Submission: Gas Market Review

Executive Summary

Gas is not just a fuel. It is a foundation of Australia’s industrial base, a competitive export, and an essential enabler of the energy transition. A healthy gas market supports gas-powered generation, manufacturing, fertilisers, chemicals, food processing, and other sectors that underpin jobs and regional economies. Without a secure and competitively priced domestic supply, these industries face decline, risking our sovereign capability.

However, the East Coast Gas Market faces structural challenges. Supply-demand imbalances, falling industrial demand in key states, underdeveloped long-term contracting, overlapping regulation, and unpredictable policy interventions are discouraging the private investment needed in both gas production and transmission. Without reform, Australia risks higher prices, lower reliability, and a loss of competitiveness for industry.

This submission identifies seven key reforms to improve market stability, unlock investment, support gas exports and ensure that Australian gas is available for Australian users — at all times of the year and under both long-term contracts and spot arrangements.

1.1   Summary of recommendations

Recommendation One: Modify the Form of Regulation Review process.

APGA recommends the Government consider the following reforms to strengthen regulatory certainty and support investment confidence in the East Coast Gas Market:

• Establish and communicate a clear evidentiary threshold for initiating a Form of Regulation Review, requiring the regulator to demonstrate either a clearly defined market failure or material harm before a Form of Regulation Review can be initiated.
• Introduce a narrow, independent review mechanism as a safeguard to ensure FoRR decisions are subject to oversight, maintaining investor confidence. 
• Require the relevant Minister to make a FoRR decision, based on the recommendation of the regulator.

Recommendation Two: Introduce mechanisms to help protect brownfield projects from the uncertainty of potential price regulations.

APGA recommends that the Federal Government consider target reforms to extend elements of the Greenfield Incentive framework eligible brownfield projects.

Such reform should:

• Provide equivalent regulatory certainty and incentive structures for eligible brownfield projects as those available to greenfield developments, including time-bound derogations from economic regulation and price determinations.
• Establish transparent eligibility criteria to ensure only projects that provide demonstrable market and consumer benefits qualify.
• Encourage investment decisions that maximise the capacity and efficiency of existing infrastructure where this offers a lower-cost and faster-to-market solution.

Recommendation Three: Establish clear and time-bound approvals processes.

APGA recommends that the Federal Government introduce statutory timeframes and procedural milestones for major gas infrastructure approvals to improve investment certainty and align Australia with global best practice.

Such reform should:

• Mandate fixed approval timelines under the EPBC Act, and other relevant legislation.
• Set clear thresholds and limits for appeals and judicial review to avoid infinite delays.

Recommendation Four: Reconsider the application of the Day Ahead Auction.

APGA recommends that the Federal Government consider targeted reforms to the Day Ahead Auction (DAA) framework to ensure it does not undermine the long-term contracting required to support pipeline investment in the East Coast Gas Market.

Such reform should:

• Exempt pipelines granted the Greenfield Incentive from being subject to the DAA for the duration of the derogation period.
• Preserve the commercial outlay for new infrastructure projects that rely on firm, long-term contract to achieve financial viability.

Recommendation Five: Introduce a carefully designed Domestic Reservation Policy.

APGA recommends that the Federal Government implement a carefully designed domestic gas reservation scheme to ensure Australian gas is available to Australian end-users.

Such reform should:

• Be structured to underpin long-term domestic contracting and support investment in new and upgraded gas infrastructure.
• Operate in a way that is responsive to market conditions, avoiding distortions in times of oversupply while ensuring adequacy during shortages.
• Protect Australia’s reputation as a reliable energy supplier by meeting existing export commitments and minimising sovereign risk.
• Maintain a clear distinction between energy policy, focused on securing adequate and reliable supply, and industry policy, which should be the mechanism to support sectors that remain under pressure even once energy market settings are optimised.

Recommendation Six: Supporting the development of renewable gases.

