Declining supply and entrenched demand in all three of Australia’s domestic gas markets – the East Coast, West Australia (WA) and the Northern Territory (NT) – is creating similar issues. We tend to think of these as essentially separate, disconnected and divided by vast swathes of land. But the reality is that scarce local supply has been sanctioned in all three markets and domestic demand remains resilient.
Starting with the largest, the increasingly tight East Coast market continues to hit headlines as it deals with supply crises, government interventions and new regulations. Undersupplied, underinvested and underexplored, it is also divided by activism and state and federal politics.
Traditionally more sedate, the WA market has slowly drifted in a similar direction. New forecasts highlighting potential gas shortages have sparked more state intervention in the market, including banning LNG exports by certain suppliers.
The NT market might be the smallest, but it’s ahead of the curve, already experiencing emergency upstream shortages that sparked increased domestic supply from LNG exporters.
Much has been written in isolation of the challenges facing each of Australia’s markets, particularly the East Coast. But very little work has been done to compare the commonalities driving all three to the brink of shortage, and beyond.
Our paper will explore the supply situations and policy decisions in each zone that have brought us to our current situation. It will review the most likely and cost-effective new supply sources and the solutions to better balance the market in each zone.

Each Australian gas market has followed a different trajectory, with the west being defined by large LNG projects, a relatively small domestic market, and a long-standing domestic gas reservation that historically ensured the domestic market was oversupplied and prices remained low.
The east coast market instead relied for decades on supply from the Cooper and Gippsland Basins which only supplied the domestic market, with both now in decline. The establishment of LNG export capacity in Queensland connected the east coast market to international markets for the first time and was followed by bans and moratoriums on gas development in some jurisdictions.
Notwithstanding their very different history, both markets now face potential domestic supply shortages within a decade, and both have experienced government intervention in the past 12 months. Government’s stated aims are to lower prices, ensure ongoing investment in supply, reduce emissions, and continue LNG exports.
This paper examines forecast supply and demand, the impact of government intervention, net zero policies and the importance of maintaining Australia’s export reputation as a reliable supplier. Getting this balance just right will require a challenging ‘Goldilocks moment’, with serious consequences if we get it wrong.

In August 2023, Western Australia updated its domestic gas reservation policy to ban onshore gas exports through the existing pipeline network, primarily affecting the Perth Basin. While the policy update aimed to secure domestic gas supplies amid projected shortfalls, it may complicate the outlook, with restricted access to capital, reduced incentives for substantial investments in large-scale developments, and the elimination of a potential future demand source. WA's domestic gas consumption is expected to peak by the end of this decade and then steadily decline as part of the state's net-zero ambitions. In contrast, the LNG market especially in Asia is set to grow into the 2040s, offering lenders demand certainty. This paper assesses 15 potential new gas developments for the domestic market under various onshore policy scenarios. WA’s domestic gas market is projected to require 9-10 trillion cubic feet (TCF) of gas over 2023-50. Existing Domestic Market Obligations (DMOs) are expected to supply approximately 5 TCF during this period, leaving a gap to be filled by both the onshore resource base, around 3 TCF, and potential new DMOs, contributing an additional 2.5 TCF. Based on the scenario modelling, the paper reiterates the importance of gas in WA's energy transition and the need to ensure future supply failing which prices could rise to LNG netback or trigger further intervention.

There is a huge unconventional shale gas resource in the remote heart of the Northern Territory with the potential to trigger big new gas developments in Darwin, including export LNG, and underpin the chronically undersupplied East Coast market. And yet despite this promise, the Beetaloo is not universally viewed as a viable commercial project.
Nonetheless, the Beetaloo is one of the hottest topics in Australia’s upstream sector, and two of its key operators, Tamboran and Empire, are closing in on FID for initial gas production. So why are many in the market still sceptical the play will work?
To create a definitive answer, we will investigate the key factors required to make the Beetaloo commercially viable. We will evaluate what a realistic Beetaloo gas project could look like across a range of resource sizes, EUR/production profiles, gas prices, and development scenarios.
The work aims to understand the key cost barriers and price hurdles that need to be broached for economic success. From the economic models, we will compare breakeven prices and unit production costs across a range of project scenarios.
There has also been extensive press coverage about the environmental impact of a Beetaloo development. Operators have low CO2 gas and the potential to sell low-carbon or net-zero gas or LNG. We model emissions profiles as well as review options for, and the cost of, dealing with CO2.
From here we can determine the full range of economic pitfalls and potential rewards that lie in wait for ambitious Beetaloo operators.

We present our analysis of the east coast fundamentals and our long-term gas price assumptions through 2032 in Wallumbilla and the Southern States. The paper concludes that the market has a chance to return from the brink of dysfunction. The replacement of lower-cost legacy supply near demand centers with higher-cost CSG from a remote region in another state through limited infrastructure – or LNG imports – fundamentally signals higher prices even as domestic demand declines from 526 PJ in 2022 to 477 PJ in 2032, with possible intermittent increases during coal retirements. Added to the mix is long-term demand and policy uncertainty, the current era of monetary tightening and vanishing finance for fossil fuel projects. The relationship between east coast gas producers in Australia and the federal government now appears to have de-escalated following the inclusion of potential price cap exemptions in the recently released mandatory code of conduct for the domestic wholesale gas market. Gas remains a crucial long-term input in the manufacturing sector and will continue to support gas-intensive industries if price alignment can be achieved, which is what will be needed to ensure the gas sector's longevity in the energy transition. We also discuss the role of gas in the NEM which is headed for an increasingly chaotic coal exit, keeping gas extremely relevant to support system resilience.