Australia’s Gas Problem — and the Corridor That Fixes It

Australia has more gas than it can use and cannot deliver it to Australians. The fault is not supply. It is that the country has never built a national gas network.

1. The numbers

• 106,301 PJ of proven and probable (2P) gas reserves; 247,427 PJ of total demonstrated resources.
• 6,123 PJ produced in 2023–24, of which 4,509 PJ was exported as LNG.
• Eastern Australian domestic customers used about 488 PJ in 2024. Industry took 46 per cent of it.
• Gas supplies about a quarter of Australia’s total energy consumption — 1,478 PJ of 5,977 PJ in 2023–24.
• Gas used for electricity generation fell about 45 per cent between 2010 and 2024. Industrial gas use fell 27 per cent from its 2012–13 peak.
• Victoria supplied almost 1,030 PJ to other states between 2017 and mid-2025.
• Petroleum exploration spending is running at about a quarter of its level a decade ago.
• The Northern Territory Government estimates more than 200,000 PJ of gas in the Beetaloo Sub-basin.
• The Beetaloo’s only route to the eastern market is one 622 km pipeline with a nameplate capacity of 90 terajoules a day.
• The domestic reservation scheme begins 1 July 2027 and applies only to export contracts entered into after 22 December 2025.

2. What falls, and what does not

Australian gas demand is falling in aggregate and holding in the uses that are hardest to replace. Both facts matter, and the second is the one that decides infrastructure.

Gas burned for electricity generation dropped by nearly 100 PJ between 2010 and 2024, a fall of about 45 per cent. Industrial consumption is down 27 per cent from its peak. Household electrification continues. Total volumes decline.

Feedstock cannot be electrified

Gas is not only a fuel. It is the molecule from which ammonia is made, and ammonia is the base of nitrogen fertiliser, of explosives, and of the urea that Australian heavy trucks require to run legally. The Australian Energy Regulator records gas as a major feedstock in ammonia production for fertilisers and explosives, alongside its use in pulp and paper, metals, chemicals, stone, clay, glass and processed foods.

An electric furnace can replace a gas furnace. Nothing replaces a carbon and hydrogen atom in a chemical process. That demand does not fall with electrification.

Winter peaks are rising as coal exits

AEMO’s 2026 Gas Statement of Opportunities finds that gas-powered generation continues to play a critical role during winter peak demand periods as coal retires, and that gas infrastructure will need to cater for an increasingly seasonal and volatile demand profile.

The shape of demand is changing rather than disappearing: lower average throughput, higher peaks, concentrated in winter and in industry. A system built for steady flow is being asked to deliver surges.

3. Three grids that do not touch

Western Australia’s gas market is physically separate from the eastern market. The Northern Territory’s reserves connect properly to neither. Papua New Guinea has no Australian connection at all.

Within the eastern market, the constraint is direction. The southern states depend on gas moving down from Queensland and on stored gas: Victoria’s Iona facility required about 12 PJ of injections before May 2026 to be ready for winter. APA’s East Coast Gas Grid Expansion Stage 3A is being built specifically to raise north-to-south transport capacity.

AEMO’s 2026 outlook forecasts shortfall risk under extreme peak-day conditions in southern Australia from 2029, and a need for additional supply in most scenarios from 2030, as production from legacy southern fields declines. The ACCC’s quarterly assessment for the third quarter of 2026 put the east coast balance between a 12 PJ shortfall and a 3 PJ surplus, the difference depending entirely on how much uncontracted gas the LNG producers chose to export.

That last sentence is the structural fact. Whether Australian households have enough gas in a given quarter is decided by an export shipping decision, because the alternative supply cannot physically reach them.

4. What reservation reaches, and what it does not

On 7 May 2026 the Government announced a domestic gas reservation scheme. From 1 July 2027, east coast LNG exporters must supply 20 per cent of their export volumes to domestic customers, with compliance tied to export approvals and $35.5 million allocated over four years to administer it.

The obligation applies only in respect of export contracts entered into after 22 December 2025. The long-term foundation contracts that underwrote the existing LNG projects are excluded.

Western Australia has run a 15 per cent reservation since 2006. Analysis of the WA scheme records most WA LNG exporters lagging their domestic reservation commitments, and WA gas prices rising materially from a low base, with shortages forecast in coming years.

