Australia’s Fuel Security — Part 2: Every Method of Domestic Production

Every method by which Australia can replace an imported litre — what it displaces, what it is made from, and how long it takes to build. Part 2 of the Fuel Sovereignty pair; Part 1 carries the position.

1. The replacement task, in numbers

• About 50 billion litres of transport fuel burned a year; about 90 per cent of refined fuel imported.
• Refined product arrives at roughly 850,000 barrels a day — 80 to 90 tanker cargoes a month.
• Diesel is the critical stream: about 91 per cent imported, demand still growing, hardest to electrify.
• Reserves held: about 30 days of diesel onshore against a 90-day obligation. The current programme’s ceiling is 50.
• Domestic production: about 400,000 barrels a day, mostly light condensate, more than 94 per cent exported.
• Two refineries remain, both running imported crude, covering about a fifth of demand.
• Every litre of the task is one of three things: demand that can be removed, fuel that can be made here, or a residual covered by a reserve.

Part 1 sets out how this position arose, what it costs and what the Government is doing about it. This memo takes the position as given and sets out every method of replacing an imported litre. The test applied to each is the one the current response fails: does it reduce the number of imported litres the country depends on, and by how much.

2. How an imported litre is replaced

A stockpile holds fuel; it does not supply it. A bigger tank holds more of a fuel the country still does not make, and a stockpile drains — once drawdown starts, the clock runs. A reserve in the ground or in a standing crop is the opposite on every count: it costs nothing to store, cannot be embargoed or turned back at sea, sits dispersed across the continent rather than concentrated in tank farms, and is drawn by producing.

Nor is the answer reopening the old refineries as they were. They were beaten on margin, and they were engineered for the light, sweet domestic crude the country no longer produces in quantity. The viable path is conversion: electrify the demand that can be electrified, make the residual from feedstocks Australia actually has, and add refining capacity in the form matched to its own crude.

Domestic fuel costs more per litre today than an imported cargo on a calm day, and the build is measured in years. The sections below are ordered by how fast each lever moves the import number, and every method is stated with what it replaces, what it is made from, the scale available here, and how long it takes.

3. The method set: displacement, feedstock, scale and lead time

The table lists every route by which an imported litre is replaced or removed. Scales are indicative and are set out with their sources in the sections that follow.

The fallback row exists to settle the resource question, not as part of the plan. Every other row is treated in full below.

4. Demand displacement: electrifying the transport task

Every tonne-kilometre moved off imported diesel is a barrel never shipped in, and demand removed never has to be produced, stored, insured or escorted. This is the largest single category in the whole method set, and most of it runs on one piece of infrastructure.

The continental corridor is the structural answer. A single elevated right of way carrying electrified heavy freight, passenger maglev and high-voltage transmission converts the two biggest liquid-fuel tasks in the country — long-haul freight and domestic passenger travel — onto domestic electricity, and carries the transmission that powers them in the same easement.

The fuel it displaces is imported. The electricity that replaces it is generated here, and cannot be embargoed, turned back at sea or repriced by an insurer. Four streams carry the transport task, and each has an electric replacement.

Passenger fleet electrification: about one third of imported oil

The single largest prize is ordinary. An all-electric passenger fleet would replace roughly a third of Australia’s imported oil with domestic electricity. The vehicles exist, the turnover is underway, and every replacement is permanent: a car bought today stops consuming imported fuel for its entire service life, and improves further as the grid does, with no second purchase required.

Freight to electrified rail: the largest single diesel task

Long-haul freight is the biggest diesel line in the country and the one with the clearest replacement. Rail is several times more energy-efficient than road per tonne-kilometre before electrification, and runs on domestic power after it.

The corridor is what makes the conversion possible at continental scale: the same elevated right of way carries the electrified freight track and the high-voltage transmission that runs it, so the vehicle and its fuel supply are one build rather than two. Water and fibre share the trench, which is what pays for a route no single service could justify alone.

Passenger maglev: the intercity and domestic aviation task

The corridor’s passenger service is maglev on the same structure. It replaces two fuel demands at once: the intercity car journeys that consume petrol, and much of the domestic aviation task that consumes jet fuel — the hardest fuel in the country to replace by any other route, because there is no battery answer for it and the biofuel volumes required are very large.

The alignment matters as much as the technology. A corridor connecting the capitals through the inland puts freight, passengers, transmission, water and data on one route, and every one of those services runs on Australian electricity rather than an imported litre.

Short-haul trucking: battery-electric, deployable now

Urban and regional distribution — the return-to-base fleets that run fixed routes and park overnight — is the segment where electric trucks already work without new infrastructure beyond depot charging. It is a smaller share of the diesel task than long haul, and it needs nothing invented.

Mining and agriculture: about 35 per cent of national diesel

Mining alone accounts for about 35 per cent of national diesel use. These are the most concentrated, most electrifiable fleets in Australia: fixed sites, known duty cycles, and haul routes that lend themselves to trolley assist and battery swap. The operators’ own analyses show electrification pays — once the subsidy below stops halving the return.

Domestic aviation: displacement by high-speed rail

High-speed rail on the main corridors removes much of the domestic flying task and with it a share of imported jet fuel. It is the longest-dated item in this section and the one that depends most directly on the corridor being built.

The Fuel Tax Credit: a $10 billion a year counter-incentive

One policy pulls hard against every line above. The Fuel Tax Credit refunds excise on off-road and heavy-vehicle diesel at about $10 billion a year and rising. Mining accounts for about 35 per cent of the country’s diesel use and received about $4.5 billion of the $9.6 billion credit spend in 2023–24.

The credit’s roughly 50 cents a litre is about five times the roughly 10-cents-a-litre cost of exceeding an emissions baseline under the Safeguard Mechanism, so for the covered miners the payment to keep burning imported diesel outweighs the penalty around five to one.

A facility exceeding its baseline by up to 30 per cent need only explain why on-site abatement was not undertaken, with the rebate unaffected. Redirecting the credit — from rebating imported diesel to backing electrification and domestic fuel — requires no new technology and no new money. It points an existing $10 billion a year at the import number instead of away from it.

5. Biofuels: crop, waste and residue feedstocks

Australia already grows fuel, and grows more of the feedstock than it processes. Every method in this section uses land, crops or waste streams that exist now.

Canola biodiesel: 18–22 days of national diesel a year

After the 2025–26 harvest, around 5.84 million tonnes of canola sat in Australian silos — roughly 2.2 billion litres of biodiesel equivalent, about 34 to 37 days of national diesel, needing no tanker, no Gulf and no foreign government’s permission.

A standing rule reserving half of each year’s crop for domestic processing would yield 1.1 to 1.3 billion litres a year — 18 to 22 days of diesel from domestic feedstock, every year, on land already farmed. Australia currently exports the seed and buys the fuel.

