Algeria and Morocco are racing to build rival gas corridors anchored by Nigerian gas — two very different routes pitched to connect West African reserves with European buyers. Both pipelines are designed to carry up to 30 bcm of gas a year, but neither project has secured enough gas to fill itself, let alone both at once. Nigeria’s marketable output can’t support two 30 bcm pipelines running at capacity, Europe’s gas demand is falling rather than rising, and neither corridor has a European buyer locked in.

Project specs: Algeria’s roughly 4.1k km USD 13 bn Trans-Saharan Gas Pipeline (TSGP) would run north from Nigeria through Niger before joining Algeria’s gas network, which includes an operational export system that already spans pipelines, LNG plants, and established European buyers. Morocco’s 6.8k km USD 26 bn African Atlantic Gas Pipeline (AAGP) would stretch along the West African coast before connecting with Morocco, where the government is assembling an interconnected gas market almost from scratch, betting that domestic and regional demand can make individual sections useful before the full corridor exists.

IN CONTEXT- Both pipelines are bids for influence in neighboring Sahel, and can be read as part of a growing (but longstanding) Algeria-Morocco geopolitical rivalry. The two neighbors’ land crossings have been shut down since the 1990s, and diplomatic ties were severed in 2021 after the pair exchanged accusations supporting separatist groups. The latest breakdown in ties saw Algiers cut off the Maghreb-Europe line that once carried its gas across Morocco into Spain in 2021.

Algeria broke ground first — but only on its own side of the border

State-owned Sonatrach officially launched construction of the Algerian section of the TSGP. The line would follow the Trans-Saharan Road from the Niger border to Hassi R'Mel, connecting with Algeria’s national transmission network and existing export infrastructure. Sonatrach did not disclose the cost of the section now under construction, the contractor, a completion date, or a financing structure — and there are no publicly announced Nigerian

The missing piece is Niger. Physical work has not begun on Niger’s roughly 840 km section, UAE-based commodity analyst Natalia Katona tells EnterpriseAM, and its financing and construction arrangements remain unclear, despite speculations that Algeria plans to lead the financing itself. The route also crosses territory exposed to militant violence, while relations between Algeria and Niger only recently began recovering from the tension that followed Niger's 2023 coup.

That limits what Algeria’s construction launch actually proves. The Algerian section could stand on its own by connecting planned southwestern fields — including developments in the Ahnet Basin — to the country's northern gas and export network, Katona argues. As a corridor to Europe, though, it could still be a dead-end at the Nigerien border unless Niger and Nigeria complete their own connections.

Claims that the TSGP is already 60-70% complete need unpacking, too. Those estimates generally count existing domestic pipelines in Algeria and Nigeria that could eventually be incorporated into the corridor — not that most of the dedicated TSGP pipeline has already been laid.

Morocco secured the framework — not the money

Morocco’s AAGP is a bit behind: The pipeline’s latest milestone was when Ecowas leaders signed an intergovernmental agreement, creating a common institutional framework for a pipeline crossing multiple jurisdictions. The line would pass through or connect 13 West African states, Mauritania, and Morocco, with additional links proposed for landlocked Sahel markets — each one adding its own permitting, regulation, tariffs, currency exposure, and political risk.

Getting governments to sign a framework is one thing. Getting lenders to finance construction across it is another. Morocco is now courting the US Export-Import Bank and the World Bank; neither has committed funding, and no financing package approaching the project’s estimated cost has been announced.

The pipeline is meant to be built in stages, not as one continuous line. Construction is slated to begin in 2028, with first gas targeted for 2031 pending financing, while the full corridor may not be finished until the 2040s. A proposed initial phase could connect offshore gas fields from Mauritania and Senegal to Morocco before the Nigerian section is built — insulating the northern end from delays further south.

