The new Domestic Gas Reservation Scheme: What it means for LNG and gas supply in Australia

On 7 May 2026, the Commonwealth government announced the design of a new East Coast Gas Reservation Scheme, marking the most significant structural intervention in Australia’s gas market in decades. While initially unveiled as a reservation scheme for the east coast, when the draft design framework was published on 27 May 2026, it was recast as a Domestic Gas Reservation Scheme and is designed to operate on a national basis (DGR Scheme).

From 1 July 2027, liquefied natural gas (LNG) exporters will be required to reserve an amount equivalent to 20% of export volumes for sale into the domestic gas market. Offers to the domestic market will not be sufficient to acquit an exporter’s domestic supply obligation (DSO) – rather, the exporter must physically supply gas to gas buyers in the domestic market.

Resources Minister Madeleine King stated that the DGR Scheme would ensure the east coast gas market is no longer “hostage to international markets,” aiming to address forecast domestic supply shortfalls and place sustained downward pressure on prices that have increasingly mirrored international LNG pricing since exports commenced in the 2010s. This is due, among others, to a phenomenon known as ‘LNG net back pricing’, i.e., a gas producer supplying gas to an LNG export project wants the price for their gas to be equivalent to the LNG sales price for that gas after deducting transportation, processing, marketing, shipping and other costs associated with the sale of the LNG. Theoretically, this should be higher than the domestic sales price.

Key features of the DGR Scheme

The DGR Scheme will apply to prospective supply contracts and spot‑market gas but will not disturb LNG export contracts entered into prior to 22 December 2025 (the date the DGR Scheme was first flagged by the government).

Under the DGR Scheme, LNG exporters will require Ministerial export approval and, as part of that process, will need to demonstrate how their export contracts (including new contracts) are consistent with, and allow compliance with, their Domestic Supply Obligation.

LNG exporters may seek a variation to their annual DSO to take account of LNG export contracts entered into before 22 December 2025 (when the DGR Scheme was first announced). These contracts are intended to be recognised within the DGR Scheme, so variations are expected to be needed only where necessary to make the DSO workable. To obtain a variation, an exporter must satisfy the relevant Ministers that it cannot reasonably meet its DSO given its existing contractual commitments and available supply. Any extensions or material changes to those contracts agreed after 22 December 2025 will not be treated as pre‑existing contracts.

While expressed to be a national scheme, given that LNG is only exported from projects in Queensland, Western Australia and the Northern Territory, the impact of the Scheme is effectively limited to those jurisdictions. There are no existing or proposed LNG export projects in any of New South Wales, Victoria, Tasmania or South Australia.

Also, the impact of the DGR Scheme on LNG projects and their investors in Western Australia is likely to be substantially less than on the projects in Queensland and the Northern Territory. This is because LNG projects in Western Australia have long been subject to a 15% DSO, so, in effect, the DGR Scheme effectively only amounts to an increased burden of 5%. The DGR Scheme will more severely impact Queensland’s three major LNG projects – the Australia Pacific LNG project, the Gladstone LNG project and the QCLNG project and the two LNG export projects in the Northern Territory, being the Ichthys and the Darwin LNG projects.

The DGR Scheme replaces existing intervention tools such as the ‘gas trigger’ under the Australian Domestic Gas Security Mechanism, signalling a shift from reactive market intervention to a standing, structural control on export volumes.

The DGR Scheme also incorporates a release valve mechanism under which, once minimum liquidity and market conduct obligations have been met, the AER may permit DSO volumes that are surplus to domestic demand to be exported. However, any released volumes accrue as a liability to be made up in subsequent periods (capped at 30% of annual DSO), meaning the mechanism provides temporal flexibility rather than a reduction in the overall domestic supply obligation.

Commercial implications

For LNG exporters, the policy affects export flexibility and project economics, particularly for future gas supply developments. While legacy contracts are protected, new supply arrangements will need to accommodate reduced exportable volumes and greater regulatory oversight.

