Australia's Domestic Gas Reservation Scheme: inside the Draft Design Framework

The Australian Government has announced key elements of its proposed Domestic Gas Reservation Scheme. The Reservation Scheme is intended to commence in 2027, with the DSO taking effect on and from 1 July 2027. The Draft Design Framework represents a significant shift in Australia's approach to ensuring domestic gas supply security.

Key takeaways

• All Australian LNG exporters (including in Queensland, Western Australia and the Northern Territory) will have an annual Domestic Supply Obligation (DSO) to supply a proportion of their total production equivalent to 20% of their LNG exports to the Australian domestic market.

• LNG producers will need to apply to Ministers for an export approval licence, submit Board-endorsed compliance plans for the 2027 regulatory period, and provide evidence of export contracts, associated terms and conditions, and how their DSO commitments will be met.

• Ministers will have the ability to attach conditions to a licence, including where regulated entities are granted a variation in their DSO to account for existing export contracts.

• Before 1 July 2027, Ministers, with advice from the AER, will decide on export approvals, announce the forward pro-rata DSO for 2027, and confirm individual DSOs taking into account any approved variations. To inform approval decisions, the AER in consultation with AEMO will provide advice on the domestic market's demand outlook, the impact of exports on domestic supply, and any adjustments to DSO requirements.

• The regime will operate alongside state-based reservation schemes (such as Western Australia's domestic reservation policy) and other state-based arrangements (such as Queensland's Australian Market Supply Condition). We expect this to be subject to further consultation.

• Offers alone are not sufficient to meet the DSO. LNG exporters must physically supply the gas to the domestic market in order to meet their DSO. The requirement for physical supply, as opposed to merely making offers, is a critical distinction from previous regulatory arrangements.

• Where an LNG exporter is unable to meet its DSO from its own production, it may acquit its DSO by entering arrangements with other producers to supply gas on its behalf, but this will be subject to an additionality test. That test will require that the third party arrangement must result in the supply of gas that would not otherwise have been made available to the domestic market.

• If an LNG exporter is already supplying gas to the domestic market under existing gas supply agreements, those volumes will count toward meeting its DSO.

• Qualified relief is available for existing LNG export contracts – there must be “no viable alternative” to meet the DSO.

• There is no price floor proposed. The frameworks suggests supply must be on "domestically competitive terms" and the proposed changes include establishing a forward price curve and publishing commodity price data as close to real-time as practicable.

• A liquidity requirement will be introduced, designed to achieve a "modest oversupply" (equating to 110% of domestic demand). This will require DSO volumes that are unable to be contracted in advance to be made available through short term markets, with the volume limit set at up to 30% of the LNG exporter's DSO.

• To manage periods of significant oversupply, the scheme includes a discretionary ability to reduce the DSO and a market-based release valve (as a mechanism of last resort), which is yet to be fully developed. The maximum annual accrual under the release valve is set at 30% of the DSO. Any reduced DSO volumes via these mechanisms will accrue or must be made up in future periods. However there is not yet a mechanism for managing the drawdown, or any cap on cumulative accrued liabilities across multiple years.

• The Gas Market Code's conduct and negotiation obligations will be replaced by new selling practice requirements.

What do market participants need to do to prepare?

Consultation on the framework is open until 30 June 2026.

Affected gas market participants should consider engaging with the consultation process and continue to monitor for additional detail and information sessions.

As this policy is expected to have wholesale changes to the Australian domestic gas market, gas producers and gas market participants should review their development and production plans and gas marketing practices in light of the proposed changes.

Export approval

Regulated entities (all LNG exporters in Australia), will need to apply to the Ministers for export approval. In order to maintain approval to export, regulated entities must meet their annual Domestic Supply Obligation (DSO).

Regulated entities will have the opportunity to propose an individual variation in their annual DSO to account for pre-existing LNG contracts (those entered into before 22 December 2025) or other relevant matters such as existing regulatory schemes or infrastructure constraints.

The Ministers will have discretion to impose conditions on an export approval, including where regulated entities are granted a variation in their DSO to account for existing export contracts

How is the supply obligation calculated?

Central to the framework is the DSO, which will require LNG exporters to supply a proportion of their total production equivalent to 20% of their LNG exports to the domestic market. The DSO will be calculated on the thermal energy content of the volume of LNG exported, using the formula:

DSO = 20% × LNG Exports.

