Gas Market Review Report And Fundamental Reforms Ahead

This update follows our earlier analysis of the 2025 Gas Market Review consultation available here.

The Australian Government's Gas Market Review Report (December 2025) calls for fundamental reform of the East Coast gas market to address forecast supply shortfalls and provide regulatory certainty for long-term investment. The Report recognises that while current gas production meets domestic demand, structural supply shortfalls are forecast from 2029 on the East Coast and 2030 on the West Coast, despite abundant reserves.

Existing mechanisms – the Gas Market Code, ADGSM, and Heads of Agreement – are considered insufficient and duplicative, creating opportunities for consolidation. Key drivers for reform include:

• Persistent high gas prices impacting trade-exposed industries.
• Market concentration limiting buyer bargaining power.
• Short-term contracting trends and regulatory uncertainty undermining investment confidence.
• Strong linkage between domestic and LNG export markets, exposing local prices to global volatility.

The core recommendations of the Report are:

Producers will be closely monitoring how the new reservation scheme is operationalised, particularly given the indication that reservation volumes may be assessed on a contract-by-contract basis rather than across total output of a new project (the latter being the Western Australian model). Questions also remain as to whether domestic volumes will need to be fully contracted on a long-term basis to satisfy LNG export pre-approvals, and how this may affect participants seeking to market domestic gas on a short-term basis.

Consultation begins in 2026, with implementation from 2027. These changes represent a significant shift toward a consolidated, long-term regulatory framework. The Government aims for this to enhance supply security, affordability, and investment confidence.

In addition, the following complementary workstreams are being carried out:

• the Australian Energy Market Commission (AEMC) is progressing Stage 2 of the Reliability and Supply Adequacy framework in the National Gas Rules and measures aimed to improve liquidity and competition; and
• the Energy and Climate Change Ministerial Council (ECMC) is undertaking a consultation on extending AEMO's East Coast gas system reliability and supply adequacy functions beyond the current AEMC reforms above, including a Last Resort Investment Support Tool.

This paper focuses on reforms targeted for the East Coast gas market, rather than any potential changes in Western Australia.

Context and Drivers for Reform

Please refer to our earlier analysis of the 2025 Gas Market Review consultation available here. That paper summarised the submissions to the Gas Market Review and provides context to the Government's final report and the decision to pursue fundamental reform.

The Gas Market Review Report (the Report) was released by the Australian Government on 22 December 2025. It recognises that while current gas production meets domestic demand, structural supply shortfalls are forecast from 2029 on the East Coast and 2030 on the West Coast, despite abundant reserves.

The Report assesses three reform options – retaining the current framework, implementing incremental changes or pursuing comprehensive reform. The Report concludes that only fundamental reform can address structural shortfalls and deliver the requisite regulatory certainty for long-term investment. The Government will proceed with a comprehensive overhaul of gas market regulations, with a view to ensuring supply security, affordability, and investment confidence.

Existing mechanisms – the Gas Market Code (the Code), the Australian Domestic Gas Security Mechanism (ADGSM), and the Heads of Agreement (HoA) – are recognised as insufficient to achieve these objectives. The Report found that, as certain aspects of these separate mechanisms are duplicative or pursue similar policy objectives, there are opportunities to consolidate and streamline the framework.

The Report emphasises the importance of maintaining supply and affordability in the domestic gas market, while preserving Australia's position as a reliable and stable energy export partner. The Report also recognises that Australia's LNG exports have delivered significant national economic benefits through taxation, royalties, and employment, while also supporting energy security by facilitating development of gas resources that would otherwise be uneconomic for domestic supply alone. Around 90% of Australia's 2023-24 LNG exports were shipped to Japan, South Korea, Taiwan and China (JKTC). These exports are supported by 51 medium-to-long-term contracts, most of which expire between the mid-2030s and 2040s. The Report acknowledges that recent crisis-response regulatory measures have increased uncertainty for Australia's trading partners.

LNG exports remain vital to Australia's economy, but can expose domestic users to global price volatility. The scope for higher returns in international markets has created a strong link between domestic and export markets. The Report mentions that gas producers may prioritise more lucrative international LNG spot sales over domestic gas supply, diminishing incentives for long-term contracting domestically and causing local prices to reflect scarcity and buyer willingness to pay, rather than underlying production costs. Pricing in workably competitive markets will take into account a range of factors, including availability of long term contracts at prices which support the investment required to develop resources. This is increasingly an issue as potential production focuses on reserves which face higher costs of production. Measures which adversely impact the sustainability of long term production can result in shorter-term contracting. The operation of the Code and regulatory uncertainty, has also led to shorter-term contracting in the market, particularly given the exemptions available for shorter-term deals and challenges in interpretation and practical implementation of the Code. This is further expanded on in our prior paper here.