For domestic gas users, particularly manufacturers, power generators and large industrial customers, the DGR Scheme may improve supply certainty and negotiating leverage over the medium term. However, the extent to which domestic prices fall will depend on how producers respond commercially, including whether reservation volumes are sold on a short- or long-term contract basis. It is interesting to speculate, however, what the price dynamics of ‘reserved’ gas sales will be in the Australian market given that buyers know that exporters must physically supply gas into the market to meet their DCO but buyers aren’t required to buy it.

Economic impact

From an economic perspective, the climate change and energy minister, Chris Bowen anticipates a modest oversupply of gas into the east coast market, intended to decouple domestic prices from international volatility and reduce them. If achieved, this could support industrial competitiveness and energy affordability during the energy transition.

The reservation measures have been announced amid sustained pressure on the Commonwealth government to introduce additional taxes on gas export revenues, particularly following periods of elevated LNG profits. By opting for a reservation scheme instead, the government appears to be pursuing domestic price and supply outcomes while attempting to avoid the risk of backlash from Asian trading partners resulting from a new export tax. This approach has not been entirely successful, however, given comments from some of Australia’s LNG trading partners in Asia (some of which are touched on below).

However, the DGR Scheme may dampen investment signals for new upstream gas projects, particularly where returns depend heavily on LNG exports. Over time, reduced investment could offset some of the anticipated supply benefits. This is discussed in more detail below.

Scope and limitations of the DGR Scheme

Despite the impact on LNG exporters, the DGR Scheme is actually quite narrow in its scope in that it does not contemplate broader structural reform to gas supply, exploration or development. While Australia holds substantial underdeveloped or undeveloped gas reserves both in onshore and offshore reserves, the policy response reflected in the Scheme is focused solely on the allocation of existing production between export and domestic markets, rather than on measures to accelerate the development of new supply. Likewise, despite the importance of natural gas to the energy transition in Australia, DGR Scheme was not accompanied by any streamlining of new gas project approval processes, additional funding to support exploration, development or production, or any relaxation of Safeguarding rules under the National Greenhouse and Energy Reporting Act 2007 (Cth) (NGERS).

Also, while the DGR Scheme will apply to new LNG projects in Australia, we note that no final investment decision for a completely new LNG export project has been made in Australia since 2012 and since that time only a relatively small number of domestic-focused gas fields have been brought into production.

Undeveloped and underdeveloped gas basins

As mentioned, significant gas resources remain undeveloped or underdeveloped across Australia, including on the east coast. According to Geoscience Australia’s Energy Commodity Resources 2025 report, Australia’s total demonstrated gas resources (conventional and unconventional) are estimated at 247,427 petajoules (220tn cubic feet), of which 106,301 PJ (95 Tcf) are classified as proven and probable (2P) reserves [1]. However, resources are being depleted at a faster rate than they are being replaced by new discoveries and petroleum exploration expenditure remains at only a quarter of what it was a decade ago [2].

In the Northern Territory, the Beetaloo Sub-basin contains approximately 6,206 PJ (5.52 Tcf) of prospective shale gas but remains largely pre-production despite the lifting of the NT’s fracking moratorium in 2018[3].

In Queensland, the Galilee Basin holds significant CSG contingent resources estimated at 2,575 PJ (2.29 Tcf), but with no large-scale commercial production established to date [4].

New South Wales has maintained effective restrictions on CSG development since 2012, with the result that the state produces almost none of its own gas and is dependent on imports from Queensland and Bass Strait [5]. Notably, the Gunnedah Basin in NSW contains an estimated 2,261 PJ (2.01 Tcf) of contingent CSG resources that remain undeveloped (and see further commentary in the next section regarding the timeframes associated with the development of that project) [6].

