[TBN] Tamboran Resources: First Beetaloo Gas and the FY2026 Going-Concern Test

Tamboran Resources is an early-stage company trying to move unconventional gas in the Beetaloo Sub-basin of Australia's Northern Territory from exploration to its first commercial sale, and it reports FY2026 full year ended June 30, 2026 results on 2026-09-24[1]. The company still had no revenue in that fiscal year: it lost US$9.41 million in the third fiscal quarter ended March 31, 2026, general and administrative expense fell from US$5.41 million in the first fiscal quarter to US$3.08 million, and the accumulated deficit since inception reached US$191.5 million[2]. At the same date it reported US$101.9 million of cash, and together with the US$188 million (net of fees) April public offer and entitlement issue plus US$15 million from an acreage sale, management put pro forma liquidity at about US$298 million[3]. Company guidance points at one event: management said first gas sales from the Beetaloo pilot project remain on track for the third quarter of calendar 2026 and within the original P50 budget and schedule, while pricing for future medium and long-term gas sales contracts is still under discussion and not finalized[4]; during the commissioning period the company sells gas at 75% of the price under the Northern Territory Government Gas Sales Agreement (NTGGSA)[5]; in February it disclosed that roughly US$45.5 million of investment was still needed over the remainder of FY2026 to progress its development plans[6]; and management named the annual financial statements as the point at which it expects to be better positioned to evaluate whether the substantial doubt about going concern can be alleviated[7].

Three things in this annual report deserve attention. The first is when first gas sales actually start and at what price they settle: the Northern Territory Government's take-or-pay contract locks in 40 TJ/d of gross supply, equivalent to roughly 19 MMcf/d net to Tamboran, through the end of 2034 with a buyer's option to extend to mid-2041[8], but commissioning volumes settle at only 75% of the contract price[5], so both the absolute size of the first gas sales revenue and the implied unit revenue have to come from the report itself. The second is whether the going-concern conclusion changes: the FY2025 annual report put substantial doubt about the company's ability to continue as a going concern into its risk factors[9], management has tied the re-assessment to this report[7], and the relationship between the planned investment for the coming fiscal year and year-end cash plus undrawn facility capacity decides whether that language is deleted or retained. The third is whether the well cost curve has genuinely moved down: the company estimated gross drilling and completion cost for the remaining pilot wells at roughly US$30 million each against a long-term target of US$16 million[10], and calculates that locally sourced sand saves about US$4 million per well[11], so whether the report updates that number decides whether growth beyond 40 TJ/d is affordable at all.

Company Background and Business Structure

Tamboran's assets are concentrated in one basin and one shale. The company was founded in 2009, completed its US listing in 2024, is now listed in both New York and Australia (NYSE/ASX: TBN), is headquartered in Sydney, runs a fiscal year ending June 30 and, as of March 31, 2026, was still an operator with fewer than fifty full-time employees. It holds interests in six exploration permits and one permit application in the Beetaloo Basin: a 25% non-operated working interest in EP 161, where Santos is the operator; a 38.75% working interest in EPs 76, 98 and 117 held through TB1, a 50/50 joint venture with Daly Waters, where Tamboran is the operator and whose permits cover four million gross acres (1.5 million net); and a 100% working interest in EPs 136, 143 and EP(A) 197, where it is also the operator[12]. On September 2, 2025 the joint venture received Northern Territory Government approval to sell appraisal gas under the Beneficial Use of Gas legislation, the first approval granted under that legislation; combined with the earlier consent from Native Title Holders for sales of up to 60 TJ/d over three years, the Shenandoah South Pilot Project now holds every approval needed to sell gas[13].