APGA recommends that the Federal Government review the Gas Market Code to ensure regulatory obligations are proportionate to the scale and market impact of the producer.

Such reform should:

• Clarify the application of the ‘small producer’ exemption to remove uncertainty and compliance risk.
• Ensure that compliance and reporting requirements do not impose disproportionate burdens on small producers, including emerging renewable gas developers.
• Focus regulatory effort on producers with the scale and market power to materially influence domestic supply and pricing outcomes.

Recommendation Seven: Federal Government must encourage long-term policy stability.

APGA recommends that the Federal Government, with bipartisan support, set stable, long-term gas market settings to provide certainty and enable investment. This will allow proposed reforms to take full effect and reduce the need for further intervention.

Australia’s gas transmission sector is ready to deliver the infrastructure needed but only if the investment environment is stable, regulatory risk is reduced, and supply-side reforms ensure end-users can access gas when they need it. These seven recommendations provide a balanced pathway to help restore market function, attract private capital, and secure the role of gas in supporting Australia’s economy through the energy transition.

2       Introduction

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.

APGA welcomes the opportunity to contribute to this Gas Market Review (the Review) and to help shape a robust East Coast Gas Market. This is a pivotal process. A well-functioning gas market is essential to supporting Australian homes and businesses, driving a competitive downstream economy, and sustaining a strong export sector that helps our regional trading partners decarbonise while meeting their energy needs. Getting the Review right will secure the long-term affordability, reliability and security of domestic gas, while underpinning the Future Made in Australia agenda through economic resilience and sovereign capability.

Today, Australia’s trade balance remains heavily reliant on coal and gas exports, which together generate more income than all non-mining goods and services combined. As global demand for coal declines, one of our largest export revenue streams will inevitably contract. Without a credible downstream economic diversification plan, Australia risks structural trade deficits that could weaken the dollar and increase the cost of essential imports.

Gas has a unique role in managing this transition. It remains in strong demand as a lower-emissions fuel and critical industrial feedstock, while domestically it underpins the competitiveness of the manufacturing and processing sectors. Secure, affordable gas supply would preserve a valuable export earner and provide the foundation for rebuilding high-value industries. Without it, the contraction of Australia’s industrial base, including job-rich sectors such as fertilisers, plastics, chemicals and food processing, will accelerate as operations offshore or close entirely. A strong gas market is therefore essential to reversing this decline, rebuilding manufacturing capability and protecting sovereign capability.

Ongoing concerns over domestic gas supply and pricing have driven major Commonwealth interventions, including the Australian Domestic Gas Security Mechanism (ADGSM), the Gas Code and the Heads of Agreement (HoA). While well-intentioned and initially delivering short-term gains such as increased contracting following the Gas Code’s implementation in early 2024, these measures have not addressed the underlying supply-demand imbalance.

The ACCC found that the majority of contracts agreed in the second half of 2024 for both 2025 and 2026 supply, have a term length of exactly 1 year.[1] This constrained certainty for buyers and deterring long-term investment. It warned that regulatory uncertainty, short-dated exemptions and pending reviews are undermining market confidence and contributing to longer-term declines in supply security, investment appetite and buyer confidence.

Addressing structural barriers, particularly those affecting the midstream sector, is essential to unlocking new supply and infrastructure capacity while maintaining export capability. A sustainable gas market must be underpinned by long-term contractual arrangements and regulatory stability to give investors confidence. Key barriers include:

• Form of Regulation Review (FoRR) uncertainty — AER’s ability to self-initiate reviews without clear thresholds undermines investment confidence in infrastructure.
• Regulatory instability — frequent changes to market rules and intervention without allowing time for impacts to materialise, creating uncertainty for investors.
• Underdeveloped long-term GSA market — reduced producer appetite to offer long-term contracts and customer reluctance to commit at current prices.
• Duplicative reporting — overlapping disclosure requirements across multiple agencies increasing compliance costs without improving transparency.
• Disproportionate compliance burden on small gas producers — regulatory settings designed for large incumbents applied to emerging or low-volume producers.

