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3. Finding new sources of gas to meet demand

Principle 3: New sources of gas supply are needed to meet demand during the economy-wide transition. Government policies to enable natural gas exploration and development should focus on optimising existing discoveries and infrastructure in producing basins, applying technology-neutral approaches to exploration data acquisition (to minimise seismic surveying where possible), prioritise energy security, and align with our net zero emissions targets. Robust environmental approval processes are key to the social license of the gas industry.


Gas remains crucial to our economy and region to support the transition to net zero. To meet our future energy needs and decarbonise our economy, we need continued gas supply:

  • at the right time
  • in the right place
  • with high levels of workplace safety and conditions
  • at the lowest cost
  • at the lowest emissions intensity 
  • with the least impact on our environment
  • with the maximum benefit for communities.

In the near term, there is concern around the potential for demand to outstrip supply over coming years. This annual supply gap is forecast to emerge in 2028 on the east coast and by 2030 on the west coast if there is insufficient new supply developed. Meeting these supply challenges will need location-specific solutions, including:

  • maximising production from existing resources and developing adjacent new gas fields supplying the domestic market, provided environmental impacts can be managed
  • demand reduction through the net zero sectoral plans
  • gas substitution through expanding the supply of low emission gases
  • LNG producers making more gas available to domestic users
  • expanding gas infrastructure, including pipelines and LNG import terminals.

We will likely need to explore all of these solutions to meet our gas demand needs through to 2050.

Developing new gas supply is technically challenging, expensive, and a lengthy process. Gas fields deplete as gas is extracted. Exploring for gas requires advanced technology and techniques, such as seismic surveys which, as with any other human activity, have the potential for some level of impact on the environment and must be managed accordingly. We need new and continued investment to develop and sustain supply to meet demand. This investment is facilitated by a strong regulatory framework that aims to balance environmental and social impacts while encouraging new supply. There is always room to improve our regulatory settings. They must remain fit for purpose to achieve Australia’s goals.

Without continued investment in Australia’s gas sector, both the east and west coast markets could experience gas price and supply volatility. In the near term, potential shortfalls in gas supply could increase volatility in gas markets and drive up prices. Without further investment in new gas supply and gas infrastructure, these shortfalls will negatively affect Australian households and businesses, and the reliability of our electricity system.

Alternative gas sources may also meet demands for gas. Low-emission gases such as hydrogen and biomethane may become important elements of Australia’s energy landscape, as well as adding to our exports. These low-emissions gases are not yet produced at a scale or price able to compete with natural gas. However, they are expected to become more competitive as technology costs reduce and these gases are produced on a commercial scale.

Read Appendix A for more information about the scenarios that are used to help shape forecasts in this section. 

Read Section 2 of the analytical report for information about alternative clean fuels, Section 5 of the analytical report for the natural gas supply outlook, and Section 7 for analysis of options to close the supply gap.

Where is natural gas produced today? 

While Australia has substantial gas resources, they are not evenly spread. Most of Australia’s remaining gas reserves are offshore, in the Northwest Shelf region, onshore Queensland, and onshore and offshore Northern Territory. This places most of the Australian gas resources and reserves geographically far from demand centres in the southern states. Gas produced in Commonwealth waters, south of Victoria, has declined to low levels after 50 years of production. This offshore resource in Commonwealth waters is processed in Victoria, and supplied to customers in Victoria, Tasmania, NSW and South Australia. 

The Australian Capital Territory does not produce gas. New South Wales, which currently produces minor quantities of natural gas, plans to develop resources around Narrabri in the Gunnedah Basin. If developed, Narrabri is expected to produce around 70 PJ per year for the domestic market once fully operational.

This production does not precisely align with gas markets. Australia has three distinct market segments with materially different outlooks for gas. 

  • East coast gas market has two segments:
    • southern states comprised of NSW, ACT, Victoria, South Australia, and Tasmania
    • northern states of Queensland and the Northern Territory.
  • Western Australia is physically separated from the east coast gas market.