Every link in the chain from wellhead to buyer has a named counterparty. Upstream is the Shenandoah South Pilot Project, where wells are drilled with 10,000-foot horizontal sections in the Mid-Velkerri B shale: SS-4H, SS-5H and SS-6H were drilled and cemented in October 2025, and stimulation of SS-6H was completed in December 2025 with 58 stages across a 10,009-foot (about 3,050-metre) lateral[14]. The rig, the frac spread and the oilfield services come from Helmerich & Payne, Liberty Energy and Baker Hughes, all three of which are also shareholders in the company[15]. Raw wellhead gas is dehydrated and compressed into sales gas at the Sturt Plateau Compression Facility (SPCF), a 40 TJ/d (39 MMcf/d) plant held 50/50 with Daly Waters[16], and is then delivered into the existing Amadeus Gas Pipeline through the 23-mile (37-kilometre), 12-inch Sturt Plateau Pipeline that APA Group builds, owns and operates; Tamboran and Daly Waters Energy have contracted all foundation capacity on that pipeline from the start of operations until at least 2041[17].

Three features of the funding structure matter at the corporate level. TB1 is consolidated as a variable interest entity, so reported assets and assets under construction include the joint venture partner's share and gross and net figures have to be checked line by line. Construction funding comes from a US$118 million (gross to the joint venture) SPCF syndicated facility, of which US$46 million was drawn at March 31, 2026 and US$77 million remained undrawn, with the Northern Territory Government guaranteeing Tamboran's 50% share up to A$75 million[5]. The net working interest in the pilot area is not yet settled: the company currently holds 38.75% across 20,309 acres of the Southern Pilot Area as non-operator, expects to move to 50% after completing the acquisition of Falcon Oil & Gas and the proposed acreage swap with Daly Waters, and expects 44.375% once the farm-down to Daly Waters Energy completes[18].

Financial History and Current Position

Tamboran's financial history is a pure spending record. In FY2025, the year ended June 30, 2025, revenue was zero, the operating loss was US$39.32 million, the net loss US$36.90 million and loss per share US$2.52, with general and administrative expense of US$21.71 million; operating cash outflow was US$29.64 million, capital expenditure was US$110.1 million, financing activities contributed a net US$101.1 million and the year ended with US$39.44 million of cash[19]. Over the three prior years the net loss was US$7.83 million in FY2022, US$32.03 million in FY2023 and US$21.92 million in FY2024, revenue was zero throughout, and the swings came from exploration spending and one-off items rather than operations. On the same statements, assets under construction related to the SPCF rose from US$7.542 million at the end of FY2024 to US$24.441 million at the end of FY2025, which shows where the money went that year[16].

In FY2026 the first three fiscal quarters again produced no revenue, and the losses did not narrow much. The net loss was US$8.18 million in the first fiscal quarter, US$6.61 million in the second and US$9.41 million in the third, while general and administrative expense fell from US$5.41 million to US$3.08 million over the same span[2]. As an interim reference point, at December 31, 2025 the accumulated deficit since inception was US$182.1 million, alongside a working capital surplus of US$38.4 million and US$32.6 million of long-term debt drawn for SPCF construction; that working capital surplus itself came from capital raising during the period[20].

The balance sheet was visibly rewritten by continuous financing over the same period, and the cost shows up in the share count. Cash rose from US$39.44 million at June 30, 2025 to US$101.9 million at March 31, 2026, total assets rose from US$446.5 million to US$672.1 million, long-term borrowings went from zero to US$44.58 million, shareholders' equity stood at US$395.6 million and non-controlling interests at US$151.0 million; over the same stretch the weighted average diluted share count rose from 14.66 million in FY2025 to 17.52 million in the first fiscal quarter of FY2026 and then to 22,397,089 shares in the third[2]. The company has raised roughly US$300 million since September 2025[21], including about US$219 million (net of fees) from a capital raise and PIPE transaction, which is also the main source of the US$298 million of pro forma liquidity[3].

