Santos (ASX: STO) warns Australia’s 20% gas reservation rule could undermine GLNG economics

Santos Limited (ASX: STO) has warned that Australia’s proposed 20% domestic gas reservation rule could place the Santos-led Gladstone LNG project at a structural disadvantage from July 2027. The company argues that GLNG has no uncontracted gas and requires its reserves to meet minimum long-term LNG commitments. Santos believes the proposed compliance framework could allow better-supplied LNG exporters to reduce domestic sales while imposing a disproportionate obligation on GLNG. SGH Limited (ASX: SGH), which owns about 30% of Beach Energy Limited (ASX: BPT), has separately called for the scheme to be delayed until 2030 and redesigned around confirmed supply shortages. The dispute has turned a policy intended to improve gas affordability into a test of contract protection, competition and long-term investment incentives.

Why does Santos say Australia’s 20% domestic gas reservation rule disadvantages GLNG?

Australia’s proposed Domestic Supply Obligation would require LNG exporters to make gas equivalent to 20% of relevant export volumes available to the domestic market. The obligation is scheduled to begin in July 2027 and is intended to create a modest gas surplus, reduce prices for industrial users and protect households from international gas price volatility.

The framework is designed to respect existing long-term LNG contracts, with the obligation focused on new contracts, contract extensions and spot market volumes. The commercial complication is that compliance may still be assessed against broader export volumes and an exporter’s ability to obtain gas elsewhere. That distinction matters for GLNG because the project has no material pool of uncontracted gas that can simply be redirected.

Santos argues that all GLNG reserves are required to support minimum LNG contract commitments. If the project must make additional domestic volumes available, GLNG may need to buy more gas from third parties, arrange swaps with competing exporters or reduce the flexibility available for managing its export portfolio.

The proposed merit-based compliance structure is another point of contention. Santos believes projects with surplus gas could reduce existing domestic sales, redirect flexible volumes into the LNG spot market and still obtain a more favourable compliance position than GLNG. The result could be a policy that changes competitive behaviour between LNG exporters without necessarily creating the full amount of genuinely additional domestic supply anticipated by the government.

How does GLNG’s contract structure differ from Australia Pacific LNG and Queensland Curtis LNG?

GLNG is operated by Santos, which owns 30% of the joint venture. PETRONAS and TotalEnergies SE each hold 27.5%, while Korea Gas Corporation owns the remaining 15%. Gas produced in Queensland’s Surat and Bowen basins is transported through a dedicated pipeline to the two-train liquefaction facility on Curtis Island.

The project has produced approximately 6 million tonnes of LNG annually in recent years. Unlike some competing Queensland exporters, GLNG has relied on a combination of its own coal seam gas, purchases from third-party producers and gas swaps to meet export commitments. This exposure makes the cost and availability of east coast gas more important to GLNG’s economics than it would be for a project with deeper reserve coverage.

Australia Pacific LNG and Shell-operated Queensland Curtis LNG have different production profiles, reserve positions and levels of uncontracted supply. Australia Pacific LNG has historically held the strongest reserve position among the three Curtis Island projects and has produced approximately 9 million tonnes of LNG annually. This provides more flexibility to balance exports, domestic sales and operational requirements.

GLNG’s major export commitments also extend beyond the July 2027 start of the reservation scheme. Its Korea Gas Corporation contract runs until 2031, while some third-party gas supply arrangements are approaching expiry. Replacing or renewing those feedgas agreements could become more expensive if GLNG is simultaneously required to source additional volumes for domestic compliance.

Santos’s central argument is therefore not that GLNG should avoid contributing to Australia’s domestic market. The company’s position is that compliance should reflect the project’s contract structure, reserve availability and existing domestic contribution rather than applying an obligation that competitors can satisfy more easily.

Could the July 2027 start date weaken east coast gas investment before shortages emerge?

The timing of the scheme has become as contentious as the 20% reservation level. The Australian Energy Market Operator’s 2026 outlook pushed the expected annual east coast gas supply crunch to 2030, one year later than previously forecast. Lower consumption, greater battery deployment and extensions to coal-fired generation have reduced the near-term volume of gas required for electricity generation.

That does not mean the market is free from risk before 2030. Seasonal shortages can emerge earlier during winter demand peaks, infrastructure outages or periods of low renewable generation. Gas also remains essential for industries that cannot easily electrify their heat requirements, including chemicals, fertilisers, food processing, glass and metals.

The government wants the reservation scheme to produce enough surplus gas to lower prices and provide a buffer against these short-term risks. Industrial customers have sought contracted gas below A$10 per gigajoule, compared with contract prices that have often remained in the A$13 to A$15 range. East coast spot prices have generally traded between approximately A$7 and A$11 per gigajoule during 2026, although spot prices can change rapidly during periods of high demand.

Producers are concerned that creating a substantial surplus before an annual shortage materialises could push prices below the level required to support new development. Gas projects require upfront investment in drilling, processing, pipelines and environmental approvals. If the expected domestic price is reduced through regulation, marginal fields may be delayed even if those projects will eventually be needed.