Importantly:

• LNG exports will be measured at the point of loading and converted to joules (to align with how domestic supply is measured). LNG that is resupplied into the domestic market (for example, through a regassification terminal) is excluded from the calculation;

• the framework provides that gas supplied by a regulated entity to the domestic market under existing supply agreements (including those entered into before 22 December 2025) can count towards the acquittal of the regulated entity’s DSO;

• the reservation percentage is not subject to a time-bound review. Instead, the primary legislation will outline a mechanism through which Ministers may review the reservation percentage based on advice from the AER (in consultation with the Australian Energy Market Operator (AEMO)) and clear and observable criteria. The framework flags that such criteria could include forecast material and persistent undersupply of gas to the domestic market beyond what is manageable through AEMO’s East Coast Gas System Reliability and Supply Adequacy functions; and

• regulated entities may seek to vary their annual DSO to account for volumes under existing export contracts entered into on or before 22 December 2025, subject to demonstrating there is no viable alternative to meeting their DSO without a variation.

When does the DSO take effect?

The legislation enacting the Reservation Scheme is intended to commence in 2027, with the DSO taking effect on and from 1 July 2027.

Are existing LNG export contracts protected?

The Government states that existing contracts (entered into on or before 22 December 2025) "will be respected" as a "core announced design principle" for the Reservation Scheme. However, the mechanism by which they are respected is narrower than this commitment suggests.

There is no "of right" protection for volumes supplied under existing LNG export contracts. Instead, LNG exporters must apply for a variation in their annual DSO and will only receive relief from its DSO obligation in respect of existing contracts for export if it can demonstrate to the Ministers that there is no viable alternative to meeting their DSOs without breaking those contracts.

There is no definition of what "no viable alternative" means but regard will be had to a broad range of matters including volumes committed under current contracts, forecast LNG production, volume of uncontracted gas, the ability to buy gas from third parties, the ability to conduct location swaps, the ability to flex down delivery volumes under export contracts, and the ability to fulfil export contracts using LNG sourced from portfolios or international markets.

The practical effect is a discretionary pathway to a DSO reduction that is subject to a potentially stringent threshold test and Ministerial satisfaction.

Extensions or variations to existing contracts executed after 22 December 2025 are not considered existing contracts for these purposes. The framework does not define "extension" or "variation" and does not address commercial arrangements such as the exercise of contractual extension options that were embedded in agreements signed before 22 December 2025.

Infrastructure constraints

As part of an entity's application for export approval, Ministers will have discretion to vary the DSO if the entity is unable to physically supply gas due to infrastructure constraints.

Regulated entities will need to demonstrate they are putting in place commercial arrangements to overcome any infrastructure constraints that may otherwise prevent them supplying their DSO gas into the domestic market over the medium-longer term.

More detail is needed to assess how this requirement would apply to floating LNG projects and other projects where market connection relies on third party infrastructure. The framework does not address what happens if the commercial solution proves unviable or whether the entity remains indefinitely liable for an obligation it physically cannot discharge.

What is the impact on existing policies, like Western Australia's gas reservation?

The framework has flagged that a regulated entity may be entitled to a variation in its DSO to reflect "existing regulatory arrangements (such as state-based reservation schemes or other arrangements with state and territory governments)." However, little detail has been provided as to how this regime will operate alongside such state-based reservation schemes (such as Western Australia's domestic reservation policy) and other state-based arrangements (such as Queensland's Australian Market Supply Condition). We expect this to be subject to further consultation.

How does the DSO work practically?

Export approval process

1 April 2027 – deadline for export approval submission: By 1 April 2027, LNG producers will need to apply to the Ministers for an export approval, submit Board-endorsed compliance plans for the 2027 regulatory period (pro-rated from 1 July 2027), and provide evidence of export contracts, associated terms and conditions, and how their DSO commitments will be met. We expect that it will be at this point that an LNG exporter must also propose any variation to its DSO to recognise existing export contracts. In doing so, LNG exporters should assume that their baseline DSO obligation is 20% of their total exports, with any reduction for existing contracts to be the subject to the grant of a variation by the Ministers.

Before 1 July 2027 – Ministers to decide on export approvals: Before 1 July 2027, the Ministers, with advice from the AER, will decide on export approvals, announce the forward pro-rata DSO for 2027, and confirm individual DSOs taking into account any approved variations.