Operating Model

There is one revenue source, one customer and one physical path, which makes the revenue equation unusually simple. Wells at Shenandoah South produce Mid-Velkerri B shale gas, the SPCF turns it into sales gas, and the Sturt Plateau Pipeline moves it into the Amadeus Gas Pipeline for delivery to the Northern Territory Government; revenue equals gross delivered volume times Tamboran's net working interest times the fixed, CPI-escalated NTGGSA contract price, on a take-or-pay contract for 40 TJ/d gross with a total term of about 15 years[15][8]. Two details shape the first revenue: during commissioning the gas settles at 75% of the contract price[5], and the contract price itself is confidential, so outsiders can only infer unit revenue by dividing gas sales revenue by disclosed volumes. Volumes beyond 40 TJ/d have no contracted outlet today; the company lists the East Coast domestic market and LNG as later options, and on the ACCC's March 2026 numbers the average contracted producer price for 2027 supply was about US$9.20 per mcf, roughly a 158% premium to Henry Hub over the same period, but neither the price nor the timing of that path is settled[22].

Before revenue exists the income statement is only cost, so the profit model has to be read in two stages. The FY2025 operating loss of US$39.32 million consisted almost entirely of general and administrative expense and exploration-related spending, with no gross margin to speak of. Once revenue appears, profit will be set by three blocks: revenue from net delivered volume times the realized price; field operating cost, including SPCF compression and processing (which, if the sale process completes, shifts from depreciation on an owned facility to a tolling fee under a long-term processing agreement), pipeline transport, water and camp costs; and depletion once reserves are recognized, plus interest on the SPCF syndicated facility. At the 40 TJ/d contract scale, revenue will not cover corporate general and administrative expense in the near term, so the testable question is not whether the company is profitable but whether the composition of the loss shifts from pure spending to spending offset by revenue.

The cash equation has three segments, and financing has been the lead actor throughout. Operations stay negative before first gas (FY2025 operating cash outflow was US$29.64 million) and only then add a small stream of gas receipts; investing is dominated by drilling, completions and facility construction, with FY2025 capital expenditure of US$110.1 million and the February 2026 statement that roughly US$45.5 million was still required over the remainder of FY2026[6]; financing includes the FY2025 net inflow of US$101.1 million, the SPCF syndicated facility, and the March 2026 farm-down of about 10,000 acres to Daly Waters Energy in exchange for a carry of up to US$28.5 million subject to structured off-ramp provisions[23], as well as the SPCF sale process started with Daly Waters in the December 2025 quarter[14]. The runway those three segments add up to is what decides the going-concern conclusion in the annual report.

Industry and Competitive Position

Measured by area, Tamboran is the largest holder in the Beetaloo Basin, with 2.8 million net prospective acres and three to four stacked benches across two depocenters[15]. What makes its position unusual is not a reserve metric but the fact that it is the first operator to connect this basin to a commercial gas network: before the SPCF and the Sturt Plateau Pipeline were built, the basin had no outlet at all[17], and as of August 31, 2026 SPCF construction had been completed on time and under budget[21].

The company faces three market layers, and the peer structure determines the shape of the third. The local Northern Territory market is locked up by the NTGGSA at a fixed, CPI-escalated, take-or-pay price[8]; the East Coast domestic market is mostly contracted business-to-business with a limited spot market and has shifted in recent years from commodity-linked to fixed-price agreements, with the ACCC reporting an average of about US$9.20 per mcf for 2027 supply[22]; the third layer is LNG export, though the company has said no capital will go into full FEED or construction work on the NT-LNG project until a joint venture partner is finalized[4]. Among peers, Santos operates EP 161 and is currently drilling Jibera South 1H and Newcastle South 1H with Tamboran, while INPEX entered the basin through the farmout with Daly Waters Energy and plans to start a four-well program in the Beetaloo Central Development Area (BCDA) in mid-2027[21]; their entry both validates the resource and means future long-distance evacuation is more likely to be a shared facility than any single company's private route.

Core Debates

Can the Shenandoah South pilot turn imminent first gas into a sustained contracted revenue line?

