Tamboran (TBN) Q1 2027 earnings review
Tamboran sells its first gas, but it needs more cash
Tamboran, a gas driller in northern Australia, sold its first gas but still spends more than it earns. Its share of sales came to $1.8 million, which accounting rules kept off its income statement. Chief executive Todd Abbott said the wells match earlier tests. Cash fell 27% from June, and by our math the rest of this year's project plan needs about $20 million a quarter.
| Gas sales, Tamboran's share | $1.8M none a year ago |
|---|---|
| Daily gas sales rate | 24.8 million cubic feet about 60% of the contracted volume |
| Cash held for Tamboran | $165M $225M at June 30 |
| Spending plan for the first project | Unchanged about $61M left for the fiscal year |
⚖️ Verdict: 🟢 Bullish
The story got better because an older well flowed more after a year shut in. Outside engineers also put a first number on what a standard well can recover. The bad news: Tamboran may need new money after June 2027, and its partner search has no date.
The question now is how fast output from these wells drops after many months of flow. Either it holds up and supports pipelines to bigger markets, or each well recovers too little gas to pay for itself. The next quarterly reports will start to settle it.
🐂 Bull Case
Tamboran Now Sells Gas to the Territory
Tamboran, which explores for shale gas in Australia's Northern Territory, began selling gas on September 5 through its new processing plant. Chief executive Todd Abbott said Tamboran and partner Daly Waters Energy became the first companies to sell gas from the Beetaloo Basin.
Its share of output reached 0.31 billion cubic feet, and the wells met 98% of the volumes the Territory government requested. While the plant starts up, the government pays 75% of the contract price. After that, a take-or-pay deal obliges it to pay for 40 terajoules a day, even when it takes less.
What to watch: the take-or-pay start date, which the gas group forecasts for early 2027. An on-time start would bring revenue on the full contracted volume, even in months of low demand.
Gas Wells Flow in Line With Earlier Tests
How much gas each well yields over its life decides whether the Beetaloo can support pipelines to bigger markets. Abbott said the results "support our view that declines remain relatively low and rates should rise as the wells continue to clean up". The rates back the second part, but weeks of flow cannot show a decline.
- SS2-2H ST1, reopened after a year: 10.2 million cubic feet a day, up from 7.2 million in 2025
- Same well, scaled to a standard 10,000-foot length: 18.4 million, near 19.5 million for a 2024 well
- New wells SS2-3H and SS2-5H, first 30 days: 8.8 and 10.0 million
- Outside engineers' middle estimate of total gas per standard well: 17 billion cubic feet
The older well matters most, because it shows output once a well has cleared the water used to crack the rock. By our math, its rate now sits 42% above the 2025 test. Netherland, Sewell & Associates, a reserves firm, made its estimate from these early results.
What to watch: flow history from the two wells Tamboran tracks most closely, in the next quarterly report. A gentle decline would support the engineers' estimate.
Local Sand Shows No Loss of Gas Flow
Fracturing a shale well means pumping sand into the rock to hold its cracks open, and Tamboran imports that sand from overseas. Abbott said in September that sand dug inside the basin, which Tamboran calls Beetaloo Red Sand, could save $4 million per standard well.
Tamboran used the local sand in 10 sections of the SS2-5H well. Early flow shows "no degradation in deliverability from using local sand", the explorer said. It plans to test the sand again in at least one of the three new wells.
What to watch: flow from the local-sand sections against the rest of the well after a year of production. Equal flow would let Tamboran use local sand in every well, a step Abbott said it will not take before that history exists.
🐻 Bear Case
Tamboran Still Warns It Needs More Money
Tamboran's results slides say "Maintain strong balance sheet". Its quarterly filing still says that its losses and spending plans "raise substantial doubt regarding the Group’s ability to continue as a going concern". Cash and an undrawn loan cover this fiscal year's project work, the filing says. But Tamboran also wrote that it "may require significant additional funds after June 30, 2027".
- Cash net to Tamboran: $165 million, against $225 million in June
- Committed spending not yet booked: $94 million, down from $126 million, including four joint-venture wells by May 2028
- Payment from Daly Waters Energy: $15 million, inside the $180 million cash figure but still subject to conditions
This matters because each permit requires set work by a deadline, and Tamboran can lose a permit if it does not complete the work. In July the regulator refused to ease the later years of work on permit EP 76. New shares or a partner deal would fund the work, but both dilute current owners.
What to watch: the December-quarter cash balance and any funding deal before June 2027. A deal would show how much acreage Tamboran must give up to fund the permits.
No Partner Yet, and Drilling Rig Idles
Tamboran wants a large partner to help fund its biggest blocks, but it again gave no date for a deal. Abbott tied new drilling to it: "We expect to undertake additional wells in our Orion acreage once we finalize our strategic partnership".
In November, Tamboran agreed a cut standby rate with rig owner Helmerich & Payne for up to 180 days after current drilling ends. A standby rate is the fee Tamboran pays while the rig sits unused. In exchange, the rig contract runs 1.5 days longer for each day at the cut rate.
What to watch: a signed partner deal, for which Tamboran has set no date. Until one arrives, partners such as Santos lead the next wells, and Orion, a block where Tamboran owns 78%, gets no new wells.
