Tamboran Resources Corp

The call did not include consolidated revenue, EPS, or gross margin figures. Operationally, Tamboran said first gas sales started, gas has flowed for 20 days, and volumes are currently limited by the Northern Territory Government’s 25 terajoules per day nomination level during commissioning. The company said the Sturt Plateau Compression Facility was completed on time and approximately $9 million below budget, and that during commissioning it receives 75% of the gas price; once the supply period begins, the contract quantity is 40 terajoules per day with take-or-pay protections. Tamboran raised US$186 million net of fees in April, ended the quarter with US$225 million in cash and US$31 million in undrawn debt, and expects first quarterly gas sales and revenue to be reported in 1Q fiscal 2027 in November.

Todd Abbott framed the quarter as a major de-risking milestone, emphasizing that first gas sales, facility completion, and drilling/completion improvements mark real progress toward plateau production and contracted supply. His tone was constructive but disciplined: he repeatedly stressed that the company still needs more production history, repeatability, and basin scale before costs and performance can reach U.S.-style shale levels. He also highlighted strategic optionality through partner discussions, a planned 2027-2028 delineation program, and the importance of infrastructure and market access.

The CFO did not provide a detailed financial review beyond the balance sheet and funding update. Management said the April equity raise brought in US$186 million net of fees, quarter-end cash was US$225 million, undrawn debt was US$31 million for SPCF funding, and pro forma cash rises to US$240 million including the expected US$15 million from Daly Waters Energy, subject to conditions precedent. They also noted that over the next two quarters some pilot-project revenue and costs will be capitalized under U.S. GAAP during commissioning, which will make the income statement less reflective of cash movement in the period.

Analysts focused on drilling efficiency, well productivity, sand testing, capital spending, partner selection, and the timing of moving from 25 terajoules per day toward the 40 terajoule take-or-pay contract level. Management said drilling gains came from bit design, vibration dampening, and better directional planning, while pressure data and early well performance were described as in line with expectations. On sand, Tamboran said early stages looked positive, but it will not move to a full red-sand program until more production history confirms the economics and performance. On the East Coast pipeline, management said APA Group is progressing permitting and right-of-way work, but binding GSAs and pipeline agreements depend on clearer subsurface delineation and more upstream data.