5. Adapting the gas and electricity markets

Principle 5: Gas and electricity markets must adapt to remain fit for purpose throughout the energy transformation.

Summary

Australia’s gas market can be broadly divided into three segments:

1. An upstream segment, which comprises companies that explore, produce and process gas from a variety of sources. These include fossil fuel sources, such as underground gas reservoirs and from coal mining operations, and non-fossil fuel sources, such as biomethane and synthetic methane. 
2. A midstream segment, which includes gas storage facilities and a pipeline network that transports and distributes gas to homes and businesses. The network comprises larger, high‑pressure pipes to move gas vast distances and smaller, lower pressure pipes to deliver gas to individual consumers. It also includes LNG import terminals.
3. A downstream segment, comprising homes and businesses which use natural gas for heating, cooking, and manufacturing.

This section considers the midstream section as upstream is discussed under Principle 3, and downstream under Principle 1 and Principle 4.

Pipelines link all states and mainland territories in Australia, except Western Australia. The Australian Energy Regulator regulates pipelines in all jurisdictions except Western Australia, where the Economic Regulation Authority (a WA state regulator) performs this role.

As gas production in Commonwealth waters and processed in Victoria reaches end of life, the ability to move gas from where it is produced in the north to where it is needed in the south, is becoming increasingly necessary. Gas pipelines are already a critical feature of Australia’s gas infrastructure, but have capacity limits. Gas storage plays an increasingly important role, particularly during high-demand periods in winter, and import terminals may play a role in the future. However, as observed earlier, gas from LNG import terminals may be more expensive than gas extracted closer to demand centres.

Existing gas infrastructure may be able to be used for low-emission gases in some cases.

Read Section 6 of the analytical report for more information on competition, costs and pricing, and Section 7 for more information on pipelines and import terminals.

Moving gas is expensive

Gas development and transportation has high fixed costs. Ongoing production, however, has lower, short-run marginal costs. As a result, gas is more affordable in locations where:

• gas is consumed where it is produced, or 
• the significant fixed development costs is spread across a large user base consuming a large volume of gas. 

Both exploration for, and development of, gas resources is expensive. This increases barriers to entry for new market participants and tends to lead to market concentration, where a few market participants control a large proportion of the market.

Pipelines, storage and re-gasification terminals

Australia’s gas infrastructure is critical to delivering reliable and affordable energy to households and businesses. This infrastructure has expanded and adapted over time to meet the growing energy needs of Australia and changing sources of supply.

Gas pipelines allow the transport of gas from where it is produced and processed to where it is used. Gas storage facilities are vital for managing demand and supply fluctuations. These facilities store surplus gas produced in summer for use in winter, when the demand is higher. 

Gas storage plays a crucial role in balancing supply and demand. Adequate storage near high-demand areas ensures timely delivery during peak times and helps to address peak day gas supply shortfalls.

Australia’s gas storage facilities 

LNG import terminals, also known as re-gasification terminals, are an alternative way to store and supply gas to consumers instead of traditional pipelines and storage infrastructure. There are four potential LNG import terminals at various stages of development in south eastern Australia. However, there is still regulatory and commercial uncertainty around the development of re-gasification terminals in Australia. 

Proposed LNG Import Terminals 

One of these terminals, operating at maximum capacity, could partially bridge the gap between expected supply and expected demand over the longer term. The combination of two import terminals operating at maximum capacity would be nearly able to bridge the gap between expected supply and expected demand out to 2042, and should be considered alongside other avenues to improve supply or reduce demand. While import terminals can provide supply to reduce the supply gap, this will expose south-eastern markets to the international LNG price. 

Australia’s west coast infrastructure is not subject to capacity constraints 

The most important gas pipeline which delivers gas from WA’s main gas fields to Perth and other gas users on the network is the Dampier to Bunbury Natural Gas Pipeline (DBNGP). Built in the 1980s and spanning 1,530 kilometres, the capacity of the pipeline is far beyond WA’s forecast daily gas supply gap. In addition, the DBNGP was connected to another important transmission pipeline, the Goldfield Gas Pipeline, in July 2023. This provides an alternative gas supply route for consumers in the southern goldfields region. Infrastructure is not anticipated to be a barrier to meeting potential west coast gas shortfalls. 

Australia’s gas markets in transition to 2050

For the physical gas market, the current gas transmission infrastructure may not be suitable for gas needs in the future.

The current local gas distribution network is understood to tolerate a low percentage of hydrogen without adverse effects to infrastructure or end-user appliances. This marginally reduces the carbon intensity of the supplied gas. The IEA estimates that burning green hydrogen in boilers would require three-to-five times more renewable energy than highly efficient heat pumps to deliver the same amount of heat in a home. 

In some low-pressure networks, different infrastructure may tolerate greater percentages of hydrogen. While transporting hydrogen in high pressure pipelines remains uncertain, Australia has reformed its national gas regulations to allow testing of hydrogen blending. Several tests are underway across Australia.

Biomethane is chemically identical to natural gas, and can be used in the existing natural gas infrastructure. While biomethane production may occur at the same location as its end use, it is also likely to develop in multiple locations close to available feedstock, particularly where it is also close to transmission and distribution infrastructure. This will need changes to the network to allow multiple input points. 

Several projects across the world are exploring the potential of other low-emission gases to replace natural gas. Japan, for example, has set targets for synthetic methane – produced through combination of green hydrogen with carbon dioxide – to replace unabated natural gas. As an identical substitute, synthetic methane can enter existing gas infrastructure and appliances. This may create more opportunities for Australia’s LNG industry to continue supplying gas into Asia. Successful deployment would need cost effective green hydrogen production, a rigorous carbon management solution and a deeply decarbonised LNG supply chain. 

Read Section 2 of the analytical report for more information about alternative clean fuels.

Forecast gas shortfalls in south-eastern Australia can be mitigated by moving gas across significant distances, using pipelines and/or import terminals, and by carefully managing storage. This infrastructure may also be adaptable for low emissions gases in the future, particularly with regard to chemically similar products such as biomethane and synthetic methane, and may create opportunities for clean energy exports in the future.