The Report contends that high gas prices continue to put pressure on trade-exposed industries that are unable to electrify, and market concentration is limiting buyers' bargaining power – further reinforcing the need for structural reform.

Reforms and Implementation Pathway

Domestic Gas Reservation Scheme

A cornerstone recommendation of the Report is a prospective domestic gas reservation policy, requiring LNG exporters to allocate between 15-25% of new gas production to domestic markets. This would impose a binding obligation to supply reserved gas to the domestic market, replacing the current HoA requirement to merely "offer" (rather than "sell") uncontracted gas. Under the existing framework, there is no need for producers to adjust prices to reflect buyers' willingness to pay in order to satisfy the HoA obligation.

The Report recognises that volumes supplied under the current HoA framework represent approximately 10% of domestic demand and have had minimal impact on lowering domestic gas prices. Most offers by HoA signatories have been at export parity pricing, supporting the ACCC's view that additional gas is unlikely to flow to the domestic market unless LNG netback prices align with levels acceptable to domestic buyers.

This is a different model to the existing gas reservation policy in Western Australia, which is based on bilateral contracting and summarised in our prior paper available here. The Report does not expressly mention any impact on the existing Western Australian gas reservation policy. However, there is an industry expectation that the new scheme will not change the current WA policy - similar to how the Code, HoA and ADGSM have the capacity to operate nationally but primarily apply in the East Coast gas market at present.

Producers will be closely monitoring how the new reservation scheme is operationalised, particularly given the indication that reservation volumes may be assessed on a contract-by-contract basis rather than across total output of a new project (the latter being the Western Australian model). Questions also remain as to whether domestic volumes will need to be fully contracted on a long-term basis to satisfy LNG export pre-approvals, and how this may affect participants seeking to market domestic gas on a short-term basis.

The Report recognises that protecting foundational export contracts will be critical to building acceptance for the scheme and maintaining relationships with trading partners, while ensuring exporters satisfy domestic supply obligations.

Gas Pricing Framework

Findings – a gas reservation scheme may help reduce prices

The Report found that, although gas prices have fallen significantly since the 2022 crisis and commitments to domestic supply have increased, the East Coast market remains highly exposed to international price volatility. Higher gas prices present a trade-off: while they incentivise investment in new supply and infrastructure, they also reduce domestic demand and drive substitution toward cheaper alternative energy and feedstock. Some industries lack viable near-term alternatives, being vulnerable to sustained high costs.

Stakeholder submissions indicate that the Code's "reasonable price" cap mechanism has been ineffective in materially reducing or containing costs. Even with a gas reservation scheme, East Coast gas prices are still expected to pose challenges for Commercial and Industrial (C&I) users who cannot readily electrify or switch feedstocks.

Recommendations – remove the price cap

The Government proposes to phase out the Code's "reasonable price" cap and the Conditional Ministerial Exemptions framework, subject to the successful implementation of a gas reservation scheme and transitional arrangements. Where these reforms do not sufficiently reduce prices for industrial users critical to Australia's sovereign interests, the Government may consider targeted measures (such as ad-hoc subsidies) to ensure their ongoing operational viability. It is complex to achieve a balance between supporting local industries exposed to global competition and maintaining sufficient incentive for investment in industries where Australia has a comparative advantage. There are advantages in ensuring transparency in the targeted measures which are adopted.

Market Conduct and Efficiency Reforms

Findings – buyer bargaining power has not improved, shorter-term contracting prevalent and centralised markets are critical

C&I gas buyers continue to face limited options in gas supply, with approximately 90% of gas traded through bilateral contracts. While producers are generally regarded as acting in good faith, only a small proportion are considered to provide genuine offers, such that buyers' ability to negotiate competitive outcomes are generally constrained. Existing regulatory instruments have not materially improved bargaining power or confidence for C&I users, and the Code's EOI process has been criticised for its inefficiency.

Further, contracting trends are shifting toward short-term agreements of less than 12 months, while long-term volumes remain below pre-2022 levels and flexibility in non-price terms is declining. The ACCC has attributed this partly to exemptions from EOI requirements for short-term gas supply agreements, which may have unintentionally shifted the market toward shorter-term contracting.

In its own reviews, the ACCC has found that there is no evidence of a persistent market failure or any systemic problem requiring price regulation. Indeed, the ACCC went on to find that there is a risk that doing so would harm an already fragile competitive environment, with any reduction in competition operating to the detriment of C&I users. The ACCC recognised that retailers face a range of challenges in supplying to C&I users and that these challenges are likely to increase in the future.

