Australian Oil & Gas
Risk Landscape 2026

The Australian Domestic Gas Security Mechanism (ADGSM) is the federal government's power to restrict LNG exports if domestic supply is deemed insufficient. It has never previously been triggered on the east coast. In early April 2026, Minister for Resources Madeleine King issued a formal notice of intent to consider using these powers for the Q3 2026 winter period — a direct response to ACCC findings that the east coast faces a credible gas shortfall if Queensland LNG producers export all uncontracted volumes.[Australian Energy Producers] A 30-day industry consultation window is now open, with a ministerial decision expected by mid-May 2026.

The mechanism that produced this crisis is straightforward. The ACCC's gas inquiry found that production forecasts from key producers were downgraded between December 2024 and early 2026, converting a projected Q4 2025 surplus into a possible 2 PJ shortfall.[ACCC] For winter 2026, southern states are increasingly reliant on Queensland reserves as Victorian offshore supply declines — but pipeline infrastructure limits how much Queensland gas can flow south. The ACCC noted that large storage volumes would be needed before Q3 2026 to cover winter heating demand, and that timeline is already tight.[ACCC]

For investors, the mechanism risk is asymmetric. If the government activates ADGSM restrictions, Queensland LNG exporters — primarily Santos's GLNG project — face volume constraints and potential revenue loss on spot cargoes. If the government does not activate it and a shortage materialises, the political response is likely to be more aggressive intervention in the following period. Either outcome increases the regulatory risk premium on east coast LNG assets.

The Australian government is actively modelling a windfall tax on gas and coal exports. The policy context: LNG export values reached A$65 billion in the 12 months to June 2025, primarily to Japan, South Korea, and China, while industry paid A$22 billion in taxes over the same period.[Investing.com] A Department of Prime Minister and Cabinet document, cited in April 2026 reporting, frames the policy goal as preventing producers from benefiting from high international prices at domestic customers' expense.[Investing.com]

The proposed mechanism — an additional 25% levy on top of existing PRRT and corporate tax obligations — would not operate in isolation. Wood Mackenzie modelling, commissioned independently, found that the combined effective rate for some producers would reach 80–90%.[Investing.com] The Australian Energy Producers CEO Samantha McCulloch cited this modelling in her 2026 ADGO speech, drawing an explicit parallel to the UK's Energy Profits Levy: introduced in 2022 at a 25% rate, it contributed to a 78% effective rate environment and was followed by a doubling of North Sea gas prices and a sharp contraction in exploration investment.[Australian Energy Producers]

The risk for investors is not simply the direct tax impact — it is the investment chilling effect. Australia's Resources and Energy Quarterly (June 2025) flagged rising global trade barriers and softening export outlooks.[Dept of Industry] If a windfall levy is legislated, the pipeline of uncommitted LNG expansion projects — which already face competition from US LNG and Qatari capacity expansion — becomes materially harder to sanction. The IEEFA, which supports an export tax, frames this differently: it argues that tax proceeds could fund domestic energy cost relief. Both views reflect the same underlying fact — the policy is being seriously considered, not merely floated.[IEEFA]

When Strait of Hormuz tanker traffic halted in late February 2026 following escalating Middle East conflict, Australia's fuel supply system was immediately exposed. Brent crude spiked to $82 per barrel intraday, diesel prices surged 50–67%, and over 500 service stations were reported empty.[Discovery Alert] The event was not a systemic collapse — but it demonstrated in real time that Australia's supply buffer is measured in weeks, not months. The International Energy Agency requires member states to hold 90 days of net import cover; Australia consistently falls below that threshold.