Phasing makes the concept smarter, but it doesn’t change the underlying commercial risk, Blue Water Strategy Senior Advisor Cyril Widdershoven tells EnterpriseAM. Individual sections only make economic sense if they have their own gas supply and paying customers, he argues — the phased model is commercially smarter than building one giant pipeline in a single step, but every phase still has to prove it can generate cashflow independently.

The bigger risk: The AAGP may never become the transcontinental pipeline it’s being sold as. Delays to the northern connection could leave the southern West African section operating permanently as a regional pipeline rather than a stage of a Nigeria-to-Europe corridor, Nigeria-based energy economist Kashema Bahago tells EnterpriseAM. “That's not necessarily bad, but it's a different investment thesis than the one the pipeline is currently being sold on,” Bahago says.

The AAGP’s proposed 30 bcm capacity, for instance, isn’t 30 bcm of Nigerian gas earmarked for Europe — Morocco’s National Office of Hydrocarbons and Mines‏ (ONHYM) expects roughly 15 bcm to supply Morocco domestically, with the rest continuing toward export, though it hasn’t explained how withdrawals by other countries along the route fit into that allocation.

Algeria has more ways to sell the gas, if it shows up

If Nigerian gas reaches Algeria, there are several ways to monetize it: The country exports gas to Italy through the roughly 33.5 bcm TransMed pipeline and to Spain through the approximately 10 bcm Medgaz line. Sonatrach also operates liquefaction plants with combined installed capacity of some 56 mn cubic meters of LNG annually (c.34 bcm of nat gas), of which at least half is not utilized, allowing gas to be sold beyond fixed pipeline destinations. That existing infrastructure makes Algeria the obvious incumbent. A Nigerian molecule could theoretically be delivered through a pipeline, shipped as LNG, or blended into the domestic network.

But nameplate capacity is not the same as spare capacity. Algeria’s export pipelines already carry Algerian gas, while several of its LNG trains are decades old. Domestic consumption is rising on industrial diversification, and mature fields require continued investment to maintain production. “Algeria therefore does not have another 30 bcm per year of uncommitted gas to fill TSGP itself,” Katona says. The TSGP may end up serving a defensive purpose as much as an expansionary one — using Nigerian feedgas to keep existing pipelines and liquefaction plants utilized as domestic demand absorbs local production. But it still depends on gas crossing Niger and on whether Sonatrach operates the line as a third-party tolling line, buys gas and resells it, or uses a hybrid structure.

Morocco starts from a very different position: It produces small volumes of gas — not enough to anchor a regional system — and it has no operating liquefaction or domestic regasification terminals. Since 2022, Morocco has bought LNG on international markets, unloaded it at Spanish terminals and transported the regasified gas through the reversed Maghreb-Europe Gas Pipeline, which previously carried Algerian gas through Morocco into Spain before Algiers halted supplies in 2021 amid deteriorating relations between the two. That gives Morocco an operating cross-border connection but not yet a northbound export business. Carrying AAGP gas into Spain would require reversing commercial flows again.

The supply problem

Nigeria holds Africa’s largest proven gas reserves — but its bottleneck is processing, transporting, and selling it. Gross Nigerian gas production reached some 7.93 bcf/d in May. A single 30 bcm-a-year pipeline would require approximately 2.9 bcf/d at full capacity — equivalent to some 37% of gross production. If Nigeria is required to fill both pipelines at their nameplate capacity, they would need about 5.8 bcf/d, or more than 70% of present output.

That constraint tightens further when raw production is separated from gas that can actually be sold: Nigeria’s marketable output sits at around 4.5-5.5 bcf/d, after accounting for gas reinjected into oilfields, flared, or otherwise unavailable because of inadequate gathering infrastructure, Bahago tells us. “Under current production realities, Nigeria cannot realistically supply both pipelines at full capacity without a massive scale-up in marketable production,” Bahago says.

Not all production is available for new exports. In May, some 3.07 bcf/d was sold into export markets and another 2.18 bcf/d domestically, with the remainder used in field operations, reinjected, lost during processing, or flared. Future production also faces competing claims from LNG, the West African Gas Pipeline, domestic power generators, and energy-intensive industries.

