Algeria is producing near-record volumes of natural gas, yet its liquefaction plants are running at a fraction of capacity. The explanation says a lot about Sonatrach’s priorities, and about why the long-delayed Trans-Saharan Gas Pipeline (TSGP) suddenly matters.
Algeria’s gas story looks contradictory. Production is high and pipeline exports to Europe are running close to their limits. Yet the country’s two big LNG complexes, Arzew and Skikda, have roughly 25 million tonnes a year of installed capacity and export only about 9 to 10 million. During the first ten months of 2026, LNG exports fell by almost 12% year on year to about 7 million tonnes .
This is not simply a story about ageing hardware. It is a story about priorities, and about a gas balance that is getting tighter every year. The Trans-Saharan Gas Pipeline, which would carry Nigerian gas north through Niger to Algeria’s Hassi R’Mel hub, is best understood as an option that lets Algeria manage that squeeze, not as a rescue for idle LNG trains.
1. The gap: a balance that no longer closes
The starting point is domestic demand. Algeria consumed roughly 57 billion cubic metres (bcm) of gas at home in 2025, more than half of national output, while exports slipped to about 45.7 bcm. Power generation, petrochemicals and subsidised household use keep pushing that number up, and mature fields such as Hassi R’Mel are in slow decline.
2025 (approximate) | Volume |
|---|---|
Implied production | ~103 bcm |
Domestic consumption | ~57 bcm (about 56%) |
Gas exports (pipeline + LNG) | ~45.7 bcm |
LNG installed capacity | ~25 Mt/yr |
LNG actually exported | ~9.4 Mt/yr |
On the other side of the ledger, commitments are growing. As Europe works to phase out Russian gas, Central and Eastern European buyers are looking for new pipeline supply. Sonatrach is reported to be ramping up deliveries to Germany’s VNG and extending supply to Czech utility ČEZ from January 2027, routed north through the TransMed pipeline via Italy . Every extra cubic metre promised to those customers has to come from somewhere.
Algeria is not standing still. The $2.3 billion Hassi R’Mel Boosting Phase III project is due to complete around April 2027, new tie-ins are coming online, flare-gas recovery partnerships are underway and solar is being added to reduce the gas burned in power plants. But these measures largely offset declines and demand growth. Net new exportable gas in 2027 is likely to be only 1 to 2 bcm.
2. Why pipelines come first, and LNG gets what is left
When gas is scarce, Sonatrach does not treat every export route equally, and for good reasons:
- Predictable revenue. Long-term pipeline contracts with take-or-pay terms give stable cash flows that finance budgets and investment plans.
- Better, steadier margins. There are no liquefaction, shipping or regasification costs on top of the gas.
- Political alignment. A physical pipeline ties buyers in Italy, Spain and now Central Europe to Algeria for decades.
- Lower operational risk. LNG trains are complex, capital-intensive and prone to outages. Recent reporting attributes part of the drop in output to failures and maintenance at Arzew, where capacity expansion work is also under way.
The consequence is that LNG is the residual outlet. When a new pipeline commitment is signed and no new production appears, the gas comes out of the feed that would otherwise go to liquefaction.
The clearest evidence comes from what happens when the priority order is temporarily reversed. During maintenance on the Medgaz pipeline to Spain in September 2024, flows fell from about 28 million cubic metres a day to 13 million. Algeria responded by offering extra LNG cargoes: exports reached 700,000 tonnes in the month to September 20, up from 450,000 tonnes in August, a rise of roughly 55%. Gas that could not go through the pipe went to ships within weeks.
That episode shows two things. LNG really is the swing outlet. And the liquefaction trains can run much harder when feed gas is available, which means that feed, not just hardware, is part of the constraint.
There is also an important limit on the pipeline side. Medgaz is already operating near its nameplate capacity, and expansion talks only began in 2026, with any additional capacity years away. Incremental gas for Europe therefore tends to end up either on TransMed or in LNG.
3. The TSGP as an option
Here the pipeline’s logic becomes clear. Nigerian gas arriving at Hassi R’Mel would not have a single destination. It could:
- Flow directly into pipeline contracts, supporting the long-term deals that Sonatrach prefers.
- Feed the idle liquefaction trains, turning spare capacity at Arzew and Skikda into spot-market sales when prices are attractive.
- Cover domestic demand, freeing Algerian gas for export.
