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1. Getting to net zero emissions by 2050

Principle 1: Australia is committed to supporting global emissions reductions to reduce the impacts of climate change and will reach net zero emissions by 2050. Gas production and use must be optimised through the transition and residual use must be abated or offset to achieve this economy-wide commitment.


In 2050, Australia’s natural gas use will look very different from today. Australia cannot reach our 2050 net zero targets without reducing and decarbonising our consumption of natural gas. Natural gas consumption will continue on the pathway to net zero. Decarbonising natural gas use in Australia will need:

  • increased energy efficiency and electrification of processes that currently use natural gas
  • replacing natural gas with low-emission gases
  • any remaining emissions from natural gas use to be reduced as low as possible, and where not possible, fully offset.

Gas consumption is not uniform across sectors or across Australia. Gas is used by households and small businesses, by industry and in power generation. Each of these broad sectors has a different pattern of gas consumption.

Gas is used in all states and territories. Each state and territory also has a different pattern of gas consumption.

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

Read Section 3 of the analytical report for analysis of domestic demand for natural gas.

Gas use in Australia’s transition to a net zero economy

Gas will support our economy during the transition to net zero and will remain a critical part of the energy landscape in 2050 and beyond. Transforming how we make products and power our economy will be challenging, but the energy transformation is already underway. 

Technologies allowing households and businesses to decarbonise are becoming increasingly available. For industrial gas use, the transition pathway is more complex and will depend on the cost and availability of alternatives. In some cases, these alternatives will require  new technologies. In other cases, solutions will combine existing technologies in new ways. A challenge for governments, society, investors, and market participants will be to maintain investment across the energy sector at the pace required to achieve net zero. 

We explore these opportunities and challenges based on detailed projections of the east coast and west coast gas demand scenarios produced each year by the Australian Energy Market Operator (AEMO). 

Australia’s forecast natural gas demand depends on many factors. Each AEMO projection is based on assumptions about how quickly we adopt alternatives to gas, as well as social and economic conditions. These projections reflect the best knowledge available.

The largest declines in gas consumption are anticipated in east coast buildings

The largest declines in gas demand on the east coast are forecast for commercial and residential buildings. Depending on the scenario, by 2043, domestic and small business consumption of gas will decline between 49% and 72% on 2023 levels. This is unless residential and commercial consumers are unable, or choose not to, electrify. These projections assume an increase in the rate of electrification (the replacement of existing gas appliances with electric alternatives), and a reduction in the rate of new natural gas connections. 

Building demand for gas by scenario, 2023–43
This figure shows the projected growth by the different scenarios on the east coast for the Buildings sector between 2023 and 2043. From an initial value of 175 PJ in 2023, step change with no electrification increases to 219 PJ in 2043, step change decreases to 51 PJ in 2043, progressive change decreases to 93 PJ in 2043 and green energy exports decreases to 62 PJ in 2043.

Note: Building demand covers gas used for residential and commercial heating on the east coast

Source: Analytical Report, Figure 3.7; AEMO (2024b)

Achieving the reduction in household gas demand assumed in AEMO’s high-ambition scenario (‘green energy exports’) will be challenging. In this scenario, Australia’s east coast would need to disconnect, or provide low-emission gases to, around 144,000 houses each year for the next 20 years. This equates to removing just under 400 houses per day, which is a large logistics challenge. In 2021, about 68,000 households joined the gas network across NSW, Victoria, South Australia and the ACT.

Building (households and small business) gas demand makes up a small portion of Australia’s domestic gas consumption (21%, excluding demand from the LNG sector). This means that reducing building gas consumption will have a modest impact on Australia’s gas-related emissions and climate targets. 

… to reach net zero by 2045, which Victoria is committed to … about 200 Victorian homes would need to be upgraded every day between now and 2045. 

Master Plumbers Australia and New Zealand

Electrifying Australian homes will mean a surge in demand for electricians and/or tradespeople with electrical licences… 

AGL Energy

GPG will play a crucial role in assisting the transformation of our electricity markets 

AEMO forecasts that 2035 gas demand from the electricity sector (GPG) could be 10% lower, or up to 96% higher than in 2024. The large range in forecast demand reflects the complex interaction between gas and electricity markets, driven by:

  • the closure of coal-fired power generators
  • how quickly renewables can be added, scaled up and commercialised
  • the greater volume of electricity generation needed to support electrification of current gas consumption. 

Under all scenarios, a point to note is that while we may use more gas overall, we may need less gas during specific periods of time. There is a strong potential for declining use of GPG up until 2032. 

The graph gives a simplified view by focusing on the Step Change scenario. Under this scenario, electricity generation is projected to more than triple by 2050 as more parts of our economy electrify. GPG capacity grows in absolute terms, but decreases significantly as a percentage of overall power generation. 

