Australia Oil & Gas Market: Structure,
Capital Flows, and Investment Risk

The geographic split in Australian gas production is not evenly contested — it is structurally decided. Western Australia, producing over 60% of the national total, is the anchor of Australian LNG exports and is not facing near-term decline.[AEMO] The North West Shelf and offshore Carnarvon Basin projects continue operating at scale, and WA's domestic gas reservation policy — mandating minimum domestic supply from all LNG projects — gives the state a degree of energy security unavailable on the east coast.

Queensland's Surat-Bowen Basin is the single growth story on the east coast in 2025–2026. It accounts for 65% of east coast gas production and is expanding: Senex Energy's Atlas gas fields came online in February 2025, and Roma North is progressing toward production.[IEEFA] The problem is that Queensland's gas flows primarily to Curtis Island LNG export terminals, not to southern domestic users. The infrastructure connecting Queensland supply to Victoria and South Australia is constrained, so Queensland growth does not automatically resolve the south's supply shortfall.

Victoria's Gippsland Basin — the Longford processing facility and its upstream fields — is the most important declining asset in the domestic market. AEMO's 2025 Gas Statement of Opportunities projects that southern production capacity will fall 47% by 2029, with legacy offshore Victorian fields contributing over 30% of that decline.[AEMO] South Australia's Cooper Basin is mature, hosting Santos's Moomba carbon capture and storage project but showing no near-term production growth. The Northern Territory's Beetaloo Basin — potentially a major shale gas source — remains commercially undeveloped due to community resistance and water constraints, with no credible near-term production timeline.

China is the largest single buyer of Australian LNG, and Asia as a region takes over 70% of global LNG imports.[GECF] Australia exported over 80 million tonnes of LNG in FY2024–25, accounting for nearly 20% of global trade — the bulk from Western Australia, with significant volumes from the three Curtis Island trains in Queensland (APLNG, QCLNG, GLNG).[EnergyQuest] APLNG — the ConocoPhillips and Origin Energy joint venture — provided production guidance of 645–680 PJ for FY2025–26, one of the few operator-level figures publicly available.

Revenue is falling faster than volumes. Q4 2025 LNG export revenue came in at $14.4 billion — down from $17.5 billion in Q4 2024 — driven by both lower average prices and reduced shipments of 1.2 Mt quarter-on-quarter.[EnergyQuest] The revenue decline is significant because it arrived precisely when global spot prices were rising: north Asian JKM and European TTF prices surged 44% and 54% respectively in late February 2026. Australian LNG was selling into the market at structurally lower prices than spot, reflecting the legacy long-term contract structure that ties most volumes to oil-price linkages rather than gas-on-gas competition.

The specific contract expiry schedule — which deals are coming up for renegotiation, with which buyers, on what terms — is not publicly disclosed. What is clear from Santos's Barossa development and the new LNG supply and purchase agreements commencing in 2026 is that operators are actively working to replace expiring volumes.[IEEFA] The risk is that replacement contracts, if negotiated now, face competition from US Gulf Coast LNG — which has lower construction costs and more flexible destination clauses — at a moment when Asian buyers have more options than at any point in the past decade.

AEMO's 2025 Gas Statement of Opportunities is explicit: without new investment, southern Australia faces peak-day supply shortfalls from 2028 and structural supply gaps from 2029.[AEMO] The ACCC's Gas Inquiry March 2026 interim report forecasts east coast demand of 499 petajoules against a supply base that is actively declining in the south.[ACCC] East coast gas prices averaged $12.68/GJ in Q4 2025 — low by global standards but rising fast enough to alarm industrial users who built business models around $6–8/GJ assumptions.

The three structural causes are not disputed. First, Victorian offshore production is falling at 36% between 2025 and 2029 and by 58% by 2031 — this is depletion, not price or policy.[AER] Second, Queensland growth feeds export terminals, not the domestic pipeline grid, because the infrastructure connecting Curtis Island production southward is insufficient. Third, the replacement supply options — Beetaloo Basin shale, Victorian onshore, new Cooper Basin acreage — all carry lead times of five to seven years from exploration to first gas.

The one near-term supply addition with a confirmed timeline is Origin Energy's Golden Beach storage facility (507 million cubic metres capacity, production start 2028), backed by an A$25 million investment.[Argus] Nine new exploration areas covering 16,000 km² have also been opened in Queensland's Cooper/Eromanga and Bowen/Surat basins, with a 37 km Sturt Plateau gas pipeline (AUD 70 million) connecting the Shenandoah South pilot project to the Amadeus pipeline.[Industry.gov.au] These are genuine supply-side additions — but their combined scale does not close the gap AEMO has identified.

The biggest single signal from capital markets in this period is the ADNOC-led consortium's USD 18.7 billion approach to Santos in November 2024 — the largest prospective transaction in the sector's history.[IEEFA] The offer was not accepted, but its scale and its source — Abu Dhabi National Oil Company, a state-backed strategic buyer — reveal what is genuinely valued: an integrated portfolio of Australian LNG export capacity, upstream production, and infrastructure that cannot be replicated at lower cost. State-backed international capital is prepared to pay a significant premium for that combination.

