The buyer and the backstop

APA's release names the day. Commissioning of first gas from Tamboran and Daly Waters Energy's Shenandoah South Pilot Project took place on Tuesday 1 September 2026, with the gas to flow through APA's newly constructed Sturt Plateau Pipeline, linking with APA's Amadeus Gas Pipeline. APA's chief executive and managing director Adam Watson attended, and congratulated Tamboran, Daly Waters Energy and the NT Government.

The buyer of that gas is the Northern Territory Government. In April 2024, Tamboran announced a binding, long term take-or-pay gas sales agreement to supply the Territory with 40 TJ a day for an initial term of nine years. The price is not published. It escalates at 100 per cent of the Consumer Price Index, and the Territory holds an option to extend six and a half years, through to mid-2041.

In September 2025 the same government did something else. Under agreements dated 29 September 2025, it guaranteed up to $75 million of Tamboran's $90 million share of the $180 million debt that financed the Sturt Plateau compression facility. If the project defaults and neither the project nor the other guarantors can repay, the Territory repays the lenders.

So the public carries the volume commitment, the price mechanism and the default risk on the same project, and cannot read the contract that sets any of them.

01First gas, and the date on the record

The commissioning is documented by the pipeline owner rather than the seller alone. APA's release gives the date as Tuesday 1 September 2026, says the gas will flow through APA's newly constructed Sturt Plateau Pipeline and link with APA's Amadeus Gas Pipeline, and records Adam Watson, APA's chief executive and managing director, attending and congratulating Tamboran, Daly Waters Energy and the NT Government.

The pipe itself is short. APA's project page describes "a proposed 37 km underground natural gas pipeline" connecting Tamboran Resources' gas development in the southern Beetaloo Basin to the existing Amadeus Gas Pipeline, lists 100 per cent APA ownership, and gives a 2026 proposed opening. The page still reads as a proposal, which places it before the day the gas was commissioned.

What is flowing is appraisal gas. Tamboran's site tour deck, filed with the US Securities and Exchange Commission, lists among its achievements "Secured Native Title and Government Approval under the Beneficial Use of Gas legislation to sell appraisal gas from the Pilot Area", and gives final investment decision as announced in September 2025. NT Budget Paper No. 2 records the same thing independently, describing petroleum "being sold under an exploration permit (appraisal gas) in the Beetaloo Sub-basin", and noting that final investment decision was reached by Beetaloo Energy Australia, formerly Empire Energy Group Limited, and Tamboran Resources Corporation.

That distinction, appraisal gas sold under an exploration permit, returns later in this piece. It is the hinge on which the public's royalty share may or may not turn, and no document opened for this article resolves it.

02Who paid for the pipe and who paid for the plant

APA's construction release is dated 5 November 2025. It said "The estimated ~$66.5 million project will support regional employment and local supply chains, delivering approximately 150 jobs during peak construction", and described welding the 37 kilometre line over the coming months. The same release confirms a 40 TJ/d pipeline, an NT pipeline licence, and a registered Indigenous Land Use Agreement facilitated by the Northern Land Council, both dated September 2025.

That figure belongs on the company's side of the ledger, not the public's. It is APA's own estimate at construction start rather than a final cost, and APA presents it as its project cost, funded by shareholders. It is not a grant, and it is not counted anywhere in this article as public money.

The plant is a different matter. Tamboran's release of 1 September 2026 gives the Sturt Plateau Compression Facility a capacity of 50 TJ/d, about 48.5 MMcf/d, a contracted volume of 40 TJ/d, about 38.8 MMcf/d, a "GSA for up to 14 years with the Northern Territory Government", and a P50 budget of A$141 million, or US$99 million. The facility is held by the SPCF Trust, 50 per cent Tamboran and 50 per cent Daly Waters Infrastructure, LP, which the release describes as under common ownership with Tamboran's upstream joint venture partner, Daly Waters Energy, LP.