To inform approval decisions, the AER in consultation with AEMO will provide advice on the domestic market's demand outlook, the impact of exports on domestic supply, and any adjustments to DSO requirements. The Ministers will have the ability to attach conditions to a licence, including where regulated entities are granted a variation in their DSO to account for existing export contracts.

1 September 2027 – deadline for 2028 compliance plan By 1 September 2027, LNG producers must submit their Board-endorsed compliance plans for CY2028 to the AER (including any requests to vary the DSO for that year).

By 1 November 2027 – Ministers to decide on variation requests Before 1 November 2027, the Ministers, with advice from the AER, will decide on any DSO variation requests.

It is expected that similar timelines will continue to apply for each following calendar year.

How is the DSO practically met?

Offers alone are not sufficient to meet this obligation. LNG exporters must physically supply the gas to the domestic market in order to meet their DSO. This may be met via:

• their own production by way of standard commercial and market-based arrangements, including long and short term bilateral contracting, sales into AEMO-facilitated markets, and other contractual agreements that result in the delivery of gas to domestic buyers; or

• where an LNG exporter is unable to meet its DSO from its own production, it may acquit its DSO by entering arrangements with other producers to supply gas on its behalf, but this will be subject to an additionality test. That test will require that the third party arrangement must result in the supply of gas that would not otherwise have been made available to the domestic market. It is unclear how the AER or Ministers will determine what gas "would not otherwise have been" supplied domestically (ie additional gas) or that gas is merely being reallocated.

The framework notes that this could include gas supplied by another LNG exporter, gas supplied via an LNG regassification facility, gas supplied by another domestic producer where the regulated entity has underwritten the development of supply from a new or expanded field, or renewable gases such as biomethane.

The framework expressly states that "gas supplied by a regulated entity to the domestic market under existing supply agreements (including those entered into before 22 December 2025) can count towards the acquittal of the regulated entity's DSO." This suggests that if an LNG exporter is already supplying gas to the domestic market under existing gas supply agreements, those volumes will count toward meeting its DSO.

How is the DSO enforced?

The AER will establish a performance reporting framework to assess whether regulated entities remain on track to meet their DSOs, supporting early identification of emerging compliance risk. The AER will have a range of standard remedies available including court enforceable undertakings, issuing infringement notices, injunctions, or financial penalties. Where non-compliance relates to a failure to meet the DSO, the AER will also be able to escalate the matter to Ministers, who may then decide to vary, suspend or revoke an export approval.

Financial penalties are proposed to be at least as high as those available under the Competition and Consumer (Gas Market Code) Regulations 2023 (Cth) (the Gas Market Code). For tier 1 penalty provisions, the current maximum penalty for a body corporate is the greatest of $100 million, three times the value of the benefit obtained, or 30% of the body corporate's adjusted turnover during the breach turnover period.

At what price do DSO volumes need to be supplied?

The framework does not prescribe a specific price at which DSO gas must be sold. Importantly, there is no floor price below which regulated entities are relieved from selling DSO gas.

The existing Gas Market Code includes a "reasonable price" mechanism set at $12/GJ. The previous Gas Market Review Report recommended phasing out the $12/GJ reasonable price mechanism and the Conditional Ministerial Exemption framework, subject to the reservation scheme being successfully implemented.

It is not yet clear if or when the reasonable price mechanism will be phased out.

The framework appears to rely on structural and behavioural measures to constrain pricing:

• The minimum liquidity requirement is designed to ensure a modest oversupply of the domestic market, which should exert downward price pressure.

• The selling practice obligations require that "price and non-price terms should reflect appropriate risk allocation" and that gas must be offered on "domestically competitive terms" as a precondition for accessing the release valve.

• The Gas Market Code's conduct provisions will require regulated entities to negotiate in good faith when entering into gas supply agreements.

How is supply and demand to be managed?

Minimum liquidity requirement

A minimum liquidity requirement will apply, designed to ensure a modest oversupply of the domestic market (suggested to be 110% of existing market demand) and put downward pressure on prices.

Any DSO volumes that are unable to be contracted under longer term arrangements will need to be made available to the market through shorter term markets. Meeting this requirement will be a precondition for use of the Reservation Scheme's flexibility mechanisms for managing oversupply (set out below).