The ACCC has now issued for consultation draft guidance for retailers selling to C&I customers, focusing on:

• Imposing an obligation of good faith in all aspects of the contract negotiations and over the life of the contract;
• Imposing some prescription around the offer process;
• Adopting an overall principle of risk allocation that the party best placed to manage the risk should bear the relevant risk;
• Imposing additional obligations on retailers when selling spot market linked products to C&I users; and
• Requiring publication of non-price terms on retailers' websites.

The Report also expressed the view that centralised markets can play an important role in the more efficient operation of short term markets by increasing transparency, improving liquidity and addressing risk through the use of a central counterparty and monitoring margin positions. This is particularly pronounced as coal exits the market and reliance on gas powered generation (such as gas peaking plants) grows.

Recommendations – shift from EOI prescription to selling principles, clarifying the Code's application, enabling the GSH & DTS and considering equity marketing

The Report recommends significant reforms to improve market conduct and enhance efficiency across Australia's gas sector. A key proposal is streamlining the Code by replacing the Code's EOI process with principles-based selling requirements for long-term contract exceeding 12 months. This reform aims to simplify compliance while promoting transparency and fair dealing.

Other suggestions in the Report to address stakeholder concerns include:

• making the EOI process more flexible to reflect practical contracting timelines;
• clarifying that bilateral contracting is permitted; and
• excluding buyer-initiated offers from EOI requirements to reduce compliance burdens and encourage long-term bilateral contracting.

Another proposal is that centralised trading platforms, such as AEMO's Gas Supply Hub (GSH) play an increased role as a full virtual hub, thereby enabling greater market participation and liquidity for the short-term market. This would be supported by a requirement that, wherever feasible, all uncontracted and reserved gas transactions for supply periods up to 12 months be conducted through the GSH. Complementing this, the development of a forward trading market on the Victorian Declared Transmission System (DTS) is recommended to provide additional flexibility and price discovery.

To further strengthen liquidity, the Report proposes introducing a "market-maker" regime – either voluntary or mandatory – or implementing a periodic auction process under the Code. These measures target strengthening trading activity within the GSH and any future markets established on the Victorian DTS.

In addition, the Report announces the Government's intention to explore amendments to the Code requiring wholesale market participants to market and sell gas based on upstream equity interests rather than joint venture structures. The implementation of such a change is intended to enhance competition and reduce structural barriers to entry. This is issue which the ACCC has previously considered, particularly for mature projects.

Noting that, in some circumstances, joint arrangements may be appropriate for gas buyers, the Report requests that the ACCC assist gas buyers by raising awareness of competition law mechanisms that facilitate collective negotiations, thereby improving bargaining power and market outcomes for industrial users.

Transparency, Governance and Reporting Reforms

Findings – transparency remains poor, heavy reporting burden and regulatory costs

The Report identifies fragmentation of price and supply transparency across gas markets, which increases search and transaction costs for participants. Smaller buyers often rely on incomplete and outdated price information, while larger suppliers benefit from broader market engagement during bilateral negotiations. Publicly available long-term price data is limited to ACCC quarterly reports, which lag the market by three to six months, while short-term pricing is only available through AEMO's Gas Bulletin Board (GBB)and trading hubs. Supply transparency remains poor, with obligations under the Code and the HoA failing to materially improve access to uncontracted gas or EOIs.

Enhanced transparency would help reduce information asymmetries, strengthen competition, and support more efficient contracting. However, these benefits must be balanced against the reporting burden imposed on market participants. Extensive reporting burdens have created a significant regulatory cost, which is ultimately passed through to buyers. Removing the HoA and the ADGSM would alleviate this burden for East Coast LNG exporters, particularly where duplicative requirements exist due to limited information-sharing between regulatory agencies.

The Report indicates that fundamental reform could marginally increase regulatory costs for gas market participants compared to the other options (no change or incremental reform), with uneven impacts across stakeholders. Further consultation is required to assess these costs and implications in more detail.

Recommendations – AEMO to lead near real-time reporting on the GBB, new forward price index, voluntary reporting and AER to have central regulatory oversight

The Report recommends measures to improve transparency. Central to the proposed reforms is the introduction of AEMO-led near real-time transaction reporting on the GBB, which would create a forward price index (based on agreed contract prices and other existing price indicators) and centralise reporting of uncontracted gas and EOIs.

In addition, the Report proposes expanding the scope of reported information to include voluntary disclosure of buyer-led EOIs, material changes to reserves, and details of undeveloped gas projects that have not yet reached final investment decision.