Tamboran's site tour deck describes the facility as a simple dehydration and compression plant, states that "Tamboran and DWE each own 50% interest", that "Capital spend is tracking below P50 cost forecast", and carries a stat panel figure of "US$99 million Gross P50 capex". It also gives an "Indicative tariff of ~US$2.5 million per month to upstream operations", an indicative figure running from the facility to upstream operations. Daly Waters Infrastructure, LP is described in Tamboran's release as under common ownership with the upstream joint venture partner, Daly Waters Energy, LP.

On provenance, because it matters when a company's own slide pack is doing this much of the work. The deck is filed with the SEC as Exhibit 99.1 in accession 0001628280-26-059462, with every file in that accession timestamped 31 August 2026. Its cover gives a 2026 Beetaloo Basin site tour at the Shenandoah South wellpad, August 31 to September 1, 2026. It states: "This presentation was approved and authorized for release by Todd Abbott, the Chief Executive Officer of Tamboran Resources Corporation."

03The contract signed in April 2024

The mechanism is on the record in that filing. Gas is delivered "at the APA-owned Amadeus Gas Pipeline (AGP) on a take-or-pay basis at a market-competitive gas price", and that price escalates "at 100% of the Consumer Price Index (CPI)". The filing adds that "The NTG has an option to extend the GSA for a further six-and-a-half years through to mid-2041", and that "The NTG's extension option is at a slightly discounted price". The supply commitment was conditional on the APA transport agreement, the processing agreement and final investment decision. Final investment decision was announced in September 2025, and first gas was commissioned on 1 September 2026.

The price mechanism is on the public record. The price is not, and has never been.

Three different term figures are published, and all three are Tamboran's. The site tour deck describes a "fixed-price (CPI-escalated) take-or-pay contract with NTG for total term of ~15 years. Initial 9-year term with buyer's option to extend to mid-2041". Tamboran's commissioning release of 1 September 2026 says "GSA for up to 14 years". The July 2024 filing gives nine years plus a further six and a half to mid-2041, which is about 15 and a half. The roughly 15 year construction is the one the company's own arithmetic supports. The 14 year figure is an outlier, and it does not reconcile the nine years with the extension option.

The discount arrives with the first molecule. The commissioning release states: "During commissioning, the BJV will sell gas to the NTG at a discounted rate under the long-term GSA, consistent with industry practice." BJV is the joint venture, in the release's abbreviation, and the release does not expand it. Discounting is not new to this contract in any case. The 2024 filing already recorded that the Territory's extension option is at a slightly discounted price. What no document gives, at any point in the term, is a number.

Update, 9 September 2026. The discount is now being paid. Tamboran's release of 8 September 2026 says that "over the weekend" it and Daly Waters Energy "delivered our first molecules of gas from the Beetaloo Basin into the Northern Territory gas network", that "during this commissioning period, Tamboran and DWE will receive a discounted price for the gas, reflecting the interruptible nature of supply during the commissioning period", and that volumes "are expected to ramp up to the full 40 terajoules per day (TJ/d) contracted to the Northern Territory Government under a long-term take-or-pay agreement by early 2027". So the first gas the Territory has taken under this contract was bought at a discount whose size is not stated, from a base price that has never been stated. We found nothing published by the Territory Government or the seller since that discloses the price, the take-or-pay level or the make-up rights. The sealed part of the deal is still sealed.

04The mechanism to watch: the Territory is both the buyer and the backstop

The Territory's exposure is disclosed in its own books, under contingent liabilities, at page 88 of NT Budget Paper No. 2 for 2026-27. Under the heading Strategic gas agreements, the paper says the agreements "commit the Territory to pricing, volumes and timing of gas supply to meet forecast future requirements", and that the risks "are outweighed by the broader benefits of gas security and ability to mitigate risk by selling excess gas to the east coast gas market". Then it sets out the second commitment.