That flexibility is the real value. Algeria does not need to decide today whether the extra molecules are better sold under contract or on the spot market. It needs the ability to choose as markets, contracts and demand evolve. The same logic that ranks LNG last also makes spare LNG capacity valuable as a hedge, and the TSGP would keep that hedge funded.
The scale is significant. Idle capacity of about 15 million tonnes a year is equivalent to roughly 20 bcm of gas. A 30 bcm TSGP, the figure often cited for the project’s eventual design flow, would more than cover that.
The argument here is analytical. It describes what the numbers imply, not an explicit Sonatrach strategy, and readers should treat it as the logic of the situation rather than an official statement of intent.
4. What is actually happening on the ground
The project has moved from concept to action, at least on paper:
- June 2026: Sonatrach reportedly began work on the roughly 1,210 km Algerian section from Aoulef in Adrar toward the Niger border, self-funded .
- October 2026: Algeria’s parliament reportedly authorised the deployment of the army to help secure shared energy sites and the transit corridor in northern Niger [source needed]. Given the sensitivity of that claim, it should be sourced to an official announcement or credible news report.
- November 7, 2026: at ADIPEC in Abu Dhabi, the head of Nigeria’s state oil company is reported to have said that Nigeria, Algeria and Niger have aligned on a joint-venture structure (45% Sonatrach, 45% NNPC, 10% SONIDEP) ahead of final investment decision talks in 2027 .
- Early 2027: Niger is expected to start building its roughly 720 km section.
5. Financing: smaller than $13 billion, but not solved
The project’s original price tag was about $13 billion, and Western lenders, under climate pressure, would not fund long-distance fossil-fuel pipelines. Two things have changed.
First, the external funding need is smaller. Nigeria has built much of its domestic trunk line, and Algeria is paying for its own section. The remaining gap is concentrated in Niger’s transit corridor and compression, which this analysis estimates at roughly $3 to $5 billion [this is an estimate, so show the breakdown or cite a source for the cost of the Niger section.
Second, a new lender has arrived. The $5 billion Africa Energy Bank, established by Afreximbank and the African Petroleum Producers’ Organisation and headquartered in Abuja, is due to begin operations on January 4, 2027, after a two-year delay. It exists precisely because traditional financiers are retreating from fossil fuels.
A note of caution is needed. The $5 billion is the bank’s target size, and capital still has to be raised and paid in. A single anchor loan of $1 to $2 billion would be a very large share of that, so the realistic picture is a blended structure: the bank, Afreximbank, export-credit agencies, joint-venture equity and possibly Gulf or Asian co-lenders. The bank is a broad energy lender rather than a dedicated pipeline financier. It makes the project fundable. It does not make it funded.
6. What could go wrong
A credible case for the TSGP has to confront its weaknesses:
- Timing. The squeeze begins in 2027, but a pipeline that starts construction in Niger in 2027 will not deliver gas before the early 2030s. The project cannot solve the next three years. Upstream projects, flare-gas recovery, solar and subsidy reform have to carry Algeria until then.
- Nigeria’s supply. Nigeria needs enough spare gas for 30 bcm a year, while it has its own LNG exports and domestic shortages. The pipeline must beat the alternative of liquefying that gas at Nigerian terminals, and that comparison has to be made on cost, not assumed.
- Security. The route crosses parts of the Sahel where insurgency, politics and sabotage are persistent risks. The same transit risks that make LNG look attractive also apply to a 4,000 km pipeline.
- Reliability at home. Even with more feed gas, Arzew’s trains must run reliably. Feed gas alone will not restore LNG output if maintenance problems persist.
- Long-term demand. European gas demand is expected to fall over time, and buyers increasingly resist long, rigid contracts. Contracts signed now could look different by the mid-2030s.
The bottom line
Algeria’s idle LNG capacity is not just a technical failure. It is the visible result of a deliberate hierarchy: domestic demand first, long-term pipeline contracts second, flexible LNG last. With domestic consumption rising, production plateauing and new commitments to Central Europe on the way, that hierarchy leaves little gas for the ships.
The Trans-Saharan Gas Pipeline matters because it can change that arithmetic. Nigerian gas at Hassi R’Mel would give Algeria a choice: lock in more long-term pipeline business, switch the idle trains back on when the spot market pays, or ease the domestic squeeze. The case is not that the TSGP is cheap, quick or risk-free, because it is none of those. The case is that, in a tightening gas balance, an option on external supply is worth more than the cost of keeping it open.
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