Without addressing these barriers, the ability of the market to deliver affordable, reliable and lower-emissions energy to Australian industry, households and regional partners will be at risk. Our submission outlines the reforms APGA considers necessary to remove barriers to midstream investment, increase the efficiency of existing infrastructure, and enable the East Coast Gas Market to deliver secure, affordable, and lower-emissions energy to consumers.

2.1   Structural barriers

2.1.1  Market dynamics

Australia’s gas transmission infrastructure is developed under a “contract carriage” model, which differs fundamentally from the “market carriage” approach used in other forms of energy infrastructure. Under market carriage, users access energy through a shared transportation network without needing to reserve specific capacity, and system development is effectively centrally planned. In contrast, contract carriage requires a pre-arranged agreement between a user and a transportation provider for dedicated capacity.

In practical terms, this means electricity transmission and distribution infrastructure, and to some extent gas distribution networks are developed through centralised planning processes, whereas gas transmission pipelines are developed according to specific needs. These pipelines are designed for bespoke capacity requirements and constructed only when there is a customer prepared to commit to a long-term transport agreement.

This model carries higher inherent risk for investors because returns are not guaranteed, unlike under the market carriage model. However, it drives more efficient capital allocation by requiring infrastructure proponents to secure commercial agreements before committing funds. This ensures projects are “right-sized” to actual demand, reducing the risk of overbuilding, avoiding unnecessary capital expenditure, and lowering costs for end users.

2.1.2  Importance of long-term contracts

The construction of a new pipeline 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. As noted by the ACCC in its 2016 Gas Inquiry, new pipelines tend to be built to meet the demand of foundation shippers, and existing pipelines are generally expanded in stages to meet incremental increases in demand.[2] This is, in part, because financiers impose constraints on debt, requiring pipeline operators to demonstrate low demand-side risk. As a result, spare or excess capacity is rarely built into new infrastructure, and ideally a pipeline would be fully contracted at the point of commissioning.

Historically, these foundational contracts were decadal in length, reflecting the fact that they were the only means to secure access to gas transport and this long-term commitment was necessary to justify the scale of capital investment. In recent years, the link between long-term contracts and infrastructure investment has weakened. A sharp contraction in the availability of long-term Gas Supply Agreements[3] has in turn reduced the prevalence of long-term Gas Transport Agreements. Without these longer-term agreements, the economics of developing new pipeline capacity or expanding existing assets are significantly weakened.

Several factors have contributed to this shift, including the introduction of mechanisms such as the Day Ahead Auction,. While these measures have been intended to improve competition and efficiency, they have also altered the commercial dynamics that underpin investment in new transmission infrastructure.

2.2   Policy direction creating demand risk

APGA strongly supports the transition to a net zero global economy, recognising the need to reduce emissions while maintaining energy security and affordability. Significant de-risking measures exist in other parts of the energy transition, particularly for infrastructure such as renewable generation, electricity transmission and storage, but comparable mechanisms are absent for gas transmission.

The midstream sector is not seeking public funding for gas transmission infrastructure. However, the additional regulatory risk being layered onto an already higher risk investment class is making it more challenging to reach Final Investment Decisions, discouraging private capital in a sector that’s vital to delivering a stable, affordable and orderly transition.

The combination of the energy transition and evolving emissions policies means infrastructure investors face significant long-term demand risk. A key question for the Gas Market Review is how governments can help industry manage, rather than eliminate, this transition risk and enable capital to flow into projects that will be vital for supply security.

While commercial assessments of future demand will always be necessary, the single most effective action the Commonwealth can take is to address regulatory uncertainty and provide a stable environment for long-term investment decisions.

