Seismic data companies have sunk more than $100 million into Nigeria since the Petroleum Industry Act took force in 2021, the Nigeria Upstream Petroleum Regulatory Commission (NUPRC, the country's upstream oil regulator) reports. The money funds subsurface mapping (imaging of rock layers beneath the seabed and land) to assess basin potential and prepare fresh exploration campaigns. What the figure does not reveal is how much of that spend has converted into discovered, commercially recoverable reserves.

The disclosure came alongside a familiar pledge: Nigeria plans to more than double its oil and gas reserves by intensifying exploration, particularly in deepwater areas and underexplored basins. Minister of State for Petroleum Resources Heineken Lokpobiri outlined the ambition on Tuesday, November 10, at the 44th Annual Conference of the Nigerian Association of Petroleum Explorationists (NAPE) in Lagos. No timeline accompanied the doubling target.

What has actually been approved?

The regulator's own numbers, announced on November 10, are concrete, even if approvals are not the same as barrels:

• 145 new drilling operations approved since the beginning of 2026
• 595 well re-entry operations (reopening existing wells for further production or assessment)
• 39 field development plans signed off
• 46 drilling rigs currently active

The commission also reports more than $57 billion worth of field development plans approved since 2024, with some projects already past final investment decision (FID, the point at which an operator commits capital). The NUPRC has not broken down how much of that $57 billion is under construction versus still on paper.

Where is the money going?

Nigeria has introduced fiscal and regulatory reforms designed to pull international oil companies toward capital-intensive offshore developments. In March 2024, President Bola Tinubu announced measures to improve investment conditions in the oil and gas sector. He followed with a new fiscal incentive framework for deepwater offshore projects in August 2026.

Shell's Bonga South West project illustrates the strategy. The Nigerian presidency pegs the offshore development's cost at roughly $10 billion. In August 2026, NNPC Ltd and its partners in oil mining lease OML 118 (the licence block containing the Bonga fields) signed contractual amendments to advance the scheme. The government says the project could attract between $15 billion and $21 billion in investment over its lifetime — an estimate, not a committed figure.

The broader projection is larger still. The NUPRC estimates operators could initiate 22 major offshore projects between 2026 and 2030, representing potential investment of $30 billion to $50 billion. In October 2026, the state launched another licensing round covering 40 blocks across onshore, shallow-water and deepwater areas. Whether those blocks attract bids at scale depends on terms the regulator has yet to publish in full.

What does the majors' exit change?

The offshore push coincides with a structural shift on land. Several international oil majors have sold portions of their onshore assets to Nigerian companies, expanding the domestic operators' share of production:

• Shell transferred its subsidiary Shell Petroleum Development Company (SPDC) to the Renaissance consortium in March 2025
• Eni sold Nigerian Agip Oil Company (NAOC) to Oando in August 2024
• ExxonMobil completed the sale of its onshore and shallow-water assets to Seplat Energy in 2024 for approximately $1.28 billion

These transactions have increased the role of Nigerian producers in the upstream industry. Shell and Eni, for their part, have retained interests primarily in natural gas and capital-intensive deepwater offshore operations.

What does this change for investors? On paper, plenty: more than $100 million in seismic groundwork, 46 active rigs and a pipeline of incentives spanning to 2030. In practice, the gap between approved plans and sanctioned, funded projects remains the number to watch — and it is the one the official announcements do not quantify.