3 July 2026
The Australian Pipelines and Gas Association (APGA) represents the owners, operators, designers, constructors and service providers of Australia’s pipeline infrastructure. Our members deliver more than 1,500 PJs of natural gas each year for domestic use and over 4,500 PJs for export markets, underpinned by the highest standards of safety, reliability and operational performance. For decades, this infrastructure has been a cornerstone of Australia’s economic strength, providing secure, low-cost energy that has supported growth, sustained long-term trade, and enabled industry to compete globally.
The Future of Gas Statement comes at a critical time for New South Wales and for the gas industry at large.
APGA recommends that the Statement:
APGA welcomes the opportunity to contribute to the New South Wales Department of Primary Industries and Regional Development consultation on a new Future of Gas Statement for NSW. Much has changed in the East Coast Gas System since the last Statement in 2020, not in the least two energy security crises which demonstrated the critical need for secure gas supply. There have also been considerable developments in policy and regulation applying to the gas sector, not all of which has had positive impacts on the investment environment.
That market uncertainty is a major contributor to why the Australian Energy Market Operator (AEMO) has forecast likely gas shortfalls in the southern states from 2029, which includes NSW. Without significant new investment in gas supply and infrastructure these shortages are likely to become more frequent and more serious, at the same time gas is relied on to firm a National Energy Market increasingly dominated by variable renewable electricity. Gas remains a significant input into the economy, as a source of energy and as a feedstock for the production of fertiliser, construction materials, explosives and plastics – where it cannot easily be replaced.
A 2026 Future of Gas Statement needs to consider these factors as well as the broader state of the gas market.
At the beginning of the process to develop a new vision, it is worth considering the vision of the 2020 Future of Gas Statement:
Reflecting on progress since 2020, there have been significant new gas infrastructure developments in NSW. This includes but is not limited to the development of the Port Kembla Energy Terminal (PKET) coupled with the reversal of Jemena’s Eastern Gas Pipeline; APA’s East Coast Grid Expansion and the conversion of the Moomba to Sydney Ethane Pipeline to natural gas; Tallawarra B; and the Hunter Gas Project and associated pipeline infrastructure.
The Narrabri Gas Project is the only gas production project in NSW.[1] This is by design: the 2020 Future of Gas Statement has limited any other gas extraction projects in the state. Hence until Narrabri comes online, NSW is a gas importer, from Queensland, Victoria and South Australia, and potentially Western Australia, and the Northern Territory through the use of PKET as a virtual pipeline. This puts it in a precarious position given Victorian gas sources are also declining.
Since 2020, the retirement of the Eraring coal-fired power station was also extended twice: to August 2027, and then to April 2029. This has materially delayed and scaled down the transition to lower-emission gas powered generation: “The temporary extension of the operating life of the Eraring Power Station in New South Wales has materially contributed to a lower forecast for GPG compared to the 2025 GSOO.”[2] It is worth noting that this delay will ‘cost’ NSW approximately 13.2 million tonnes CO₂-equivalent emissions annually.
The 2026 Future of Gas Statement for NSW must acknowledge what has worked, and what has not, in the original statement and reflect a world that has changed considerably. Extensions in the lifespans of coal fleets, the slowing pace of the renewables buildout, and the challenges inherent in transforming traditional electricity networks into ones designed to handle distributed production and storage while simultaneously supporting significant and unexpected new sources of energy demand have all forced a reconsideration of how gas can help managing an orderly transition to net zero.
APGA considers that the 2020 Statement had mostly sensible and enduring ideas, with the notable exception that gas exploration and production should not be geographically limited. When it comes to actions, all four should be taken forward to 2026, because they all remain a priority:
The Future of Gas Statement must articulate a commitment for the future of gas as a commodity and an energy source in NSW, and a vision that it be used to effectively reduce the state’s energy emissions. Investor confidence in gas infrastructure assets, which are long-lived and expensive, has been steadily undermined by changes in economic regulation of and policy relating to the gas market. Policies that prioritise opening access to these assets has unpicked the previously strong relationship between long-term foundational contracts and the construction of those assets.
While these regulatory aspects are a national responsibility, NSW can go some way into assuaging investor confidence that gas assets are a safe investment in the state, and that the state will not pursue policies that impact guaranteed returns.
The 2020 Statement drew a line under gas exploration projects beyond Narrabri: “the NSW Government will not release further areas for gas exploration in NSW. This means that the Government will only support limited gas production projects in NSW, specifically, the Narrabri Gas Project and its potential extensions.”