Distributed crushing: micro and macro plants in the growing zones

The constraint is not the crop. It is that Australia has almost nowhere to process it.

National crushing capacity is about 1.6 million tonnes against a canola crop of 6.2 to 7.6 million tonnes. There are eight crushing plants in the country: six in New South Wales and Victoria, and two small ones in Western Australia, which is the largest growing state. Around six million tonnes of seed is exported each year, almost all of it unprocessed.

Rabobank’s assessment of that arrangement is direct: converted to renewable diesel, the exported seed would be more than two billion litres of fuel, against the more than thirty billion litres of diesel Australia imports; and because the crushing happens offshore, “a large share of the processing margin, jobs and strategic control sits offshore”.

The answer is not one national plant. It is crushing and biorefining capacity built through the growing zones themselves, at two scales.

Macro plants at grain-belt hubs, sized to a district’s harvest, crushing seed and producing biodiesel or renewable diesel alongside meal. Micro plants at co-operative and farm scale, cold-pressing and converting a few million litres a year for the fleets that operate within a few hundred kilometres of them.

Four things follow from siting them where the crop grows. Freight falls, because seed is bulky, low-value and currently railed to a port and shipped to Europe, while the fuel it becomes is shipped back the other way.

The meal — around 60 per cent of the seed by weight, and forecast at 754,000 tonnes this year — stays in the district as high-protein stockfeed for the beef, dairy, pig and poultry industries that are already there.

Farm and haulage fleets run on fuel made within the region they work in, which is the shortest supply chain available to any fuel anywhere. And a plant in a town is a permanent employer rather than a loading facility.

The employment runs in three waves, and each lands in the region rather than at a port.

Building them. A programme of standardised plants repeated across the grain belt is a construction order book: civil, structural, mechanical, electrical and instrumentation trades, moving from district to district. Because the designs repeat, the crews and the fabrication runs repeat with them, which is the same logic that makes the corridor programme an industrial base rather than a series of one-off projects.

Making them. Standardised crushing and biorefining modules can be fabricated in Australia rather than imported as complete plants. That is a manufacturing order book with a known quantity and a known schedule, which is the condition under which a Tier-2 or Tier-3 supplier will invest in capacity — the mechanism set out in The Sovereign Manufacturing Multiplier.

Running them. Every plant then carries permanent operating employment: process operators, maintenance fitters and electricians, laboratory and quality staff, logistics and administration, on shift work that continues for the life of the plant. Around it sits the local trucking, engineering services and supply trade that any processing facility generates.

The point is what these jobs are not. Loading seed onto a train is a handful of shifts at a receival site; crushing it, converting it and blending the fuel is a workforce. Rabobank’s finding is that exporting the seed sends “the processing margin, jobs and strategic control” offshore — and those three travel together. Bringing the processing home brings all three back to the districts that grow the crop.

There is a price effect as well, and it is measured rather than argued. Regions with higher crushing density already show more stable pricing than export-dependent zones such as Western Australia; expanding capacity absorbs surplus supply, stabilises basis and reduces volatility, which in turn supports grower confidence and sustained planting.

One further fact settles the case. Australian canola production for 2026–27 is forecast to fall 19 per cent, to 6.2 million tonnes, because of diesel and nitrogenous fertiliser supply constraints and price rises caused by the Middle East disruption. Imported fuel and imported fertiliser are now cutting the size of the crop that could replace them.

Hemp: ~800 L/ha biodiesel from seed, ~4,500 L/ha ethanol from stalk

Industrial hemp is the highest-yielding oilseed available for this purpose and it produces two different fuels from one crop. Hemp seed runs 30 to 35 per cent oil by weight, giving a biodiesel yield around 780 to 800 litres a hectare — higher than soybean, sunflower, peanut or rapeseed — and hemp biodiesel meets both the American ASTM D6751 and European EN 14214 fuel standards, outperforming conventional diesel on every measure except oxidation stability, which is addressed with additives.

The rest of the plant is the second fuel. Hemp stalk is 55 per cent cellulose with only about 4 per cent lignin, which makes it an unusually good lignocellulosic feedstock: estimates put lignocellulosic ethanol at around 4,500 litres a hectare, and the same biomass gasifies to methanol or digests to biomethane.

One hectare therefore yields a diesel substitute, an alcohol fuel and a chemical feedstock, from a crop that grows on infertile soil, tolerates drought, suppresses weeds and needs none of the drying that corn and sugar require.

Australia licenses industrial hemp as a low-THC agricultural crop under state legislation, and grows it now for fibre, seed and food at small scale. The constraint is processing capacity and offtake certainty, not agronomy or law. A crushing and biorefinery capability sized to a guaranteed domestic fuel offtake turns marginal country into fuel-producing country.

Algae: highest yield per hectare, and the least proven at cost

Algae is the highest-yielding oil crop known and the one with the widest gap between its theoretical and its demonstrated performance. Both facts belong in the record.

The theoretical yield is extraordinary: a hectare of algae can produce more than 58,000 litres of oil a year against about 172 litres for a hectare of corn. It grows on non-arable land in saline or waste water, without competing with food production or fresh water, which suits a dry continent with a long coastline and high solar radiation — and Australian teams at Murdoch and Adelaide have led the world in open saline pond production rates.

The demonstrated yield is far lower. Sustained pilot-scale culture returns roughly 5,000 to 10,000 litres a hectare a year: high against field crops, but nothing like the theoretical figure.

Costs remain around $8 to $16 a gallon of gasoline equivalent, driven by harvesting and drying rather than growing; open ponds are vulnerable to contamination and culture crashes; water use runs to hundreds of litres per litre of fuel unless saline or waste streams are used; and most commercial producers have moved to higher-value products such as omega-3 supplements and feed rather than fuel.

Algae therefore belongs here as a research and pilot line rather than a delivery line — worth funding at demonstration scale, particularly integrated with wastewater treatment and industrial carbon dioxide streams, and not counted toward any near-term replacement figure.

Hydrotreated renewable diesel and sustainable aviation fuel

Beyond first-generation biodiesel sit hydrotreated renewable diesel and sustainable aviation fuel — drop-in fuels chemically equivalent to their fossil counterparts, compatible with existing engines, aircraft, pipelines and storage, with no blend wall and no vehicle modification.

They are made from the same crops plus tallow, used cooking oil and processing residues — feedstocks Australia produces in volume and currently exports. They are also products the world is short of and pays a premium for, which means a plant built for domestic security has an export market behind it from the first day.

Ethanol, tallow, used cooking oil and biomethane

Australia has operating ethanol capacity from wheat starch and sugar molasses that has historically run below capacity for want of mandated demand. Ethanol displaces petrol directly in existing blends.