2.2.1  Emissions policies increasing uncertainty

The transition to a net zero economy is essential, and a central challenge is finding the right balance between ensuring reliable energy supply and reducing emissions. The consumption of gas, whether to produce electricity, generate heat for industrial processes, or as a chemical feedstock, produces emissions that must be accounted for and ultimately reduced. The pace and scale of that reduction is subject to debate but in the meantime, gas remains critical to the Australian economy, both as a replacement for higher-emitting energy sources such as coal and as an enabler of grid stability in an electricity system increasingly dominated by variable renewable generation.

Like other infrastructure sectors, gas suppliers and transporters require access to a broad and stable customer base to de-risk investment. Yet some jurisdictions are signalling that, in line with emissions reduction objectives, gas use should and will decline across the economy, particularly in the residential and commercial sectors, where phase-out timelines are being proposed well before 2050.

This particularly includes Victoria, which historically has experienced some of the country’s highest reliance on gas for residential, commercial and industrial heating and energy. Rather than seeking to maintain this through encouraging investment in new supply, Victoria has actively pursued policies to destroy demand.

This disconnect between what we know about the necessity of gas during the transition, and how gas is treated through emission reduction policies, introduces demand risk. As AEMO in the VGPR notes: “Investment uncertainty in gas supply and infrastructure projects remains high as all projects currently underway or proposed in the VGPR outlook period face a range of challenges to reach investment decisions, maintain schedules and reach completion.”[5]

This risk is apparent in reluctance to develop gas resources or infrastructure, and is reasonable where investors cannot be certain their market will be curtailed through government intervention. This risk is compounded by the erosion of long-term contracts.

3       Opportunities to enable midstream investment

The East Coast Gas Market is undergoing significant change in both the profile of demand and the nature and location of supply. With production from the southern gas fields offshore from Victoria in decline, southern states are becoming increasingly dependent on gas transported from Queensland. Gippsland production is projected to fall from 243 PJ/year in 2024 to 109 PJ by 2028, creating a substantial shortfall in locally produced gas. As a result, customers in Melbourne and other southern markets are now often relying on gas transported from production hubs in Queensland, rather than from fields located offshore.

This shift underscores the critical role of gas transmission infrastructure now and into the future. Pipelines that connect distant production basins to southern demand centres are increasingly essential to ensuring reliable supply, supporting market integration, and maintaining downward pressure on prices. Without adequate investment in new and expanded transmission capacity, southern states risk supply constraints that could compromise energy security and increase costs for households and industry.

3.1   Form of Regulation Reviews

Discretionary intervention, particularly Form of Regulation Reviews (FoRRs) initiated by the Australian Energy Regulator is a major barrier to midstream investment in the East Coast Gas Market. These powers allow the AER to review and change the regulatory status 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. This risk can render otherwise viable investments uncommercial.

This framework departs significantly from the principles in Chapter 3 of the National Gas Law, which separate key regulatory functions between different bodies to ensure balance and accountability. Under the current FoRR arrangements, the AER can initiate, investigate, determine and implement reviews, concentrating all decision-making power within a single entity. This centralisation erodes checks and balances, heightens uncertainty, and reinforces investor concerns about the predictability of regulatory outcomes and the absence of meaningful avenues for recourse.

The FoRR powers were intended as a mechanism for the regulator to respond where there was a documented risk of market power being exercised by pipeline operators. However, in implementing these powers, the AER adopted a program of two FoRRs per year, placing all gas transmission pipelines into a rolling review schedule. This means that any transmission investment must account for the heightened possibility that its economic regulation could be changed at any time, with flow-on impacts for other projects that rely on its connection.

The current process does not require the AER to demonstrate a substantiated concern regarding market power, nor to draw on information gathered through its existing monitoring powers. Instead, operators may be required to provide information separately under a s42 information request, a process that imposes its costs and administrative burden.

APGA has engaged extensively with state and federal governments through the Energy and Climate Change Ministerial Council (ECMC), as well as directly with the AER, on the operation of the FoRR process. We acknowledge the AER has made amendments to its approach; however, these changes have not been clearly articulated to the market. As a result, significant uncertainty remains until the evidential parameters for initiating a FoRR are formally defined, communicated, and understood by midstream investors.

