Algeria’s Hydrogen Opportunity: What Must Be True for SoutH₂ to Pay Off

 

The SoutH₂ Corridor promises to link Saharan sunshine to Europe’s heavy industry. Between the political declarations and a working hydrogen market lie physics, water, capital and demand, and each one can break the project. This is the full picture: where hydrogen really fits, what the corridor demands, and what Algeria should insist on.

1. The perpetual mirage

For decades, hydrogen has been the mirage of the energy world, always on the horizon and never quite within reach. It emits only water vapour when burned and carries roughly 120 MJ per kilogram, nearly three times the energy of gasoline by weight. Its low density by volume makes it hard to store and move, which is a problem that shapes this entire story.

The promise of a ubiquitous “hydrogen economy” has been replaced by a narrower industrial strategy. Hydrogen is still an indispensable tool for reaching net-zero, but it is a specialised one. It will matter most in the heaviest and hardest-to-electrify corners of industry, and much less in mass consumer markets.

2. A market still built on fossil fuel

The world uses about 100 million tonnes of hydrogen a year, according to IEA estimates. More than 99% of it is made from fossil fuels. Low-emissions hydrogen is still below 1% of supply.

Analysts classify hydrogen by a “colour spectrum” based on production method and carbon footprint:

Type	Production	Lifecycle emissions (kg CO₂e/kg H₂)	Indicative cost (per kg)
Brown/black	Coal gasification (mainly China, India)	~18–26	~$1.00–2.00
Grey	Steam methane reforming of natural gas	~10–14	~$1.20–2.50
Blue	Natural gas with carbon capture (CCS)	~1–5 (depends on capture rate and methane leakage)	Above grey
Green	Electrolysis with wind, solar or hydro	~0–1	~$2.50–7.00 unsubsidised

The cost gap explains why the transition is slow. Green hydrogen can cost up to three times as much as fossil hydrogen, and no industrial customer will pay that “green premium” without a mandate, a subsidy or a carbon price that closes it.

3. Production is captive, and so is the price

Hydrogen is costly to compress, liquefy and move, so most of it is made where it is consumed. The large majority of today’s supply is “captive”: produced at the factory gate, in refineries and fertiliser plants. The world’s largest consumers are therefore also its largest producers, and the national picture looks like this (approximate, from IEA-type estimates):

Country/region	Annual production (Mt)	Main source	Strategic role
China	~25–33	Coal and grey gas	“The Factory”: about 60% of installed electrolyser capacity and the lowest hardware costs
United States	~11	Cheap natural gas	“The Subsidiser”: the 45V credit of up to $3/kg, now facing a construction-start deadline
Middle East	~11–15	Domestic gas	“The Exporter”: giant solar-to-ammonia projects such as NEOM
India	~8–10	Coal and imported gas	“The Scaler”: national quotas for fertiliser
European Union	~7–8	Imported gas	“The Regulator”: mandates, CBAM and price discovery

Two lessons come from this table. First, the cost curve is being set in China. Chinese alkaline systems are built for around $600/kW, against roughly $2,500/kW for many Western makers. Second, money and capacity are not the same thing. Europe attracts a large share of announced investment but delivers a much smaller share of operating capacity because project development costs are high. Investment announcements are not production.

4. The engine room: three electrolyser technologies

Green hydrogen depends on electrolysers, which use electricity to split water. No single technology wins everywhere:

• Alkaline (ALK), the workhorse. It uses abundant nickel and iron, accounts for most installed capacity, costs roughly $500–1,200/kW, and has stack lives of up to about 100,000 hours. It reacts slowly to power fluctuations, so it suits steady supply such as hydro, nuclear or a firmed grid.
• Proton exchange membrane (PEM), the renewable match. It costs roughly $1,100–1,800/kW and can ramp up and down in a fraction of a second, which suits variable wind and solar. It depends on platinum-group metals. Iridium is the bottleneck, with only about 7–8 tonnes mined worldwide each year.
• Solid oxide (SOEC), the efficiency leader. Operating at roughly 600–850 °C, it can use waste heat and steam from steel or chemical sites, needs far less electricity per kilogram (around 38–45 kWh/kg of electricity plus heat), and costs $2,000–4,000+/kW. Its drawbacks are higher capital cost and shorter stack lives.

