Australia may still stand as the world’s third-largest LNG exporter (behind Qatar and the United States) but the foundations of that success are faltering. The September 2025 start-up of the Barossa Project, designed to feed Darwin LNG, and ConocoPhillips’ November drilling success in the Otway Basin offer welcome headlines, but they do little to offset the deeper structural imbalance now shaping Australia’s national gas landscape. Most production remains concentrated in Western Australia and Queensland, far from the south-eastern population centres that depend on it, while new developments struggle to keep pace with both export commitments and rising domestic demand. At the same time, new investment is increasingly deterred by regulatory tightness and stringent environmental requirements, leaving Australia’s long-term gas outlook more fragile than its export rankings suggest.
For decades, exploration was one of Australia’s greatest strengths: since the 1960s, hydrocarbons were discovered at a rate of roughly a billion barrels of oil-equivalent per year. But after 2015 that trend began to change. Offshore exploration has declined and is now concentrated almost entirely in the west and northwest – regions with little population, limited domestic industrial demand, and a direct pathway into Asia-facing LNG terminals. Australia’s geography has amplified this imbalance: the most prolific basin, North Carnarvon, lies off the western coast, while nearly two-thirds of the population and most of the country’s industrial load are located in the east, with no pipeline linking the two. As a result, most new offshore discoveries naturally flow into LNG export plants rather than the domestic market, deepening the divide between where gas is produced and where it is consumed. This structural disconnect has become the central fault line in Australia’s energy system, and it has grown more severe as LNG exports have expanded.
Recent drilling activity shows glimmers of hope but underscores how little has been done in recent years. The first offshore hydrocarbon exploration well since 2023 – Chevron’s Deep 1 and Dino South 1 – was drilled only in May 2025. In November, ConocoPhillips, alongside 3D Energi and Korea National Oil Corporation, spudded its first well under the Otway Basin Program near shores of Victoria province (53 km offshore from Port Campbell, 12 km from existing gas production wells), a government-funded initiative designed to shore up southeastern supply. Just two weeks later, on November 17, the company announced it had struck gas in the two target reservoirs (Waare A and Waare C) – the first discovery in the region in four years – adding that six wells are planned across two permits. However, the potential flow rates and ultimate resource recovery are still to be determined.
The consequences of waning exploration activity are increasingly visible in production trends. While national gas output more than doubled between 2015 and 2021, rising from around 5.5 million cubic metres per month to roughly 13 million cubic metres, it has since plateaued. Over the last 4 years production has hovered around an average of 13 million m3/month, signalling that without new exploration, the country has already reached a stagnation point and risks slipping into structural decline.
With national output flattening, the weakest point in Australia’s gas system is increasingly the east coast, where demand keeps rising even as local supply fails to keep pace. Eastern Australia’s gas system is built around Queensland’s CSG (coal seam gas)-LNG plants, which draw from the domestic market and have steadily increased their intake. When long-term lower-priced contracts expired between 2016 and 2019, domestic prices rose sharply and began tracking regional Asia LNG netback values – the price LNG exporters could earn overseas, minus regasification and shipping. That linkage now defines the market: in Queensland, New South Wales (NSW) and Victoria, gas started behaving like a globally traded commodity, not a locally priced utility. Each winter, gas flows southward, but the constrained pipeline network cannot meet peak demand, causing local tightness and sharp price spikes. Government have required CSG-LNG exporters to offer uncontracted volumes to the domestic market before selling spot cargoes abroad. An east-coast price cap of A$12/GJ, introduced in summer 2023 and extended up to 2033, aims to protect consumers from global volatility. Despite the cap having exemptions, allowing undeveloped fields to be priced under a “reasonable price” mechanism, the result is a system that suppresses price signals just when investment is needed most.
Pressure on supply is exacerbated by state-level environmental opposition. In NSW and Victoria, local resistance has prevented new projects for years. The Narrabri CSG development, which could supply up to half of NSW’s demand, spent a decade stalled by protests, litigation and political friction before finally being approved in 2020. Victoria’s ban on onshore gas exploration from 2017 to 2021 – still prohibiting coal seam gas – ensured that Queensland remains the only state producing CSG. This geographic bottleneck forces the market to rely on higher-cost southern basins and long-distance interstate flows, raising prices, increasing winter risks, and tightening supply further.
At the same time, the electricity system has become more fragile. This summer, wholesale power prices reached A$107 per MWh – a decade high – as supply stress collided with ageing coal-fire power stations that still make up around 65% of the energy mix. Outages during high demand are becoming more common, amplifying the consequences of any gas shortage.
The unstable regulatory environment is beginning to scare away investors. In September, Abu Dhabi National Oil Company abandoned its planned US$19 billion acquisition of Santos, deterred by regulatory risk, domestic gas obligations and environmental pressures. Without major external investment, Australian producers face stagnation and an increasing likelihood of failing to meet both domestic commitments and international contract terms. ExxonMobil has already paused recent investments, citing the unpredictability of approvals and fiscal settings. Woodside’s North West Shelf expansion project – the largest export facility in the country – only received provisional clearance in May after more than six years in the approvals pipeline.
The final irony is that Australia may soon need to import LNG to stabilise the very market it once dominated. Several regasification projects are advancing. Squadron Energy’s Port Kembla terminal is expected to begin operations in mid-2026. Vopak has acquired an FSRU (floating storage and regasification unit) for its Port Phillip Bay project in Victoria, with imports projected to begin in 2029. Four additional import terminals are under construction across Victoria, South Australia and New South Wales. But FSRUs are costly and scarce, and any imported LNG would force domestic prices to track not only global spot levels (already volatile) but also shipping and regasification costs.
For this reason, expanding domestic local supply (by projects similar to the Otway Basin exploration near to the southeast coast) remains the lowest-cost, lowest-emission, and most strategic solution. Yet approvals are slow, regulatory obligations are heavy, and investor confidence is wavering. If Australia cannot reset its approach, capital will migrate to more welcoming jurisdictions. Timor-Leste is already preparing a new exploration bidding round for 2026, having secured revised maritime boundaries and signalling its capability to attract upstream investment that Australia appears unable to accommodate.
Australia’s gas system is entering a decisive phase. A decade of declining exploration, increasing regulatory intervention, environmental constraints and infrastructure fragmentation has pushed the market toward structural imbalance. The Barossa start-up and the Otway discovery show that new supply remains possible – but unless the policy framework shifts, these isolated wins will not prevent deeper shortages, higher prices and eroding investor confidence. The country must choose whether to remain a global LNG power with a secure domestic market or allow its system to drift toward chronic vulnerability.
By Natalia Katona for Oilprice.com