3. Finding new sources of gas to meet demand

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.

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.

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.

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.

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.

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.

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. 

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.