A typical alkaline or PEM system uses 50–60 kWh per kilogram of hydrogen. This number matters for everything that follows, because hydrogen’s lower heating value is about 33.3 kWh/kg. At 55 kWh/kg, electrolysis is about 60% efficient, so roughly 40% of the electricity is lost before the hydrogen leaves the plant.

5. Why hydrogen is not yet a commodity

To a trader, hydrogen is not yet a commodity. Oil, gold and gas have standard tickers and liquid futures. Hydrogen has no global spot market. Prices are mostly hidden inside private, multi-year offtake contracts between one producer and one buyer, and this is what blocks financing: banks will not lend billions for electrolysers without long-term buyers.

Germany’s H2Global scheme tries to bridge the gap. A government-backed intermediary signs long-term supply contracts of about ten years with producers, then resells the hydrogen to buyers on short-term contracts, absorbing the difference.

Shipping is the second barrier. Liquefying hydrogen at −253 °C consumes roughly a third of its energy content. This is why the global trade is turning to carriers such as green ammonia, which is easier to liquefy and ship and can use existing chemical vessels and ports.

6. The great sorting: where hydrogen wins and loses

The most important shift of recent years is the acceptance of hydrogen’s limits. Direct electrification has won passenger cars and short-haul transport because it is far more efficient. A battery-electric car converts roughly 70–80% of the electricity it receives into motion. A hydrogen fuel-cell car, after electrolysis, compression and reconversion, uses a third or less, so it needs two to three times as much renewable electricity per kilometre.

Hydrogen is therefore moving to sectors where batteries are too heavy, too slow to charge, or physically unable to do the job:

• Ammonia and fertiliser, where hydrogen is already the core feedstock.
• Chemical synthesis, such as methanol.
• Primary steelmaking. Hydrogen-based direct reduction of iron ore (DRI) replaces coking coal and emits water instead of CO₂. It is a leading route, though not the only one: scrap-based electric furnaces, electrowinning and CCS are alternatives.
• Long-haul shipping, through ammonia or methanol.
• Selected long-haul trucking and seasonal storage, where the case is real but contested, because battery trucks are advancing quickly.

Passenger cars and home heating are effectively out. Projections of hydrogen’s share of the 2050 energy mix vary widely by scenario, roughly 10% in some industry studies and lower in others, so treat any single number with caution.

7. Europe looks south

Europe’s interest in North African hydrogen has two roots. The disruption of Russian gas exposed the cost of energy dependence, and EU climate rules require decarbonisation in industries that cannot easily electrify. Germany expects hydrogen and derivative demand of 95–130 TWh by 2030, with 50–70% of it imported, which is about 45–90 TWh of imports.

The Southern Hydrogen Corridor, SoutH₂, is the flagship answer. It is backed by Algeria, Tunisia, Italy, Austria and Germany. Its main features are:

• A route of about 3,300 km from North Africa into Italy, Austria and Germany.
• A planned transport capacity of up to 4 million tonnes of hydrogen a year.
• More than 65% of the infrastructure to be built from converted gas pipelines, according to UNIDO.
• Full operation targeted for the early 2030s.
• European sections developed by operators such as Snam, TAG, Gas Connect Austria and bayernets.

On the Algerian side, Sonatrach and Sonelgaz signed a memorandum in October 2024 with VNG, Snam, SeaCorridor and VERBUND Green Hydrogen, launching the ALTEH₂A feasibility work. Initial results are expected in 2027. Political milestones followed: a first ministerial declaration in Rome, a UNIDO-hosted secretariat, and a joint declaration in Algiers on October 1, 2026.

These are real steps, but declarations do not build electrolysers or sign buyers. The 4 Mt figure is a transport capacity shared between Algeria and Tunisia. It is not production, and it is not contracted demand.

A useful comparison: 4 Mt is about 133 TWh of hydrogen energy, which is larger than Germany’s entire projected 2030 import need. The corridor is sized for a market that does not yet exist.

8. What four million tonnes really means

The industrial scale is easy to underestimate. Using a 55 kWh/kg consumption figure:

• Electricity: 4 Mt × 55 kWh/kg = 220 TWh a year. That is about 2.6 times Algeria’s current national electricity consumption of roughly 80–85 TWh.
• Electrolysers: 220 TWh ÷ 8,760 hours = about 25 GW running continuously.
• Solar: if the electricity came from tracking solar alone at around 2,200 full-load hours (a 25% capacity factor), it would take about 100 GW of panels, roughly 150 million 650 W modules covering something like 2,000 km². Capacity factors for tracking arrays in the Sahara can be higher, so this is a conservative case.
• Cost: with illustrative figures of $600/kW for solar and $400/kW for Chinese alkaline electrolysers, the solar-only build comes to about $100 billion. The electrolyser share depends heavily on how the plant is designed, and Western-built systems would cost far more.
• Water: the stoichiometric minimum is 9 litres per kilogram, or 36 million m³ a year. With purification and cooling, a realistic range is 60–80 million m³.