A reservation determines who may buy a molecule. It does not build the pipe that carries the molecule from a field in the Territory to a factory in Victoria. Where no pipe exists, a reserved volume is a volume reserved somewhere else.

5. The network is privately owned, and the owners decide what gets built

Australia’s gas transmission pipelines are private assets, mostly outside price regulation, and several of the largest are controlled from outside Australia.

Most pipelines are not price-regulated

The ACCC’s 2016 inquiry into the east coast gas market found monopoly pricing giving rise to higher delivered gas prices for users and, in some cases, lower ex-plant prices for producers, with a range of economic inefficiencies following from it. Its chairman put it plainly: there are very few constraints on monopoly pricing by pipeline operators.

The inquiry also found that the coverage test for regulation under the National Gas Law is unlikely to be met by the majority of transmission pipelines, so the constraint does not apply where it is most needed.

Most east coast transmission pipelines are non-scheme pipelines: not subject to full or light regulation, only to an information disclosure and arbitration framework introduced in 2017. By 2019 the ACCC reported that some pipeline operators did not appear to be taking their disclosure obligations seriously and were continuing to exploit information asymmetries to the detriment of shippers.

At the time of the 2016 inquiry APA owned 13 of the roughly 30 transmission pipelines on the east coast. The Northern Gas Pipeline holds a 15-year derogation from both the standard access chapter of the National Gas Law and the disclosure framework, and is instead subject to access principles agreed with the Northern Territory Government.

Who owns the pipes

Jemena operates as SGSP (Australia) Assets, owned 60 per cent by the State Grid Corporation of China and 40 per cent by Singapore Power. Its assets include the Eastern Gas Pipeline carrying Gippsland gas to Sydney, the Queensland Gas Pipeline, the VicHub interconnect, the New South Wales distribution network and the Northern Gas Pipeline.

The Australian Gas Infrastructure Group was formed when CK Infrastructure, listed in Hong Kong, acquired the DUET Group in 2017, combining the Dampier to Bunbury Natural Gas Pipeline, Australian Gas Networks and Multinet into an entity holding around 34,000 kilometres of distribution network and more than 3,500 kilometres of transmission pipeline. In 2018 the same group led a $13 billion bid for APA, which the ACCC cleared and the Foreign Investment Review Board did not.

The pipeline that carries 30 per cent of Western Australia’s gas to Perth, and the pipeline that carries Victorian gas to Sydney, are owned by companies headquartered in Hong Kong and Beijing.

The east–west connection, and who argued against it

A pipeline joining Western Australian gas to the eastern market has been proposed repeatedly and has never been built. The Australian Government commissioned a pre-feasibility study, delivered by ACIL Allen, on a line costed at around $5.6 billion. It concluded that the connection is technically feasible but not currently the best or most economical option for the supply issues facing the eastern market, and pointed instead to more flexible short and medium-term options.

Among the alternatives promoted at the time was an LNG import terminal at Port Kembla, proposed in 2020 by Jemena, whose managing director stated publicly that imported gas was cheaper than a Western Australian pipeline. In August 2020 the Western Australian Government banned the export of Western Australian gas to the eastern states, which advocates of the west–east pipeline said would effectively cancel the project.

The proposal to solve an east coast shortage by importing liquefied natural gas into the world’s largest LNG exporting country was advanced by a pipeline owner, assessed against a national connection, and preferred.

The tanker alternative, and where it stands

The alternative advanced against a national pipeline is to move gas by ship: liquefy it, carry it in tankers, and regasify it at import terminals on the east coast. It is cheaper to start, and it is being built.

The Port Kembla Energy Terminal is Australia’s first LNG import terminal, rated at 500 terajoules a day — enough for nearly all of New South Wales’ peak demand. Construction finished in December 2024, and it connects to Jemena’s Eastern Gas Pipeline. Three more terminals are in progress, at Geelong, in South Australia and elsewhere.

The record of that path so far is specific. The project was proposed in 2018 at an estimated $250–300 million and has been reported since September 2024 at around $1 billion. Its commercial start date moved from 2026 to 2027 after the operator sub-chartered the floating storage and regasification vessel, the Höegh Galleon, to Egypt’s state gas company until the end of 2026.

A Spanish operator has been engaged to preserve and maintain the completed terminal, with the vessel temporarily disconnected and held for quick reactivation when required.

