand Constraints: Current gas sales are limited by Northern Territory government nominations (25 TJ/d vs. 40 TJ/d contract), which are subject to seasonal variations. Lower nominations reduce immediate revenue potential.
• Operational Uncertainty in Local Sand: While early tracer data is positive, the full efficacy of using 100% local red sand remains unproven over long-term production histories. Failure could negate anticipated cost savings of U.S. $4 million per well.
• Infrastructure Dependency: Expansion decisions (e.g., SPCF expansion) depend on external pipeline infrastructure and third-party upgrades. Lack of control over surrounding networks introduces execution risk.
• Partner Alignment Risk: Finalizing strategic partnerships is critical for unlocking the full capital program and resource commercialization. Delays or misalignment with partners like Daily Waters Energy, Inpex, or Santos could slow development timelines.

Q: Analyst asked about specific drilling improvements driving success on SS1 6H and pro-forma cost reductions. / A: CEO highlighted improved bit design and vibration dampers for upper zones, plus optimized directional plans through hard 'rope sandstone' allowing single-bit runs. Long-term cost reduction requires repeatability across crews and scale of activity to enable efficient service company logistics, aiming for U.S.-level cost structures.

Q: Analyst requested clarity on CapEx for remaining calendar year and status of securing a strategic partner. / A: CFO noted capital focus remains on de-risking (four pilot wells, two Santos wells, four BCDA wells). Full CapEx program is not locked in until a strategic partner is finalized, as different partners have varying focuses on depot centers. Discussions are active but timeline uncertain.

Q: Analyst inquired about scalability of in-basin red sand testing and SPCF expansion milestones. / A: CEO confirmed confidence in pumping local sand but will not move to 100% usage until production history validates long-term zone contribution. SPCF expansion decision hinges primarily on certainty that surrounding third-party pipeline infrastructure can transport incremental volumes to high-value markets.

Q: Analyst asked when nominations would increase from 25 to 40 TJ/d and details on East-side Santos wells. / A: CEO explained 25 TJ/d limit is a seasonal NTG restriction, not a well limitation, likely rising to 40 TJ/d by year-end as wet season demand increases. On east-side wells, primary target is B-Shale; vertical frack data from 2019 shows potential but requires further appraisal to justify capital allocation.

Q: Analyst questioned what data triggers 100% local sand adoption and current drilling time targets. / A: CEO stated the hurdle is verifying that local sand zones maintain relative contribution under changing downhole stresses over time, comparing them to offset wells. Current drilling target is ~25 days per well, which has been beaten on some sections, with more ambitious targets expected in future development mode.