Tallow and used cooking oil are the feedstocks that make renewable diesel work at low cost, and Australia exports both. Biomethane from landfill, manure and food waste substitutes for natural gas and for compressed-gas transport, and is the shortest-lead-time item in this section because the waste streams and the gas network already exist.

6. Domestic crude: resource base, exploration and refining capacity

The resource base: 98 per cent self-sufficient in 2000, 5.6 per cent today

This is the standard answer, and it is a claim about effort rather than about geology. The record does not support it.

Australia has been self-sufficient in oil within living memory. In 2000 the country produced and refined more than 560,000 barrels a day and met 98 per cent of its own needs. It now produces about 5.6 per cent of the crude oil it consumes.

A single discovery in Bass Strait in 1965 delivered that self-sufficiency, and the Gippsland Basin has produced more than five billion barrels across five decades. Production has declined since the 1980s peak because the fields are old, not because the continent was searched and found empty. The Northern Carnarvon Basin still accounts for close to 70 per cent of Australian oil production.

What changed is the looking. Petroleum exploration expenditure runs at about a quarter of its level a decade ago. A country that stops drilling stops finding, and then reports the absence of finds as an absence of oil.

Where Australia has looked recently, it has found. Dorado was the largest oil discovery in Western Australia this century, made in 2018 by a well that was chasing gas, in a sub-basin that had seen around seventeen exploration wells against more than fifteen hundred in the basin next door. It was not found because the Bedout was searched thoroughly. It was found on the seventeenth attempt in a place nobody had bothered with.

Taroom Trough, Queensland: 200 barrels a day already in production

The Taroom Trough, in the Bowen Basin near Roma and Miles, is the clearest current test of whether Australia has oil, because production has already started.

Shell is producing about 200 barrels a day of high-quality crude from a pilot, trucked to IOR’s Eromanga refinery a thousand kilometres west of Brisbane and turned into diesel. The volume is small. What matters is that it is Australian crude, refined in Australia, entering Australian supply, from a formation the Queensland Government describes as potentially the country’s first major new oil province since the 1970s.

The activity behind it is not small. Exploration permits over about 750 square kilometres — an area the size of Singapore — were awarded in February 2026 to Omega TN, Tri-Star Stonecroft and Drillsearch, with further areas released by competitive tender in March. Tenure holders have committed more than $500 million to exploration and appraisal. Omega, Elixir, Santos, Beach and Shell’s subsidiary are all in the ground.

Modelling by Omega with the oilfield services firm SLB compares the upside of its Canyon sandstone to the liquids-rich unconventional basins of the United States, including the Eagle Ford. Industry estimates put the region’s total hydrocarbon resource in the hundreds of millions of barrels, and backers argue it could reach around 176,000 barrels a day — enough to feed both remaining Australian refineries, and comparable to Kingfish, the largest oil field the country has ever produced.

The state has moved accordingly: a Taroom Trough Development Plan under the Queensland Coordinator-General, a works regulation to fast-track the roads and trunk infrastructure, and a request that the Commonwealth recognise the basin as a project of national interest.

The qualifications are real and should be stated. Exploration is at an early stage, the type and quality of the oil across the basin is not yet established, and extraction would require hydraulic fracturing, which is contested. None of that makes the resource absent. It makes it unproven, which is the condition of every field before it is drilled — including Bass Strait in 1964.

Bight Basin: 5 billion barrels estimated, zero exploration permits

The Great Australian Bight is the clearest case of the difference between unexplored and barren. Geoscience Australia’s assessment of the central Bight estimated on the order of five billion barrels of oil and 14 trillion cubic feet of gas. Independent estimates range from 1.9 billion barrels of oil equivalent to a high case of six billion barrels over forty years, and one permit holder put nine billion barrels across the fields it held.

The basin is 796,563 square kilometres and is described in the petroleum-geology literature as one of the least explored passive margins in the world. Its thickest depocentre, the Ceduna Sub-basin, covers more than 155,000 square kilometres and had five exploration wells drilled in it before the most recent round. The wells that were drilled sat on the thin margins of the basin, not in the prospective sections.

Every company that held acreage there left, and the stated reasons were commercial rather than geological: BP withdrew in 2016, Chevron in 2017, and Equinor in February 2020, saying the project did not stack up financially against other global projects in its portfolio. Murphy Oil surrendered EPP43 on 14 July 2021 — the last remaining petroleum exploration title in the Bight Basin.

So the largest prospective oil province in the country currently has no exploration permit over any part of it, and the deepest, most prospective section has been tested by five wells. Nobody has established that the Bight is empty. Nobody has looked.

Unconventional liquids: Beetaloo, and the Taroom Trough resource

Beyond conventional oil, several wells in the Beetaloo Sub-basin have confirmed the presence of liquid hydrocarbons, with estimates in the hundreds of millions of barrels, and the Taroom Trough in Queensland remains to be proved up.

Australia holds significant undeveloped shale basins and tight-oil production is proven at scale in the United States. Shale is higher-emission and contested, and it belongs behind the cleaner routes in build order — but its existence is a fact about the resource base, and the resource base is the thing being denied.

Production and export: 400,000 barrels a day, 94 per cent shipped out

The final answer to “there is no oil” is that Australia produces about 400,000 barrels a day of petroleum liquids right now, and ships more than 94 per cent of it overseas to be refined by somebody else. Roughly 300,000 to 380,000 barrels a day of Australian hydrocarbon leaves the country every day of the year while the country imports nine litres in ten of its refined fuel.

That is not a country without oil. It is a country that exports its oil and buys back the products made from it.

Condensate splitting: refining the liquids already being exported

Australia produces about 400,000 barrels a day of petroleum liquids, most of it light condensate from its gas fields, and exports more than 94 per cent of it. The two existing refineries cannot process it — they are configured for heavier imported crude — so the country ships out the one hydrocarbon it has in quantity and buys back the products made from it.

A condensate splitter is the plant that closes that loop. It is simpler than a full refinery, matched exactly to the feed Australia produces, and it yields naphtha, kerosene and diesel fractions from a stream already flowing. No new well is required, no exploration, and no discovery: the feedstock is loaded onto ships today.

Micro and macro refineries: modular capacity sized to the field

Refining capacity does not have to arrive as a single mega-plant. Modular refineries — skid-mounted process units built in a factory and bolted together on site — complete in under a year rather than five, at a fraction of the upfront capital, and scale in increments of roughly 1,000 to 40,000 barrels a day.

That range covers two distinct roles, and the country needs both.

Macro units at the coastal gas and condensate hubs — Karratha, Darwin, Gladstone — where the light liquids are already gathered, stabilised and loaded for export. A splitter placed where the export terminal already stands takes its feed off an existing stream and puts finished naphtha, kerosene and diesel into domestic supply instead of onto a ship.