This question decides whether the step from explorer to producer is actually complete, rather than being one more arrow on a schedule. Tamboran has generated no revenue since inception, the first three fiscal quarters of FY2026 again produced none, and the company itself has said it does not look for production revenue before the second half of calendar 2026[6]. The Northern Territory Government's take-or-pay contract locks 40 TJ/d gross, roughly 19 MMcf/d net to Tamboran, through the end of 2034 with a buyer's option to extend to mid-2041, and it is the company's first and so far only contracted revenue source[8].

The current evidence supports two readings. As of August 31, 2026 SPCF construction was complete on time and under budget and the facility had moved into commissioning, first gas sales to the Northern Territory were described as imminent, and SS-9H had entered the drilling plan on the SS1 pad[21]; the pipeline has been built by APA with foundation capacity contracted[17]; and at the well end SS-4H, SS-5H and SS-6H have all been drilled, with SS-6H delivering a 20-day average initial production rate of 10.3 MMcf/d in April 2026[23]. The equally defensible reading is that all of this is facility-level and single-well evidence: on the May 2026 call management still described medium and long-term contract pricing as not finalized[4], commissioning volumes settle at only 75% of the contract price[5], so the first revenue is both small and unrepresentative of a steady state, and the same quarterly material indicates roughly 14% of the SS-6H lateral may have been impeded by downhole obstructions, which means repeatability of single-well deliverability still has to be proven across several wells[23].

The financial transmission runs from gross delivered volume times net working interest times the realized price into gas sales revenue, while an interruption or a shortfall against the daily contract quantity can trigger shortfall liquidated damages that hit the same line in reverse[8]. What is worth watching is therefore whether subsequent-events disclosure in the annual report gives a specific start date for first gas sales and whether pricing has moved from the 75% commissioning level to the full contract price, what unit revenue is implied by dividing gas sales revenue by disclosed volumes in the first quarter with revenue, what initial rates SS-3H, SS-4H and SS-5H deliver on the same basis after stimulation, and whether SS-7H, SS-8H and SS-9H are needed to fill 40 TJ/d. The observable falsifiers are equally clear: an SPCF or pipeline commissioning failure that interrupts delivery for more than a quarter, conditions precedent to the NTGGSA not all being met so the contract never becomes binding, or actual deliveries falling below the daily contract quantity and triggering damages would each break the idea that first gas equals a revenue line.

Will the FY2026 annual report lift the long-standing going-concern doubt?

This is not boilerplate language; it directly affects the terms and size of any refinancing. Tamboran has had no revenue since inception, the accumulated deficit was US$191.5 million at March 31, 2026, and the FY2025 annual report put recurring operating losses, negative cash flows and substantial cumulative net losses raising substantial doubt about the ability to continue as a going concern into its risk factors[9]. More importantly, in the May 2026 10-Q management itself designated the annual financial statements as the re-assessment point, saying it expects to be better positioned then to evaluate alleviation of the doubt provided execution continues, which makes the September 24 report a decision point the company set for itself[7].

The evidence on both sides is specific. At March 31, 2026 the company held US$101.9 million of cash, US$46 million of the US$118 million (gross to the joint venture) SPCF syndicated facility had been drawn and US$77 million remained undrawn, with the Northern Territory Government guaranteeing the company's 50% share up to A$75 million[5]; adding the April public offer and entitlement issue, management put pro forma liquidity at about US$298 million[3], against roughly US$45.5 million of investment still required over the remainder of FY2026[6]. The other reading is that these numbers show the company is not short of cash right now, not that it no longer needs cash: management explicitly tied alleviation to three operational steps that are not all complete, namely stimulation of the three wells on the SS2 pad, tie-in of those wells to the SPCF and commissioning of the SPCF[7]; the weighted average diluted share count has already risen from 17.52 million in the first fiscal quarter of FY2026 to 22,397,089 in the third[2], which shows the runway has been maintained by issuing stock; and the US$38.4 million working capital surplus at December 31, 2025 was itself the product of capital raising[20].