With local production in the Bass Strait approaching end of life, the southern states face the prospect of becoming dependent on gas transported from northern gas fields, or on yet-to-be-completed LNG import terminals to meet domestic demand. However, as noted previously, LNG imports to the east coast may be more expensive than the nearby depleted sources in offshore Commonwealth waters near Victoria.

Responsible management of Australia’s natural gas resource is critical for securing the stable and affordable energy supply needed for economic growth while aligning with Australia's emissions reduction targets. Without future investment, there are real risks gas will become unaffordable and unavailable to Australian households and industry well before 2050. Accordingly, further exploration, acreage release and gas production will be required.

Australian gas basins, pipelines and LNG facilities

This map details basin names, cumulative production, 2P gas reserves, and 2C gas resources, with the estimated end-year for 2P gas reserves noted beside each basin. The Northern Territory, Queensland, and the Southern states are interconnected via major pipelines. In Western Australia, major pipelines connect the key demand centres to the gas supply facilities. Gas processing facilities are concentrated near Wallumbilla in Queensland, southern Melbourne, and Northwest shelf in Western Australia.

Calendar year 2022. Source: Analytical Report, Figure 5.7

Future gas gaps

Without further gas projects or development of gas currently under retention lease, an annual gas supply gap is forecast to emerge by 2028 on Australia’s east coast and grow over time. On the west coast, a gas supply gap is expected to emerge around 2030 and grow substantially from 2030 due to a forecast increase in GPG demand from coal-fired stations closing.

East coast gas supply and demand outlook, 2025–2035

The figure presents the annual gas supply and demand outlook for the East coast from 2025 to 2035, in PJs. It reveals a slight decrease in annual gas demand, from approximately 1,900 PJ/year in 2025 to around 1,800 PJ/year in 2035. However, the supply is projected to decline significantly, from roughly 1,800 PJ/year to about 1,100 PJ/year within the same timeframe. It shows a major annual gas supply gap is expected to emerge by 2028 on the east coast and the annual imbalance is expected to grow over time.

Source: Analytical Report, Figure 5.1

West coast domestic gas supply and demand outlook, 2023–2033

The figure presents the annual gas supply and demand outlook for the west coast from 2023 to 2033, in PJ. It indicates that the annual demand is projected to exceed the supply from 2024 onwards, with a supply gap expected to persist between 2024 and 2033, the annual imbalance is anticipated to increase significantly from 2030, reaching around 150 PJ in 2033.

Notes: Does not account for gas sold as LNG from offshore basins due to data limitation. Both gas supply and demand are based on AEMO’s Expected scenario from WA GSOO (2023). 

Source: Analytical Report, Figure 5.2

AEMO and the ACCC update their forecasts regularly and have forecast shortfall risks in the past. However, we avoided these shortfalls thanks to new supply being brought on by the market. Due to factors covered under Principles 1 and 4, the future of gas consumption in Australia is increasingly uncertain. This creates investment uncertainty which potentially reduces new supply.

Exploration and investment in the gas industry has been low over recent years. Stakeholder consultation has indicated the following, unranked range of factors that might contribute to low investment levels: 

  • global developments, such as cyclical (and structural) movements in oil and gas markets and prices as well as international government policies
  • uncertainty over low-emission gas demand, particularly demand required to achieve net zero
  • government project approval processes
  • legal challenges which delay projects
  • concentration of the titleholders of undeveloped reserves contributing to ‘gas hoarding’ behaviour
  • government interventions that affect investment conditions
  • the decline in the social license required for the gas industry to operate in Australia
  • the decline in access to project finance from financial institutions
  • commercial decisions to postpone capital expenditure to give greater dividends to gas company shareholders in the short term.

Possible sources of additional domestic supply 

The east coast gas market could have sufficient gas supply to meet domestic and export demand at least out to 2035. According to estimates prepared by the ACCC, supply could be met if discovered resources and reserves are developed. The potential locations of gas supply in the east coast gas market could include the Bowen, Surat, Galilee, Cooper, Gippsland, Bass, Otway, McArthur (Beetaloo) and Gunnedah basins. 

