In April 2026, Senegal’s energy minister visited Nigeria for bilateral talks on strengthening energy ties. The meeting came as both countries are simultaneously scaling gas production, expanding refining capacity and positioning themselves for regional electricity exports. At the same time, the West African Power Pool is preparing for permanent grid synchronization across 15 countries by mid-2026, after a successful four-hour test in November 2025. The convergence of these developments points to a structural shift that has been discussed for decades but never materialised: the emergence of a functioning West African energy market. The question is whether this time the infrastructure, the gas volumes and the political alignment are sufficient to move beyond bilateral arrangements into something closer to an integrated regional system.
The starting point is the scale of the gap. Cross-border electricity trade in the ECOWAS zone stood at approximately 8.5% of total production in 2018, according to Global Energy Monitor data. More recent estimates place the figure in the 10 to 15% range, depending on which bilateral flows are counted and how transit arrangements are classified. By comparison, the Southern African Power Pool operates with substantially higher levels of grid interconnection and transparent market trading. West Africa has the generation capacity, the demand and the geographic density to sustain much higher trade volumes. What it lacks is the transmission infrastructure, the commercial frameworks and the payment discipline to support them.
Nigeria is the largest generation market in the region. Its installed capacity exceeds 13,000 MW, though actual output consistently falls well short of that figure due to transmission constraints, gas supply interruptions and grid instability. The national grid collapsed twice in January 2026 alone, following a December 2025 outage. These are not one-off events. They reflect structural fragility in the 330 kV transmission system. Despite this, Nigeria currently allocates 600 MW for bilateral power trade agreements with Benin, Togo and Niger, and projects $1 billion in annual export revenue from mid-2026 if permanent synchronization holds. The economic logic is straightforward: Nigeria’s domestic tariff is among the lowest in the region, while neighbouring countries pay significantly more per kilowatt-hour. Exporting at regional prices generates revenue that the domestic market, with its below-cost tariffs and collection challenges, does not.
But the payment record complicates the picture. In Q2 2025, Nigeria’s Market Operator invoiced $17.54 million to international bilateral customers, of which only $9.01 million was remitted, a payment performance of 51.33%. Total outstanding obligations, including carried arrears, reached $17.8 million. International customers paid less than half of their invoiced amounts. This gap is widening concerns among Nigerian generation companies about cash flow exposure from cross-border sales. Without stricter commercial terms, security deposits or sovereign guarantees, expanding electricity trade risks deepening financial stress across the power value chain rather than relieving it.
Senegal’s trajectory is different in structure but converging in direction. The country began producing oil from the Sangomar field in mid-2024, with output stabilising at around 100,000 barrels per day and 36.1 million barrels generated in 2025. The Greater Tortue Ahmeyim LNG project, shared with Mauritania, exported 24 LNG cargoes between February 2025 and February 2026, alongside 1.6 million barrels of condensate. Prime Minister Sonko has announced plans to end natural gas imports by 2026, targeting annual budget savings of CFA 140 billion ($227 million). The government’s gas-to-power plan envisions natural gas accounting for three-quarters of installed capacity, supported by the refurbishment of the 335 MW Bel Air plant and construction of a new 366 MW facility.
The next stage is Yakaar-Teranga, an offshore gas resource estimated at approximately 25 trillion cubic feet, discovered by Kosmos Energy a decade ago. BP held a 60% operating stake but exited in 2023 over a fundamental disagreement: BP wanted LNG exports, the Senegalese government insisted on domestic gas supply as the primary use case. Kosmos’ contract expires in July 2026, at which point Senegal will likely become the sole shareholder. Petrosen’s CEO has indicated the first phase would require approximately $2.5 billion to produce 300 million cubic feet per day for the domestic market, with a second phase of roughly $5 billion for downstream development including fertiliser, petrochemical, steel and cement production. Total development cost: $7.5 billion. Financing options being explored include regional bond markets, development finance institutions and diaspora-linked capital, with 15 to 20-year offtake contracts providing the project debt foundation.
The Senegal-Nigeria alignment is not a formal gas trade agreement. It is a mutual recognition that both countries are entering a phase where gas volumes, refining capacity and regional electricity ambitions intersect. Nigeria’s 2026 gas master plan targets an additional 1.8 billion cubic feet per day of supply, part of broader ambitions to reach 10 bcf/d by 2027 and 12 bcf/d by 2030. Nigeria is also accelerating mini-LNG and small-scale liquefaction for off-grid industry, transport and distributed power. The Dangote Refinery, at 650,000 barrels per day, is exploring expansion to 1.4 million bpd. In December 2025, Nigeria issued Permits to Access Flare Gas to 28 awardees, expected to unlock $2 billion in gas investments. On the Senegalese side, Petrosen has launched a $100 million onshore exploration campaign targeting new crude discoveries by late 2026.
The transmission layer is where the regional dimension becomes concrete. The WAPP synchronization test of November 2025, conducted between 05:04 and 09:04 am, connected the Nigerian grid with the interconnected systems of all 14 other ECOWAS member states. Power flowed at a single stable frequency for four uninterrupted hours. WAPP’s Secretary General has stated the target is permanent synchronization of all 15 countries by end of June 2026. The Nigerian Independent System Operator was formally admitted to WAPP in January 2026. A 48-hour follow-up test is planned.
If permanent synchronization holds, the market structure changes. A unified regional electricity market allows real-time energy exchanges, optimises resource use across seasonal and daily cycles, and enables generation assets in one country to serve demand in another without the bilateral contract-by-contract approach that currently governs trade. For gas-fired power in particular, this means a Senegalese gas-to-power plant or a Nigerian generation facility could participate in a regional dispatch order, selling surplus output across borders at market-clearing prices.
The obstacles, however, are not primarily technical. The November test proved the technical feasibility. The obstacles are institutional and financial. National transmission infrastructure remains insufficient to support large-volume cross-border flows. Regulatory frameworks for private sector participation in cross-border grid projects are limited. Payment risk from international offtakers remains unresolved. Ghana’s April 2026 suspension of electricity exports after the Akosombo fire demonstrated how quickly a national grid crisis can cascade into regional supply disruption. Weak national grids cannot be the foundation of a strong regional market.
The gas dimension adds a further layer of complexity. West Africa’s gas producers export the majority of their LNG to Asia and Europe. In 2024, sub-Saharan LNG volumes reached 26.9 million tonnes, with 60% going to Asia and 25% to Europe. Domestic market obligations exist in Nigeria, Senegal-Mauritania, Angola and Cameroon, but regional gas trade within West Africa remains minimal. There is no equivalent of the Lobito Corridor for gas. No regional pipeline connects Senegal’s gas basins to Ghana’s thermal fleet or Nigeria’s industrial demand centres across the broader ECOWAS zone. The West African Gas Pipeline, linking Nigeria to Benin, Togo and Ghana, remains the only operational cross-border gas infrastructure in the region, and its utilisation has been constrained by supply and commercial disputes for much of its operational life.
The structural question is whether the current convergence of gas production ramp-ups, grid synchronization progress and bilateral political alignment is sufficient to shift the regional energy market from its current 10-15% trade penetration toward something materially higher. The gas volumes are arriving. The grid synchronization is technically proven. The political will, at least at the ministerial level, is expressed. What is missing is the midstream infrastructure, the payment architecture and the regulatory harmonisation required to convert bilateral relationships into a functioning market. Every previous cycle of West African energy integration promises has stalled at this same point. The difference now is that both Senegal and Nigeria have production assets coming online that need markets, and the cost of not integrating is becoming measurable in lost revenue and persistent energy poverty across the region.