The gas it is built to receive is imported. The terminal was proposed to bring in natural gas from South-East Asia, and its developer describes it as supplying domestic gas “without the need for new gas fields in Australia”. Shipping Western Australian gas east is not available to it: Western Australia prohibited the export of its gas to the eastern states in August 2020.

Every cargo therefore arrives on a foreign-flagged tanker, priced against the Asian LNG market, after paying for liquefaction at one end and regasification at the other — and Australia holds no gas storage of the kind that a pipeline network provides as a matter of course. A terminal is a delivery point for a cargo somebody else decides to send. A pipeline is a connection to a field.

What can be turned back, and what cannot

The two paths fail in different ways, and the difference is in who decides.

Three sea lanes have been closed to commerce since 2023 — Hormuz, the Red Sea and the Black Sea — and in each case the closing mechanism was underwriting rather than sinking. Within 48 hours of the strikes of February 2026, war-risk premiums rose fivefold, insurers re-quoted cover at around sixty times pre-crisis rates, and tanker traffic fell by more than 80 per cent. No navy reopened any of the three.

A cargo is a commercial decision taken by its owner. It can be sold to a higher bidder while at sea, held for a supplier’s home market, or priced out of reach by an insurer who has never seen an Australian port. In March 2026 the Energy Minister confirmed that six fuel cargoes bound for Australia had been turned back or deferred. The regasification vessel for Australia’s first LNG import terminal spent 2026 on sub-charter to Egypt.

A domestic pipeline has no flag, no charter, no chokepoint, no port queue and no war-risk premium. It cannot be re-sold mid-voyage, because there is no voyage. Gas placed in it arrives where the pipe goes.

Pipelines are not invulnerable: the Nord Stream lines were destroyed by sabotage in 2022. The difference is in repair and redundancy. Line pipe is a stocked commodity, a buried land section is cut out and replaced by domestic crews in days to weeks, and a network fed by nine basins reroutes around the break while the work is done. An import terminal that loses its supply has nothing behind it.

The concentration point on a pipeline is the compressor station, which is why a national network built as a network rather than a single line is the form that matters: the Northern Gas Pipeline’s entire throughput passes one compressor rated at 90 terajoules a day.

The MMA position

Decisions about which national gas infrastructure is built currently rest with the companies that own the existing pipelines and are answerable to their shareholders. A national network that connects every basin to every market is not in the commercial interest of an operator whose returns depend on regional pricing power in a fragmented system.

The corridor programme places the delivery network in public hands. The route is planned as national infrastructure, the build decision is made on national supply security rather than on a single operator’s book, and tolling revenue returns to the Australian public. Producers compete to sell into a network they do not own.

6. What a corroded pipe already proved

On 3 June 2008 the wall of a pipe at Varanus Island, corroded from 11 millimetres to 1.5, ruptured and exploded. Western Australia lost 30 per cent of its domestic gas supply for two months and Pilbara industrial supply fell 45 per cent.

Losses were assessed at up to $3 billion by the state inquiry and $6.7 billion by the Chamber of Commerce and Industry. Full production took more than a year to restore. The state met the emergency with its reserve generation already offline: the Collie coal-fired station was out with damaged turbine blades and a 120-megawatt plant at Kwinana was down for maintenance.

Victoria ran the same test a decade earlier. The Longford fire of 25 September 1998 killed two workers and left the state without gas for twenty days, with property damage of about US$443 million.

Western Australian domestic gas comes from essentially two sources — the North West Shelf at Karratha at around 65 per cent, and Varanus Island at around 30 per cent before 2008 — and travels to Perth down one 1,600-kilometre pipeline. A chain fails at one link. A network reroutes.

7. Papua New Guinea, and the pipeline that was cancelled

Papua New Guinea holds producing gas fields within pipeline distance of Cape York, and the connection has been engineered before.

Chevron and IPC proposed a Papua New Guinea to Queensland pipeline in 1995, initially to carry gas about 3,000 kilometres from the Pandora field in the Gulf of Papua to Cape York.

The design evolved into a 3,800-kilometre line from the Southern Highlands to Cape York and on to Gladstone, including 650 kilometres along the Torres Strait seabed. AGL and Petronas were selected in 1998 to develop the Australian section, and sufficient reserves were committed in 1999 for line-pipe procurement to begin.