Addressing this regulatory risk, 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. If implemented, these reforms would unlock the private capital required for essential transmission infrastructure.

Recommendation One: Modify the Form of Regulation Review process

APGA recommends the Government consider the following reforms to strengthen regulatory certainty and support investment confidence in the East Coast Gas Market:

• Establish and communicate a clear evidentiary threshold for initiating a Form of Regulation Review, requiring the regulatory to demonstrate either a clearly defined market failure or material harm before a Form of Regulation Review can be initiated.
• Introduce a narrow, independent review mechanism as a safeguard to ensure FoRR decisions are subject to oversight, maintaining investor confidence. 
• Require the relevant Minister to make a FoRR decision, based on the recommendation of the regulator.

3.2   Inequitable incentives for greenfield vs brownfield infrastructure

In 2006, the Commonwealth, through the South Australian Parliament, introduced the Gas Pipelines Access (South Australia) (Greenfields Pipeline Incentives) Amendment Act 2006. This reform implemented a key recommendation of the 2002 Parer Review, which recognised that heavy-handed or uncertain regulation has a chilling effect on private investment under the contract carriage framework. The Parer Review sought to reduce this risk, ensuring regulatory settings encouraged the development of new pipeline capacity.

The Amendment acknowledged the competitive benefits of new pipeline development and the financial challenge of building large-scale, capital-intensive infrastructure with decadal lifespans and correspondingly long investment horizons. It introduced the ability for proponents of new or greenfield pipelines to apply for Greenfields Incentive and Price Protection Determinations. These determinations provided a 15-year derogation from economic regulation, third-party access, and from specified prices for pipeline services in access disputes. The incentive was later incorporated into the National Gas Law (NGL).

To date, five pipelines have been granted this status — Wallumbilla-Gladstone Pipeline, APLNG pipeline, GNLG pipeline, the Comet Ridge to Wallumbilla Pipeline Loop, and the Northern Goldfields Interconnect.

While the framework allows applications for major extensions of existing non-scheme pipelines, meaning the pipeline can be made longer, it does not allow projects to qualify where the proposal is solely to expand the capacity along the existing length. As such, this has not been a significant driver of investment in brownfield infrastructure, even where expanding capacity on an existing alignment would be a lower cost or more efficient way to meet market needs. This creates an imbalance where regulatory settings favour building new infrastructure over optimising the capacity of assets already in place. Allowing brownfield capacity expansions to be protected from the uncertainty posed by potential imposition of price regulation in the future would unlock more value from the existing network, deliver capacity faster, and lower costs for investors and end users.

APGA recognises that not every brownfield augmentation should qualify for such incentives and welcome the opportunity to engage with government on possible forms of protection, as well as the thresholds and criteria that should apply to ensure that brownfield exemptions are targeted to projects that deliver clear efficiency, competition and public benefit outcomes. Properly calibrated, this reform would complement the existing greenfield framework and ensure that investment decisions focus on the most cost-effective and timely infrastructure solutions for the East Coast Gas Market.

Recommendation Two: Introduce mechanisms to help protect brownfield projects from potential future regulations.

APGA recommends that the Federal Government consider target reforms to extend elements of the Greenfield Incentive framework eligible brownfield projects.

Such reform should:

• Provide equivalent regulatory certainty and incentive structures for eligible brownfield projects as those available to greenfield developments, including time-bound derogations from economic regulation and price determinations.
• Establish transparent eligibility criteria to ensure only projects that provide demonstrable market and consumer benefits qualify.
• Encourage investment decisions that maximise the capacity and efficiency of existing infrastructure where this offers a lower-cost and faster-to-market solution.