The Report recommends consolidating regulatory oversight under the Australian Energy Regulator (AER), as the proposed "single-lead agency", to streamline governance and reduce duplication. This would involve discontinuing the ACCC Gas Inquiry after a transition period and eliminating overlapping reporting burdens. The AER's expanding Wholesale Market Monitoring functions presents an opportunity to streamline this. Further information is available here and here.

Gas Infrastructure

The Report refers to projections that annual gas powered generation (GPG) is to increase from ~5.4TWh in FY2025 to ~17.7 TWH by FY2044 before falling to ~6.4 TWh by 2050. Correspondingly, annual gas consumption of GPG is forecast to more than double to over ~180 PJ/year by 2044. The Report underscores the need for new and upgraded infrastructure to transport gas produced in northern regions of Australia to southern demand centres. It recommends that the Government encourage private sector investment in pipeline networks and storage facilities, to ensure reserved gas can be delivered and stored near demand centres at an affordable cost and sufficient capacity.

The Report advocates for measures to stimulate infrastructure investment and proposes potential amendments to the National Gas Law (NGL), particularly aimed at incentivising pipeline capacity expansions. It anticipates that the proposed domestic gas reservation scheme will strengthen incentives for infrastructure development, improving transport efficiency and capacity. Additionally, the Report supports extending AEMO's powers to enable intervention as a last resort to address gas infrastructure constraints in the East Coast gas market. These proposed changes are contingent on, and intended to complement, broader reforms currently being considered by the ECMC, including the consultation on extending AEMO's reliability and supply adequacy function (see below).

The ECMC and Resources Ministers are also exploring alternative measures to address medium-term supply shortfalls, including identifying gas storage options in South Eastern Australia and investigating barriers to development of key supply and infrastructure.

Implementation Pathway

The Report calls for a structured transition plan to support the proposed reforms. This includes a potential short-term extension of the HoA, obtaining stakeholder feedback on provisions to be retained, and exploring whether the Code should be exempted from the sunsetting provisions in the Legislation Act 2003 (Cth). The Code is scheduled to sunset automatically on 1 October 2033. If the Government wishes to keep the Code in force beyond this date, it must proactively remake or extend the instrument before it sunsets.

Complementary Reforms

In conjunction with the above recommendations, the Report proposes that the Government consider amending the NGL to:

• extend greenfield pipeline exemptions to brownfield capacity expansion projects, to encourage further development; and
• permit applications for exemptions from the Day Ahead Auction for both greenfield and brownfield projects, to incentivise foundation customer contracting.

A number of other reforms are currently being progressed under the NGL including:

• anonymising trades in the GSH, with AEMO as a central clearing body; and
• harmonising prudential arrangements across AEMO-operated markets to lower entry barriers and reduce costs.

Other reforms and consultation

AEMC - Reliability and Supply Adequacy Reforms

Another reform under development alongside the Report's recommendations is the rollout of Stage 2 of the East Coast Gas Market Reliability and Supply Adequacy (RSA). These reforms build on Stage 1 reforms implemented in 2023, which expanded AEMO's powers under the National Gas Rules to monitor, signal, and manage gas supply shortfalls.

Stage 2 focuses on enhancing planning frameworks and governance arrangements. Senior Energy Officials have submitted four rule change requests to the AEMC, which are at various stages of consultation and determination. The proposals include:

1. Introducing a reliability standard and associated settings to improve risk management and investment signals.
2. Establishing a supplier of last resort mechanism to enable AEMO intervention when market participants cannot meet reliability requirements.
3. Requiring advance notice of gas infrastructure closures to improve transparency and support planning responses.
4. Implementing new projected assessments of system adequacy (PASA) for short-term (seven-day) and medium-term (12-month) horizons to provide better visibility of potential shortfalls.

Current Status of Rule Changes

These Stage 2 reforms are expected to be progressively and mostly implemented throughout 2026. Some reforms – such as PASA forecasting and reliability standard changes – are likely to extend into 2027.

Proposed extension of AEMO's powers via the Last Resort Investment Support Tool

In parallel, the ECMC is consulting on whether to expand AEMO's powers to address structural shortfall that are projected to occur in the East Coast gas market. The central focus is the introduction a last resort investment support tool (LR RSA tool).

The objective of the LR RSA tool is that "tool should only be exercised to prevent, reduce or mitigate an identified threat" when there is no reasonable prospect of addressing the threat in time through other means, its use is an appropriate response given the type, scale, and consequences of the threat, and no other AEMO functions provide an effective solution.

