The decommissioning rort

Australia’s offshore gas industry has spent decades building an enormous physical footprint on the Australian continental shelf. The decommissioning task covers:

More than 700 wells to be plugged and abandoned permanently. 7,600 kilometres of pipelines to be removed. 520 subsea structures. 57 platforms with a combined weight of 755,000 tonnes — equivalent to the steel in 14 Sydney Harbour Bridges. 11 floating facilities including FPSOs and floating LNG vessels.

This infrastructure accumulated since ExxonMobil drilled Australia’s first offshore well in 1965. Removing it requires specialist vessels, engineering expertise, and environmental management on a scale Australia has almost no domestic experience with. The Government’s 2024 Offshore Decommissioning Directorate was established specifically to begin building that capability.

This is not a problem for the distant future. The Government’s roadmap notes that half the work is expected to start this decade.

Under Australian law and the PRRT framework, decommissioning costs are classified as deductible expenditure — they can be offset against a company’s tax liability. For projects that have paid substantial PRRT, decommissioning costs generate a refund: the company receives back 40 per cent of the cleanup cost from the government. For projects that have paid corporate income tax but little PRRT, decommissioning costs reduce income tax at 30 per cent.

The combined effect: research by IEEFA found that the government could end up bearing up to 58 per cent of the total decommissioning cost through these mechanisms. For ExxonMobil’s Bass Strait fields — which have paid substantial PRRT since production began decades ago — the 58 per cent figure may apply. For the large offshore LNG projects — Gorgon, Wheatstone, Pluto, Ichthys, Prelude — which have paid minimal or zero PRRT, the government exposure is lower on the PRRT side, but income tax deductibility still applies at 30 per cent.

This is the decommissioning rort’s central mechanism: the same tax structure that allowed companies to avoid PRRT during the productive, profitable decades of gas extraction also allows those companies to share their cleanup costs with the public. The two are not separate problems. They are the same design flaw expressed at different points in the project lifecycle.

The most instructive recent case of what happens when decommissioning goes wrong is the Northern Endeavour floating production vessel, moored 550 kilometres northwest of Darwin.

In 2016, Woodside paid a newly-formed one-person company called Northern Oil and Gas Australia (NOGA) A$1 to take over the Northern Endeavour — including an estimated A$260 million in decommissioning liabilities. NOGA went insolvent in 2019. The unmaintained vessel remained stranded at sea, posing escalating environmental risk. The Commonwealth was forced to take over management of the vessel.

The Government subsequently levied the entire offshore petroleum industry to recover its costs. Chevron Australia — a company with no interest in or involvement with the Northern Endeavour — has now paid more than A$276 million towards the cleanup cost of a vessel it never owned. In 2024 alone, Chevron paid A$95 million under this industry levy.

Woodside sold the Northern Endeavour vessel for A$1 — plus transfer of A$260 million in decommissioning liabilities — to a company that then went insolvent. The vessel sat unmaintained at sea. The Commonwealth intervened. The entire industry was levied to pay. Chevron alone has paid A$276 million for a vessel it had no connection to.Summary of events, IEEFA / Australia Institute / Chevron Tax Transparency Report 2024

In 2021, the Government introduced ‘trailing liabilities’ — making previous owners of offshore titles liable if new owners cannot afford to decommission. This was designed to close the Woodside/NOGA loophole. But the Northern Endeavour case had already demonstrated the risk: a profitable company can legally transfer a massive decommissioning liability to an entity without the financial capacity to meet it.

The decommissioning problem is not purely theoretical. Several offshore gas fields are already in various states of abandonment, and regulators are already issuing enforcement notices for failing infrastructure.

Seven Group Holdings (SGH) — the Kerry Stokes company that owns 30 per cent of Beach Energy and which, as Article 8 of this series documented, also has significant media interests — owns the Longtom gas field off the Gippsland coast. NOPSEMA, the offshore environment regulator, found a decade of subpar performance at the field and ordered SGH to fix a well that has been leaking gas at a small rate since at least 2023. SGH failed to meet three prior commitments it had made to the regulator.

Production from Longtom ceased in 2015 following an electrical fault. The gas has been stranded ever since. SGH has a decommissioning provision that assumes its pipeline remains on the seabed — an assumption regulators have not yet formally approved.

Longtom is a small field. But it illustrates the pattern that IEEFA and other analysts have documented at scale: decommissioning is routinely delayed by companies, infrastructure is left in place well beyond its operational life, and when regulators finally act, the standards established for responsible closure were not being met.

There is one additional mechanism through which gas companies are seeking to avoid or defer their decommissioning obligations: repurposing infrastructure for carbon capture and storage (CCS).

Santos withdrew decommissioning plans for its Bayu-Undan field in the Timor Sea — a field approaching the end of its producing life — and proposed instead to use the infrastructure for CCS. The proposal was made without Santos releasing any cost estimates or technical studies demonstrating its feasibility. If CCS projects are approved as alternatives to decommissioning, they defer the cleanup liability indefinitely — and potentially allow companies to claim public subsidies for CCS activities using infrastructure that was already due for removal.

The Government’s Offshore Decommissioning Roadmap addresses this risk, noting the need to ‘ensure that decommissioning remains the responsibility of the offshore industry’. Whether CCS repurposing proposals are assessed rigorously enough to prevent this from becoming a systematic avoidance mechanism remains to be seen.

The decommissioning rort follows directly from the extraction rort this series has documented across nine articles.

The gas industry extracted hundreds of billions of dollars of public resources over decades while paying minimal resource tax. The PRRT — designed to capture Australia’s share of the super-profits from that extraction — collected less than beer excise. The companies that paid the least PRRT during their productive decades are now approaching the period where their infrastructure requires decommissioning.

Because they paid minimal PRRT, they have minimal PRRT liability against which to offset decommissioning costs. Instead, they use income tax deductibility — a 30 per cent offset that is not resource-tax specific but is available to any corporate taxpayer. The Australian public pays 30 per cent of the cleanup for an industry from which it never received more than a token share of the extraction profits.

If the PRRT had been designed properly — if it had collected at anything approaching Norway’s 78 per cent, or even the 25 per cent the ACTU now proposes — the companies would have paid substantial resource tax during the productive decades. The PRRT refund mechanism would then work as designed: the government returns 40 per cent of decommissioning costs, partially offsetting prior resource rent payments, in an arrangement that was always intended to be part of the overall tax economics. Instead, because almost no PRRT was ever paid, the decommissioning period is purely a cost.