The transmission is an arithmetic one: cash plus undrawn facility capacity plus announced inflows, less corporate cash costs and planned capital expenditure, gives twelve-month liquidity coverage, and that coverage sets both the going-concern conclusion and the dilution pressure from further financing. What to watch is whether the going-concern paragraph in the annual report says the doubt is alleviated or still substantial and whether any alleviation carries conditions, the ratio of the planned investment for the coming fiscal year to year-end cash plus undrawn capacity, whether the SPCF sale process completes and how the consideration and subsequent tolling fees change the cash structure, and whether new equity issuance is announced around the report. The falsifying conditions are an annual report that maintains or strengthens the substantial doubt, another equity raise around the report to top up working capital, or planned spending that clearly exceeds available liquidity.

Is the cut in well cost from about US$30 million toward US$16 million actually happening?

The Northern Territory Government contract locks in only 40 TJ/d, and that volume alone cannot carry the company's scale story[8]. Whether Beetaloo turns from a pilot into a basin-scale development depends on what each 10,000-foot, roughly 60-stage horizontal well costs: in the FY2025 annual report the company estimated gross drilling and completion cost for the remaining pilot wells at approximately US$30 million each, including drilling, stimulation and extended production testing, against a long-term development well target of US$16 million[10]. That gap of nearly half decides whether incremental volumes are genuinely profitable or merely recover their cost in an East Coast environment priced at about US$9.20 per mcf[22].

The company has broken the cost reduction into steps that can be checked one by one. More than 2 million pounds of local Beetaloo Red Sand was delivered and placed across 10 stages of the 2026 stimulation program with no observed impact on pump pressures or fracture initiation; on a basis of 2,800 pounds per foot, which is about 28 million pounds for a 10,000-foot well, and a cost falling from US$0.24 to US$0.07 per pound, full adoption is calculated to save roughly US$4 million per well, with efficient repeatable well design, contract service optimization and bulk ordering supplying the rest of a targeted 50% reduction in drilling and completion costs, and the field wash plant trial has been completed successfully[11]. The equally reasonable reading is that this evidence comes from the company's own calculation and a single ten-stage trial: on the May 2026 call management said plainly that the full drilling and completion efficiency gains depend on moving to continuous full-time operations[4], and the near-term well count is limited, with the four-well BCDA program alongside Daly Waters Energy and INPEX not starting until mid-2027[21], so what shows up in the short run is more likely to be individual savings than a downward shift in the total cost curve.

The transmission runs from gross drilling and completion cost per well times net working interest times wells completed in the period into natural gas asset capital expenditure and investing cash outflow, a line that was US$110.1 million in FY2025[19]. What to watch is whether the annual report updates the gross cost per well and how far the new figure sits from US$30 million, whether local sand expands from a 10-stage trial to full-well supply and whether pump pressures and production hold up when it does, the ratio of FY2026 natural gas asset capital expenditure to wells completed in the period, and whether SS-9H and the four-well BCDA program advance on schedule. The falsifiers are local sand being abandoned after an operational problem in a wider trial, an annual report that raises the per-well cost estimate or stops disclosing it on a per-well basis, or delayed infill wells that force the company to hold plateau production at a higher cost.

Risks and Falsifiers

The net working interest in the pilot area is not final. The company's interest in the Northern and Southern Pilot Areas depends on completing the Falcon Oil & Gas acquisition, the acreage swap with Daly Waters and the farm-down to Daly Waters Energy, and the company states that its interest is expected to be 44.375% once the farm-down completes[18], with the Falcon acquisition and the farmout arrangements both listed among the key achievements of the past twelve months[21]. The same gross delivered volume produces different net revenue and net capital expenditure under different interests, so a change in the interest directly changes the absolute level of revenue and cash flow; the falsifier is an annual report confirming all three transactions are complete and giving the final pilot-area working interest.