Woodside's handling of its Louisiana LNG project illustrates the opposite logic. The company has cut its capex commitment from USD 17.5 billion to USD 9.9 billion by bringing in Stonepeak and Williams as partners — a 43% reduction in its own exposure — while keeping its first cargo target at Q4 2026.[IEEFA] A further reduction to USD 7.0 billion via a 20% equity sale is under consideration. Woodside's approach is textbook risk mitigation for a volatile commodity cycle: retain upside through equity, reduce downside through partnership, and free cash for Australian operations where the company has operational advantage. Woodside's 2025 free cash flow came in at USD 1.889 billion, confirming the underlying earnings strength of its existing asset base.

APA Group's final investment decision on Stage 3A of the East Coast Grid Gas expansion plan is the most significant midstream commitment in this period — targeting southeastern Australia's premium domestic wholesale prices, which reached USD 12–15/GJ in 2024, double export benchmarks.[IEEFA] Santos's Moomba CCS project reaching CO₂ injection in September 2024 (1.7 million tonnes per year capacity) represents a different kind of investment: it is not primarily a production decision, it is a positioning decision — making Moomba-produced gas commercially viable in a future where carbon credentials affect offtake contract bankability.

The regulatory environment for Australian oil and gas has shifted materially since 2024. Four distinct mechanisms now constrain operator returns: PRRT deduction limits, east coast price caps, the WA domestic gas reservation policy, and the proposed 25% export levy. Each one individually is manageable. Together, and on top of each other, they represent a step-change in the fiscal burden on Australian LNG production at a moment when competing jurisdictions — Qatar, the United States, Canada — are offering more stable fiscal frameworks for long-term capital commitments.

The PRRT modification introduced in 2024 limits deduction utilisation to 90% annually for offshore petroleum projects, accelerating taxable profit recognition and raising effective tax rates.[AEP] Industry associations have consistently flagged that this change, while modest in isolation, reduces the net present value of projects with large upfront capital requirements — exactly the profile of every major offshore development in Australia. The proposed 25% LNG export levy is categorically different. A revenue-based levy on gross LNG exports ignores profitability entirely. Industry bodies have argued it would halt marginal project development and could trigger a structural reduction in new supply commitments precisely when Australia needs new production to replace depleting southern fields.[AEP]

Western Australia's domestic gas reservation policy is the one regulatory mechanism that has demonstrably worked as intended: WA has not experienced the domestic supply shortfalls that now threaten the east coast. The policy requires LNG projects to set aside a minimum share of production for domestic users, which has kept WA industrial gas prices stable and reduced the political pressure that drives more disruptive interventions. The east coast has no equivalent mechanism with the same track record, which is part of why federal policy is now reaching for blunter instruments like price caps and export levies.

The competitive position of Australian LNG has deteriorated relative to 2020–2022 peaks, and the deterioration is structural rather than cyclical. Australia produces predominantly from mature or maturing offshore platforms (North West Shelf, Gorgon, Ichthys, Wheatstone) built during a capital expenditure boom when construction costs were at their highest. The all-in cost of Australian LNG delivered to north Asia is now higher than competing US Gulf Coast supply, which benefits from lower construction costs, Henry Hub-linked pricing, and destination flexibility that long-term Asian buyers increasingly demand.

The buyer side — dominated by Chinese, Japanese, Korean, and Taiwanese utilities and trading companies — has accumulated market power over the past five years. The combination of US supply growth, Qatari expansion, and post-pandemic demand volatility has given Asian buyers more optionality at contract renegotiation than they have had in decades. Santos's active pursuit of new Barossa LNG supply and purchase agreements, and Woodside's willingness to cut its Louisiana LNG exposure through partnership, both reflect operator awareness that securing long-term offtake is no longer automatic.[IEEFA]

The threat from substitutes — renewable energy displacing gas-fired power in Australia's key Asian export markets — is real but slower-moving than headlines suggest. Japan and South Korea have both signalled continued LNG demand through the mid-2030s to support their energy transitions. China's renewables buildout is the biggest wildcard: if Chinese domestic renewable capacity grows faster than forecast, LNG import demand may plateau earlier than the GECF's +1.20% CAGR trajectory implies.[GECF]

The base case — fiscal constraint but no export levy — is the most likely outcome. The federal government faces competing pressures: it needs new supply to prevent the east coast shortfall AEMO has named, and it needs revenue to fund policy commitments. A 25% export levy on gross revenues resolves the revenue pressure but risks triggering exactly the supply reduction it cannot afford. The more likely outcome is a continuation of PRRT tightening — politically easier to explain, less immediately damaging to project economics — combined with expanded domestic supply obligations.[AEP]

The bear case is not a demand collapse — global LNG demand is structurally supported. The bear case is policy-induced investment deterrence that prevents new Australian supply from replacing the Victorian decline. If the export levy is legislated, marginal projects that are currently at pre-FID stage (Scarborough Phase 2, Beetaloo pilot programmes, new Cooper Basin acreage) will face internal rate of return hurdles they cannot clear under revenue-based taxation. The shortfall AEMO has identified for 2028–2029 would deepen, domestic prices would rise sharply, and the political pressure would generate further interventionist policy — a self-reinforcing cycle.[AEMO]

The bull case requires two things to happen together: the export levy is rejected in May 2026, and one or more of the major uncommitted supply projects reaches FID before Q4 2026. Woodside's Scarborough development is 94% complete and targeting a first cargo in Q4 2026 — if that milestone is hit on schedule, it provides a material confidence signal for the next wave of investment decisions. The ADNOC consortium's interest in Santos, even if no transaction completes, has established a floor valuation for integrated Australian LNG assets that supports equity-raising for new developments.