Most projects located in these basins are yet to reach final investment decisions. Because of this, they are subject to various contingencies including commercial factors, regulatory approvals and infrastructure constraints. Many projects are in the early stages of exploration and appraisal. 

Gas transport and storage infrastructure is constrained in south eastern states

In contrast to the southern states, only around one-third of current gas reserves in Western Australia and Queensland have been produced, and the Northern Territory has only used 4% of its gas reserves. Current transmission infrastructure linking northern supply to the south is, however, limited. As a result, more investment in pipelines and storage capacity would be needed for northern gas to provide a long-term solution to southern gas needs.

While the capacity of the major pipeline that connects Queensland and the Northern Territory to southern gas markets has been increased. AEMO forecasts this north-south transportation will be increasingly relied on to meet southern gas demand, with gas flows approaching capacity limits under high demand conditions, for around 10-20% of the year from 2026. AEMO (2024) further forecasts that storage levels will require increasingly careful management, and may not meet gas demand during temperature extremes. 

We have mechanisms to divert uncontracted gas to the domestic market through the Australian East Coast Domestic Gas Supply Heads of Agreement, and contracted export gas to the domestic market through the ADGSM, which is a measure of last resort. These are, however, only able to ensure gas supply for the southern states within the limits of existing infrastructure constraints to transport the gas to market. 

There are options to meet the west coast’s potential supply shortfalls 

In the near term, AEMO identifies a number of near and longer-term solutions to prevent gas shortfalls. Gas storage could help manage fluctuations in demand, subject to storage availability and the duration of supply needed from storage. 

Over the medium and long-term, a combination of supply from undeveloped gas fields and reductions in gas demand may reduce shortfall pressures. For instance, on 9 January 2024, WA’s largest gas user, Alcoa, announced the closure of its Kwinana refinery. While this resulted in hundreds of job losses in the region, the plant consumed approximately 5% of domestic west coast gas demand. 

The Western Australian Government has continued to release onshore gas acreage in the Canning, Northern Carnarvon, Amadeus and Perth Basins, which, if developed, would improve the state’s supply outlook through its Domestic Gas Policy. Developments in the Perth Basin are the most likely, near-term solutions to Western Australia’s forecast gas shortfalls. AEMO (2023) has considered the Bonaparte, Browse, Canning or Roebuck Basins will not contribute to domestic supply to 2035. However the Domestic Gas Policy will ensure these resources, along with the Scarborough LNG project, will contribute to WA supply in the long term.

The Western Australian Parliament is reviewing Western Australia’s Domestic Gas Policy to ensure it remains fit for purpose and is being adhered to.

New gas supply is … critical to meet the needs of the WA market in both the short and long-term, [to] displace high-emitting energy sources such as coal and diesel and provide a flexible energy source to support renewable generation, ensuring an orderly energy transition. On the demand side, the WA Government expects gas demand to increase into the 2030s, particularly as coal-fired generation is retired and new mining and mineral processing projects are developed. 

Government of Western Australia

Sources of gas supply from outside Australia’s oil and gas sector

Low-emissions gases, such as hydrogen and biomethane, make a small contribution to Australia’s current energy mix. Scaling alternative sources of gas supply is a critical opportunity for Australia. 

Once commercialised, low-emissions gases can complement or replace natural gas. Low-emission gases include biomethane and hydrogen. Combusting biomethane releases the carbon absorbed by the biogenic material from the atmosphere during its life. On this basis biomethane is often considered to have net-zero carbon emissions. This is consistent with the approach used by the Intergovernmental Panel on Climate Change (IPCC) in guidelines for national greenhouse gas inventory reporting and accounting for bio-based energy sources.