Development costs rose by close to $1.5 billion in 2006, a state of emergency was declared in the Southern Highlands that August, and the project was cancelled in 2007 after Australian customers withdrew from the conditional sales agreements. Australian gas was cheap at the time.

The conditions that killed it have reversed

Australian domestic contract prices now sit around $13.55 a gigajoule, up 4 per cent in the final quarter of 2025. Southern supply is forecast short from 2029. The customers who walked away in 2007 are the manufacturers now closing plants over gas costs.

On the Papua New Guinean side, PNG LNG has operated since 2014 and remains the country’s only producing gas project; Santos holds 39.9 per cent with the state company Kumul acquiring a stake. ExxonMobil completed the US$1.3 billion Angore tie-in to the Hides conditioning plant.

Twinza’s US$1.5 billion Pasca A project is opening undersea gas in the Gulf of Papua, with the state’s Mineral Resources Development Company taking up to a 50 per cent interest. A final investment decision on the US$10 billion Papua LNG project has been forecast, and deferred, every year since 2018.

PNG’s constraint is stated by its own project directors: outside the LNG enclaves there is no road, rail, power or water at the deposits, which is why development there costs and takes several times what the same work costs in Queensland. A connection built as shared infrastructure is a different proposition from a single-purpose export line — it carries PNG’s gas to a market, and it carries power, data and freight capacity back.

8. Gas as one service on the corridor

The Modern Movement Australia corridor programme cuts a single continental right of way carrying freight rail, high-voltage transmission, water and fibre. A gas pipeline is one more service in that trench.

The corridor is the cost; the pipe is the addition

On a continental pipeline the route is the project: acquisition, easements, approvals, access roads, earthworks and camps. Where a corridor is already being surveyed, approved, cleared and serviced for other traffic, the incremental work of laying pipe alongside is a fraction of a standalone build. The 2007 cancellation followed a cost escalation on 3,800 kilometres of single-purpose line with a single revenue stream.

Every field to every market

The six corridors reach the North West Shelf and Browse in the west, Bonaparte and the Beetaloo in the north, the Cooper, Surat and Bowen in the centre and east, Gippsland in the south, and Papua New Guinea via the Karumba landing. Connected, they form one pool rather than a set of regional markets, each with its own pricing power and its own single points of failure.

Fields with no route to market stay in the ground

The Beetaloo Sub-basin holds an estimated 200,000 petajoules on the Northern Territory Government’s figures, and 6,206 PJ of it is already classified as contingent shale resource. Its only path to the eastern market is the Northern Gas Pipeline: 622 kilometres of 14-inch line from Tennant Creek to Mount Isa, commissioned in 2019, with a nameplate capacity of 90 terajoules a day. Every molecule must pass through a single compressor station rated at the same 90 terajoules.

The scale mismatch is on the record. In 2022 Jemena and Tamboran signed a memorandum for about 100 terajoules a day of capacity for one pilot development in the Beetaloo — more than the entire pipeline is built to carry. The proposed capacity expansion and the extension from Mount Isa toward the Wallumbilla hub have shown no reported progress and are treated as cancelled.

The line has also demonstrated the fragility of a single connection. It was shut down between September and December 2022 because upstream production had declined far enough that the pipeline and its compressor station were not receiving adequate flows to operate safely. In August 2024 Jemena completed a reversal project so that gas could flow from Queensland into the Northern Territory to help cover southern shortfalls. A pipeline built to bring northern gas to eastern markets now runs backwards.

AEMO names the constraint directly, listing the North to East Australia Pipeline Project or upgrades to the Northern Gas Pipeline as what would enable better access to proposed Northern Territory developments. The gas is not the obstacle. The route is.

The same holds for Bonaparte, the Canning, the undeveloped Cooper and Bowen unconventional resources, and PNG’s Gulf province fields. Australian petroleum exploration spending is running at about a quarter of its level a decade ago, and a resource with no path to a customer is not a reserve anyone spends money finding. A corridor that passes within reach of a basin turns an exploration prospect into a development case, because the connection question is answered before the drill bit turns.

Sovereign ownership of the delivery network

The corridor and its services are owned by the Modern Movement Australia. Tolling revenue on the gas line returns to the Australian public rather than to foreign infrastructure funds, and the delivery network cannot be sold into foreign control.

