By GSR Research Desk | November 9, 2026
Algeria has some of the largest gas resources in Africa, direct pipelines to Europe and a fast-moving investment programme. Yet its export margin is a question of arithmetic: how much gas the old fields can still deliver, how much the home market takes, and what is left for Europe. This is the full picture, with confirmed facts separated from ambitions.
1. Resource is not the problem, supply is
Algeria is not running out of gas. The Sahara holds major basins, including Hassi R’Mel, Berkine and Illizi, and the country already has pipelines to Italy and Spain and LNG plants at Arzew and Skikda. Few producers have all of that.
The issue is time. The most productive fields have produced for decades, domestic demand keeps absorbing a larger share, and new fields need technology and capital. The question for the next decade is whether Sonatrach can turn geology into extra molecules reaching the pipeline and the export terminals.
2. Hassi R’Mel: investing to hold the line
Hassi R’Mel is the backbone of the gas system, and its challenge is declining pressure. Sonatrach’s response is a $2.3 billion programme: three compression stations, 20 turbo-compressor trains, upgraded gathering networks and condensate treatment. It is run by a consortium of Italy’s Tecnimont and Baker Hughes, awarded in May 2024 and launched that December. The goal is to maintain output at 188 million cubic metres a day and recover an extra 121 bcm of gas, 7 million tonnes of condensate and 3 million tonnes of LPG over the field’s life. The first station was due in October 2026, the next in January 2027 and the third in April 2027. theenergyyearbedigest
This is an investment in preserving an existing asset, not a new discovery. A large part of upstream spending has to offset natural decline before it adds growth. The claim that the compressors instantly release a fixed 5–10 bcm in 2027 is not supported by the published project description, so any near-term volume gain should be presented as an estimate.
3. The domestic competitor
Gas fuels almost all of Algeria’s electricity, household heating and cooking, and much industrial activity, including fertilizers and petrochemicals. That creates a direct trade-off. Every cubic metre burned for power or used by new industries is one that cannot be sold abroad.
The balance depends on definitions, so it needs care. Gross production includes gas reinjected to maintain pressure, gas flared and gas lost in processing. Marketed gas is what remains. Domestic demand includes power, households and industry. A clean statement of the export margin should be: marketed production, minus total domestic demand, minus long-term pipeline commitments, equals what is available for LNG. Public numbers often mix these categories, which is why they produce contradictory conclusions.
The practical levers are efficiency and substitution: cutting flaring, improving power-plant efficiency, using more solar for electricity and managing industrial gas use. For Algeria, energy efficiency is partly an export strategy.
4. Two export systems with different roles
Pipelines to Italy (TransMed) and Spain (Medgaz) carry most exports under long-term contracts. They offer predictable revenue and political alignment. LNG at Arzew and Skikda is more flexible but more expensive and often underused. It tends to receive whatever is left after domestic demand and pipeline contracts. That is why the LNG plants are the natural “residual” and why they are sometimes described as running well below capacity.
5. A changed European market
Europe’s demand for non-Russian gas is legally anchored. Regulation (EU) 2026/261, adopted in January 2026, sets a stepwise ban on Russian pipeline gas and LNG: short-term LNG contracts were banned from 25 April 2026, long-term LNG ends from 1 January 2027, and the remaining long-term pipeline contracts end by 30 September 2027. Russia’s share had already fallen sharply, but the remaining volumes still need replacing. onlinebrusselstimes
Asia and the Gulf add another layer. The 2026 Persian Gulf conflict closed the Strait of Hormuz from March, disrupting LNG and fertilizers and raising the value of supply from outside the Gulf. Conditions have since eased, so Algeria should not plan on a permanent crisis premium. What the shocks did show is that buyers will pay for diversified, short-haul supply, and Algeria’s position in the Mediterranean is a durable advantage.
6. Money and partners
Sonatrach’s investment priorities put exploration and production at the centre. In October 2025 the energy minister described a $60 billion five-year plan focused on upstream. Later official figures have cited larger totals, such as about $71.6 billion to 2030 with roughly $52 billion upstream; these probably reflect different scopes and should be quoted with their source.