Micro units inland, sized to a field or a district: the Eromanga refinery already does exactly this, taking Queensland crude by road and producing diesel for the region around it at up to about 1,250 barrels a day. A unit of that size can be justified by one modest field and one regional fuel market, which is why it exists while larger projects do not.

The pattern is the same one that applies to crushing. Small plants near the resource are financed by a single field and a local market rather than by a global product slate; they shorten the haul at both ends; and repeated standard designs become a fabrication order book rather than a series of bespoke projects.

The limits are real and should be stated: weaker unit economics per barrel than an Asian mega-refinery, and a narrower product range. What they offer is speed, low upfront cost, a configuration matched to the crude Australia actually has, and capacity that can be added a unit at a time as demand and discovery allow.

Lytton and Geelong: the remaining refining base

Lytton and Geelong produced 12 billion litres in 2025, about a fifth of national needs, and both run imported crude. They are the only refining skill base in the country, and the workforce, permits and port infrastructure they carry are the foundation of anything built next. Keeping them is not a solution to import dependence, but losing them removes the base from which the rest is built.

Dorado: 344 million barrels, no investment decision

Dorado, off the Pilbara coast, was the largest oil discovery in Western Australia this century — found in 2018 by a well chasing gas, in the Bedout Sub-basin, which had seen around seventeen exploration wells against more than fifteen hundred in the basin next door.

It is light, low-emission crude, holding a gross contingent resource of 344 million barrels of oil equivalent, and it has still not been built. The joint venture deferred its 2025 investment decision, declined to buy the production vessel and did not enter detailed engineering. In June 2026 its junior partner said a decision could come in late 2027, with first oil about three years after that. The development has been optimised to 60,000 barrels a day using a redeployed vessel.

Australia’s largest undeveloped oil field was found in 2018 and remains undeveloped in 2026, while the country imports nine litres in ten of its refined fuel.

Frontier exploration: Bedout, Bight and Canning

The same sub-basin holds further discoveries and leads — Pavo, Apus, Roc — and the Great Australian Bight remains essentially untested, as does much of the Canning. A sovereign exploration effort across the frontier basins is the item with the longest lead time and the lowest cost to begin, and nothing else on this list replaces it.

7. Fossil conversion: gas-to-liquids, methanol and coal-to-liquids

Australia’s three largest energy endowments — coal, gas and renewable power — each convert to transport fuel by proven routes.

Gas-to-liquids (Fischer–Tropsch)

Commercial at Shell’s Pearl plant in Qatar, turning natural gas into diesel and jet fuel of very high quality. Applied to gas reserves among the largest on earth, it converts a resource Australia exports into the fuel Australia imports. The plants are large, capital-heavy and slow to build, which is why the method belongs in a programme rather than a crisis response.

Methanol from natural gas

Methanol is the simplest liquid a gas molecule becomes, the technology is long established, and it is already accepted as a marine fuel and a chemical feedstock. It is the lowest-complexity conversion route on this list and the one that most readily uses stranded gas at a wellhead.

Coal-to-liquids (Fischer–Tropsch)

Australia holds some of the world’s largest coal reserves, measured in centuries at current rates of use, and the conversion is proven at national scale: coal-to-liquids has fuelled much of South Africa’s economy for decades through Sasol’s plants, producing diesel and jet fuel to standard specification.

The trade-off is stated plainly. Emissions run higher than conventional refining, which is why this method sits behind the clean routes in build order — but it converts the country’s single largest energy resource into the fuel it currently imports, from mines and workforces that already exist. Germany, blockaded and cut off from crude, ran on synthetic fuel made from its own coal, and it was the loss of those plants that ended its war.

Shale and tight oil: fallback only

Australia holds significant undeveloped shale basins, and tight-oil production is proven at scale in the United States. Shale is higher-emission and contested; it belongs in the fallback row, not the plan. Its existence matters for one reason: a country with centuries of coal, vast gas, untested basins and a standing crop has not run out of fuel options. It has declined to use them.

8. Electrofuels: hydrogen, ammonia and synthetic hydrocarbons

Australia has the best combined solar and wind resource of any developed economy. Electricity converts to liquid and gaseous fuels by established chemistry, and the volumes the country could make run far beyond its own use — which is what an export industry requires.

Green hydrogen: heavy transport and industrial heat

Hydrogen from renewable electricity and water substitutes for diesel in heavy transport where batteries are hardest — long-haul trucking, rail on unelectrified track, some mining equipment — and for gas in industrial heat. It is also the input the rest of this section depends on.

Every electrofuel is priced by the electricity that makes it

This section rests on one number. Electrolysis converts electricity into hydrogen, and that electricity is the dominant cost in every product downstream of it: ammonia, methanol, synthetic kerosene and synthetic diesel are all hydrogen with further steps added. A hydrogen industry is an electricity industry wearing a different label.

That is why the electrofuel path and the generation programme are the same programme. Australia’s interior carries roughly 2,400 to 2,800 kilowatt-hours per square metre a year of solar resource against 1,600 to 1,800 in the coastal zones, and the corridor carries the transmission that brings it to load at marginal cost, because the easement is already being cut for freight, water and fibre.

The generation and transmission case is set out in The Power Imperative, Three Plans, One Grid and How the Grid Works, with the storage case in the Alice Hub.

Stated plainly: at high electricity prices these fuels are a laboratory curiosity, and at low ones they are an export industry. Nothing about the chemistry changes between those two cases. Cheap power is not a helpful condition for the hydrogen path. It is the path.

Green ammonia: marine fuel, nitrogen fertiliser and AdBlue urea

Ammonia made from green hydrogen is a shipping fuel and an export commodity. It is also the molecule behind nitrogen fertiliser and the urea that Australian heavy trucks require as AdBlue — the input that ran to about ten days of national stock during the 2026 crisis and can stop 99 per cent of the heavy fleet on its own. A green ammonia plant answers a fuel problem and a fertiliser problem with the same equipment.

e-Methanol, e-kerosene and synthetic diesel

Hydrogen combined with captured carbon dioxide produces methanol, kerosene and diesel that are chemically equivalent to their fossil equivalents and drop into existing engines and aircraft without modification. These are the premium end of the fuel market and the products that decarbonise the sectors nothing else reaches.

Hydrogen as a process input for renewable diesel and SAF

The connection rarely made: hydrotreated renewable diesel and sustainable aviation fuel both consume large volumes of hydrogen in production, and most of the world’s hydrogen is made from fossil gas. Domestic renewable hydrogen is therefore not only a fuel in its own right but the input that lets the grown-fuel section above scale without importing the very thing it is meant to displace.

All of these cost more per litre today than an imported cargo. Their case is strategic position: each converts a resource the country owns into the fuel it buys, and each produces a surplus that has a market.