Victoria’s Bass Strait gas fields have been in structural decline since the early 2010s, with exploration curtailed by state moratoria. In 2012, an administrative moratorium was placed on all onshore gas exploration and development in Victoria [7]. In 2017, the Victorian Government legislated a permanent ban on hydraulic fracturing and coal seam gas extraction and replaced the administrative moratorium on onshore conventional gas with a legislative moratorium that halted all exploration and development activities until 30 June 2020. While the moratorium on onshore conventional gas was lifted from 1 July 2021, onshore exploration activity has been minimal [8].

Offshore, the Great Australian Bight remains subject to exploration difficulties. BP withdrew from its proposed exploration drilling program in the Bight in 2016 following sustained environmental campaigning [9] and in 2019, the Norwegian energy company Equinor similarly abandoned its Great Australian Bight exploration plans citing commercial reasons amid intense opposition [10]. No major operator has since proposed an exploration drilling program in the Bight.

New exploration permits in the Otway Basins remain in bidding process following the December 2025 acreage release [11].

There are also significant undeveloped reserves in WA and while the government there is broadly supportive of gas developments, hydraulic fracturing is effectively banned in 98% of the State.

The existence of these undeveloped resources raises questions about the policy approach the government has chosen, that is, to intervene in the allocation of existing production rather than pursuing measures to facilitate development of new supply from identified resource basins that could be directed into the domestic market. Such projects could then incorporate the new rules into their economics at the outset instead of, as is the case with the impact of the Scheme, after investment decisions have already been made.

Gas project timelines in Australia

Santos Limited’s Narrabri Gas Project in the Gunnedah Basin illustrates the delays inherent in Australian gas approvals. Santos first acquired exploration interests in the early 2000s, with the formal EIS process commencing around 2014 and conditional approval granted in September 2020[12]. Production has not yet commenced, with the project subject to ongoing legal challenges supported by the Environmental Defenders Office (EDO) despite having received both NSW and Commonwealth approvals [13]. The total elapsed time from exploration to production is likely to exceed 20 years.

Similarly, the Scarborough gas field, located offshore of Western Australia in the Carnarvon Basin, was first discovered in 1979 but did not achieve final investment decision until November 2021, a gap of over 40 years [14]. Even after investment, the project was subject to multiple legal challenges in 2023 and 2025, contesting the validity of NOPSEMA’s environmental approval. In 2023, the Federal Court found that NOPSEMA did not have the power to approve part of Woodside’s offshore Environment Plan, introducing further delay and uncertainty to the $16.5 billion project [15]. As the 2025 challenge was unsuccessful, first gas is now expected at the end of 2026 [16].

Similarly, the Barossa gas field in the Timor Sea had its 2022 Environment Plan set aside by the Federal Court in 2022 following a challenge brought by the Tiwi Islands Traditional Owners, represented by the EDO. The Court found that Santos had failed to adequately consult with Traditional Owners [17]. Santos was required to submit a new Environment Plan, introducing nearly 4 years of delay. First gas was finally shipped in 2026.

The pattern across jurisdictions is one in which developers face extended approval timelines followed by the prospect of judicial challenge upon grant. So, despite the fact that Commonwealth and State governments have detailed legislative frameworks and processes for the grant of project approvals, which include extensive public consultation opportunities, Federal and State legislation enables various parties such as environmental groups to challenge the approvals their own agencies and Ministers issue. These challenges usually commence after a project receives approval but can also be the subject of judicial review of decisions by Federal or State Government Ministers. Indeed, some of the environmental groups mounting those challenges are also funded by some of the same Australian governments issuing the approvals, including the Commonwealth government [18].