This creates the policy’s central contradiction. A reservation requirement can improve affordability by increasing near-term supply, but an obligation that depresses prices too far may reduce the investment needed to sustain supply after existing fields decline. The success of the scheme will depend on whether it produces a controlled surplus or an investment-damaging glut.

What commercial options would Santos have if the domestic supply obligation remains unchanged?

Santos’s first option would be to increase production from its Queensland gas assets. Additional production would reduce GLNG’s reliance on external purchases and create more flexibility between domestic and export commitments. However, coal seam gas developments require continuing drilling because individual wells decline relatively quickly, making sustained capital expenditure necessary.

The second option would be to acquire more third-party gas. This could satisfy GLNG’s export requirements while allowing other Santos volumes to be marketed domestically. The difficulty is that additional purchasing by GLNG could increase competition for the same gas the policy is intended to make more affordable.

Gas swaps with Australia Pacific LNG, Queensland Curtis LNG or domestic producers offer another possibility. GLNG could deliver gas into one part of the interconnected east coast market while receiving replacement supply closer to its export facilities. Swaps can reduce transportation constraints, but they require commercially acceptable counterparties and a compliance system that recognises equivalent deliveries.

GLNG could also seek a reduced obligation based on the absence of uncontracted gas. That approach would protect existing LNG commitments while requiring better-supplied projects to shoulder more of the initial reservation burden. Competitors may resist such a structure because it could reward GLNG for having less reserve coverage and a greater historical dependence on domestic purchases.

The final option would be to accept lower margins. If GLNG must purchase higher-cost feedgas while offering domestic gas at regulated or policy-influenced prices, the difference would reduce project cash flow. Santos owns 30% of GLNG, so the financial exposure is proportionate rather than consolidated across the full project, but lower distributions would still affect the company’s Australian gas earnings.

How do Barossa LNG and Pikka oil production change Santos’s ability to absorb policy risk?

Santos enters the policy dispute while transitioning from a period of heavy project spending into higher production. First-quarter 2026 production increased by 2.7% from the previous corresponding period to 22.5 million barrels of oil equivalent. Sales revenue reached US$1.27 billion, while free cash flow was approximately US$383 million.

Santos maintained its 2026 production guidance of 101 million to 111 million barrels of oil equivalent. The range represents a substantial increase from 87.7 million barrels of oil equivalent produced in 2025, supported by Barossa gas and Pikka Phase 1 oil production.

Pikka Phase 1 achieved first oil in Alaska in May 2026. Santos operates the project with a 51% interest, while Repsol owns 49%. Pikka is expected to reach gross plateau production of approximately 80,000 barrels per day during the third quarter of 2026, providing Santos with a material source of oil-linked revenue outside Australia.

These production additions improve Santos’s ability to absorb some Australian policy pressure. They also reduce the company’s dependence on GLNG as a source of growth. However, diversification does not remove the need to defend GLNG’s economics, particularly after Santos’s 2025 underlying profit declined 25% to US$898 million and revenue fell 8% to US$4.94 billion.

Santos generated US$1.8 billion of free cash flow during 2025, providing a stronger financial base than the earnings decline alone suggests. Investors will nevertheless expect Barossa and Pikka to convert production growth into sustainable cash returns. An unexpected regulatory burden at GLNG would absorb part of the benefit just as Santos moves beyond peak construction spending.

Why does SGH want the federal gas reservation scheme delayed until 2030 and redesigned?

SGH Limited has called for the reservation obligation to be delayed until 2030, aligning implementation more closely with the expected emergence of an annual east coast supply gap. SGH argues that imposing the scheme in July 2027 could damage domestic producers before the market faces a structural shortage.

The position is commercially relevant because SGH owns about 30% of Beach Energy. Beach Energy is primarily exposed to domestic gas rather than LNG exports, meaning lower east coast gas prices could reduce revenue without providing an offsetting export benefit.

Beach Energy modelling has indicated that a blanket reservation scheme could weaken investment in southern gas production. Southern fields play an important role in meeting winter peaks because they are located closer to major demand centres in Victoria and New South Wales. If lower prices make those developments uneconomic, the annual market could appear adequately supplied while remaining vulnerable on individual high-demand days.

SGH has proposed obligations that activate when an actual shortage is identified. It also wants physically disconnected export projects to be exempt and producers to satisfy obligations by genuinely offering gas to domestic customers rather than being compelled to complete sales at uneconomic prices.

That approach would make the scheme more responsive to market conditions but less certain for manufacturers. Industrial buyers want guaranteed volumes and predictable prices, not a mechanism that activates only after a shortage has become visible. The government must therefore choose between early intervention that may distort investment and a later trigger that may provide too little time for industrial customers to secure supply.

What does the Santos dispute reveal about Australia’s broader gas market reform challenge?

Australia produces far more gas than it consumes, yet its eastern and western gas systems are not physically connected. Large export volumes from Western Australia cannot readily solve shortages in Victoria or New South Wales. A national reservation percentage therefore does not automatically translate into gas being available where it is most needed.