3.3   Lack of defined statutory timeframes

Australia’s approvals framework for major transmission projects compares poorly with international peers. In Canada, the United States and the European Union, statutory timeframes for environmental and planning approvals are mandated, often with legislated limits from application to final decision. By contrast, Australian processes under the Environment Protection and Biodiversity Conservation Act (EPBC), state environmental assessment regimes and native title legislation often have no fixed deadlines.

This lack of temporal certainty undermines Australia’s competitiveness for international capital. Investors assessing projects across multiple jurisdictions are more likely to favour countries where the regulatory pathway is predictable and time-bound, enabling clearer risk assessment and faster progression to FID. In Australia, proponents cannot provide reliable delivery schedules, which complicates financing and can materially delay commencement.

This compounded by the broad scope for third-party legal challenge. In some frameworks, the absence of statutes of limitations allows appeals to be mounted long after approvals are granted, prolonging timelines, increasing costs and eroding investor confidence.

These factors create systemic risk for nationally significant gas infrastructure and upstream projects. Reforming the EPBC Act to introduce clear, consistent and enforceable statutory timeframes, while streamlining and clarifying approvals requirements, is essential. This reform must apply to all nationally significant energy projects, renewables, gas, and electricity transmission, rather than relying on selective carve-outs that create winners and losers and distort investment signals.

Recommendation Three: Establish clear and time-bound approvals processes

APGA recommends that the Federal Government introduce statutory timeframes and procedural milestones for major gas infrastructure approvals to improve investment certainty and align Australia with global best practice.

Such reform should:

• Mandate fixed approval timelines under the EPBC Act, and other relevant legislation.
• Set clear thresholds and limits for appeals and judicial review to avoid infinite delays.

3.4   Examining existing interventions

The Day Ahead Auction was introduced as a market-opening intervention but has ultimately increased investment risk in gas transmission infrastructure. It was implemented in response to concerns that some pipeline capacity contracted to firm shippers was going unused on a daily basis while shippers without firm contracts could not easily access it. In the absence of contractual arrangements, this was viewed by the Commonwealth and the Australian Energy Market Commission (AEMC) as an inefficient allocation of East Coast Gas Market pipeline capacity. Hence the Day Ahead Auction was implemented to open access to unutilised capacity.

Facilitated by AEMO, the Day Ahead Auction provides a platform for gas transport customers to bid for access to contracted but un-nominated transportation capacity on designated pipelines and compression facilities in the East Coast Gas Market. The reserve price for this capacity begins at zero.

On some days, transport customers can access services for free – which is obviously well below the cost of providing those services. This effectively embeds a free rider problem in the gas transport market, as it creates a strong disincentive for gas customers to contract all, or even most, of their requirements. The result is a disruption to the critical link between firm gas transport contracts and the economic viability of new pipeline development.

APGA considers there is scope for reform to ensure that the Day Ahead Auction does not disincentivise investment in new pipelines, which must be underpinned by firm, long-term contracts. One potential reform would be to exempt pipelines granted the Greenfield Incentive from being subject to the Day Ahead Auction for the duration of their derogation period. This would preserve the commercial certainty needed to justify new investment while still allowing the Day Ahead Auction to operate on mature assets where the sunk costs have already been recovered.

Recommendation Four: Reconsider the application of the Day Ahead Auction.

APGA recommends that the Federal Government consider targeted reforms to the Day Ahead Auction framework to ensure it does not undermine the long-term contracting required to support new pipeline investment in the East Coast Gas Market.

Such reform should:

• Exempt pipelines granted the Greenfield Incentive from being subject to the DAA for the duration of the derogation period.
• Preserve the commercial outlay for new infrastructure projects that rely on firm, long-term contract to achieve financial viability.

4       Opportunities to reform the broader East Coast Gas Market

Securing domestic access to affordable, reliable, and competitive gas is critical to sustaining Australia’s energy-intensive industries, which underpin jobs, sovereign capability, and economic resilience. While reforms to improve the investment environment for gas infrastructure are necessary, infrastructure changes alone will not deliver additional domestic gas. Structural market reforms are also required to restore a functioning environment for long-term Gas Supply Agreements (GSAs).