The trench outlives the service

Gas volumes decline over the period the corridor is designed for. A shared right of way is not exposed to that trend the way a single-purpose line is: the corridor continues earning from rail, transmission, water and fibre regardless of what the gas line carries, and the pipe itself can carry hydrogen or biomethane, or sit idle, without stranding the asset around it.

9. What the network delivers

Supply security. Nine producing basins feeding one connected system, instead of two plants and a pipeline in the west and a north-to-south bottleneck in the east. When a field, a plant or a line fails, the network reroutes. That is what the 2008 and 1998 failures could not do.

Competition on a national basis. Regional pricing power exists because regional grids are isolated. Every field reachable by every market removes the isolation, and producers compete for domestic load rather than dividing it.

Industry that stays. Industry takes 46 per cent of domestic gas in eastern Australia. Fertiliser, explosives, alumina, glass, chemicals and food processing are the plants that close first when delivered gas is short or dear, and they are the plants that make a country able to supply itself.

A shared asset with the region. A line to Papua New Guinea is a two-way piece of infrastructure between neighbours: PNG gains a market and domestic energy access, Australia gains supply diversity, and both acquire a connection neither has an interest in severing. The same principle carries the subsea corridor network set out in The Asia-Pacific Subsea Corridor Network.

The full programme is set out on the Gas pillar page, with the transport-fuel counterpart in Australia’s Fuel Security — Part 2: Every Method of Domestic Production and the concentration-risk analysis in The Island Castle.