These numbers apply to the whole corridor, not Algeria alone, because Tunisia also plans production. But they show what is being asked of the Sahara.

9. The trap of “cheap grid hydrogen”

Faced with 100 GW of solar and a $100 billion bill, an appealing shortcut is to plug electrolysers into the national grid and sign a power purchase agreement for a smaller amount of solar. The arithmetic looks attractive: 25 GW of electrolysers running around the clock, backed by 17 GW of solar, at roughly $22–23 billion of hardware.

It does not work. 17 GW of solar at 2,200 hours produces about 37 TWh a year, which is under a fifth of the 220 TWh needed. The remaining ~180 TWh would come from a gas-fired grid. At roughly 0.4 tonnes of CO₂ per MWh, that is around 70 million tonnes of CO₂ a year, more than the grey hydrogen it was meant to replace. It would not qualify as green under European rules.

The same flaw sinks the headline price of $1.58 per kilogram that this model produces. That figure implies electricity at about 1.5 cents per kWh, and it leaves out stack replacement, storage, water-treatment capital and the cost of finance. Independent estimates are much higher. A June 2026 study in Applied Energy put competitive Algerian production zones at roughly €4.60–5.20/kg under its assumptions. Even that is a modelled potential, not a selling price.

Real green hydrogen needs real renewable electricity: new solar and wind, plus storage or firm clean power for the hours the sun is down, and a grid that can carry it.

10. Pipelines versus cables

Critics of SoutH₂ argue that Europe should import electrons through subsea high-voltage cables rather than molecules through pipelines. The physics supports part of the argument. HVDC links lose only about 0.3% per 100 km plus roughly 1.5% at the terminals, so a 300 km subsea link can deliver around 97% of the electricity sent.

The comparison is often presented unfairly, though. It sets electricity delivered against hydrogen delivered. A steelmaker or fertiliser plant needs hydrogen, and if Europe converts the electrons itself, it loses the same ~40% at the electrolyser. Starting from 100 MWh of Saharan solar:

• Hydrogen made in Algeria: about 60 MWh of hydrogen after electrolysis, and a few percent to around 10% less after compression and pipeline transport, so roughly 54–58 MWh arrives.
• Cable plus European electrolysis: about 97 MWh arrives as electricity, and about 58 MWh as hydrogen after conversion in Europe.

The end result is similar. What differs is where the capital, the water use and the risk sit. A cable is also limited by capacity. A 2 GW link can carry at most about 17 TWh a year, roughly an eighth of the energy in 4 Mt. The two routes complement each other: cables for power, and pipelines for bulk industrial molecules. Pipeline conversion is not automatic either. Hydrogen’s small molecules and behaviour under pressure mean that seals, compressors, valves and metering all need checking, and some sections will need replacing.

11. Water and the carbon alternatives

Algeria is a water-stressed country, and this argument deserves a fair hearing. Producing 4 Mt of hydrogen needs tens of millions of cubic metres of purified water, and desalination plants create brine that must be managed along the coast. The scale, however, is moderate. National desalination capacity is on the order of 2.5 million m³ per day, roughly 900 million m³ a year (verify), so the hydrogen requirement would be a single-digit share of it. The real issue is siting and brine handling, not an absolute shortage.

Some suggest skipping green hydrogen and producing blue hydrogen from Algeria’s gas. This raises two problems.

• Grey hydrogen is a climate liability. At 11–13 kg of CO₂ per kg, 4 Mt would emit 44–52 million tonnes of CO₂ a year, equal to a quarter or more of Algeria’s current emissions. Under the EU’s carbon border mechanism, a CO₂ price of €70–100 per tonne adds roughly €0.8–1.2 per kilogram of hydrogen.
• Carbon storage carries geological risk. Algeria’s In Salah project (2004–2011), run by Sonatrach with BP and Statoil, injected about 3.8 million tonnes of CO₂ into a sandstone reservoir at the Krechba field. Monitoring showed signs of pressure-related fracturing in the lower part of the caprock, and injection was suspended in 2011. It remains a landmark case study in both the promise and the limits of CCS.