The ADGSM, Gas Code, and Heads of Agreement are all designed to support domestic supply. However, their impact has been limited, while prevailing market incentives continue to favour spot sales over long-term contracts. In the early and mid-2010s, long-term GSAs were essential for producers to secure project financing. Many of those assets are now mature and no longer require the same revenue certainty, making short-term sales more attractive and reducing the availability of reliable, long-term supply. This shift is contributing to market dysfunction and deterring investment in infrastructure and industrial capacity.

For customers, reluctance to enter medium- and long-term agreements, partly due to concerns about locking in higher prices, has further entrenched short-term contracting behaviour. Addressing these incentives on both the supply and demand sides will be complex, but is essential to restoring market function.

4.1   Domestic Reservation

The central objective of the Gas Market Review should be to set energy market settings that deliver affordable and reliable supply. Access to competitively priced gas is essential for the survival of energy-intensive industries. Excessive prices risk forcing users to exit the market or scale back operations, with long-term consequences for infrastructure utilisation, investment, and industrial capability. This has direct implications for the midstream sector.

While APGA does not take a position on the precise definition of a ‘reasonable’ price for the purposes of this Review, supply and price should be considered separately, with the primary focus on increasing supply. Once constraints are eased, the market will establish a new price equilibrium. If that price remains unsustainable for important industries, it should be addressed through industry policy rather than attempting to resolve it within energy policy.

To help ensure that increased supply reaches Australian customers, a domestic reservation scheme should be introduced so gas is consistently available to end-users throughout each calendar year, under both spot and long-term contracts. Existing mechanisms such as the ADGSM, Gas Code and Heads of Agreement have provided some initial protection for domestic supply, but they have not been fully effective in guaranteeing timely, affordable access. Without reform, there is little evidence this environment will improve.

Any reservation scheme must be prospective and carefully designed to maintain year-round domestic supply security while preserving Australia’s reputation as a reliable trading partner and avoiding undue sovereign risk. Meeting existing export agreements is essential, as they underpin some of the largest infrastructure investments in Australia’s history.

In the long term, the most effective way to secure domestic supply is to increase gas production and ensure the regulatory environment supports sustained investment in both production and transmission infrastructure. A well-calibrated domestic gas reservation scheme could help provide greater certainty for long-term domestic contracting once in place, but it must be complemented by initiatives that boost supply in the short term to address current market tightness.

Recommendation Five: Introduce a carefully designed Domestic Reservation Policy.

APGA recommends that the Federal Government implement a carefully designed domestic gas reservation scheme to ensure Australian gas is available to Australian end-users.

Such reform should:

• Be structured to underpin long-term domestic contracting and support investment in new and upgraded gas infrastructure.
• Operate in a way that is responsive to market conditions, avoiding distortions in times of oversupply while ensuring adequacy during shortages.
• Protect Australia’s reputation as a reliable energy supplier by meeting existing export commitments and minimising sovereign risk.
• Complement, rather than replace, broader supply-side reforms to improve domestic market resilience.
• Maintain a clear distinction between energy policy, focused on securing adequate and reliable supply, and industry policy, which should be the mechanism to support sectors that remain under pressure even once energy market settings are optimised.

4.2   Market transparency measures

Current disclosure requirements for gas market participants are, in some cases, no longer fit for purpose. APGA considers there are clear opportunities for reform to ensure transparency measures deliver meaningful value without imposing unnecessary compliance burdens.

4.2.1  Gas reserves disclosures

The 2022 Market Transparency amendments to the National Gas Rules require gas field owners to report 2P reserves and 2C contingent resources, with a breakdown between developed and undeveloped reserves. Reporting must also cover fields above the materiality threshold, including production status, development status, anticipated timing to production, and annual movements in 2P reserves such as production, extensions, upgrades, downgrades, acquisitions, or other revisions.