How the SPCF will be held is also unsettled. Tamboran and Daly Waters have started a process to sell 100% of the SPCF[14], and if it completes the company would pay a tolling fee to a third-party owner under a long-term processing agreement instead of owning the plant[5]. A sale would change assets under construction and borrowings in one step and would convert processing cost that had been carried as depreciation into a recurring tolling expense, altering the composition of unit operating cost after first gas; the falsifier is an annual report disclosing that the sale is complete or terminated and setting out the fee structure of the processing agreement.

Australia's Safeguard Mechanism creates an obligation that grows with production. Once a Beetaloo facility emits more than 100,000 tonnes of CO2-e a year, all Scope 1 emissions for that year must be offset with Australian Carbon Credit Units or Safeguard Mechanism Credits, and the offset price cap rises each year by CPI plus 2%[24]. That is a cash cost rising roughly in line with volume, and it compresses operating profit per unit of gas during any expansion phase; the falsifier is an annual report showing emissions still below the 100,000-tonne trigger, or a disclosed range for offset costs already locked in.

The other side of a take-or-pay contract is shortfall damages. Once the NTGGSA becomes binding, the joint venture must have the daily contract quantity available every day unless excused by permitted interruptions or force majeure, and an unexcused shortfall can attract liquidated damages[8]. Those damages come straight out of gas sales revenue that has only just appeared and could widen the loss while revenue is still too small to cover corporate overhead; the falsifier is a full fiscal quarter delivered at the full contract price with no shortfall provision recorded in a quarterly or annual report.

Funding the runway with new shares is a path dependency. The company itself warns in its 10-Q that raising funds by issuing additional equity securities will further dilute existing stockholders[6], and the balance sheet of the past year was built on roughly US$219 million (net of fees) from a capital raise and PIPE transaction[3]. A rising weighted average diluted share count lifts the denominator of loss per share directly and dilutes revenue per share once first gas arrives; the falsifier is two consecutive fiscal quarters after first gas in which the weighted average diluted share count no longer rises because of financing.

The last risk is that cost reduction depends on continuous operations. Management has said the full efficiency gains require moving to a continuous full-time drilling program[4], and the near-term well count is limited, so economies of scale may be deferred. If well cost stays near US$30 million[10], the same production target requires more capital expenditure and more financing; conversely, if gross cost per well falls below US$20 million across two consecutive operational batches without a move to full-time drilling, the idea that cost reduction requires continuous operations is falsified.

What to Watch Next

• First gas as a revenue line: the FY2026 base is zero revenue against a contract for 40 TJ/d gross, about 19 MMcf/d net[8]. Watch the specific start date for first gas sales in subsequent-events disclosure and whether pricing has moved off 75% of the contract price[5]. Confirmation is a full fiscal quarter delivered at the full price with no shortfall provision; falsification is an interruption longer than a quarter or a contract that never becomes binding.
• Repeatability of well deliverability: the base is SS-6H's 20-day initial production rate of 10.3 MMcf/d in April 2026[23]. Watch initial rates from SS-3H, SS-4H and SS-5H on the same basis, and whether SS-7H through SS-9H are needed to fill 40 TJ/d. Confirmation is several wells at a similar rate; falsification is new wells materially below SS-6H.
• Going concern and funding runway: the base is US$101.9 million of cash, US$77 million undrawn and about US$298 million of pro forma liquidity[3]. Watch whether the going-concern paragraph says the doubt is alleviated or still substantial, and whether alleviation carries conditions[7]. Confirmation is alleviation without a fresh raise; falsification is maintained doubt or another equity issue around the report.
• Planned investment against liquidity: the base is roughly US$45.5 million required over the remainder of FY2026[6]. Watch the planned investment figure for the coming fiscal year against year-end cash plus undrawn capacity. Confirmation is planned spending covered by existing liquidity; falsification is planned spending clearly above it.
• Well cost: the base is roughly US$30 million per remaining pilot well against a US$16 million long-term target[10]. Watch whether the annual report updates that estimate and whether local sand expands from 10 stages to full-well supply[11]. Confirmation is a new estimate clearly below US$30 million; falsification is a raised estimate, the end of per-well disclosure, or local sand being dropped.