A Drilling Problem Forced a New Well Branch
Faster drilling is one way Tamboran plans to bring the cost of each well toward US shale levels. It targets under 25 days per well, and Abbott said in September that repeating the same work with the same crews brings costs down.
SS1-4H took 24 days, but SS1-6H needed 32. On SS1-2H, a problem down the hole forced the crew to drill a new branch, finished in early November. Tamboran said the work stays "within the contingency capital expenditure budget", the reserve it keeps for such problems.
What to watch: drilling days on the next wells Tamboran runs itself. Wells under 25 days would show that the speed gains Abbott described can repeat.
Risks this quarter didn't answer
Three standing concerns got no decisive evidence in this quarter's filing or results slides. Each depends on a step Tamboran does not fully control, so the reading on each stays where it was.
- Gas volumes: the Territory government still sets daily volumes during start-up; the take-or-pay start, forecast for early 2027, would end that limit.
- Ties to Formentera, the private equity firm of long-time shareholder Bryan Sheffield: its Daly Waters companies co-own the plant and joint venture and owed Tamboran $7.8 million at September 30; regulators still have to approve the planned permit swaps.
- Pipelines to eastern Australia and binding sales contracts: no new step this quarter; a signed contract with an eastern buyer would move this concern.
👓 Other Themes
A Stronger Australian Dollar Raised Reported Values
Tamboran reports in US dollars but runs its business in Australian dollars. The Australian currency strengthened between June and September, so converting its accounts added $12.4 million to shareholders' equity. Currency moves on cash and debt still cost $2.1 million in the income statement.
Abbott Becomes Managing Director as Falcon Buyout Ends
On October 19 Tamboran's board added the managing director role to Abbott's job as chief executive. The company said the step reflects his leadership "as the Company moves from appraisal into development". On November 10 it paid 4.1 million Australian dollars to buy out the last outside holders of Falcon Australia, a Beetaloo acreage owner it took over in May.
💲 Other KPIs
The share count held steady this quarter, after rising 23% in the June quarter. The average count nearly doubled from a year ago. That is why the loss per share narrowed 26%, to $0.35, even though the total loss widened.
Costs climbed 44.5% from a year ago. Advisory and legal fees more than doubled, partly on stock options for former Falcon executives, and staff costs rose with headcount. The loss for shareholders widened 48.1%, to $12.1 million, because Tamboran still books no revenue.
Capital spending rose 37% from the June quarter and more than doubled from a year ago. Drilling and testing wells took $48.6 million, and the processing plant took most of the rest, including financing costs.
🔮 Guidance
Unchanged. The filing puts the rest of this fiscal year's project spending at about $61 million, covering the three new wells, their link-up and the plant's final start-up. Against last quarter's $113 million full-year figure, that implies about $52 million went out in the first quarter, by our math. The rest works out to about $20 million a quarter.
Unchanged. Tamboran still plans to finish starting up the Sturt Plateau Compression Facility, its gas processing plant, by December. It now forecasts the plant's cost at about $10 million below budget, against about $9 million last quarter. Once the plant reaches practical completion, the income statement will start to show gas revenue.
Unchanged. Tamboran forecasts the take-or-pay contract with the Territory government to begin in the first quarter of 2027, after the plant finishes start-up. The filing adds that substantial revenue will not arrive before early 2027 "at the earliest". Until practical completion, Tamboran subtracts gas sales from the cost of its wells instead of booking revenue.
Delayed. Tamboran now plans to fracture the three new wells in the December quarter and through the wet season, then connect them to the plant in early 2027. Last quarter's plan had them connected by December. The delay keeps the plant on the first pad's five wells for longer.
Unchanged. Santos, which runs the EP 161 permit where Tamboran owns 25%, is drilling two horizontal wells. The first well's vertical section reached all the target shale layers in October, in line with Tamboran's expectations. Fracturing and flow tests follow in mid-2027.
Unchanged. Daly Waters Energy and Inpex plan to start a four-well program in the Beetaloo Central Development Area, where Tamboran holds 10%. Tamboran does not run these wells, so its share of the cost stays small.
❓ Key Questions
What price does the gas contract pay?
By our math, the discounted start-up sales brought about $5.81 per thousand cubic feet. The full contract price sets how much revenue take-or-pay brings once it starts in early 2027.
When will the $15 million from Daly Waters arrive?
Tamboran counts this payment from its 2025 acreage sale in its cash figure, but the money still depends on conditions it has not named. Its timing matters for a company that may need new money after June 2027.
How will Tamboran pay for permit wells due by 2028?
Permit deadlines run to May 2028, and the regulator refused to ease work on EP 76. Without a partner or new shares, missed work could cost Tamboran permits.
Is the plant expansion decision still due mid-2027?
Last quarter Tamboran planned a decision on expanding its processing plant to about 100 terajoules a day by mid-2027. This quarter's reports record small spending on the expansion but give no decision date.
How fast is output falling at the two watched wells?
Tamboran published 30-day rates but no decline data. Decline rates decide how much gas each well recovers, and so whether pipelines to bigger markets can win financing.