However, the effectiveness of these disclosure requirements remains uncertain. For example, recent Bass Strait discoveries were later subject to significant reserve downgrades before being upgraded again, creating uncertainty for gas buyers and infrastructure developers assessing the viability and timing of new pipelines. Such volatility in reserves data complicates investment decisions and increases the risk of delays in bringing critical pipeline capacity online, heightening the potential for supply-demand imbalances in the East Coast Gas Market in future years.

4.2.2  Supporting the development of renewable gases

Under the Gas Market Code, gas producers must comply with extensive annual reporting requirements and procedural obligations relating to supply agreement negotiations, with significant penalties for non-compliance. While the Code provides exemptions from pricing rules for ‘small producers’, defined as those producing less than 100 PJ per annum and supplying only the domestic market, uncertainty remains over the application and interpretation of this mechanism.

This uncertainty results in a disproportionate compliance and cost burden for smaller producers whose operations differ substantially from the large-scale producers the Code was designed to regulate. The issue is particularly acute for emerging renewable gas producers, which must meet these obligations alongside the inherent challenges of establishing a new industry.

Recommendation Six: Micro-producer exemption to help accelerate renewable gases.

APGA recommends that the Federal Government review the Gas Market Code to ensure regulatory obligations are proportionate to the scale and market impact of the producer.

Such reform should:

• Ensure that compliance and reporting requirements do not impose disproportionate burdens on small producers, including emerging renewable gas developers.
• Focus regulatory effort on producers with the scale and market power to materially influence domestic supply and pricing outcomes.

4.3   Policy stability and continuity

The Review outlines a range of reform options that, while targeted at gas producers, will have flow-on impacts for market participants across the supply chain. Whatever measures are ultimately adopted, they must remain in place without further amendments.

Over the past decade, the gas market has faced sustained policy upheaval, with successive interventions often introduced before previous reforms had time to take effect. In addition to the ADGSM, Gas Market Code and Heads of Agreement, significant reforms have included:

• ACCC Gas Inquiry reporting (2016)
• Information Disclosure & Arbitration for non-scheme pipelines (2016)
• Pipeline capacity trading framework/Day Ahead Auction (2017)
• Gas pipeline economic regulatory reforms (2022)
• East Coast Gas System supply adequacy reforms Stage 1 (2022)
• Gas Transparency Measures & Market Transparency Rule (2023)
• Part 10 & 18A – Pipeline Reporting Guidelines (2023)
• Safeguard Mechanism Reforms (2023)
• East Coast Gas System supply adequacy reforms Stage 2 (2025-)

An unstable regulatory environment increases costs, raises sovereign risk, and deters investment in essential infrastructure. This uncertainty is no longer acceptable.

Recommendation Seven: Federal Government must encourage long-term policy stability.

APGA recommends that the Federal Government, with bipartisan support, set stable, long-term gas market settings to provide certainty and enable investment. This will allow recent reforms to take full effect and reduce the need for further intervention.

5       Consultation questions

[1] ACCC, 2025, Gas Inquiry 2017-2030: Interim update on long-term contract prices for July–December 2024, https://www.accc.gov.au/system/files/gas-inquiry-march-gsa-2025-interim-report.pdf

[2] ACCC, 2016, Inquiry into the east coast gas market, https://www.accc.gov.au/system/files/1074_Gas%20enquiry%20report_FA_21April.pdf

[3] ACCC, 2024, Gas Inquiry 2017-2030: December 2024 Interim Report, https://www.accc.gov.au/system/files/accc-gas-inquiry-interim-report-december-2024.pdf

[4] AEMO, 2025, Quarterly Energy Dynamics Q2 2025, https://www.aemo.com.au/-/media/files/major-publications/qed/2025/qed-q2-2025.pdf

[5] AEMO, 2025, Victorian Gas Planning Report, https://www.aemo.com.au/-/media/files/gas/national_planning_and_forecasting/vgpr/2025/2025-victorian-gas-planning-report.pdf