The structural cause is well-established: Australia closed its last major domestic refinery in 2021, and now imports 85–90% of its refined petroleum products, primarily from Asian refineries located 3–4 weeks by sea from Australian ports.[Discovery Alert] Alternative supply from the US Gulf Coast extends the shipping lag to 55–60 days. The refinery configuration mismatch compounds this: Australia's demand is heavily weighted toward diesel, while much of Asia's refining capacity is prioritised gasoline. During crude grade shortages or sanctions-related disruptions, this mismatch limits the ability to substitute supply sources quickly.[Discovery Alert]

For oil and gas investors, this risk manifests in two ways. First, upstream producers selling crude internationally are relatively insulated — but the reputational and political cost of visible domestic fuel shortages creates pressure for government intervention across the entire sector. Second, any prolonged Middle East disruption that reduces Asian refinery throughput also reduces demand for Australian crude export cargoes, compressing upstream revenues. UBS forecasted Brent reaching $120 per barrel if Hormuz disruptions were prolonged — but that scenario also carries demand destruction risk.[Discovery Alert]

AEMO forecasts that offshore Victorian gas supply — the primary source of piped gas for New South Wales, South Australia, and Victoria — will fall 36% by 2029 and 58% by 2031.[IEEFA] Simultaneously, overall east coast gas demand is only falling 7% through 2029, which means the supply gap widens materially year on year. The structural shortfall has already been revised forward from 2029 to 2028 in more recent analysis, and a west coast shortfall is now separately projected from 2030.[IEEFA]

Three potential fixes exist on paper, but none is confirmed. First, Queensland reserves: the state holds the largest eastern reserves and lowest production costs, but southbound pipeline capacity from Queensland is constrained. APA Group's East Coast Grid investments — totalling over A$700 million — have increased north-to-south capacity by 24% and aim to cover gaps to 2032, but peak winter 2026 demand may still exceed what the infrastructure can deliver.[IEEFA] Second, new Victorian exploration: no significant offshore discoveries have been reported through late 2025. Third, LNG import terminals: Viva Energy's proposed 140 PJ/year terminal could in principle bridge the gap, but as of the research date it remains unapproved.

For investors, this structural decline creates a two-sided risk. Beach Energy and Cooper Energy, with Victorian offshore assets, face production decline curves that are visible and quantified — any valuation model that does not account for a 36–58% supply fall over five years is materially mispriced. For Queensland LNG producers, the structural decline increases the political and regulatory pressure to retain gas domestically rather than export it — which is precisely the pressure now manifesting in the ADGSM consultation.

The Strait of Hormuz disruption in late February 2026 was not a simulation. Tanker traffic halted, Qatar halted LNG production temporarily, a Saudi refinery was shut following a drone strike, and Brent crude hit $82 per barrel intraday before pulling back.[Discovery Alert] UBS publicly forecast $120 per barrel if the disruption was prolonged. Australia, which sources 85–90% of its refined fuel from Asian refineries that are themselves dependent on Middle Eastern crude, sat exposed with fewer than 25 days of diesel stockpiles.

Geopolitical risk for Australian oil and gas investors operates through two channels. The first is price: Brent crude volatility directly affects the revenue of upstream producers selling crude internationally, while diesel and aviation fuel price spikes pass through to the cost base of every industry that consumes fuel — compressing downstream margins and ultimately consumer demand. The second is supply volume: if Middle Eastern production is disrupted for more than 3–4 weeks, Asian refineries reduce throughput, cutting the supply of refined products available for Australian import. These two channels can move in opposite directions — a prolonged disruption may spike crude prices while simultaneously reducing the volume of refined product Australia can actually purchase.[Discovery Alert]

A separate, lower-profile geopolitical pressure comes from Russian supply. Ukrainian drone strikes on Russian refineries have caused an estimated 0.7–0.8 million barrels per day of processing losses through early 2026, tightening the global refining market and limiting Australia's ability to find alternative supply during Asian refinery outages.[Discovery Alert] Australia's economic security outlook for 2026, assessed by the United States Studies Centre, flags geopolitical tensions and bond yield shifts as compounding headwinds for resource export earnings — already forecast to fall 5% to A$369 billion in 2025–26.[Dept of Industry]

Australian Energy Producers CEO Samantha McCulloch stated explicitly at the 2026 ADGO conference that "investment in Australia is already suffering from regulatory uncertainty, high taxes, slow approvals and unchecked activism."[Australian Energy Producers] This is not industry lobbying rhetoric in isolation — it maps directly onto what the data shows: exploration activity is low, the structural gas shortfall is being brought forward, and no major uncommitted LNG expansion project has reached a final investment decision in the period covered by this research.