The consultation paper outlines supply‑side investments that may be supported under the LR RSA tool, including domestic gas processing and upstream production facilities, LNG import terminals, transportation infrastructure, gas storage facilities, and blending and processing facilities. It expressly excludes projects that involve material production risks, which require additional Ministerial approval during the tender stage.

As a condition of receiving support under the LR RSA tool, proponents would be required to make the supported products or services available to the market through existing AEMO markets and/or a new AEMO auction on standardised terms and subject to a reserve price. This requirement is intended to preserve incentives for market participants to contract on commercial terms and to ensure supported investments contribute directly to market liquidity and reliability outcomes.

The consultation opened on 7 January 2026 and submissions are due by 13 February 2026. The ECMC is expected to make its decision in mid-2026. The policy design appears to be at an advanced stage, as the consultation paper is accompanied by exposure draft legislation, regulations and a guide on the key changes that would need to be made for its implementation.

Potential design of the Last resort tool

Under the draft proposal, before AEMO seeks Ministerial approval to implement the LR RSA tool, the following conditions must be met (and consideration must be given to whether use of the LR RSA tool aligns with its objectives):

• AEMO identifies a threat to the reliability or adequacy of supply in the East Coast gas system; and
• AEMO communicates the threat to the market through its East Coast gas system RSA monitoring and communication functions or through the annual Gas Statement of Opportunities (GSOO) (and there is no market response).

Where Ministerial approval is obtained, the same Ministers will be responsible for determining:

• whether AEMO should proceed to an EOI and then tender, or directly proceed with a competitive tender process;
• the tender scope and related conditions, including:
  • the scope of the threat for which a tender may seek a solution; and
  • the amount of financial support AEMO may provide; and
• how the costs should be shared between funding jurisdictions.

In line with Ministerial directives, AEMO would be responsible for conducting the EOI and/or competitive tender to identify the solution(s) required to address the threat within the required location and timeframe. AEMO would also be responsible for evaluating the tender responses and deciding whether to enter into a contract with a proponent to support the investment (being an investment support agreement).

The consultation paper proposes the investment support agreements will take the form of one of two types of revenue support agreements: a fixed revenue contract or a revenue cap-and-floor contract on a case-by-case basis. This is similar to contracts used in the Capacity Investment Scheme and Long-Term Energy Service Agreements in the NEM.

The use of the LR RSA tool may be stopped at any point before the investment support agreement is executed. This flexibility is to recognise that a market solution may emerge while the approval and tender process are on foot.

Costs – Net cost recovery

The net costs associated with the LT RSA Tool include the payments made under investment support agreements and related program costs such as running the EOI and/or tender, monitoring contracts, making supported products and services available, compliance and reporting obligations.

The proposed cost-recovery approach consists of three main steps:

• Step 1 - Cost sharing between jurisdictions (% of net costs to each funding jurisdiction).
• Step 2 - Allocation of net costs to gas and electricity markets in funding jurisdictions (% of net costs to each market).
• Step 3 - Allocation of net costs to energy users in funding jurisdictions (net costs to each user) (gas-fired power generators would be excluded from the allocation to gas users, as their share of costs will be recovered from NEM participants).

The consultation paper also considers alternative cost-allocation approaches, such as beneficiary or causer-pays models or exclusions for participants with direct contracts. Due to practical difficulties in identifying the causer, it recommends the net-cost allocation approach (outlined above) as the most equitable option.

Potential extension of the Gas Statement of Opportunities

The consultation paper also seeks feedback on proposed changes to the GSOO aimed at improving forward-looking information and reducing information barriers that may be limiting market-led investment. It proposes changing the GSOO's publication cycle to every two years, with the option to update key information if market or system conditions change. Under the proposed extension, the GSOO would provide a 10-year outlook on reliability and supply risks, detailed information on potential supply-side projects (including location, scale, type, timing, and associated risks), and highlight options capable of addressing identified threats within the required time and location, including assessments of cost and deliverability.

Preparing for the Reforms: Next steps

The Government plans to commence stakeholder consultation on the design of the domestic gas reservation scheme and associated market reforms soon in 2026. Market participants are encouraged to actively engage by providing feedback. Implementation of the reservation scheme is targeted for 2027, alongside broader reforms to pricing, transparency, and governance – marking a significant shift toward a consolidated and longer-term regulatory regime. The complementary reforms being progressed by the AEMC and ECMC should also be considered closely as they have critical implications for the overall framework and reliability measures.

HSF Kramer is leading the market in navigating these changes, including advising clients on compliance obligations, competition law, structuring, marketing and trading arrangements, and engaging effectively in the consultation process. Our team combines deep regulatory expertise with practical industry insights to help manage risk and realise opportunities arising from these reforms.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.