10. Sources

1. Reserves and resources (§1) — Geoscience Australia, Australia’s Energy Commodity Resources 2025: total demonstrated resources of 247,427 PJ (220 Tcf), of which 106,301 PJ (95 Tcf) are proven and probable (2P) reserves; unconventional 2C contingent resources of 14,313 PJ excluding coal seam gas, of which 6,206 PJ are Beetaloo Sub-basin shale; petroleum exploration expenditure of A$1,093 million in 2023, with activity since 2016 at about a quarter of its level a decade earlier.
2. Production, exports and consumption (§1, §2) — Australian production of approximately 6,123 PJ in 2023–24 with about 4,509 PJ exported as LNG; gas at about 24.7 per cent of total Australian energy consumption, 1,478 PJ of 5,977 PJ (industry statistics compiled from Department of Industry, Science and Resources data). IEEFA, Australian Gas and LNG Tracker: 83 per cent of gas produced in the first half of 2025 used for exports; gas consumption for electricity generation almost 100 PJ lower in 2024 than 2010, a fall of about 45 per cent; industrial gas consumption down 27 per cent from its 2012–13 peak; Victoria supplying almost 1,030 PJ to other states between 2017 and mid-2025; most Western Australian LNG exporters lagging domestic reservation commitments.
3. Eastern domestic demand and feedstock use (§1, §2, §9) — Australian Energy Regulator, State of the Energy Market 2025, chapter 4: eastern Australian domestic customers used around 488 PJ in 2024; industrial customers consumed 46 per cent of gas sold to the domestic market; gas used to manufacture pulp and paper, metals, chemicals, stone, clay, glass and processed foods, and as a major feedstock in ammonia production for fertilisers and explosives.
4. Supply adequacy outlook (§2, §3) — AEMO, Gas Statement of Opportunities, March 2026: shortfall risks under extreme peak-day demand conditions in southern Australia from 2029, with a need for additional supply in most scenarios from 2030; continued decline in production from legacy southern fields; gas-powered generation continuing to play a critical role during winter peak demand periods as coal retires; gas infrastructure required to cater for an increasingly seasonal and volatile demand profile; committed APA East Coast Gas Grid Expansion Stage 3A upgrades increasing north-to-south transportation capacity.
5. Quarterly balance and prices (§1, §3, §7) — ACCC gas inquiry reporting, 2025–2026: an east coast supply–demand balance for the third quarter of 2026 of between a 12 PJ shortfall and a 3 PJ surplus depending on how much uncontracted gas LNG producers export; long-term contract prices offered by producers for 2026 rising by an average of 4 per cent in the final quarter of 2025 to $13.55 per gigajoule; Victoria’s Iona storage facility requiring about 12 PJ of injections before May 2026.
6. The domestic reservation scheme (§1, §4) — Australian Government announcement of 7 May 2026: from 1 July 2027, LNG exporters to supply 20 per cent of export volumes to domestic customers, in respect of export contracts entered into after 22 December 2025, with compliance linked to export approvals and A$35.5 million allocated over four years in the 2026–27 Budget for implementation and administration; Western Australia’s 15 per cent domestic reservation in place since 2006 (Allens; University of Technology Sydney analysis; industry reporting, May 2026).
7. Varanus Island and Longford (§6) — Western Australian parliamentary inquiry into the Varanus Island incident: a pipe wall corroded from 11 mm to 1.5 mm ruptured on 3 June 2008, cutting 30 per cent of the state’s domestic gas supply for two months and Pilbara industrial supply by 45 per cent; losses assessed at up to A$3 billion by the inquiry and A$6.7 billion by the WA Chamber of Commerce and Industry; full production restored after more than a year; the Collie coal-fired station and a 120 MW Kwinana plant simultaneously offline. Royal Commission into the 1998 Esso Longford fire: two workers killed, Victorian gas supply interrupted for twenty days, property damage of about US$443 million. Western Australian supply structure: North West Shelf approximately 65 per cent and Varanus Island approximately 30 per cent, delivered via the 1,600-kilometre Dampier to Bunbury pipeline.
8. The Papua New Guinea to Queensland pipeline (§7) — proposed by Chevron and IPC in 1995 to carry gas approximately 3,000 km from the Pandora field in the Gulf of Papua to Cape York; developed into a 3,800 km route from the Southern Highlands to Cape York and Gladstone including 650 km along the Torres Strait seabed; AGL and Petronas selected in 1998 for the Australian section, with sufficient reserves committed in 1999 to begin line-pipe procurement; development costs rising by almost $1.5 billion in 2006 and a state of emergency declared in the Southern Highlands in August 2006; cancelled in 2007 after Australian customers withdrew from the conditional sales agreements (The Australian Pipeliner; Global Energy Monitor).
9. Papua New Guinean gas projects (§7) — PNG LNG in operation since 2014 as the country’s only producing gas project, Santos holding 39.9 per cent with Kumul Petroleum Holdings acquiring a stake; ExxonMobil’s US$1.3 billion Angore tie-in to the Hides Gas Conditioning Plant; Twinza’s US$1.5 billion Pasca A undersea project in the Gulf of Papua with Mineral Resources Development Company taking up to 50 per cent; repeated deferral of the final investment decision on the US$10 billion Papua LNG project from 2018 to 2026; project directors’ accounts of the absence of road, rail, power and water at PNG deposits and the resulting cost and schedule multiples against Queensland (Business Advantage PNG; Devpolicy; Global Energy Monitor).
10. Beetaloo (§1, §8) — Northern Territory Government estimate of more than 200,000 PJ of gas in the Beetaloo Sub-basin, cited by APA Group, Address to the Australian Domestic Gas Outlook Conference, 2025.
11. The corridor programme (§8, §9) — the six-corridor Modern Movement Australia network and its multi-service configuration, as set out on the MMA Gas and Energy pillar pages and in The Asia-Pacific Subsea Corridor Network.