Projected energy source in the NEM, Step Change
This figure shows the projected energy sources in the National Energy Market under the step change scenario by financial year to 2050. Capacity increases every year, with solar and wind increasing most significantly. Gas capacity increases between 2023-24 and 2044-45, before decreasing between 2044-45 and 2049-50. Despite the increase in gas capacity, faster growing total electricity capacity will lead to the share of gas capacity declining between 2023-24 and 2049-50.

Notes: Data derived from the 2024 Draft Integrated System Plan (ISP) report for the Step Change scenario. 

Source: Analytical Report, Figure 3.10

From 2035 to 2050, annual demand for GPG is forecast to increase, with the need for large, time-limited contributions from GPG expected to continue. 

Over time, clean and economic substitutes to unabated natural gas for power generation will emerge. We do have some grid scale alternatives today, such as pumped hydro power and battery power, while others such as biomethane, hydrogen and other biofuels are emerging. Which options ultimately prevail will depend on factors such as safety, reliability, whole-of-life cost, and carbon efficiency and performance. 

Industrial users of natural gas may have few options available to switch from gas

For industrial gas consumers, through to 2035 on Australia’s east coast, AEMO projects only small declines in industrial gas use. Even in the high-climate ambition, ‘green energy exports’, scenario, industrial gas demand is expected to fall by a maximum of 20% by 2042. This will follow an initial rise because of the rapid decrease in the use of coal. 

Industrial gas demand will vary considerably by industry and is more likely to be a series of step-changes, including in some cases, increased demand over the medium-long term ... 

Manufacturing Australia

These modest projected declines in gas consumption reflect the limited alternatives currently available for many gas uses in Australia’s heavy industry and resources sectors. Reducing demand will need advances in a range of different technologies. Deployment of these technologies is likely to need substantial changes to facilities that use large amounts of gas. Consultation indicates that some large emitters plan to use natural gas as the first step to reduce emissions before alternative energy sources (like hydrogen) and alternative technologies are commercially available at scale. This emissions reductions task will require large capital investments in Australian industry.

Substituting gas applications for other technologies requires the business to understand the replacement technology, its business case, and how its technical characteristics relate to the operations of the business. For many businesses, especially smaller businesses, the lack of expertise on these matters is a significant barrier … 

Business NSW

Direct reduced iron (DRI) processes can be configured to use natural gas and transitioned (at relatively low cost) to hydrogen once it is price competitive … Use of natural gas to manufacture DRI would … reduce BlueScope’s Scope 1 GHG emissions by approximately 3.7 million tonnes per annum. 

BlueScope low emissions iron and steelmaking study

Gas demand may increase on Australia’s west coast 

Through to 2035 on Australia’s west coast, there are similar drivers for change in gas markets. Demand from mining and mineral processing is forecast to increase slightly then remain flat. Industrial demand is likely to climb sharply in 2027, in large part due to Perdaman Industries brings its new urea plant (essential for fertiliser production) online in Karratha. Annual GPG gas use is expected to be broadly flat until 2030, before increasing to offset the exit of coal fired generation assets. The initial decline in GPG demand is driven by new renewable generation, specifically as wind combined with batteries is expected to replace a loss in coal generation capacity. High-efficiency GPG will meet an increasing portion of demand as coal exits WA’s electricity system from 2030 to 2033. 

West coast gas demand by sector, 2016–2033
Full description follows

Notes: Projections are derived from WA’s expected case scenario. 

Source: Analytical Report, Figure 3.13

This figure shows the demand on the west coast for gas by sector from 2023 to 2033. Mineral processing is the highest segment in 2023 and increases between 2023 and 2025. Mining is next highest in 2023, and increases in 2024, but decreases marginally between 2024 and 2033. GPG demand declines out to 2027 but increases strongly in 2030 and 2032 to become the largest sector. Industrial demand is flat between 2023 and 2027, before increasing significantly in 2027 and remaining at these levels out to 2033. Distribution demand has the lowest value in 2023 that is shown on the graph, it remains steady between 2023 and 2033. 

AEMO’s projections for WA gas use do not extend beyond 2033. However, the WA Government’s Energy Transformation Strategy sees GPG remaining important beyond this outlook period. Western Australia has recently reviewed its Domestic Gas Policy, through which it aims to secure Western Australia’s long-term energy needs.

Household use is a small component of west coast gas consumption and is expected to grow slightly over the outlook period. The increased uptake of electrical appliances, or addition of low-emission gases into the gas network, could instead see demand fall by the same amount. 

Western Australia has a high concentration of industries that need high heat (for example, smelting) and a large mining and minerals processing sector. These sectors create future gas demand over the outlook period, and few commercially viable technology substitutions are expected to emerge during the forecast period to 2033. Expected rates of growth in gas demand will be driven by new minerals processing such as lithium hydroxide, and mining and manufacturing consumers.

Hard rock lithium processing

Western Australia has large deposits of lithium ore (spodumene). As demand for battery technology continues to grow to meet net zero targets, Australia is increasing its spodumene processing capabilities. 