Capturing CO₂ from gas power plants has its own cost. Flue gas contains only about 3–4% CO₂, and the capture process cuts a plant’s efficiency by roughly 7–9 percentage points (for example from about 60% to about 51–53%).

12. The Desertec warning

Anyone writing about SoutH₂ should remember Desertec. In 2009, a consortium announced a roughly €400 billion plan to cover North African deserts with solar plants and export electricity to Europe. It failed to attract financing, and major industrial backers withdrew within a few years. Common explanations include unclear demand, political risk, uncertain regulation and the reluctance of investors to carry the early-stage risk.

SoutH₂ differs in important ways. It has government backing in five countries, reuses existing pipelines, and has a company-level feasibility process through ALTEH₂A. But the structural warning remains: a corridor can be ready while production is unfinished, and it can be built without buyers to fill it. Success depends on production, transport, financing and European demand all being developed together.

13. Europe’s demand is not guaranteed

The weakest link may be the market. Europe has set ambitious goals, created the European Hydrogen Bank to fund production through auctions, and designated strategic infrastructure. The IEA’s Global Hydrogen Review 2026 continues to stress the need to accelerate demand creation. Support programmes are not a mature market, though. Industrial buyers must be able to absorb the cost without losing competitiveness, and many hesitate to sign long-term contracts at today’s prices.

This puts Algeria in a difficult position. It must invest in production before a large export market exists, while buyers want proof of reliable and competitive supply before they commit. A physical corridor can help with part of that, but infrastructure alone cannot create demand.

14. What Algeria should do

The strongest strategy combines caution with ambition.

1. Keep gas as the anchor. Existing gas exports to Italy and Spain are the source of cash and credibility while hydrogen matures. There is spare pipeline capacity, and a figure of about 22 bcm is often quoted (verify).
2. Demand binding offtake. Production should be built against 15–20 year take-or-pay agreements with European buyers, ideally backed by auctions or price-stabilising mechanisms such as H2Global. Algeria should not build plants on speculation.
3. Build the green electricity first. Large-scale solar, wind and storage and a stronger grid are prerequisites. They also benefit Algeria’s own economy, whatever happens to hydrogen exports.
4. Pilot before scaling. The 2027 feasibility results should lead to projects of hundreds of megawatts, not a leap to tens of gigawatts.
5. Anchor domestic industry. Hydrogen needs a local customer. Ammonia is the clearest case: about 0.18 tonnes of hydrogen make a tonne of ammonia, so 4 Mt could support roughly 22 million tonnes of ammonia a year. Algeria already has fertiliser experience, and lower-carbon ammonia could serve agriculture and export markets. Direct-reduced iron and steel, built around Algeria’s iron ore in the south, is the second pillar. Steelmaking needs about 50–55 kg of hydrogen per tonne of DRI steel, so the volumes are significant.
6. Hold the value chain. A corridor that only exports a molecule repeats the hydrocarbon model. Domestic manufacturing, engineering services, research and training capture value that a simple supply contract does not.
7. Plan the water. Siting near desalination, brine management and clear environmental standards should be part of every project from day one.

15. The bridge, or the mirage?

Both stories are partly true. The sceptics are right that physics, cost and demand are the real tests. Hydrogen from the Sahara will not be cheap by default, and the 4 Mt headline is a capacity ambition rather than a market. The optimists are right that Algeria has real assets: abundant sunshine, a pipeline network, experienced national energy companies, and a long relationship with European buyers.

The final answer depends on what Algeria chooses to become at the end of the process. It can remain mainly an energy exporter and change the molecule it ships from natural gas to hydrogen. Or it can use hydrogen to build an industrial base that combines renewable electricity, chemicals, metallurgy, engineering and transport. The first option creates another export channel. The second could reshape the country’s economy.

The bridge is only worth building if it carries more than hydrogen. It has to carry investment, technology and the foundations of a new industry, and Algeria’s leverage in securing that is greatest before the pipes are laid.

---

.

sources : IEA Global Hydrogen Review (2025 and 2026), UNIDO SoutH₂ materials, Germany’s 2024 Hydrogen Import Strategy, the June 2026 Applied Energy study, and CBAM regulation texts.