12. Stranded fields and the Northern Gas Pipeline (§1, §8) — Northern Gas Pipeline: 622 km from Tennant Creek to Mount Isa, formerly the North East Gas Interconnector, awarded to Jemena in 2015, commercial operations from January 2019, nominal diameter 323.9 mm, nameplate capacity 90 TJ/day, with all gas passing through the Phillip Creek Compressor Station rated at the same 90 TJ/day (AEMC gas pipeline register; Jemena; APGA). June 2022 Jemena–Tamboran memorandum of understanding for approximately 100 TJ/day of capacity for the proposed Maverick pilot development in the Beetaloo; shutdown from September to December 2022 when upstream declines from the Blacktip field left the pipeline and compressor station without adequate flows for safe operation; reversal capability completed August 2024 allowing gas to flow from Queensland into the Northern Territory; no reported progress on the capacity expansion or the Mount Isa to Wallumbilla extension, both treated as cancelled (Global Energy Monitor). The Carpentaria Gas Pipeline (APA, 840 km, Ballera to Mount Isa, 119 TJ/day) currently flows northward, requiring additional works to carry Beetaloo gas toward southern Queensland. AEMO, Gas Statement of Opportunities, March 2026, identifying the North to East Australia Pipeline Project or upgrades to the Northern Gas Pipeline as enabling better access to proposed Northern Territory developments.
13. Pipeline regulation and monopoly pricing (§5) — ACCC, Inquiry into the East Coast Gas Market, April 2016: monopoly pricing giving rise to higher delivered gas prices for users and in some cases lower ex-plant prices for producers; “very few constraints on monopoly pricing by pipeline operators”; the coverage criteria for regulation unlikely to be met by the majority of transmission pipelines; APA owning 13 of approximately 30 east coast transmission pipelines. ACCC gas inquiry interim report, July 2019: some pipeline operators not appearing to take their disclosure obligations seriously and continuing to exploit information asymmetries to the detriment of shippers; definition of non-scheme (Part 23) pipelines as subject neither to full nor light regulation. Australian Pipelines and Gas Association: the Northern Gas Pipeline’s 15-year derogation from Chapter 6A of the National Gas Law and Part 23 of the National Gas Rules, subject instead to access principles agreed with the Northern Territory Government.
14. Pipeline ownership (§5) — Jemena operating as SGSP (Australia) Assets Pty Ltd, 60 per cent State Grid Corporation of China and 40 per cent Singapore Power, following the 2013–14 sale of Singapore Power International’s majority stake; Jemena assets including the Eastern Gas Pipeline, Queensland Gas Pipeline, VicHub, the New South Wales distribution network and the Northern Gas Pipeline (Australian Energy Regulator; company disclosures). Australian Gas Infrastructure Group formed by CK Infrastructure’s 2017 acquisition of the DUET Group, combining the Dampier to Bunbury Natural Gas Pipeline, Australian Gas Networks and Multinet, holding approximately 34,000 km of distribution network and more than 3,500 km of transmission pipeline; the 2018 $13 billion CKI-led bid for APA cleared by the ACCC and rejected on foreign investment grounds.
15. The west–east pipeline (§5) — Department of Climate Change, Energy, the Environment and Water, West–East gas pipeline pre-feasibility study (ACIL Allen), concluding that a pipeline connecting Western Australian gas to the east coast is technically feasible but not currently the best or most economical option for the supply issues facing the eastern market, and identifying more flexible short and medium-term alternatives; project costed at approximately $5.6 billion. Jemena’s 2020 Port Kembla import proposal and its managing director’s statement that imported gas was cheaper than a Western Australian pipeline; the Western Australian Government’s August 2020 prohibition on exporting Western Australian gas to the eastern states, which west–east pipeline advocates said would effectively cancel the project (Australian Financial Review; Sydney Morning Herald; Global Energy Monitor).
16. LNG import terminals and the shipping alternative (§5) — Port Kembla Energy Terminal: Australia’s first LNG import terminal, capacity 500 TJ/day, described as sufficient for nearly all of New South Wales’ peak day demand; construction completed December 2024; connected to Jemena’s Eastern Gas Pipeline; proposed in 2018 at an estimated A$250–300 million with the estimate reported at around A$1 billion from September 2024; commercial operations deferred from 2026 to 2027 after the FSRU Höegh Galleon was sub-chartered to Egypt’s EGAS until the end of 2026; Reganosa engaged to preserve, operate and maintain the onshore terminal with the FSRU temporarily disconnected pending reactivation; the project originally proposed to import natural gas from South-East Asia, with the developer describing supply “without the need for new gas fields in Australia”. Further terminals in progress at Geelong (Viva Energy) and in South Australia (Venice Energy / AGP Outer Harbor). Western Australia prohibited the export of Western Australian gas to the eastern states in August 2020 (Squadron Energy; Global Energy Monitor; S&P Global / Baird Maritime factbox; NSW Department of Planning).
17. Security comparison (§5) — the closure of the Strait of Hormuz, the Red Sea and the Black Sea to commercial traffic since 2023, with war-risk premiums rising fivefold within 48 hours of the February 2026 strikes, cover re-quoted at approximately sixty times pre-crisis rates and tanker traffic falling more than 80 per cent, assembled with full sourcing in The Proof of the Hormuz Pudding and The Island Castle; ministerial confirmation in March 2026 that six fuel cargoes bound for Australia had been turned back or deferred; the sub-charter of the Port Kembla FSRU to Egypt’s EGAS through 2026; the September 2022 destruction of the Nord Stream pipelines by sabotage.