Industry commentary on exploration and approval reform

Peak industry bodies have identified Australia’s gas supply challenges as primarily a development and approvals problem rather than one of resource scarcity and have consistently called for reform of Australia’s gas exploration and approval framework. APPEA has called for a more streamlined and nationalised approval process [19]. Australian Energy Producers has described the regulatory system as ‘broken’, noting that environmental plans for offshore exploration have been held up for an average of 562 days, more than triple the projected wait period and that ‘an approval no longer means an approval’ given the national regulator’s decisions have been overturned by the courts [20]. AusIMM has noted that ‘The latest international survey of mining companies casts a dark shadow over the Australian resources industry’, as no Australian jurisdiction ranks in the top 10 for the first time ever [21]. Prolonged approval uncertainty discourages the sustained investment in exploration phase activity that is a necessary precursor to new production. The DGR Scheme has amplified these concerns.

The depth of industry concern around the DGR Scheme is further illustrated by recent commentary from senior executives. Senex Energy chief executive Darren Stevenson described the proposed reservation scheme as “nationalisation by stealth,” warning that “the ministers are effectively taking control of the gas market” and that the reforms risked undermining Australia’s reputation as a destination for long-term energy investment. “What makes you confident they’re not going to do the same thing in your markets?” he said, cautioning that interventionist policies could spread beyond energy into other sectors [22]. MST Marquee head of energy research Saul Kavonic described the intervention as “a price control policy masquerading as a reservation policy.” [23]

Australian Energy Producers Chief Executive Samantha McCulloch said the proposed design “falls well short of what industry can support”, arguing it “overlays complex and opaque compliance obligations with high levels of ministerial discretion and excessive penalties for non-compliance” and would destroy market signals to invest in gas at a time when more supply is urgently needed [24].

The depth of foreign investor concern is also significant. These are parties who committed capital on the basis of Australia’s then-existing legal and regulatory framework and now face a material change to the commercial parameters of their investments. State-owned Korea Gas Corporation (KOGAS), a 15% owner in Santos’ GLNG venture, stated it regards the draft framework as ‘imposing a direct obligation’ on it to supply the domestic market, an outcome it described as ‘undoubtedly disappointing’ given the rules were not in place when it sanctioned its multibillion-dollar investment [25].

Sovereign risk considerations

There have been several decisions in Australia over the past 10 years that have caused concern among foreign investors and prompted commentators to consider the sovereign risks in Australia. For example, in June 2022 the Queensland Government increased coal royalty rates to progressive tiers of up to 40% without any meaningful prior industry consultation. At the time, Anglo American CEO Nick Barlow said “the new tax is inconceivable” and noted it would hurt cases for new investment as “significant capital investment is required.”[26] Japan’s then ambassador, Shingo Yamagami, argued the changes damaged “the trust in Queensland and beyond as a safe and predictable place to invest.” [27]

Other examples include the introduction of the east coast gas price cap and mandatory Code of Conduct in late 2022 without prior market consultation [28] and the Victorian Government’s permanent ban on hydraulic fracturing in 2017, which extinguished exploration rights that had been granted to permit holders [29].

A 2025 Wood Mackenzie report revealed that while investment in gas exploration globally had grown around 30% in the previous five years, Australian investment was lagging with just 15% growth recorded over the same period [30]. Wood Mackenzie’s report also found that 95% of those surveyed believe Australia is a less attractive place to invest today, compared with five years ago [31].

The DGR Scheme may well be viewed by some investors as a further example increased sovereign risk in Australian investments. Santos managing director and CEO Kevin Gallagher contended that requiring LNG exporters to divert gas to the domestic market would only briefly lower prices, while ultimately discouraging the investment in new supply needed for the east coast through the 2030s. He likened the situation to Argentina, stating:

“The Argentine experience is a well-documented case study in how interventions designed to protect domestic consumers can, over time, destroy the upstream investment base that sustains supply for those same consumers.”[32]

Shell Australia Chair Cecile Wake highlighted a technical yet crucial issue in the DGR Scheme’s design, distinguishing between an obligation to offer gas domestically and an obligation to sell it. While requiring producers to make reserved gas available at market-based prices preserves investment signals, mandating sales fundamentally alters the commercial incentives for upstream investment [33].