9. Reserve and critical inputs during the build

The build takes years, so the bridge must hold while it proceeds.

That means a real onshore stockpile at the 90-day obligation — not the current programme’s 50-day ceiling — held as the bridge and not mistaken for the destination; a strategic fleet doing its actual job, which is crisis carriage rather than a substitute for supply; and sovereign stocks of the small chemical inputs that can stop the country before the fuel does, urea first among them.

Store it underground

Australia holds its reserve in above-ground tanks. That is the most expensive and the most exposed way to do it.

The United States stores its Strategic Petroleum Reserve in about sixty solution-mined salt caverns between 2,000 and 4,000 feet down, with an authorised capacity of 714 million barrels. The Department of Energy puts the capital cost at roughly $3.50 a barrel against $15 to $18 a barrel for above-ground tanks — up to ten times cheaper, and twenty times cheaper than mined hard rock.

The other advantages are structural rather than financial. Geological pressure at depth closes any crack that forms, so the caverns do not leak. The temperature gradient between the top and bottom of a cavern keeps the oil circulating, which holds its quality over years of storage. The surface footprint is about a tenth of the equivalent tank farm: a five-million-tonne surface reserve needs on the order of 2,000 acres, and the land above a cavern field stays in use.

And a buried cavern is not a target in the way a tank farm is. Ground storage is flammable, visible from orbit and concentrated; the 2008 Varanus Island explosion showed what a single point of failure in surface hydrocarbon infrastructure does to a state, without anyone attacking it.

Other importing nations have already made this choice. China held an estimated 1.4 billion barrels of strategic inventory at the end of 2025, Japan about 263 million and South Korea about 79 million, and India is building salt-cavern capacity to add to its existing mined rock caverns.

Australia has sedimentary basins containing bedded salt and depleted gas reservoirs already used commercially to store gas. Whether they are suitable for liquid fuel storage is a geological question that has not been asked at national scale, and asking it is the first step. The method requires water and produces brine, which is a siting constraint rather than an objection.

Storage dispersal belongs here too. Two plants and a pipeline is the most brittle possible arrangement, and the same principle that applies to gas applies to fuel: many sites, several refineries and redundant routes survive a strike or an accident that a concentrated system does not.

Reserve measures differ in definition; figures are indicative. Sources: IEA oil-stock data; DCCEEW fuel-security reporting; 2026 reporting.

10. Export of surplus refined and synthetic fuel

Self-sufficiency is the floor. Put the levers together and the arithmetic moves one way: demand falls as the country electrifies, domestic output of biofuel, refined product and synthetic fuel rises, the gap imports fill today closes, then reverses.

At that point Australia is selling finished and clean fuel — refined product, renewable diesel, sustainable aviation fuel, green ammonia, e-methanol — into a region of energy-hungry economies sitting on the same chokepoints Australia is escaping. The country that exports raw energy and imports finished fuel instead makes the finished fuel and sells it. The wider strategic case is set out in the companion memo The Prize: A Unified AsiaPac.

11. The two paths compared

The two paths reduce to one comparison. Staying on imports is cheaper today and more expensive every year after: the standing bill, the risk premium, the crisis packages, and a vulnerability that no tank or fleet retires, because the vulnerability is the path. Building is dearer upfront and then keeps paying — in money that stays home, in crises that do not happen, and in an industry that exists and earns at the end of it.

The build also returns part of its own cost. An entire domestic fuel industry’s tax base — company, payroll and income tax across its build and operating life — is collected here rather than by a foreign treasury, and royalties are levied on any domestic feedstock.

The same plants, lines and reserves are defence assets: a country that can fuel and move itself can defend itself. Part 1 closes on the full number; this memo closes on the decision it implies. Every method above reduces the count of imported litres the country depends on. That is the test the current response fails, and the test this programme is built to meet.

12. A 100 per cent domestic supply target, and what it requires

Nothing in this memo requires a technology that does not exist. Every method above is either operating somewhere in the world today, operating in Australia at small scale, or a plant that has been built commercially by somebody else.

The obstacle is not capability. It is that no Australian government has set the objective, and without an objective there is no offtake certainty, no reservation rule, no acreage programme and no reason for a private builder to commit capital to a plant whose product competes with an imported cargo priced on a calm day.

Seven requirements of a domestic supply programme

State the target. A national objective of 100 per cent domestic supply of transport fuel, with a date, and the annual import share published against it. What is measured moves; what is not measured is announced.

Explore. Frontier acreage released and drilled — the Bight, the Bedout and the Canning — on a sovereign programme where private capital will not carry the risk alone. The Bight currently has no exploration permit over it at all, while Queensland has shown what a state can do in a year by releasing acreage, awarding permits and fast-tracking the infrastructure behind them.

Refine here, at both scales. Macro splitters at the coastal condensate hubs where the liquids are already gathered for export, micro modular units inland sized to a field and a regional market, and the two existing refineries kept as the skill base the rest is built from.

Process it where it grows. Crushing and biorefining capacity built through the growing zones at both district and farm scale, rather than a single national plant, so that freight falls, the meal stays local and the fleets that work the country run on fuel made in it.

Guarantee the offtake. A standing domestic reservation on biofuel feedstock, and long-term purchase commitments for renewable diesel, sustainable aviation fuel and biomethane. A plant is financed against a contract, not against a hope.

Redirect the subsidy. The Fuel Tax Credit’s roughly $10 billion a year currently rebates imported diesel. Pointed at electrification and domestic production it funds most of this programme without a new dollar.

Build the corridor. Electrified freight, passenger maglev and the transmission that runs them on one continental right of way. It is the single largest displacement of imported fuel available, and it is the same easement that carries the power the electrofuels need.

Build the conversion capacity. Gas-to-liquids, methanol, coal-to-liquids and the power-to-fuel plants, sequenced behind the faster levers but started, because each takes years and none starts itself.

Hold the bridge while it is built. Ninety days onshore, stored underground where the geology allows it at a fraction of the cost and exposure of tankage, a flagged fleet, and sovereign urea.

Two definitions of “fuel sovereignty” in use

Both governments use the language of fuel sovereignty. They apply it to opposite activities.

The Commonwealth’s ministerial release titled “Securing Australia’s fuel sovereignty” describes a minimum stockholding obligation, a payment to keep two refineries from closing, a government-owned reserve, and an incoming gas reservation. Every item is about holding, buying or discounting fuel. The production line in the same package is $10 million of feasibility studies.

Queensland uses the same word for drilling, refining and building. It has released acreage, awarded permits, stood up a development plan under its Coordinator-General, issued a works regulation to fast-track roads and trunk infrastructure, and asked the Commonwealth to recognise the basin as a project of national interest. Its stated objective is domestic oil supply and long-term fuel security, and its deputy premier describes the approach as pulling all levers to unlock more domestic energy production.

