Australia's energy outlook: a mixed bag of hope and concern

Recent drilling activities have shown promising signs—but also underscore how little work has been done in recent years. Chevron’s Deep 1 and Dino South 1, the first offshore oil and gas exploration wells since 2023, were not completed until May 2025. In November 2025, ConocoPhillips—partnering with 3D Energy and the Korea National Oil Corporation—drilled its first well in the Otway Basin off Victoria’s coast (53 km from Port Campbell and 12 km from existing gas production wells), under a government-funded initiative aimed at bolstering resource supply in southeastern Australia. Just two weeks later, on 17 November 2025, the company announced natural gas discoveries in two target reservoirs (Waare A and Waare C)—the region’s first such finds in four years—and plans to drill six wells across two licences. However, potential output and ultimate resource recovery rates remain undetermined. The consequences of reduced exploration activity are becoming increasingly evident in production trends. Although Australia’s natural gas output more than doubled between 2015 and 2021—from roughly 5.5 million cubic metres per month to about 13 million cubic metres per month—it has since plateaued. Over the past four years, national gas production has hovered around an average of 13 million cubic metres per month, indicating that—without new exploration—the country has hit a production ceiling and risks entering structural decline. As national output stagnates, the weakest link in Australia’s gas system is increasingly apparent along the east coast—even as local supply fails to keep pace with rising demand. The eastern Australian gas system is built around liquefied natural gas (LNG) facilities in Queensland’s coal seam gas fields, which draw gas from the domestic market and steadily increase their consumption. When long-term low-price contracts expired between 2016 and 2019, domestic gas prices surged sharply and began tracking the netback value of Asian LNG—the price LNG exporters can fetch overseas, minus regasification and transport costs. This linkage defines Australia’s gas market reality: in Queensland, New South Wales, and Victoria, gas now behaves like a globally traded commodity rather than a locally priced utility service. Every winter, gas flows south—but pipeline constraints prevent the network from meeting peak demand, triggering local supply shortages and price spikes. The government requires coal seam gas LNG exporters to offer uncontracted volumes to the domestic market before selling spot cargoes overseas. A price cap of A$12 per gigajoule on the east coast, introduced in summer 2023 and extended to 2033, aims to shield consumers from global market volatility. Though exemptions allow undeveloped fields to price under a ‘reasonable price’ mechanism, the result is dampened price signals precisely when investment incentives are most needed. Environmental opposition at the state level further intensifies supply pressures. In New South Wales and Victoria, local resistance has blocked new projects for years.

With the Labor Party trailing One Nation in polls, can export gas reserves fill the southern shortfall?

On 10 September, the Australian Labor Government released a draft Gas Reserve Bill for public consultation. The share of gas that exporters must reserve for the domestic market was set at a ‘maximum of 20%’. Four months earlier, the proposal had stated ‘equivalent to 20% of exports’, scheduled to take effect from 1 July 2027. Now, 20% has become an upper limit; the actual percentage will be determined annually by the regulator, and the obligation’s commencement date has been postponed to 1 January 2028. Gas fields and exporters face an annual, potentially fluctuating figure; southern users face a starting point delayed by six months; and the Australian Energy Market Operator (AEMO) forecasts a supply shortfall in most climate scenarios for 2030. From ‘15%–25%’ to ‘maximum 20%’ This policy has undergone three revisions over nine months. On 22 December 2025, a joint statement by three ministers stipulated that exporters must reserve 15%–25% of their production for the domestic market, with the precise proportion to be finalised after consultation. On 7 May 2026, it was fixed at ‘equivalent to 20% of exports’, effective from 1 July 2027. The 10 September draft consultation document revised it again to ‘maximum 20%’. According to ABC reporting, the Australian Energy Regulator (AER) will annually determine the mandatory volume to ensure domestic supply covers 110% of forecast demand—capped at 20% of exports—with Western Australia and the east coast calculated separately. Energy Minister Chris Bowen described this revision as a ‘reasonable calibration’. His exact words were: ‘The 20% figure remains central to the policy—but stockpiling gas Australians don’t need makes no sense.’ Resources Minister Madeleine King added that if supply in the western market is sufficient, the obligation could fall to zero. The joint statement notes exporters may supply up to an additional 200 petajoules annually—‘enough to avoid the maximum 140-petajoule shortfall forecast by AEMO’. In the statement, Bowen observed that Australia—one of the world’s largest gas producers—has long been in an ‘anomalous situation’ of domestic shortages and soaring prices. Western Australia already operates its own state-level reserve scheme requiring 15%. The 140-petajoule shortfall is real—but the question is where it occurs. How will reserved gas get to the south? AEMO’s March 2025 Gas Statement of Opportunities (GSOO) spells this out clearly. The shortfall is concentrated in the south, driven by declining output from southern gas fields such as those in Victoria. To flow south, northern gas must travel via the South West Queensland Pipeline—a route the report expects will increasingly hit its transmission capacity limits. The report states plainly that, even with committed pipeline expansions, ‘north-to-south gas transportation will continue to face transmission constraints’. In its supply-demand modelling, AEMO has already assumed that Queensland LNG producers will release gas—including uncontracted volumes otherwise destined for spot export—into the domestic market whenever shortfalls arise.

Queensland LNG holds key to Australia’s East Coast gas gap

2 days ago

AEMO forecasts an east coast gas shortfall from 2029 as southern production declines, highlighting Queensland LNG's critical role. New domestic reservation policies and pipeline expansions aim to bridge the gap between falling local output and rising demand.

icis

2026-10-16

Queensland LNG holds key to Australia’s East Coast gas gap

Queensland LNG holds key to Australia’s East Coast gas gap

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