Similarly, Woodside Energy CEO Liz Westcott emphasised a broader structural risk: the intertemporal allocation of supply. Gas redirected to meet near-term domestic demand in the mid-2020s cannot also support export commitments or future local needs in the 2030s, meaning that accelerating production today may simply bring forward, rather than prevent, a future supply shortfall [34].

To put the sovereign risk issue in context, the DGR Scheme shows that the Australian government is prepared to intervene in commercial arrangements to redirect production value from export to domestic markets in circumstances where such intervention was never contemplated when many of the affected projects were being developed. It should be noted that the three Queensland LNG projects alone represent combined capital investment in Australia of in excess of $70bn and were sanctioned based on export-oriented business cases that assumed relatively open access to international LNG markets and stability in the application of Australia’s laws with respect to investment. The introduction of a mandatory 20% domestic reservation on new volumes changes the commercial parameters for those investments and likely, for future investments.

To give a simple example of the calculus involved, take the coal seam gas dependent Queensland gas projects. Unlike traditional gas fields, flow rates from CSG wells peak relatively quickly and then taper relatively rapidly over time. To maintain supply volumes, drilling new wells is an almost continuous process. And it’s expensive. Continuing to drill those expensive wells expecting LNG pricing (as these projects were predicated on) is one thing, continuing to do so when 20% of what you produce is being sold at a decoupled and presumably lower price, is quite another. Also, what the DGR Scheme means for existing domestic producers is also somewhat unclear. If, as Minister King suggests, we have imported international LNG gas pricing into domestic markets, then presumably domestic suppliers have also been taking advantage of those higher prices, particularly considering the fact there is a domestic gas shortfall. If there is an oversupply of gas in the domestic market as Minister Bowen foreshadows, then a decoupling of domestic pricing from LNG net back pricing presumably means that the prices available for domestic gas producers may also fall. What the price signals that these scenarios send mean for future gas investments, remains to be seen.

A further consideration is the consistency of application of the DGR Scheme. Foreign investors in large infrastructure and energy projects globally want to know that the legal and tax frameworks that underpin their investments are going to remain in place the life of their projects. In unstable jurisdictions, ‘stabilisation agreements’ are designed to give that certainty. In stable jurisdictions such as Australia such agreements are generally not required because a high degree of stability is assumed. The DGR Scheme itself was unexpected, but now that it has been introduced, a further concern of foreign investors will be whether the Scheme represents a final or only an interim intervention. The possibility for there to be regulatory escalation such as an increase in the reservation percentage, extension to legacy contracts, price caps, additional taxation on export revenues or extension to other commodities is a concern that existing and future investors will now need to grapple with. Given Australia competes for capital for gas and other resources developments with jurisdictions across the Asia-Pacific, the Middle East, North and South America, and Africa, the calculus of whether to invest in Australia may have just become more complex.

Final observations and legal considerations

If you are the CEO of an Australian gas company or a foreign energy multinational considering committing significant capital to the LNG sector or upstream supply generally, the investment case for new capital commitments has just become more complex. Particularly given:

• the largely negative reaction to the Scheme from LNG exporters
• the already long lead times for new gas project approvals in Australia due to regulatory issues, bans or roadblocks of one sort or another imposed by various governments who have only recently come to appreciate the true importance of gas as means of facilitating the energy transition through the availability of fast start gas fired peaking power
• lower gas prices available to LNG exporters for domestically sold volumes
• rising labour and materials costs in Australia due to supply chain constraints and inflation
• potential sovereign risk considerations raised by the Scheme, among others
• the availability gas investment opportunities in other jurisdictions that do not face the same impediments.

Legally, the DGR Scheme also raises a range of compliance and contract related considerations. Gas producers will need to carefully assess change-in-law provisions, hardship clauses and domestic supply obligations in new and existing agreements. While the Commonwealth government has taken care to preserve existing international contracts, future disputes may arise around allocation of reserved volumes, pricing expectations and regulatory approvals.

