The Australian energy landscape: a mixed bag of hope and concern

A global LNG export powerhouse facing imminent import needs Australia is the world’s third-largest liquefied natural gas (LNG) exporter—behind Qatar and the United States—but since 2021, domestic natural gas production has plateaued at around 13 million cubic meters per month. A sharp decline in domestic exploration activity has led to gas supply shortages in the eastern states, frequently triggering price spikes. Regulatory hurdles and environmental opposition are impeding new investment, threatening both the stability of Australia’s domestic gas production and its export commitments. Industry expert Natalia Katona, writing for OilPrice.com on 22 November 2025, argues that Australia’s gas market now faces critical policy choices. Australia ranks third globally in LNG exports—after Qatar and the United States—but the foundation of this success is eroding. The Barossa project, launched in September 2025 to supply feedstock for the Darwin LNG facility, and ConocoPhillips’ successful November 2025 drilling in the Otway Basin, are welcome headlines—but they barely offset deeper, structural imbalances now reshaping Australia’s gas landscape. Most gas production remains concentrated in Western Australia and Queensland, far from the southeastern population centers that depend on it; meanwhile, new developments struggle to keep pace with export commitments and rising domestic demand. At the same time, new investment is increasingly hampered by tightening regulation and stringent environmental requirements—rendering Australia’s long-term gas outlook more fragile than its export ranking suggests. For decades, exploration has been one of Australia’s greatest strengths: since the 1960s, hydrocarbon discoveries averaged roughly one billion barrels of oil equivalent per year. But this trend began shifting after 2015. Offshore exploration has declined sharply and is now almost entirely confined to the west and northwest—regions with sparse populations and limited domestic industrial demand, but with direct access to LNG infrastructure serving Asian markets. Australia’s geography exacerbates this imbalance: the most prolific basin, the North Carnarvon Basin, lies offshore along the western coast, while nearly two-thirds of the country’s population and most of its industrial load are concentrated in the east—with no pipeline connecting the two. Consequently, most new offshore oil and gas discoveries automatically flow to LNG export facilities rather than the domestic market—widening the gap 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 grows more acute as LNG exports expand. Recent drilling activity offers glimmers of hope—but also underscores how little has been done in recent years. Chevron’s Deep 1 and Dino South 1—the first offshore oil and gas exploration wells drilled since 2023—were only completed in May 2025. In November 2025, ConocoPhillips, in partnership with 3D Energy and Korea National Oil Corporation, drilled its first well in the Otway Basin off Victoria’s coast—53 kilometers from Port Campbell and just 12 kilometers from existing gas production wells. This government-funded initiative aims to bolster resource supply in southeastern Australia.

Three years before the supply shortfall—but the Labor government has already imposed domestic supply quotas on exporters

LNG exporters must annually sell up to one-fifth of their export volumes domestically. The exact quota is set by the energy regulator at 110% of domestic demand—and takes effect from mid-2028. Resources Minister Madeleine King declined to specify how much prices might fall, citing commercial sensitivity of modeling results. According to forecasts by the market operator, the eastern seaboard supply shortfall will not materialize until 2029—even then, only under certain climate scenarios. Three-quarters Proponents of the retention scheme wield a compelling set of figures. In its March 2025 ‘Gas Statement of Opportunities’, the Australian Energy Market Operator (AEMO) noted that gas exported from Queensland’s Curtis Island accounts for roughly three-quarters of the eastern seaboard’s annual consumption; Queensland’s LNG producers control about 70% of the region’s proven and probable reserves. Prior to 2022, wholesale gas prices remained below AUD 10 per gigajoule—but surged to AUD 60 following Russia’s invasion of Ukraine. Western Australia has long maintained its own state-level retention requirement of 15%. Energy Minister Chris Bowen stated: “It’s been too long that Australians have watched our gas leave our shores.” Yet these figures point to problems the retention scheme cannot solve. AEMO’s projected shortfall is concentrated in southern eastern Australia, driven by persistent declines in southern gas field output and chronic congestion on the main north–south pipeline. Winter peak demand is increasingly reliant on storage facilities and pipeline capacity alone. As reported by ABC, even Western Australia—which already has a retention regime—is projected to face severe shortages in the 2030s. The retention scheme merely redirects gas already produced in Queensland toward domestic buyers; it does not widen pipelines or revive exhausted southern fields. 110% suppresses prices for *new* gas fields The trouble lies in that percentage. As reported by ABC, regulators must annually set the domestic supply target at 110% of actual demand—a figure Minister King describes as “moderate oversupply.” Currently, eastern seaboard wholesale prices range between AUD 10 and AUD 11.5 per gigajoule. The Australian Petroleum Production & Exploration Association (APPEA), citing estimates from the Australian Competition and Consumer Commission (ACCC), notes that the marginal cost of new supply falls between AUD 9.50 and AUD 13 per gigajoule. A system deliberately engineered to create 10% oversupply directly depresses the very price band upon which new gas field development decisions hinge. Moreover, the legislation includes a “must-sell” obligation—prompting industry concerns that producers may be forced to sell gas below cost. APPEA CEO Samantha McCulloch stated bluntly that the government “cannot expect the industry to invest billions of dollars in developing new supply” while simultaneously suppressing prices—adding that “any price effect may only be temporary.” Santos CEO Kevin Gallagher put it more simply in September: Australia does not lack gas—“it just needs to get more out of the ground.” The Labor government has refused to release its price impact analysis. APPEA cites the government’s own assessment, estimating the scheme will incur AUD 75 million in additional regulatory costs. The Coalition’s nine conditions The Coalition does not oppose retention in principle. Shadow Resources Minister Susan McDonald and Shadow Energy Minister Dan Tehan, on 2 September, outlined nine conditions—centered on ensuring the retention scheme delivers *new* production, benefiting both domestic and export markets; safeguarding existing contractual obligations; recognizing pre-existing state-level retention arrangements (e.g., in WA); lowering prices through increased supply—not price controls—with the goal of aligning prices near long-run marginal cost; and strengthening Australia’s domestic gas security framework to prevent shortages.

APA to Build Major Australia Gas Pipeline to Avert Shortfalls

14 hours ago

APA Group finalized investment in the A$920 million Bulloo Interlink Pipeline to transport natural gas from Queensland to New South Wales. The project targets commercial operations by winter 2029 to address projected energy security shortfalls in southeastern Australia.

bloomberg

2026-10-21

APA to Build Major Australia Gas Pipeline to Avert Shortfalls

APA to Build Major Australia Gas Pipeline to Avert Shortfalls

FAQ