Over time the low-emissions gas sector in 2050 could grow to compete effectively with natural gas producers. This would occur where the production costs of low-emissions gases can match or outcompete incumbent fossil fuels. As an international example, in 2022, almost 40% of Denmark’s gas consumption came from biomethane. In the same year, Denmark’s total energy consumption was 560 PJs, with 75 PJs met using natural gas and 50 PJs from bioenergy and waste, which includes biomethane. Denmark’s ambition is to use 100% biomethane in space heating by 2030. 

Australia has different challenges to Denmark, but important lessons apply. Denmark needed further investment in its gas networks to support the growth of its biomethane sector as well as cooperation and buy-in from its agricultural sector. Biomethane supply locations in Australia will be driven by suitable feedstock availability, proximity to transmission and distribution infrastructure, and the cost competitiveness of supply. Additionally, competition for bio-feedstocks will occur from other biofuel producers, such as companies who would produce sustainable aviation fuels.

Biomethane, which is fully interchangeable with conventional methane produced by the oil and gas sector, can be used in the same end applications as natural gas. In 2021–22, biogases contributed 18 PJ of energy and was mostly used in electricity generation. Most biomethane in Australia is consumed where it is produced. Where possible, biomethane developments would be best located in southern regions to support the high local seasonal demand and avoid pipeline constraints. However, even a rapid expansion of biomethane production cannot completely close the forecast gas supply gap.

Biomethane is an internationally mature technology and operating at scale … The global biomethane industry is also anticipated to generate $5.5 billion by 2032, having achieved a value of $3.1 billion in 2022. 

Bioenergy Australia

Hydrogen is a high potential fuel for producing high-temperature heat and is a useful source of molecules for industrial processes. For production of ammonia, a critical ingredient of fertiliser, hydrogen is the only known pathway to decarbonise production. Australia’s National Hydrogen Strategy is being reviewed to develop a pathway which will position Australia’s hydrogen industry as a major global player by 2030. 

Gas-to-hydrogen switching is expected to be most suited to industrial/mining and power generation sectors. Most hydrogen production today uses fossil fuels, particularly natural gas and coal. 

There are significant challenges in supplying these gases economically at the scale needed by industry and power generation. As well as scale, the cost of the hydrogen and effectiveness in industrial processes may place limits on its use. Biomethane can directly supply and substitute natural gas and therefore may be deployed sooner than hydrogen. 

Another source of natural gas supply, which is difficult to quantify, could come from Australia’s coal industry. Australia’s coal sector produces and sells natural gas. Natural gas is drained from coal seams for safety reasons and to reduce the emissions intensity of coal mining. About 90,000 homes in Queensland are powered from captured natural gas produced from underground coal mining operations in Queensland. 

Coal miners are expected to produce more natural gas to reduce the emission intensity of coal production under the incentive created by the Safeguard Mechanism. Most natural gas produced during coal mining is consumed on site. Incentives created by the Safeguard Mechanism will encourage greater capture of fugitive methane from Australia’s coal sector. This will create a new source of natural gas supply that could be directed into our gas market.

Our regulatory systems seek to balance the benefits and costs from gas production

Oil and gas activities are regulated by all levels of government with multiple government agencies in each state or territory playing a role. All levels of government are also committed to reducing greenhouse gas emissions to achieve their climate targets and address dangerous climate change.

State and territory governments primarily regulate the onshore production of oil and gas resources. These regulations cover the lifecycle of a project from explorations tenements to site closures and offshore facility decommissioning. The Commonwealth regulates offshore oil and gas in Joint Authorities with the relevant state or territory.

Across all levels of government, regulatory approvals processes seek to protect the rights and interests of the people and communities that gas development impacts. This includes the environment, water resources, Traditional Owners, landholders, and local communities.

First Nations people and regional communities

Whether onshore or offshore, gas exploration and production often takes place in areas of cultural significance to First Nations people. In some cases, First Nations people have legislated rights in relation to lands and waters. In the Northern Territory, Aboriginal land held under the Aboriginal Land Rights Act 1976 provides a right of veto to Traditional Owners in relation to exploration. Nationally, Native Title holders and registered Native Title claimants have different procedural rights (such as the right to negotiate) relating to oil and gas interests. 