Looking ahead

The reservation scheme represents a clear policy decision to prioritise domestic gas availability over export flexibility. For market participants, the next 12–18 months will be critical for contract structuring, investment planning and regulatory engagement as the market adjusts to this new framework.

Notably, the DGR Scheme does not directly facilitate new gas production, accelerate the development of undeveloped reserves or address the regulatory and approval barriers identified by industry. Its effect is limited to the reallocation of volumes from existing and future production from existing LNG projects. Stable gas supply for consumers, industry and the electricity sector among others, is critical to Australia and to the energy transition, but whether the DGR Scheme by itself sends the signals to encourage the sort of investments new gas projects require, appears unclear at best. The long-term effects of the DGR Scheme on the Australian gas sector will depend on whether new upstream investment is forthcoming and whether the regulatory environment for gas is also able to evolve in a manner that supports both domestic supply security and continued international competitiveness for LNG exports.

Authored by:
Michael Joyce, Partner

Contributions by:
Patrick Holland, Partner
Shane Wacker, Special Counsel
Sebastien Butler, Graduate

[1] Gas | Geoscience Australia

[2] Gas | Geoscience Australia

[3] Fracking set to resume in the Northern Territory as moratorium lifted – ABC News

[4] Galilee basin: the new CSG frontier – ABC News

[5] https://www.industry.gov.au/publications/future-gas-strategy/3-finding-new-sources-gas-meet-demand

[6] Gas | Geoscience Australia

[7] Restart of onshore conventional gas – Resources Victoria

[8] Types of onshore gas – Resources Victoria

[9] BP withdraws from Great Australian Bight drilling – ABC News

[10] Why did Equinor withdraw and what’s next for the Great Australian Bight? – ABC News

[11] Otway Basin acreage areas opened to petroleum exploration | Department of Industry Science and Resources

[12] Narrabri Gas Project

[13] Santos accused of ‘stringing everybody along’ over Narrabri gas project | Santos | The Guardian

[14] Microsoft Word – carnarvo.doc

[15] Legal challenge to Woodside’s Scarborough project starts | Upstream

[16] Scarborough Energy Project and Pluto Train 2 – Woodside Energy

[17] Santos wins legal battle against Tiwi Islands elders over $5.7b Barossa gas project’s underwater pipeline – ABC News

[18] Federal funding – Environmental Defenders Office

[19] Submission DR91 – Australian Petroleum Production and Exploration Association (APPEA) – Resources Sector Regulation – Commissioned study

[20] Australia’s oil & gas industry calls for fix of offshore regulatory approval ‘chaos’ as wait times increase – Offshore Energy

[21] 37.-Australian-mining-investment-attractiveness-takes-massive-hit.pdf

[22] Senex Energy boss calls Labor’s gas reservation scheme ‘nationalisation by stealth’ COLIN PACKHAM and PERRY WILLIAMS

[23] Senex Energy boss calls Labor’s gas reservation scheme ‘nationalisation by stealth’ COLIN PACKHAM and PERRY WILLIAMS

[24] Australian LNG domestic reservation angers foreign gas giants

[25] KOGAS gas reservation scheme: South Korean state-owned giant warns Albanese government plan breaks long-term LNG contracts

[26] Coal royalty increase in Queensland state budget blasted by mining industry, resources council – ABC News

[27] Japanese ambassador takes ‘highly unusual’ campaign against Queensland coal royalty hike to mining forum | Queensland politics | The Guardian

[28] Design of the Energy Price Relief Plan | Australian National Audit Office (ANAO)

[29] Victoria quietly lifted its gas exploration pause but banned fracking for good. It’s bad news for the climate

[30] Woodmac Energy

[31] Australia at risk of losing its energy edge | Wood Mackenzie

[32] East Coast Gas Reservation Scheme: What It Means

[33] East Coast Gas Reservation Scheme: What It Means

[34] East Coast Gas Reservation Scheme: What It Means