Tamboran Resources Corp. Q1 FY2027 earnings call

• First Gas Milestone: Successfully delivered first gas sales to the Northern Territory market, powering homes and businesses in Darwin. Volumes are currently limited by government nominations (25 terajoules/day) but expected to rise during peak demand.
• Commissioning Status: The Sturt Plateau Compression Facility (SPCF) was completed on time and approximately US$9 million under budget. Commissioning is ongoing; full take-or-pay obligations for 40 terajoules/day begin once production testing is complete.
• Drilling Efficiency: Completed a three-well campaign on SS-1 pad using improved drill bit designs and anti-vibration tools, achieving record speeds through the hard Moroak formation. Drilled two wells completely with one bit, a significant improvement over previous campaigns.
• Stimulation Success: Executed the largest stimulation campaign in the basin on SS-2 pad (178 stages, 30,000 lateral feet). Achieved a record of 12 stages per day using zipper frack techniques.
• Local Sand Testing: Successfully pumped Beetaloo Red Sand without impacting pump pressures or fracture initiation. Tracers indicate performance in line with other wells. This local sand could save US$4 million per well compared to imported sand.
• Balance Sheet Strength: Strengthened liquidity with a US$186 million equity raise. Pro forma cash position stands at US$240 million including expected US$15 million from Daly Waters Energy.
• Strategic Direction: Prioritizing de-risking through resource delineation. Planning to drill at least six step-out wells in 2027-2028 with partners (Daly Waters Energy, Impact, Santos). Discussions with strategic partners are ongoing to align on commercialization pathways.

The transcript does not provide specific financial performance data for distinct product segments, as Tamboran Resources is currently in the pilot/commissioning phase. The company reports delivering first gas sales to the Northern Territory market with limited volumes (25 terajoules per day) due to seasonal demand constraints. Revenue generation is currently at 75% of the gas price during the commissioning period. The firm raised US$186 million net of fees via an equity raise in April, ending the quarter with US$225 million in cash and US$31 million in undrawn debt.

• Production Volume: Expects Northern Territory Government nominations to increase from the current 25 terajoules/day toward the contracted 40 terajoules/day target by the end of the year as seasonal demand rises.
• Revenue Recognition: Anticipates announcing first quarterly gas sales and revenue in the Q1 FY2027 earnings report in November.
• Capital Program: Full capital program remains unlocked until strategic partner selection is finalized. Expect continued focus on de-risking activities in both depocenters.
• Cost Reduction: Targets maintaining drilling times under 25 days, having already achieved 24-day completions. Sees potential for more ambitious targets in future development mode.
• Infrastructure Decision: Investment decision on SPCF expansion will depend on confidence in surrounding pipeline infrastructure and ability to move incremental volumes to high-value markets.

• Market Demand Constraints: Current production is capped by Northern Territory Government nominations (25 TJ/day) rather than well capacity, limiting immediate revenue realization.
• Operational Uncertainty: Long-term decline rates and well performance data are still being established; true test of well productivity lies ahead.
• Local Sand Viability: While early results are positive, long-term performance of Beetaloo Red Sand under changing reservoir stress conditions needs validation before full adoption.
• Infrastructure Dependency: Expansion of compression facilities and access to high-value markets depends on third-party pipeline infrastructure upgrades and availability, which introduces execution risk.
• Partner Alignment: Finalizing strategic partnerships and aligning collective work programs across different depocenters may take time and affect capital planning certainty.

Q: Scott Hanold asked about specific drilling improvements contributing to success on the SS-1-6H well and the resulting pro forma cost reductions.

A: CEO Todd Abbott highlighted that changes in bit design for upper-level zones and the use of vibration dampeners significantly improved performance, allowing the team to penetrate the hard Moroak Sandstone with a single bit. He noted that while synthetic oil-based systems offer future ROP benefits, the key to reducing costs is repeatability through consistent crews and scaling up activity to achieve U.S.-level efficiency structures.

Q: Leo Mariani inquired about CapEx expectations for the remainder of the calendar year and the timeline for securing a strategic partner.

A: Management stated that capital is focused on de-risking, with four wells planned in the pilot area and two Santos-operated wells this year. They emphasized that the full capital program cannot be locked in until a strategic partner is selected, as different partners have varying focuses on depocenters. The process is moving forward with strong interest, but deals require careful thought and time.

Q: Jeff Grampp asked about the scalability of using in-basin red sand and milestones for expanding the SPCF.

A: Abbott confirmed they are highly confident in pumping the sand but will not switch to a 100% red sand program until they have sufficient production history to validate its long-term performance relative to imported sand. Regarding SPCF expansion, the key uncertainty is ensuring surrounding pipeline infrastructure can transport incremental volumes to new markets, which must be resolved before making the investment decision.

Q: Charles Meade sought clarity on when production nominations would increase from 25 to 40 terajoules/day and details on the East-side appraisal wells.

A: Abbott explained that the 25 TJ limit is a seasonal NTG restriction, not a well limitation, and expects nominations to rise toward 40 TJ by year-end as temperatures increase. For the East side, the primary target is the B shale, though multiple stacked pay zones exist. Vertical fracking data from 2019 shows potential, but capital is being carefully allocated to evaluate these opportunities closely with Santos.

Q: Anish Kapadia asked about the sequence for converting non-binding LOIs into binding agreements for the East Coast pipeline and the path to FID.

A: Abbott clarified that APA Group is actively progressing on permitting and right-of-way for the East Coast pipeline. However, binding GSAs will only occur after upstream work sufficiently de-risks the subsurface resource through pilot production data and further delineation wells. The collective industry effort will quickly demonstrate the resource size needed to merit large infrastructure investment.