Nigeria’s Gas Master Plan targets production of 10 bcf/d by 2027 and 12 bcf/d by 2030. It identifies both pipelines among the export corridors that future Nigerian production could support and maps upstream hubs intended to deliver that growth. Those targets depend on new wells, processing facilities, and gathering pipelines being financed and completed on time.

The result is that both pipelines need more than Nigerian reserves: They need upstream projects capable of producing dedicated, pipeline-quality gas under contracts that can survive domestic pressure and compete with Nigeria’s LNG pricing. Supplying one 30 bcm pipeline is going to be very challenging during the next decade, while supplying two simultaneously is currently unrealistic, so no option is in place for both, Widdershoven tells us. “When looking at financials, this situation is probably the single biggest commercial weakness of both proposals,” he says.

The buyer problem

Both pipelines are being built for a European market that’s shrinking, not growing. The Institute for Energy Economics and Financial Analysis estimates that falling consumption could reduce combined EU pipeline-gas and LNG imports by 25% between 2024 and 2030. The International Energy Agency’s base case is less severe, forecasting an 8% decline in European gas demand between the same period. The EU is phasing out Russian gas and declining domestic production could create space for replacement suppliers even as total demand falls. But Nigerian pipeline gas would enter a crowded market, competing against Azerbaijani gas, imports from Qatari, Emirati, and US LNG, alongside existing Algerian supply and Nigeria’s own LNG exports.

LNG allows European buyers to diversify supply without committing to a cross-border pipeline for decades. Financing either African corridor would typically require long-term supply agreements, transferring much of the volume risk to buyers at a time when European utilities face pressure to reduce fossil-fuel exposure. Neither project has publicly identified a European anchor buyer, disclosed an offtake contract, or otherwise shown that its delivered gas cost can compete with the next wave of LNG supply.

African buyers to the rescue? Ironically, the best customers for these pipelines may no longer be Europe. “Regional African power producers, industrial users and fertilizer plants may ultimately provide more reliable long-term demand than European utilities, " Widdershoven argues, adding that “the original business case, which was large-scale Nigerian exports to Europe, is increasingly looking weaker today than it did ten years ago.”

The security differential

Both projects are exposed to Sahel security risks, but Algeria’s exposure is clearer. For the TSGP, its Niger leg runs through the territory where insecurity and militant violence “has been the main contributor to decades of delays,” Katona tells us. “The Niger segment and northern Nigeria cross active jihadist and banditry zones,” Bahago adds, describing security as the “weakest link” for the Algerian proposal.

Morocco’s project is an offshore-heavy route that avoids Sahel’s insecure inland, Bahago tells us. But this comes with a trade-off. It swaps security exposure for the more capex-intensive deepwater engineering and piracy risks at the Gulf of Guinea. “AAGP trades security risk for construction and financing risk; TSGP trades the reverse.”

But the security risk is not fatal on its own when it comes to bankability, most of the sources we spoke to agreed. Banks can price political risk, Widdershoven says, but they cannot finance a pipeline without committed suppliers and customers. “While geopolitics is playing a key role, especially right now, these two projects will still be looked at as commercial projects; only contracts will build them,” he says.

The bottomline

“Both projects still have to prove there will be enough gas and enough paying customers,” Widdershoven tells us. But what’s different about Morocco’s pitch is that it also aims to “use this project to create new regional gas markets rather than relying solely on exports to Europe,” he adds. And this is exactly why Morocco’s pitch is bolder despite a higher cost backdrop and being behind on the actual buildout.

Ultimately, the race will be determined by who will first build infrastructure capable of earning at partial capacity — because there is no trust either project will ever carry its full 30 bcm. “The infrastructure that stays useful is whatever has an alternative market or can function independently of the export leg,” Bahago says.