The Commonwealth’s contribution to that project so far has been to ask Queensland for details without delay. A state government is running a domestic oil programme and the national government is requesting a briefing on it.

Sovereignty over a fuel you do not make is sovereignty over the paperwork. The distinction is not rhetorical: one set of measures changes how much imported fuel sits in a tank, the other changes how much fuel the country produces.

The resource base against the stated constraints

The current answer to fuel insecurity is that domestic production is not economic, not available in time, or not compatible with other objectives. Each of those is a statement about the effort the country is prepared to make, not about what the continent contains.

Australia has oil it has not looked for, condensate it exports raw, coal and gas measured in centuries, the best solar and wind resource of any developed economy, farmland that grows fuel crops, and an existing refining workforce. A country holding that combination and importing ninety per cent of its refined fuel has not run out of options. It has declined to use them.

This is a national security question before it is an energy question. The fleet, the food system, the hospitals, the mines and the defence force all run on a fuel that arrives on somebody else’s ship, through somebody else’s strait, at somebody else’s discretion. Part 1 sets out what that costs and what the Government is currently doing about it. This memo sets out every method of ending it.

13. Future-proofing: the programme does not require picking the winning fuel

The standard objection to any fuel programme is that nobody knows what vehicles will burn in 2050, so building for one fuel risks stranding the investment. It is a fair objection, and this programme is built so that it does not apply.

Every method in this memo converges on a small number of assets that hold their value whatever the answer turns out to be.

Electricity is the input under every scenario

Battery vehicles run on it. Electrified rail and maglev run on it. Electrolysis runs on it, so hydrogen, ammonia, methanol and synthetic kerosene are all electricity with steps added. Refineries, crushing plants and biorefineries consume it. Industrial heat converts to it.

Generation and transmission are therefore the one investment that pays under every technology outcome, including outcomes nobody has named yet. There is no plausible 2050 in which Australia regrets having cheap, abundant domestic power.

The corridor carries whatever the future runs on

A right of way is not a technology bet. The same easement carries electrified freight, passenger maglev, high-voltage transmission, water, fibre and a pipe — and the pipe can carry gas now, hydrogen later, or nothing, without stranding the corridor around it.

If liquid fuels decline faster than expected, the corridor is still moving freight and power. If they decline slower, it is still moving freight and power, and carrying the fuel as well. The asset is indifferent to the question.

Modular capacity is added and retired in increments

A conventional refinery or crushing plant is a single thirty-year commitment made on a forecast. A modular unit is a decision made in increments of one to forty thousand barrels a day, or one district’s harvest, over a decade.

That structure converts a bet into a sequence of small, reversible steps. Capacity that turns out not to be needed is not built; capacity that turns out to be needed is added without a new approval cycle. The same applies to distributed crushing: a plant per district, built as the offtake proves up.

The conversion plants are feedstock-flexible

Fischer–Tropsch synthesis takes gas or coal or biomass. Hydrotreaters take canola, tallow, used cooking oil, hemp or algal oil interchangeably. A condensate splitter takes any light liquid. Anaerobic digestion takes whatever organic waste arrives.

The plants are therefore not bets on a particular crop, field or resource. They are bets on the country continuing to produce hydrocarbons or biomass of some kind, which is the safest bet available.

Storage and skills outlast the fuel in them

A salt cavern holds crude, refined product or, with modification, hydrogen. A tank farm, a pipeline, a port terminal and a rail siding are equally indifferent to which molecule passes through them.

The workforce is the same story. Process engineers, operators, fitters, electricians, fabricators and cable-lay crews transfer between every method in this memo. Skills built for one route are not lost when the route changes; they are the thing that lets the country change route at all.

What the current path bets on

Set against that, the present arrangement is the least hedged position available. It depends on a single condition holding for the next thirty years: that other countries keep refining Australia’s fuel, keep shipping it, and keep choosing to send it here at a price Australia can pay.

Three sea lanes have closed since 2023. Insurers repriced marine war risk permanently. The refineries that supply Australia sit inside the region most likely to be at war. Six cargoes were turned back in a single month of 2026 with no blockade in place at all.

That is one forecast, thirty years long, with no fallback and no ability to correct if it is wrong.

Future-proofing is not prediction

The programme in this memo does not claim to know which fuel wins. It builds the electricity, the corridor, the modular plant, the feedstock flexibility, the storage and the workforce that every candidate answer requires, and it builds them in increments that can be stopped, slowed or accelerated as the evidence arrives.

Being wrong about the future is normal. Being unable to survive being wrong is a choice, and it is the one the country has currently made.