Conclusion

Tamboran is a company that has put everything on one basin, one physical gas route and one take-or-pay contract. Through the third fiscal quarter of FY2026 it still had no revenue and an accumulated deficit of US$191.5 million, and it built its facilities with roughly US$300 million of successive capital raises plus a US$118 million gross syndicated facility at the joint venture; the facility is now complete and in commissioning, and the contract locks 40 TJ/d gross through the end of 2034. The central unresolved relationship follows directly from that: a finished plant and a signed contract are not the same thing as a sustained revenue line, because commissioning volumes settle at 75% of the contract price, medium and long-term pricing is not finalized, and only one well has a complete deliverability record, so the shape of the first revenue cannot yet stand for a steady state. Until revenue starts to offset spending, the runway is still set by financing, which ties the going-concern conclusion and shareholder dilution to the same chain.

The two independent assessments published since the latest results sit on opposite sides of that chain. The H&P Research view reported by Proactive Investors holds that the 2026 stimulation campaign has materially de-risked the Beetaloo, that the performance was comparable with mature US shale regions, and that the repeatable manufacturing model used to cut costs in North America can therefore be applied in the basin, with first gas sales, lower well costs from locally sourced proppant and a potential Orion farm-out named as the catalysts[25]. Simply Wall St accepts that first gas moves the company away from a pre-revenue phase but stresses that the optimistic narrative leans heavily on timely Beetaloo project execution and ongoing access to fresh capital, with setbacks on either front quickly challenging that case, and notes a price-to-book ratio of 4.4x against an industry average of 1.4x for a company that has yet to report any gas revenue[26]. The two do not disagree that first gas is real progress; they conflict over how repeatable the cost reduction is and how dependent the company remains on outside capital, the first mapping onto the well cost debate and the second onto the going-concern and funding runway debate. Both are outside interpretations rather than confirmed facts.

What would genuinely strengthen or weaken the current understanding is a combination of later observations that can be watched together. If the annual report gives a firm start date for first gas sales, shows pricing has moved from 75% commissioning terms to the full contract price, states without conditions that the going-concern doubt is alleviated, and at the same time lowers the gross cost per well while local sand expands from 10 stages to full-well supply, then the reading that a completed facility equals a completed revenue line is materially strengthened. If instead first gas slips or delivery is interrupted for more than a quarter, the report maintains or strengthens the substantial doubt and is accompanied by another equity raise, and the per-well cost estimate is raised or no longer disclosed on a per-well basis, then the current understanding should be weakened — and all of these answers arrive in the same annual report and the two fiscal quarters that follow it.

Sources

[1] TBN earnings calendar entry for 2026-09-24 (calendar last updated 2026-09-17) · 2026-09-17 · Earnings calendar

[2] TBN 10-Q filed 2026-05-13 - cash and cash equivalents · 2026-05-13 · 10-Q · https://www.sec.gov/Archives/edgar/data/1997652/000162828026034593/0001628280-26-034593-index.htm

[3] TBN 8-K filed 2026-05-13 - 3Q FY26 highlights and pro forma liquidity · 2026-05-13 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001997652&type=8-K&dateb=&owner=include&count=40

[4] TBN earnings call 2026-05-13 - guidance · 2026-05-13 · Earnings call · https://ir.tamboran.com/

[5] TBN 8-K filed 2026-05-13 - SPCF construction and commissioning pricing · 2026-05-13 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001997652&type=8-K&dateb=&owner=include&count=40

[6] TBN 10-Q filed 2026-02-11 - liquidity and capital resources · 2026-02-11 · 10-Q · https://www.sec.gov/Archives/edgar/data/1997652/000162828026007263/0001628280-26-007263-index.htm