Lithium can be extracted from mineral concentrate by roasting and acid roasting at temperatures of around 1050°C and 200°C, respectively. From this process, lithium sulphate (which is soluble in water) is then transformed into lithium hydroxide which is used in electric vehicle batteries. 

The technology to run high heat kilns on electricity or hydrogen is not yet available. Processing lithium still requires gas. 

Carbon management and geological storage

Geological storage is a method of permanently sequestering carbon from existing industrial facilities. Geological storage requires the use of carbon capture and storage (CCS) to capture and store CO2 from industrial and extractive processes. It involves condensing CO2 into a liquid and then transporting, injecting, and permanently storing the liquid CO2 deep underground in a geological formation. Typically, it is stored at depths of more than 1 kilometre. 

CCS will likely play an important role in the decarbonisation of Australia ... CCS technology can also be used to sequester unavoidable greenhouse gas emissions from various sectors or produce fuels including ammonia and hydrogen. 

Japan Australia LNG (MIMI) Pty Ltd

Australia has significant onshore and offshore storage reservoirs potentially suitable for CCS projects. This includes storage in depleted petroleum fields. Successful deployment of CCS and negative emissions technologies can help decarbonise oil and gas operations and other hard‑to‑abate industries, such as cement production.

Given Australia’s natural advantages in the storage of emissions, it [Australia] can support the decarbonisation of those [economies] that do not have the same access to renewable energy or viable CCS sites by providing CCUS as a service … Japan, Korea, Taiwan, and Singapore all have emission reduction ambitions that will likely need the support of other countries including by providing CCS as a service. 

BP Australia

Australia’s basins ranked for CO2 storage potential

Gas basins where geology may work for storing of CO2. The Carnarvon, Browse & Bonaparte basins off the coast of Western Australia, and the Otway & Gippsland basins in offshore waters south of Victoria are highly suitable. Eromanga & Galilee basins in Queensland also have areas of high suitability. The Cannning basin onshore in Western Australia & the Surat basin that straddle QLD and NSW are ranked suitable, as is the Bass basin between TAS and VIC. McArthur and Beetaloo basins in NT are unsuitable.

Source: Geoscience Australia (2023b)

Growing carbon management and geological storage in Australia

Australia’s geological carbon management market needs to grow to support a least-cost energy transition and grow our economy. The Australian Government has committed $12 million over 3 years to provide regulatory and administrative certainty for offshore CCS projects.

There are commercial CCS projects in Australia and around the world. Australia hosts the world’s largest commercial CCS project, the Chevron Australia Gorgon LNG Project at Barrow Island in Western Australia. Over the period 2019 to 2023, this project has stored 9 Mt-CO2. This is nearly equivalent to the amount of annual emissions produced in Australia’s residential and commercial buildings sector. 

Aside from the Gorgon Project, the Australian CCS industry continues to work towards large-scale commercial projects in Australia. To be successful, the identification of geological storage sites and development of infrastructure and processes will need significant work, collaboration across industries, and investment. 

The 2023 Net-Zero Australia study suggested that a notional annual geological sequestration limit for Australia is 150 Mt-CO2. For most scenarios in its report, annual sequestration demand reaches this limit by 2040. The study suggested that successful deployment of CCS would be a multi-decade effort. It investigated scenarios to meet all storage needs and suggested that storage prioritisation should focus on emissions that are hard to abate. 

Success will need substantial investment from the private sector and will involve extensive project timeframes. Several Australian projects are in development.

Following the passage of amendments to the Sea Dumping Act, Australia and future exporting and importing destinations of CO2 must adopt further regulatory processes before any CO2 trade can occur. High levels of scientific and community confidence in the safety and efficacy of storing CO2 will be critical to the success of scaling CCS. The Australian Government will continue to organise and attract investment in Australia’s growing CCS industry through:

  • maintaining offshore greenhouse gas acreage releases
  • ensuring our regulatory systems remain fit for purpose, including through the government’s review of relevant regulation
  • encouraging innovation, including through the $15 million Carbon Capture Technologies Program
  • encouraging collaboration across industries to enable projects to reach scale
  • supporting uptake among existing industrial facilities, including through the Powering the Regions Fund.

The private sector is responsible for developing and carrying out projects where it identifies that CCS is a cost-competitive, safe, and verifiable approach to meeting emissions reduction obligations under the reformed Safeguard Mechanism. It is the Australian Government’s expectation that Australian CCS facilities will provide cost-effective abatement options for Australian hard-to-abate industries. These include those for which CO2 is an unavoidable byproduct of production (such as calcination of limestone to produce clinker for cement manufacture), and potentially for our trade partners.

Reaching net zero emissions will require concerted collaboration and effort, with no single solution available to decarbonise the economy. Technology, low-emission gases, and natural gas all have their roles to play, with some sectors able to decarbonise more quickly, and others increasing gas consumption as they transition away from current manufacturing processes. Natural gas has an important role to play, and will continue to be required by hard-to-abate industries beyond 2050.