The competitive context matters here. New LNG supply is being sanctioned — but not in Australia. US LNG export capacity is expanding, Qatari expansion is proceeding, and the global LNG market faces an oversupply risk in the late 2020s as this new capacity comes online.[Deloitte] Australia's window to sanction new LNG supply while long-term Asian demand contracts remain attractive is narrowing. If the windfall tax proceeds, if ADGSM restrictions become a recurring tool, and if approvals timelines remain extended, the investment case for Australian brownfield and greenfield LNG expansion weakens relative to competing supply sources.

The Resources and Energy Quarterly (June 2025) flagged rising global trade barriers as a softening factor for export outlooks.[Dept of Industry] Australia's 2025–26 resource and energy export earnings are forecast to fall 5% to A$369 billion, driven in part by softening commodity prices and trade barriers affecting market access.[Dept of Industry] For investors, the compounding of lower commodity prices, higher effective tax rates, and constrained regulatory approvals creates a risk environment where the upside of high LNG prices is captured by the government while the downside of low prices and high costs is absorbed by the producer — an asymmetry that historically precedes a decline in exploration commitment.

Three risks appear consistently in forward-looking analysis of the Australian oil and gas sector but have not yet produced named, quantified financial impacts on listed producers. They are worth tracking because the conditions that would make them material are observable — and investors who wait until they are mainstream will be late.

Global clean energy investment reached USD 2.2 trillion in 2025 — a 57% increase since 2022, and now roughly twice the level of investment in oil, gas, and coal combined, according to the Climate Change Authority's Annual Progress Report 2025.[Climate Change Authority] This does not mean Australian oil and gas assets are stranded today — long-term LNG contracts with Japanese and South Korean buyers insulate producers from immediate transition risk. But it sets the direction of travel for capital allocation, and the absence of new greenfield commitments in Australia's upstream sector means the asset base is ageing without replacement.

No named Australian federal or state government has announced a carbon border adjustment mechanism targeting domestic oil and gas production as of the research date. The European Union's Carbon Border Adjustment Mechanism (CBAM) — which applies to imports of carbon-intensive goods including some energy products — creates indirect exposure for Australian exporters to the EU, but Australia's LNG exports primarily flow to Asia, where no equivalent mechanism is in place. This risk is real in a 5–10 year horizon but not yet a 2026 pricing factor.[Argus Media] The environmental approvals reform that was expected to introduce a "Nature Positive" legislative framework has been delayed to 2026, extending regulatory uncertainty for projects requiring environmental sign-off.[Argus Media]

The risk environment for Australian oil and gas in 2026 is unusually concentrated in observable, time-stamped events. The mid-May 2026 ADGSM decision is the most immediate: if the Minister activates volume restrictions, Queensland LNG exporters face reduced spot cargo revenues in Q3 2026 and a strengthened precedent for future activation. If she does not activate it, watch the ACCC's next gas inquiry release for whether the Q3 2026 shortfall risk has been resolved by market action or deferred to 2027.[ACCC]

The windfall tax decision timeline is less precisely dated but politically connected to the ADGSM outcome. A gas shortfall in winter 2026 that attracts public attention would strengthen the political case for a windfall levy — meaning the two risks are correlated. If gas shortages appear on the ABC by July 2026, the probability of a windfall tax increases. Watch the federal Budget 2026–27 update (typically October) for any revenue measure language referencing LNG exports.[Australian Energy Producers]

For the structural supply risk, the watch signal is simpler: any announcement by Beach Energy or Cooper Energy of material downward revisions to Victorian offshore production guidance would confirm that the AEMO decline curve is tracking as forecast — or accelerating. Similarly, any FID announcement on the Viva Energy LNG import terminal would indicate that the market has priced in the supply gap and private capital is responding without government mandate.