References

1. The task (§1) — Australian Petroleum Statistics (DCCEEW); IEA; EIA Australia Country Analysis 2025 (~850,000 b/d refined product imported; ~400,000 b/d produced, >94% exported; ~90% refined-fuel import share; ~91% of diesel imported by 2025); IEA oil-stock data (~37 days held vs the 90-day obligation).
2. Electrification of the passenger task (§3) — an all-electric passenger fleet replacing roughly a third of imported oil — electrification and fleet-energy analyses; see also the MMA electricity memos.
3. Fuel Tax Credit scale and incidence (§3) — ~$10bn/yr (2024–25) and rising, Budget papers; IEEFA, 2026 (mining ~35% of national diesel use; ~$4.5bn of the $9.6bn credit spend in 2023–24; a 30% baseline exceedance requiring explanation only); Fortescue, submission to the Productivity Commission, 2026 (the ~$0.50/L credit ≈ 5× the cost of exceeding a Safeguard baseline; the credit roughly halving the return on fleet electrification); Climate Energy Finance (the credit as an implicit ~$190/t CO₂-e subsidy against ACCU prices of ~$30–40).
4. Canola and biofuel (§4) — ABARES crop data via the MMP fuel-crisis letter series, Letter 7, 31 March 2026 (5.84 Mt in storage ≈ 2.2bn L biodiesel equivalent, ~34–37 days of diesel; a half-crop reservation yielding 1.1–1.3bn L/yr, 18–22 days).
5. Sustainable aviation fuel and renewable diesel (§4) — IATA; renewable-fuels industry sources on feedstock base and demand outlook.
6. Dorado and the frontier basins (§5) — Santos (80 per cent and operator), Carnarvon Energy (10 per cent) and CPC/OPIC Australia (10 per cent): largest Western Australian oil discovery this century, found 2018, gross 2C contingent resource of 344 million barrels of oil equivalent; the 2025 final investment decision deferred, the identified FPSO not purchased and front-end engineering not entered; Carnarvon’s chief executive stating in June 2026 that a decision could come in late 2027, with first oil about three years after FID; development optimised to 60,000 barrels a day using a redeployed FPSO; Bedout Sub-basin drilling history (~17 exploration wells vs >1,500 in the adjacent basin; Pavo, Apus, Roc); Geoscience Australia resource assessments; the Great Australian Bight’s untested status.
7. Modular refineries (§5) — industry sources (Honeywell UOP modular trains; Howe Baker; modular-refinery technical literature): skid-mounted, <12 months to completion vs ~5 years, 1,000–40,000 b/d, topping/splitter configurations suited to light condensate; weaker unit economics than mega-refineries.
8. Coal, gas and renewables to liquid fuel (§6) — coal-to-liquids at national scale: Sasol, South Africa, producing diesel and jet fuel for decades; Geoscience Australia on Australia’s coal resource (among the world’s largest, centuries at current use); Shell Pearl GTL, Qatar; CSIRO and ARENA on green hydrogen, ammonia and synthetic fuels and Australia’s clean-fuel export potential.
9. The bridge (§7, Table) — IEA oil-stock data; DCCEEW fuel-security reporting; Strategic Fleet Taskforce (~12 ships planned); 2026 reporting on AdBlue/urea stocks near ten days.
10. The export flip and regional demand (§8) — see the companion memo The Prize: A Unified AsiaPac.
11. The situation this memo answers — the exposure, the supply line, the standing bill, the 2026 shock costs and the Government’s response register, including the Minister’s 5 August 2026 National Press Club claims — is set out with sources in Part 1: Australia’s Fuel Security — Part 1: The Position and the Government’s Response.
12. Hemp as a fuel crop (§5) — hemp seed at 30–35 per cent oil by weight giving a biodiesel yield of approximately 780–800 litres per hectare, exceeding soybean, sunflower, peanut and rapeseed; hemp biodiesel meeting ASTM D6751 and EN 14214 fuel standards and outperforming conventional diesel other than on oxidation stability, which is addressed with additives; hemp fibre composition of approximately 55 per cent cellulose, 16 per cent hemicellulose, 18 per cent pectic polysaccharides and 4 per cent lignin, with an estimated lignocellulosic ethanol yield near 4,500 litres per hectare; methanol, ethanol and biogas producible from the stalk and residual biomass; agronomic characteristics including drought tolerance, growth on infertile soil, weed suppression and no drying requirement (Zatta and Venturi 2006; Rehman et al. 2013; Gunnarsson et al. 2015; Biomass Conversion and Biorefinery, 2026; BioEnergy Research, 2026; Hemp Gazette; Biomass Connect). Industrial hemp is licensed as a low-THC agricultural crop under Australian state legislation.
13. Condensate splitting and the export of domestic liquids (§6) — Australian production of approximately 400,000 b/d of petroleum liquids, predominantly light condensate, with more than 94 per cent exported; the two remaining refineries configured for heavier imported crude and unable to process it (EIA Australia Country Analysis 2025; Australian Petroleum Statistics; Geoscience Australia).
14. Dorado and the frontier basins (§6) — Santos (80 per cent and operator), Carnarvon Energy (10 per cent) and CPC/OPIC Australia (10 per cent): largest Western Australian oil discovery this century, found 2018, gross 2C contingent resource of 344 million barrels of oil equivalent; the 2025 final investment decision deferred, the identified FPSO not purchased and front-end engineering not entered; Carnarvon’s chief executive stating in June 2026 that a decision could come in late 2027, with first oil about three years after FID; development optimised to 60,000 barrels a day using a redeployed FPSO; Bedout Sub-basin drilling history (~17 exploration wells against >1,500 in the adjacent Carnarvon Basin; Pavo, Apus, Roc); the Great Australian Bight and much of the Canning untested; Australian petroleum exploration expenditure at about a quarter of its level a decade ago (Geoscience Australia, Australia’s Energy Commodity Resources 2025).
15. Renewable diesel, SAF, ethanol and waste streams (§5) — hydrotreated renewable diesel and sustainable aviation fuel as drop-in fuels chemically equivalent to their fossil counterparts, produced from vegetable oils, tallow, used cooking oil and processing residues, all of which Australia produces and exports; Australian ethanol capacity from wheat starch and sugar molasses operating below capacity; biomethane from landfill, manure and food-waste streams (IATA; renewable-fuels industry sources; Australian Renewable Energy Agency bioenergy reporting).
16. Power-to-fuel routes and the hydrogen input (§8) — green hydrogen, green ammonia, e-methanol and synthetic kerosene and diesel from renewable electricity, water and captured carbon dioxide; ammonia as both a marine fuel and the precursor to nitrogen fertiliser and to the urea required as AdBlue by approximately 99 per cent of Australian heavy diesel trucks, with national urea stock reported near ten days during the 2026 crisis; hydrotreated renewable diesel and sustainable aviation fuel consuming substantial hydrogen in production, most global hydrogen currently being produced from fossil gas (CSIRO; ARENA; IEA hydrogen reporting).
17. The Bight (§6) — Geoscience Australia assessment of the central Bight estimating on the order of 5 billion barrels of oil and 14 Tcf of gas (cited in The Australia Institute, Oil in the Great Australian Bight, 2020); independent estimates of 1.9 billion barrels of oil equivalent with a high case near 6 billion barrels over forty years, and a permit holder’s estimate of 9 billion barrels across the fields it held (Global Energy Monitor). Bight Basin area of 796,563 km², described as one of the least explored passive margins in the world, with the Ceduna Sub-basin covering more than 155,000 km² and only five petroleum exploration wells drilled in it prior to the most recent round, all earlier wells located on relatively thin successions at the basin margins (Geoscience Australia; Marine and Petroleum Geology, 2023). Withdrawals: BP 2016, Chevron 2017, Equinor February 2020 on stated commercial grounds, and Murphy Oil’s surrender of EPP43 on 14 July 2021, the last remaining petroleum exploration title in the basin (Energy Voice; ministerial statements).