Pipeline capacity also matters. Queensland has substantial resources and three LNG export facilities, while southern production from the Gippsland and Otway basins is declining. Moving larger volumes south requires sufficient pipeline and storage capacity, particularly during winter.

New production remains the other major variable. Santos continues to pursue approvals for the Narrabri Gas Project in New South Wales, but the project will undergo further review in 2027 before significant capital is committed. Narrabri could provide a substantial share of New South Wales gas demand, although it still requires native title, production and pipeline approvals before an investment decision can be taken.

A lower domestic gas price could improve affordability for New South Wales users but weaken Narrabri’s investment case. Conversely, a reservation system that values locally produced gas and provides long-term contracting certainty could strengthen the project’s strategic position. The final policy design will determine which effect dominates.

The government is also replacing existing intervention mechanisms with the new Domestic Supply Obligation. A simpler system could improve certainty, but only if exporters, domestic producers and industrial buyers understand how obligations will be calculated. Complexity around deductions, contract extensions, swaps and compliance rankings would preserve the regulatory uncertainty the reform is supposed to remove.

How should investors interpret Santos share movements amid policy and oil price volatility?

Santos shares have recently been influenced more visibly by oil prices and project execution than by the gas reservation debate alone. The stock gained 5.78% on July 8 as escalating disruption around the Strait of Hormuz lifted Brent crude and Australian energy shares. That movement demonstrated the immediate earnings sensitivity created by Santos’s oil and LNG portfolio.

Operational milestones have also produced clear reactions. Santos shares rose as much as 3.1% to A$8.12 after Pikka achieved first oil in May. The shares had previously closed 3.6% higher at A$7.71 following the first-quarter update, despite production and revenue falling slightly short of market expectations.

The reservation scheme is more likely to affect the long-term valuation of GLNG than produce a reliable one-day share price reaction. Investors must estimate how much additional gas GLNG would need to procure, the likely domestic selling price and whether the obligation will be reduced to reflect existing contracts.

SGH’s share price is even less likely to provide a clean signal because SGH owns businesses across industrial services, construction materials, energy and media. The gas reservation debate is material to Beach Energy, but it remains one factor within a much broader SGH portfolio.

For Santos, the most important market question is whether rising production from Pikka and Barossa can outweigh weaker GLNG cash flow under the proposed rules. The answer will depend less on the headline 20% rate than on the compliance formula beneath it.

What must executives watch before Australia finalises the domestic supply obligation?

The first issue is how the government defines relevant export volumes. A system focused on new and extended contracts would have a different impact from one that calculates obligations against total LNG shipments while protecting existing contracts through deductions.

The second issue is how genuine domestic offers are treated. Requiring exporters to offer gas provides greater commercial flexibility than requiring a completed sale. However, manufacturers may argue that offers are meaningless if the price or conditions make the gas unusable.

The third issue is whether obligations can be transferred between projects. A transparent trading or swap mechanism could allow the lowest-cost producer to supply domestic customers while another exporter funds the obligation. Poorly designed transfers could instead concentrate market power among the best-supplied LNG ventures.

The fourth issue is whether the 20% rate remains fixed. Alternative industry modelling has suggested that a lower reservation level applied to new LNG commitments could meet projected annual shortfalls beyond 2035. A variable rate linked to forecasts would be more economically responsive, but it would also reduce long-term certainty.

Finally, investors should watch Santos’s 2027 review of Narrabri, the renewal of GLNG feedgas arrangements and the ramp-up of Pikka production. Together, these developments will determine whether Santos can offset regulatory pressure through new production, lower costs and a more diversified cash flow base.

What are the key takeaways from Santos’s challenge to Australia’s gas reservation policy?

• Santos believes the proposed 20% obligation disadvantages GLNG because the project has no material uncontracted gas and needs existing reserves to support minimum LNG commitments.
• GLNG’s reliance on third-party purchases and gas swaps makes it more exposed to east coast gas prices than competing LNG projects with stronger reserve coverage.
• The July 2027 start date precedes the expected annual supply crunch in 2030, although seasonal shortages and infrastructure constraints could still emerge earlier.
• A domestic gas surplus could lower prices for manufacturers, but excessive price pressure may delay the production, pipeline and storage investments required after 2030.
• Santos could respond through additional Queensland production, third-party purchases, gas swaps, a reduced compliance obligation or acceptance of lower GLNG margins.
• Barossa and Pikka provide Santos with production growth and portfolio diversification, but regulatory pressure at GLNG could absorb part of the resulting cash flow benefit.
• SGH wants implementation delayed until 2030 because lower domestic prices could weaken investment by producers such as Beach Energy before an annual shortage emerges.
• The final compliance formula will matter more than the headline reservation percentage because deductions, swaps and contract treatment determine the actual commercial burden.
• Narrabri could become more strategically important if New South Wales requires locally produced gas, although lower regulated prices could weaken the project’s investment case.
• Santos shares remain highly sensitive to oil prices and project execution, while the reservation dispute is more likely to influence long-term valuation than short-term trading.