The seller records the same arrangement from its side. Tamboran's site tour deck lists among its 12 month achievements "Secured infrastructure debt from consortium, partially backstopped by the NT Government", and in the compression facility panel states that the infrastructure is "funded via debt facility with Tamboran's share backstopped by the Northern Territory Government". Both the Territory and the seller describe it in their own documents. Neither describes the contract it sits behind.

The Territory is the buyer of the gas and the backstop of the loan that built the plant. The contract that sets both is not public.

The ABC's Jack Hislop reported on 8 May 2026 that the liability was detailed in the NT budget that week for the first time, under the headline "NT taxpayers on the hook for $75m if Beetaloo Basin fracking project defaults", alongside forecast net debt of $12.55 billion. A Tamboran spokesperson told the ABC the company is "highly confident this guarantee will not be called upon given the construction of the facility is within our forecast cost and budget". That reason is testable against the company's own filing, which says capital spend is tracking below the P50 cost forecast.

In the same report, Charles Darwin University Emeritus Professor Rolf Gerritsen called the guarantee "unusual" and "a publicity exercise rather than a serious budgetary commitment". Those are his words and his assessment, not this paper's conclusion. The honest limit sits underneath both views. The gas sales agreement is not public, so the level of the take-or-pay obligation is not on the record, and nothing published establishes what the Territory pays for, or how much of it, in any given year.

05What comes back, and the sold-only rule

Against the volume commitment and the guarantee, the public's return on the resource itself is a royalty, and its shape is set out in the same budget paper.

The Territory's petroleum royalties fact sheet, which carries no publication date, says the Territory "applies a royalty of 10% of the estimated sales value of the raw product (oil or gas)" and that "Royalties are charged on the gross value of the gas at the wellhead." It ranks three ways of arriving at that value: actual sales, described as the preferred method, then comparative sales, then the net-back or work-back method, used only "When actual and comparative sales are not available".

Where the netback method applies, the fact sheet says post-wellhead costs generally include field gathering, processing, storage, pipeline tariffs and transportation. Where that fallback applies, a compression tariff and a pipeline tariff would sit among the post-wellhead costs. No document opened says which valuation method applies to this gas. The budget paper describes wellhead value as calculated "by recognising certain post wellhead costs", and does not use the word deducted. The fact sheet also notes that royalties on ALRA land go to the relevant Land Council. No royalty holiday appears anywhere in the budget paper.

The second rule is narrower and more consequential. Royalties are only paid for petroleum product that is sold. The fact sheet says petroleum products "extracted from a well during the exploration phase, not suitable for sale, or disposed of (including flaring onsite) are not subject to royalties". The gas now flowing is appraisal gas sold under an exploration permit. Whether appraisal gas sold from an exploration permit attracts the 10 per cent is not resolved by any document opened for this article. It should be asked and answered on the record, and it is put here as a question, not a finding.

Beetaloo enters the revenue forecasts only as a possibility. At page 82 the budget paper says: "There is however, potential upside over the forward estimates with petroleum being sold under an exploration permit (appraisal gas) in the Beetaloo Sub-basin." The one hard Beetaloo number on the spending side is small: "$1.4 million per annum in 2026-27 and 2027-28 to support development of the Beetaloo Sub-Basin", listed in the fiscal outlook chapter between a $2 million land release item and a $1 million agriculture item.

06The $224 million from Canberra, most of it road

The Commonwealth committed money to the basin years before the contract. In a release of 18 March 2021 issued jointly with Senator Dr Sam McMahon, the then Minister for Resources, Keith Pitt, said: "The Beetaloo Cooperative Drilling Program is part of the Beetaloo Strategic Basin Plan and the Government's $224 million commitment to the Beetaloo." The same release said the $50 million program was expected to deliver about 10 wells and bring forward at least $150 million of private investment, funding exploration before 30 December 2022.

The department's own plan page tells it differently in one respect. It says the $50 million program was to support $200 million of exploration activity before 30 June 2022, not $150 million before December. Two official versions of what the same program was meant to buy sit side by side. No document opened for this article reconciles them.