In some cases, Native Title holders and claimants oppose future gas development. In others, gas companies and First Nations people have developed positive relationships, supporting economic development. Successful projects occur when gas proponents engage with First Nations landholders and peoples with interests in the project. This often involves considering opportunities for partnerships, agreement making and benefit sharing, strong consultative mechanisms, appropriate cultural heritage protections, support for informed decision making, and facilitating real opportunities to develop pathways and opportunities to participate in the transition to net zero. In some instances, First Nation’s people may also co-invest or co-own a project.

Djaara want to ensure renewable energy developments on Djandak benefit Djaara and avoid negatively impacting Country, Native Title, Cultural Heritage, land rights and Dja Dja Wurrung’s Recognition and Settlement Agreement (RSA). … Together we can create a sustainable and clean energy future that elevates Djaara biocultural knowledge and connection to Country and through genuine partnerships with Djaara can heal people, Country and our climate. 

Dja Dja Wurrung Clans Aboriginal Corporation (trading as DJAARA)

Offshore project proponents must consider the connection of Traditional Owners with sea country during activity planning. The government released a discussion paper in January 2024 on the consultation requirements for offshore petroleum and greenhouse gas storage activities. The government is developing options to clarify the requirements and ensure consultation is appropriately targeted to the needs of people or organisations who may be impacted by the activity. This process forms part of a broader, three‑year review of the offshore environmental management regime.

Many of Australia’s Traditional Owners may agree that there are significant social benefits in seeing an Australian gas industry that can support the nation’s transition to a ultimate net zero economy. Some may not. Those that do, are entitled as rights holders to also seek to ensure that any development on their traditional lands and waters also supports their own community’s economic prosperity and cultural integrity. 

National Native Title Council

The government is working with Aboriginal and Torres Strait Islander people to achieve a better future by identifying ways to make a practical difference and help close the gap. The government has set up a First Nations Reference Group to work in partnership with the government to design and carry out the Remote Jobs and Economic Development program. The Remote Jobs and Economic Development program will create 3,000 jobs in remote Australia, to help close the gap in employment outcomes and boost economic opportunities. The program is part of the government’s plan to replace the Community Development Plan and give Aboriginal and Torres Strait Islander people in remote communities access to real jobs, proper wages and decent conditions.

The gas production industry can provide a valuable basis to support Australia’s transition to a net zero economy. In doing so the industry can also provide an important vehicle for recognition of the rights of Traditional Owners and a foundation for the future economic prosperity and cultural integrity of Australia’s First Nations. 

National Native Title Council

Regional communities in Australia can rely on a single company or industry to support community wellbeing and prosperity. Both climate change and the economic transformation needed to reach net zero are already impacting these communities through adverse weather events as well as both the growth and destruction of local industries.

To manage and respond to long-term structural shifts in Australia’s economy resulting from the energy transition, the Australian Government is establishing the Net Zero Economy Authority to promote orderly and positive net zero economic transformation for Australia, its regions and communities. It will do this by coordinating effort, brokering investments that create jobs in the regions, and working with the Department of Employment and Workplace Relations to support workers through change. 

The Central Highlands region will encounter some economic decline associated with the energy transition … and seeks to smooth that impact with transformational opportunities – one such opportunity is the construction of the Bowen Basin Gas Pipeline, connecting the Bowen Basin gas fields to the Curtis Island LNG facilities, and enabling longer term gas production and export from this region. 

Central Highlands Regional Council

We need new sources of gas supply to meet demand during the economy-wide transition to net zero and beyond. As discussed, gas consumption is not uniform across Australia, and new sources of supply are likely to be most economic when production is close to existing infrastructure. Gas development and depletion of existing gas fields impact the surrounding regional economies. This needs to be managed to maximise the benefit of gas production, while minimising emissions and the impact on First Nations people and local communities. Robust approval processes are key to the social license for new gas supplies.