Subject to consultation, the volume limit of the liquidity obligation could be set such that up to 30% of gas is traded in spot markets. Separately, the maximum annual accrual under the release valve is also set at 30 percent.

How is oversupply intended to be managed?

To manage periods of significant oversupply, the scheme includes a discretionary ability to reduce the DSO and a complex market-based release valve, which is yet to be developed. Any reduced DSO volumes via these mechanisms will accrue to future periods.

• Prior to the regulatory period (Annual DSO flexibility): Ministers, on advice from the AER and in consultation with AEMO, may vary the DSO following an application by a regulated entity to reflect the forthcoming year's expected demand forecasts, plus a buffer. It is flagged that any such variation would face a high assessment threshold.

Any approved variation to DSO volumes for a regulated entity will be carried forward into future compliance periods, ie., unmet volumes resulting from a reduction to a DSO will accrue and must be met in future periods.

During the regulatory period (Market-Based Release Valve): A market-based mechanism will facilitate exports when the domestic market cannot absorb DSO volumes (ie. where there is more than a modest oversupply). If liquidity obligations have been met and the domestic market is observably well-satisfied, regulated entities may be excused from meeting all of their DSOs and permitted to export excess volumes. This will be subject to conditions around near-term supply adequacy metrics, conduct requirements, and participation in periodic auctions aimed at balancing short-term supply and demand. The release valve appears to be a last resort mechanism.

Accrual of DSO volumes

Crucially, any DSO volumes reduced or released via either of the above mechanisms will carry forward (or accrue) to future compliance periods, requiring regulated entities to make up such volumes in subsequent years.

This may serve as a significant disincentive to exporters producing beyond the minimum volumes necessary to meet its DSO obligation or otherwise seeking to exercise the release valve, if their development plans cannot account for such DSO volumes being carried forward into future years.

The framework does not clarify how and when regulated entities are to make up those volumes. There is little clarity as to how such make-up volumes will interact with reduced DSO volumes in future years (e.g., due to a DSO variation applicable to that later year). Further, there is not yet a mechanism for managing the drawdown schedule, or any cap on cumulative accrued liabilities across multiple years.

The framework notes that "ongoing accrual of DSO volumes could lead to excessive liabilities that may be impractical or impossible for regulated entities to deliver" and that "LNG exporters have expressed concerns that accrual volumes would be considered balance sheet liabilities".

Domestically competitive terms

The selling practice obligations require that "price and non-price terms should reflect appropriate risk allocation" and that gas must be offered on "domestically competitive terms" as a precondition for accessing the release valve. However, this concept is not defined. The framework provides that the AER will make guidelines on selling practices, but does not indicate what benchmarks or reference points will be used to assess whether terms are "domestically competitive".

The transparency measures propose establishing a forward price curve and publishing commodity price data as close to real-time as practicable on the Gas Bulletin Board, which may be intended to serve as a market-based reference point for what constitutes "competitive" pricing.

The release valve conditions require "observable evidence of genuine attempts to enter into long-term gas supply agreements" and a "minimum marketing obligation to offer gas in a manner that's transparent and accessible to as many buyers as possible". This suggests that the assessment may be intended to be process-based (was the gas marketed broadly and transparently?) rather than outcome-based (was a specific price achieved?).

What else is changing?

The framework proposes integrated market reforms to complement the reservation obligation, focusing on wholesale market conduct obligations and increased transparency measures.

Wholesale Market Conduct Obligations

The Gas Market Code's conduct and negotiation obligations will be replaced by selling practice requirements. These include requirements for producers to:

• determine reasonable open offer periods;

• negotiate timeframes with prospective buyers;

• ensure price and non-price terms reflect appropriate risk allocation;

• not withdraw or terminate offers unless there is a material change in circumstances;

• respond to Expression of Interest submissions in a timely manner; and

• negotiate in good faith.

Transparency measures

The framework proposes consolidating and enhancing transparency metrics for the east coast gas market by centralising price information, available gas supply data, and market notifications on the Gas Bulletin Board. Proposed changes include establishing a forward price curve, publishing commodity price data as close to real-time as practicable, consolidating available gas reporting requirements, facilitating buyer-led Expressions of Interest on the Gas Bulletin Board, and publishing additional notifications regarding changes to reserves and project status.