The Senate Environment and Communications References Committee interim report, at paragraph 3.31, records as detailed by DISER and Geoscience Australia that the Australian Government "has budgeted a further $175.8 million in related subsidies for the NT", being $173.6 million of road upgrades to support development of gas reserves in and around the Beetaloo, and $2.2 million for land use agreements to accelerate exploration. With the $50 million drilling program that is $225.8 million budgeted, not paid, and $173.6 million of it is road. The department describes the same $2.2 million as a Barkly Business Hub.

The smaller line items on the department's plan page cannot be stacked on top. The $36.2 million is a national Geological and Bioregional Assessment Program, with about $16.9 million allocated to Beetaloo projects to June 2021, and the $19.2 million is CSIRO GISERA across Australia, of which Beetaloo related projects received $1.6 million as at 30 June 2020. Added whole, the components come to about $284.3 million, well above the $224 million headline, which proves they are not additive. On the drilling program's rules, the Senate report records up to $50 million in total, a minimum of $750,000 and a maximum of $7.5 million per well, with applicants able to submit up to three applications. That ceiling is per well, not per applicant.

There is therefore no ANAO audit of the drilling program to cite. The page is a request for audit record, the letter defers to the Senate committee inquiry, and the page names no requester other than Adam Bandt MP. A challenge was brought in the Federal Court. The Melbourne Law School climate litigation database entry for The Environment Centre NT Inc v Minister for Resources and Water, filed in the Federal Court on 28 July 2021, records a challenge to the program instrument, the approval of about $21 million to Imperial and the decision to enter the contracts. The database states that the court found "there was no requirement for the Minister to make enquiries into climate change in relation to the decision". It also states that, for reasons unrelated to climate, "the court found that the Commonwealth's decision to enter into the Imperial Contracts was legally unreasonable". The matter is concluded, and this is the database's account, not the judgment's own words.

07The case for the deal, and what is still sealed

The shortfall the contract answers is real, and two official accounts of its cause are on the public record. The ABC reported on 8 May 2026 that Power and Water Corporation, owned by the NT government, "has been buying emergency gas from LNG exporters to keep the lights on", after Italian-owned Eni's Blacktip gas field began drying up in 2021. The ABC's report of 1 September 2026 puts it differently, saying first gas marked the end of taking emergency gas piped from Japanese gas giant Inpex and from east coast supplies, following damage to the NT's Blacktip field after Cyclone Fina. Both accounts are the ABC's.

The Territory's stated purpose is in its own budget: gas security, with the ability to sell excess gas to the east coast market named as the risk mitigation. The pipeline that carries the gas was built on APA's shareholder capital and is 100 per cent APA owned. Neither of those points is in dispute here, and neither depends on the contract staying sealed.

The rival figure is not a rival. Economist Saul Eslake is reported in the same article describing annual royalty estimates that varied from $36 million to "in excess of $220 million a year". That is a range of royalties per year, against a claim of total economic value over two decades, so the two cannot be set against each other without changing the units. Chief Minister Lia Finocchiaro's quoted words are that this was "a pivotal moment in the Territory's history".

On price, the seller is candid about what it will not say. Tamboran's deck states: "Pricing is confidential; however, the ACCC releases gas offer and bid ranges throughout the year", and cites that "In March 2026, the ACCC announced average contracted East Coast price of ~US$9.20 per mcf between July and December 2025 for supply in 2027". That is a price agreed in the second half of 2025 for 2027 east coast supply. It is not a spot price, and it is not the price the Territory pays.

What remains sealed is the part that decides whether the deal is good. The price per unit is not published. The level of the take-or-pay obligation is not published. Nor are the make-up gas rights, the volume flex, or the force majeure relief. A guarantee of $75 million appears in the budget, under contingent liabilities. The contract behind it is disclosed nowhere, and the same government stands on both ends of it.

If it’s a rort, we cover it.