18. Australian oil history and the resource base (§6) — the 1965 Gippsland Basin discovery and Australian oil self-sufficiency; more than 5 billion barrels produced from Bass Strait across five decades with production declining since the 1980s peak; the Northern Carnarvon Basin accounting for close to 70 per cent of Australian oil production (Geoscience Australia); Beetaloo Sub-basin wells confirming liquid hydrocarbons with estimates in the hundreds of millions of barrels, and the Taroom Trough remaining to be proved up.
19. Queensland and the Taroom Trough (§6) — Queensland Department of Natural Resources and Mines: exploration permits over approximately 750 km² awarded February 2026 to Omega TN Pty Ltd, Tri-Star Stonecroft Pty Ltd and Drillsearch Energy Pty Ltd, further areas released by competitive tender in March 2026, more than $500 million committed by tenure holders for exploration and appraisal, active explorers including Omega Oil and Gas, Elixir Energy, Santos, Beach Energy and QGC (Shell), and the department’s statement that the Taroom Trough “could become Australia’s first major new oil province since the 1970s”. Queensland ministerial statements, April 2026: Shell producing 200 barrels a day of high-quality crude refined at IOR’s Eromanga refinery into diesel; the Taroom Trough Development Plan under the Coordinator-General; a works regulation for Governor-in-Council approval; and the request for Commonwealth recognition under the National Interest Fast-Track Assessment Pathway. Omega Oil and Gas / SLB modelling comparing the Canyon sandstone upside to liquids-rich United States unconventional basins including the Eagle Ford. Proponent estimates of around 176,000 barrels a day, comparable to the Kingfish field, and industry estimates of hundreds of millions of barrels in total hydrocarbon resource. Countervailing assessment — early-stage exploration, unresolved questions over oil type, and the requirement for hydraulic fracturing — from the University of Technology Sydney and IEEFA, April 2026. Australian self-sufficiency in 2000 (more than 560,000 b/d produced and refined, meeting 98 per cent of needs) and current domestic production at about 5.6 per cent of crude consumed, from the same UTS analysis.
20. The two uses of “fuel sovereignty” (§12) — Commonwealth ministerial release “Securing Australia’s fuel sovereignty” (DCCEEW), describing the minimum stockholding obligation, the Fuel Security Services Payment, the government-owned reserve and an incoming domestic gas reservation, against $10 million for refinery feasibility studies in the 2026–27 package. Queensland ministerial statements, February and April 2026: acreage release and permit awards in the Taroom Trough, the Taroom Trough Development Plan under the Coordinator-General, a works regulation directed for Governor-in-Council approval to fast-track strategic infrastructure, the request for Commonwealth recognition under the National Interest Fast-Track Assessment Pathway, and the Deputy Premier’s statement that the government is “pulling all levers to unlock more domestic energy production”. Federal Environment Minister’s reported request that Queensland provide details “without delay” (University of Technology Sydney / IEEFA, April 2026).
21. Crushing capacity and distributed processing (§5) — United States Department of Agriculture Foreign Agricultural Service, Australia: Oilseeds and Products Annual (2025 and April 2026): total Australian crushing capacity approximately 1.6 million tonnes; six crushing facilities in New South Wales and Victoria and two smaller plants in Western Australia; crush volume steady near 1.3 million tonnes against exports of 4.65–4.7 million tonnes; canola meal production forecast at 754,000 tonnes for 2025–26, with crushing facilities sited near beef, dairy, pig and poultry users of meal; canola production for 2026–27 forecast at 6.2 million tonnes, a 19 per cent decline, attributed to diesel and nitrogenous fertiliser supply constraints and price increases arising from Middle East disruption. RaboResearch, Harvesting the future: how far can Australia scale canola crushing? (2026): approximately six million tonnes of seed exported annually, almost all unprocessed, equating to more than two billion litres of renewable diesel against more than thirty billion litres of diesel imported; “a large share of the processing margin, jobs and strategic control sits offshore”; regions with higher canola-crushing density exhibiting more stable pricing than export-dependent zones such as Western Australia, with expanded capacity absorbing surplus supply, stabilising basis and reducing volatility.
22. Underground reserve storage (§9) — United States Department of Energy, Strategic Petroleum Reserve: approximately 60 solution-mined salt caverns at four Gulf Coast sites with an authorised capacity of 714 million barrels, caverns 2,000–4,000 feet below the surface, typical cavern 10 million barrels; capital cost historically about $3.50 a barrel against $15–18 a barrel for above-ground tanks, described by the Department as up to ten times cheaper than surface tanks and twenty times cheaper than mined hard rock; geological pressure sealing any crack that develops, and the top-to-bottom temperature differential keeping stored crude circulating and of consistent quality. Surface footprint comparison (a five-million-tonne surface reserve requiring on the order of 2,000 acres, with underground surface facilities about one tenth of the equivalent) and the security argument that ground storage tanks are targeted, from peer-reviewed salt-cavern storage literature (Levin et al. 2005; Song et al. 2022, in Gas Science and Engineering, 2024). Comparative national inventories at end-2025 — China approximately 1.4 billion barrels, Japan approximately 263 million, South Korea approximately 79 million — from United States Energy Information Administration estimates; India’s salt-cavern programme and existing rock caverns at Mangalore, Visakhapatnam and Padur (Engineers India Ltd feasibility work). Water use and brine disposal are noted as siting constraints of the method.
23. Micro and macro refining (§6) — modular refinery configurations and delivery times from industry sources (Honeywell UOP modular trains; Howe Baker; modular-refinery technical literature): skid-mounted, under 12 months to completion against roughly five years for a conventional plant, increments of approximately 1,000–40,000 b/d, topping and condensate-splitter configurations suited to light condensate, with weaker unit economics and a narrower product slate than a large-scale refinery. IOR’s Eromanga refinery in south-west Queensland as the operating Australian example of the small inland case, taking regional crude by road and producing diesel and other products at up to approximately 1,250 barrels a day.
24. Algae (§5) — theoretical yield of more than 58,000 litres of oil per hectare per year against about 172 litres per hectare for corn, and the suitability of algae for non-arable land, saline and waste water without competing with food or fresh water (algae researchers writing in The Conversation, May 2026); Australian open saline pond production rates led by Murdoch University and the University of Adelaide. Countervailing evidence: sustained pilot-scale production of approximately 5,000–10,000 litres per hectare per year (The Conversation, 2026); pilot-scale costs of approximately US$8–16 per gallon of gasoline equivalent, dominated by harvesting and drying; open-pond contamination and culture-crash risk; water use of 600–1,900 litres per litre of fuel unless saline or waste streams are used; and the commercial pivot of most producers to omega-3 supplements, cosmetics and feed rather than fuel (industry analyses, 2025–2026).
25. The corridor as a displacement mechanism (§4) — the continental multi-service corridor carrying electrified heavy freight, passenger maglev and high-voltage transmission on a single elevated right of way, as set out across the MMA programme and on the Plan and Phase Maps pages; rail energy efficiency per tonne-kilometre against road haulage; and the absence of a battery pathway for commercial aviation at required volumes.
26. Electricity as the cost of electrofuels (§8) — electrolysis electricity as the dominant input cost for hydrogen and therefore for ammonia, methanol and synthetic hydrocarbons downstream of it; Australian interior solar resource of approximately 2,400–2,800 kWh/m²/yr against 1,600–1,800 kWh/m²/yr in the coastal renewable energy zones; generation, transmission and storage cases in The Power Imperative, Three Plans, One Grid, How the Grid Works and the Alice Hub pumped hydro memo.