In 2026, with Narrabri still years away from first gas, this strategy has clearly not provided NSW with the necessary security of supply and has underlined the risk of putting all eggs in one project basket. Other states in the NEM including Victoria, Queensland and South Australia have accelerated exploration and tenement release both onshore and offshore
The 2026 announcement that some additional regions would be open for exploration, including the Bancannia Trough and the Pondie Range Trough, was very welcome and may provide some relief. But APGA considers that this likely does not go far enough, and does not send a strong enough signal to potential explorers and developers to risk investment. The 2026 Statement reconsider exploration restrictions entirely, and commit to a more open approach to gas development where it makes economic sense to do so.
The ability for downstream users to access gas is almost entirely dependent on supply, which in turn impacts gas prices. Because tightening domestic supply has impacted domestic gas prices, where it makes economic sense to do so many residential, commercial and industrial users are transitioning their gas use to electricity (noting this necessarily can lead to increased GPG demand at some times).
Other users, who cannot make this change, are experiencing the effects of unmanageably high energy costs and without intervention, may exit the market entirely. The hollowing out of the Australian industrial base due to energy prices is unacceptable and a problem that can be solved. This indeed is the problem that the Domestic Gas Reservation Scheme is intended to solve, but work is also needed at the state level to ensure that gas users who need it, can get it when they need it at a price they are able to pay.
There are still other potential gas customers who could, given sufficient incentive and a sufficiently accessible gas price, transition from more emissions-intensive energy sources such as coal. Many industrial processes require carbon as well as high heat as an input, and coal has been the ideal source of this carbon to date. Transitioning these users from coal to gas would represent a major reduction in emissions, while also ensuring those industries stay viable in the state.
In the future those gas users can also be transitioned to carbon neutral biomethane, which is chemically identical to natural gas and can be transported using the same infrastructure. Renewable hydrogen blends, largely produced regionally, will also in the future be able to be transported in transmission pipelines, as they can be transported in distribution networks today.
Case study: BlueScope Steel
BlueScope Steel, a top Australian steelmaker, is working to decarbonise its Port Kembla Steel Works (PKSW) in New South Wales.
Steelmaking typically involves feeding iron oxide ore into coal-fired blast furnaces to produce iron, releasing about two tons of CO2 per ton of steel. Over 70% of global steel still relies on this method. One approach to reduce these emissions is direct reduction, which replaces coal with natural gas or hydrogen. This technology is commercially established across the globe and is the most viable pathway for reducing emissions at PKSW.
BlueScope views natural gas as an immediate solution to eliminate coal consumption at PKSW and reduce emissions by 60%. A reduction of this magnitude would represent ~2% of the state’s emissions, or ~23% of its industrial emissions.
Transitioning PKSW natural gas direct reduction will require a significant uplift in both gas and electricity usage - 30 to 40 PJ of natural gas per year, plus doubling its electricity usage from 1TWh per year to 2TWh per year. This equates to 7% of Australian east-coast natural gas demand and is 40 times the current gas usage at PKSW.
BlueScope Steel's decarbonisation strategy for PKSW highlights the complexities involved in transitioning to a low-carbon future. While full electrification remains a long-term objective, the immediate use of natural gas is crucial for achieving near-term emissions reductions.
Abundant gas supply can also unlock other opportunities. Data centres represent an extraordinary uplift in energy demand: according to AEMO’s 2026 Integrated Systems Plan:
Currently there are over 160 operational data centres in Australia, with almost half in Sydney and most others in Melbourne, Brisbane and Perth. They account for around 2% of today’s grid-supplied electricity use. However, that use is projected to grow in the ISP by around 25% annually to reach almost 10% of the NEM’s underlying demand by 2050 – five times the share it has today and the equivalent of 20% of today’s total demand. At the end of the March 2026 quarter, 11 large data centres representing a total of over 5 GW of maximum demand were in the connections pipeline.[3]
APGA does not share AEMO’s confidence that its “pathway remains appropriate even if data centre growth is faster than currently projected” – either for “baseload” power or for back-up power. Existing Australian data centres are largely relying on diesel generator fleets for back-up, which is neither efficient nor desirable from an emissions perspective. Integrating with existing gas networks and using in situ gas turbines is the option pursued by data centre developers in the United States, but not in Australia. This is not from a lack of desirability but is largely an issue of planning and investment incentives.
Gas powered generation can support ‘speed to power’, flexibility, and provide critical system services. Government should recognise their role going forward in helping retire coal, support the wider electricity grid in the transition to net zero, and enable new industries with significant power needs, such as AI.
Gas is currently and will remain very important in balancing a NEM dominated by variable renewable electricity. Gas use for electricity generation will continue but with a much peakier usage profile than we see today. As coal-fired power stations retire, gas will play an increasingly important role in firming renewable generation and maintaining system reliability. While total annual volumes may remain modest, peak-day gas demand is expected to increase substantially.
