Nigeria expects to launch its 2026 upstream licensing round in October, Nigerian Upstream Petroleum Regulatory Commission (NUPRC) chief executive Oritsemeyiwa Eyesan told the Gastech conference in Bangkok on September 15.

The planned launch, less than three months after the regulator selected winning bidders for 37 blocks in its previous auction, is part of a broader attempt to make licensing more regular after years of sporadic access to new acreage.

Eyesan has said NUPRC intends to hold at least one licensing round a year and, where possible, two. In an interview with S&P Global published on September 4, she said future rounds should take six or seven months and that the production target for successive auctions would be 300,000-600,000 barrels per day (bpd). Those figures are regulator targets rather than assured output.

An October launch would come slightly later than NUPRC indicated in June, when Eyesan said the 2026 exercise would begin no later than the third quarter. Before the Petroleum Industry Act was enacted in 2021, Nigeria could go five to 10 years between licensing rounds, according to S&P Global. Seven blocks were offered in the 2022-23 mini-round, 19 in 2024 and 50 in 2025.

Greater regularity should give explorers more visibility over when acreage will become available and allow Abuja to use licensing more systematically as part of its effort to raise production after years of underinvestment, operational disruption and declining output from mature assets.

Nigeria produced 1.50mn bpd of crude in August, excluding condensate, meeting its OPEC quota for a fourth consecutive month, according to NUPRC. Including condensate, production averaged about 1.68mn bpd, still well below the regulator’s ambition of reaching 3mn bpd by 2030.

Bid numbers do not equal investment

The 2025 round illustrates the distinction. NUPRC received 200 bids from 143 companies covering 37 of the 50 blocks on offer. Thirty-one companies emerged as winning bidders for those assets, while 13 blocks attracted no bids. The announcement of a winning bidder does not itself constitute the final grant of a licence, which remains subject to post-bid conditions.

Participation was substantial, but it provides only a partial indication of the capital likely to follow.

Eyesan told S&P Global that some acreage in the previous exercise had been brought to market prematurely and said future rounds would put greater emphasis on commercially viable assets. The 13 blocks that drew no bids are expected to return in the 2026 round alongside new deepwater and shallow-water acreage and, potentially, frontier onshore basins.

The regulator is also reassessing the companies bidding for licences. During discussions with Nigeria’s Independent Corrupt Practices and Other Related Offences Commission this month, Eyesan said NUPRC was reviewing qualification criteria after problems involving some indigenous operators that lacked the financial or technical capacity to develop awarded assets, as well as ownership disputes that had delayed projects.

For Nigeria, the policy tension is straightforward. A broader domestic ownership base may support local participation in the industry, but production gains depend on whether licence holders can finance exploration and development.

The 2025 rules already contain financial-capability thresholds and bid guarantees. Applicants must demonstrate specified financial resources or parent-company support, with higher thresholds for deepwater acreage. Successful bidders face further guarantees, signature bonuses, rent payments, and contractual requirements before NUPRC can grant a Petroleum Prospecting Licence.

NUPRC is also invoking Section 94 of the Petroleum Industry Act, the so-called “drill or drop” provision, to limit the warehousing of undeveloped acreage. Eyesan said in March that operators failing to meet work obligations risked losing undeveloped licences.

The October round will offer an early indication of how much more selective the regulator is prepared to become while maintaining the faster pace of licensing.

Local ownership rises as majors focus offshore

The issue has become more important as the ownership of Nigerian upstream assets changes.

Shell (LSE: SHEL; NYSE: SHEL; AMS: SHELL) completed the sale of its Nigerian onshore subsidiary to the Renaissance consortium in March 2025. Seplat Energy (NGX: SEPLAT; LSE: SEPL) completed its acquisition of ExxonMobil’s (NYSE: XOM) Nigerian shallow-water business in December 2024 after receiving regulatory approval.

Those transactions have increased Nigerian ownership of mature onshore and shallow-water production. Reuters reported in June 2025 that local companies had raised their share of national oil output to more than half, from about 40% previously.

International majors remain active, but much of their new capital is being directed towards large offshore developments.

In July, ExxonMobil and its partners announced a $1bn investment in the Usan Infill Project. NUPRC said the development was expected to add about 40,000 bpd and marked the ExxonMobil affiliate’s planned return to drilling after a decade-long hiatus.

Nigeria has also sought to improve the economics of deepwater projects. In August, the presidency announced a Deep Offshore Oil and Gas Projects Incentives framework that it said could support as much as $50bn of investment across qualifying developments. The figure is a government estimate of potential investment rather than committed capital. Shell’s proposed Bonga South West development was identified as an early beneficiary.

The 2025 licensing round itself contained only one deep-offshore block. Chevron (NYSE: CVX), through its affiliate Star Deep Water Petroleum, emerged as the winning bidder for PPL 2010, although NUPRC has stressed that winning-bidder status is not equivalent to the final grant of a licence.

A successful bid can still be followed by years of appraisal, engineering, financing and internal capital allocation before first production.

Gas faces similar commercial constraints

Nigeria’s gas sector presents much the same problem in a different form.

NUPRC puts the country’s proved-plus-probable gas reserves at 215.19 trillion cubic feet as of January 1. At Gastech, Eyesan said Nigeria was producing about 8bn cubic feet per day (bcfd), equivalent to roughly 227mn cubic metres per day.

She argued that substantially higher production could allow Nigeria to supply a larger share of African demand, while also identifying investment, infrastructure and domestic gas pricing as constraints on development.

The scale of Nigeria’s reserves does not, by itself, determine the pace at which they can be commercialised. Gas projects require processing and transport infrastructure, customers able to sign bankable contracts and prices capable of supporting capital-intensive developments.

A changing domestic market is adding to the pressure on upstream supply.

The 700,000-bpd Dangote refinery has secured at least 16mn barrels of Nigerian crude for October delivery, equivalent to roughly 520,000 bpd over the month, according to Reuters.

For producers, the refinery provides a large domestic buyer that did not exist at anything close to its present scale only a few years ago. For Nigeria, it also creates a new allocation problem: unless upstream production rises alongside refinery throughput, greater domestic crude demand can reduce the volume available for export.

From winning bids to producing barrels

NUPRC has itself set a more demanding measure of success than the number of blocks auctioned.

At July’s commercial bid conference, Eyesan said the 2025 exercise should ultimately be judged by how quickly acreage progresses through seismic work, drilling and development into production. The regulator also stressed that the announcement of winning bidders did not amount to the final grant of a prospecting licence.

Annual auctions can reduce uncertainty over when acreage will become available, while tougher qualification rules may improve the chances that successful bidders have the resources to develop it. Fiscal incentives can also improve project economics, particularly offshore.

But the evidence that matters will come later: whether winning bidders meet their conditions, whether financing is secured and development plans are funded, and whether drilling translates into sustained additions to oil and gas output.