[7] TBN 10-Q filed 2026-05-13 - going concern evaluation · 2026-05-13 · 10-Q · https://www.sec.gov/Archives/edgar/data/1997652/000162828026034593/0001628280-26-034593-index.htm

[8] TBN 10-K filed 2025-09-25 - NT Government Gas Sales Agreement · 2025-09-25 · 10-K · https://www.sec.gov/Archives/edgar/data/1997652/000162828025042774/0001628280-25-042774-index.htm

[9] TBN 10-K filed 2025-09-25 - going concern risk factor · 2025-09-25 · 10-K · https://www.sec.gov/Archives/edgar/data/1997652/000162828025042774/0001628280-25-042774-index.htm

[10] TBN 10-K filed 2025-09-25 - well cost plan · 2025-09-25 · 10-K · https://www.sec.gov/Archives/edgar/data/1997652/000162828025042774/0001628280-25-042774-index.htm

[11] TBN 8-K filed 2026-08-31 - well cost reduction pathway · 2026-08-31 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001997652&type=8-K&dateb=&owner=include&count=40

[12] TBN 10-K filed 2025-09-25 - assets and operations · 2025-09-25 · 10-K · https://www.sec.gov/Archives/edgar/data/1997652/000162828025042774/0001628280-25-042774-index.htm

[13] TBN 10-K filed 2025-09-25 - Beneficial Use of Gas approval · 2025-09-25 · 10-K · https://www.sec.gov/Archives/edgar/data/1997652/000162828025042774/0001628280-25-042774-index.htm

[14] TBN 8-K filed 2026-02-11 - second quarter FY2026 activities report · 2026-02-11 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001997652&type=8-K&dateb=&owner=include&count=40

[15] TBN 8-K filed 2026-08-31 - markets and acreage position · 2026-08-31 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001997652&type=8-K&dateb=&owner=include&count=40

[16] TBN 10-K filed 2025-09-25 - assets under construction · 2025-09-25 · 10-K · https://www.sec.gov/Archives/edgar/data/1997652/000162828025042774/0001628280-25-042774-index.htm

[17] TBN 10-K filed 2025-09-25 - APA Group agreements · 2025-09-25 · 10-K · https://www.sec.gov/Archives/edgar/data/1997652/000162828025042774/0001628280-25-042774-index.htm

[18] TBN 8-K filed 2026-05-13 - pilot working interest footnotes · 2026-05-13 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001997652&type=8-K&dateb=&owner=include&count=40

[19] TBN 10-K filed 2025-09-25 · 2025-09-25 · 10-K · https://www.sec.gov/Archives/edgar/data/1997652/000162828025042774/0001628280-25-042774-index.htm

[20] TBN 10-Q filed 2026-02-11 - going concern · 2026-02-11 · 10-Q · https://www.sec.gov/Archives/edgar/data/1997652/000162828026007263/0001628280-26-007263-index.htm

[21] TBN 8-K filed 2026-08-31 - key achievements and 12-month catalysts · 2026-08-31 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001997652&type=8-K&dateb=&owner=include&count=40

[22] TBN 8-K filed 2026-08-31 - East Coast contracted gas price · 2026-08-31 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001997652&type=8-K&dateb=&owner=include&count=40

[23] TBN 8-K filed 2026-05-13 - third quarter FY2026 activities report · 2026-05-13 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001997652&type=8-K&dateb=&owner=include&count=40

[24] TBN 10-K filed 2024-09-23 - Safeguard Mechanism · 2024-09-23 · 10-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001997652&type=10-K&dateb=&owner=include&count=40

[25] Proactive Investors 2026-07-20 - H&P Research note on Tamboran · 2026-07-20 · Proactive Investors

[26] Simply Wall St 2026-09-17 - Tamboran starts Beetaloo gas sales · 2026-09-17 · Simply Wall St · https://simplywall.st/stocks/au/energy/asx-tbn/tamboran-resources-shares/news/tamboran-resources-asxtbn-starts-beetaloo-gas-sales-is-a-23