The below chart, from AEMO’s 2026 Gas Statement of Opportunities, shows this at scale. GPG gas consumption will fluctuate but not significantly decline. But winter daily maximums will more than double, which current gas infrastructure will struggle to deliver.
The shape of this consumption shows how challenging this investment currently is and how much more so it will be in the future. Gas plant investors may struggle to make a rational case for that investment where returns are, at best, unreliable: GPG plants may run only a few times per year, meaning their fixed costs must be recovered in a small number of high-price events. This creates volatile and uncertain revenue streams that do not support project finance.
The Nelson Review of the National Electricity Market recognised that while some technologies are being progressed through explicit, technology-specific policy support, gas-powered generation is expected to deliver reliability outcomes through the market without that kind of support. At the same time, it makes clear that targeted reform is required to ensure firm, dispatchable capacity can reach commercial investment decisions in time as coal-fired generation retires. The Electricity Services Entry Mechanism recommended by the review and currently in development should help provide that project certainty, as it does not exclude gas powered generation from providing system services like the Capacity Investment Scheme. It will require more considered planning from states as to how that transition to “flexible” gas will be managed.
The Future of Gas Statement must acknowledge the critical role of gas distribution and transmission infrastructure in providing energy security, reliability and emissions reduction in NSW.
Business NSW’s 2025 paper Running on Empty 2.0 provided a sensible overview of what is necessary to enable the development of gas infrastructure.[4] Chief amongst this, in APGA’s opinion, is that the NSW Government should treat gas infrastructure as a long-term enabler of economic resilience, and that reforms are required to, in particular, mitigate investment risk associated with the risk of regulatory changes.
This recommendation goes to the heart of one of the biggest issues facing the gas market in 2026: the current regulatory environment does not support in these large, long-term assets which will enable domestic energy security and economic resilience.
Pipeline construction is effectively “underwritten” by foundational contracts between a gas customer and a transport provider to deliver a set quantity of gas over a defined period. Existing pipelines are generally expanded in stages to meet incremental increases in demand; financing constrains mean spare or excess capacity is rarely built into new infrastructure, and ideally a pipeline would be fully contracted at commissioning.
These foundational contracts were once decadal in length, as this long-term commitment was necessary to justify the scale of capital investment and hence required to secure access to gas transport. In recent years, as the availability of long-term Gas Supply Agreements has declined, so has the prevalence of long-term Gas Transport Agreements which underpin infrastructure. Without these longer-term agreements, the economic case for developing new capacity or expanding existing assets is significantly weakened.
Several factors have contributed to this shift, including the introduction of mechanisms to open access to pipeline capacity or address perceived market power. Spot markets and the Day Ahead Auction have provided access to gas and the means to transport it without long term contracts, inviting market participants to hedge.
The investment case has been further weakened by discretionary intervention, particularly Form of Regulation Reviews initiated by the Australian Energy Regulator. These powers allow the AER to review and change the regulatory status and hence capital returns of a pipeline at any time, with no avenue of appeal except on errors of law. For greenfield and brownfield transmission projects, which already carry significant commercial risk and often require capacity to be built ahead of demand, the prospect of mid-project regulatory change adds major uncertainty, making otherwise viable investments uncommercial.
While these measures have been intended to improve competition and efficiency, they have also permanently altered the commercial dynamics that underpin investment. Addressing these regulatory risks, alongside other critical reforms such as inducing more long-term contracts into the market and extending the greenfield incentive, would materially reduce the primary investment barriers facing the midstream sector.
Changes to the National Gas Law are required to reform these processes, with the ultimate goal being policy certainty to support market‑led investment. NSW, being the largest jurisdiction in the east coast gas market, should agitate for such change at the Energy and Climate Change Ministerial Council.
[1] AEMO says this of the Narrabri project in its 2025 NSW Gas Infrastructure Review: “The majority of the gas forecast to be produced by the facility would be sourced from uncertain field reserves. While the facility would add a local gas supply source to New South Wales and reduce reliance on gas imports from the other states, the additional production would come online after forecast structural gas shortfalls begin to occur, and could only partly offset the shortfalls observed from 2029 onwards.”
[2] AEMO, 2026, 2026 Gas Statement of Opportunities, https://www.aemo.com.au/-/media/files/gas/national_planning_and_forecasting/gsoo/2026/2026-gas-statement-of-opportunities.pdf
[3] AEMO, 2026, 2026 Integrated Systems Plan, https://www.aemo.com.au/-/media/files/major-publications/isp/2026/2026-integrated-system-plan-isp.pdf
[4] Business NSW, 2025, Running on Empty 2.0: The evolving role of gas in NSW, https://bczsaprodassetstorage.blob.core.windows.net/businessnswmedia/nswbcsharedmedia/businessnsw/media/pdf/running-on-empty-2-0-2025.pdf?ext=.pdf