The government is also widening participation through licensing rounds, with the 2026 round offering seven exploration areas and drawing interest from dozens of companies, according to ministry statements. Partners already include Eni, Repsol, Sinopec, Pertamina and Occidental. The model is pragmatic: Sonatrach stays central, while foreign firms bring capital, drilling expertise and technology. Contracts signed are not production, though. The test is how many exploration blocks turn into producing fields.
7. Illizi South: a template for foreign capital
The Midad Energy partnership shows how Algeria wants to finance the next generation of fields. The contract is a 30-year production-sharing agreement, extendable by 10 years, with a seven-year exploration phase. Midad pays all of the roughly $5.4 billion, including $288 million for exploration. The block lies about 100 km south of In Amenas, close to existing infrastructure, which cuts the cost of getting gas to market.
The contract projects 993 million barrels of oil equivalent over its life, including 125 bcm of marketable gas and 204 million barrels of liquids. Published development plans point to a first target of about 8 million cubic metres a day, rising toward 20 million, which would be about 7.3 bcm a year at plateau. That is a peak, since 125 bcm spread over the contract implies a lower average. A first-production target of late 2028 should be treated as ambitious, given the exploration phase.
8. Shale: a large option, not a supply
The headline number for unconventional gas has long been very large, often above 700 trillion cubic feet. A more precise reference is the USGS assessment published in April 2026: a mean of 80.1 trillion cubic feet of undiscovered, technically recoverable shale gas in the Grand Erg/Ahnet Basin Province, about 2.27 trillion cubic metres. That is a resource estimate for one province. It is not a reserve and not a production forecast.
ExxonMobil and Chevron have been in talks with Sonatrach about unconventional work, but the American model cannot simply be copied. Shale needs large numbers of wells, reliable water and disposal, infrastructure and a stable fiscal framework. Water is the hardest constraint in the arid south and part of both the economics and public acceptance. The realistic sequence is appraisal and pilot projects first, then scale, over years.
9. The Trans-Saharan Gas Pipeline: what it is, and what it is not
The TSGP would bring Nigerian gas through Niger into Algeria’s network. Construction on the Algerian segment started on 4 June 2026 at Aoulef, with Nigerian and Nigerien ministers present. The design capacity is 30 bcm a year, the full route is about 4,128 km, and cost estimates are around $13 billion. The Algerian section is reported at 1,210 km. Niger’s segment is only due to begin in early 2027.
For Algeria the pipeline has three possible roles. It could carry Nigerian gas to Europe through existing export infrastructure. It could also collect domestic gas from new fields such as Ahnet, as officials have said. And it could give Algeria a transit and trading position, with revenue from transport and infrastructure use.
One distinction matters for the supply picture. Importing gas for transit does not raise Algeria’s own production. Its value is in tolls, better use of infrastructure and relationships with Nigeria and Niger. Using Nigerian gas to refill idle LNG plants is a plausible strategy, but it is a later-stage option that depends on Nigerian supply, security, finance and the Niger section, not an assured source for 2030.
10. Three horizons
Near term (2026–2028): stabilise output at mature fields, commission the Hassi R’Mel compression stations, capture associated gas and complete delayed developments.
Medium term (2028–2032): projects such as Illizi South and blocks awarded in licensing rounds could add real volumes, and the TSGP may begin to move gas if the Niger and Nigerian segments are delivered.
Long term (2030s): shale could become a second resource base if pilots show commercial economics, water solutions and acceptable environmental performance.
11. Verdict
Algeria has what most producers would envy: resources, infrastructure and a nearby buyer. What it needs now is a new generation of productive fields, a more efficient domestic energy system and a stable investment framework. The risk is not a lack of gas in the ground. It is that decline at old fields and growth in domestic demand narrow the export margin before new supply arrives.
The best measure of success will not be trillions of cubic feet in geological assessments or billions of dollars in announcements. It will be the additional molecules that reach the pipelines, the industrial plants and the export terminals, year after year.
0 Comments