By David Whitehouse


Nigeria will need to convince investors that regulatory and security improvements can be sustained as its licensing round faces keen international competition.


The country in January opened a licensing round for 50 onshore and offshore oil and gas blocks, 35 of which are in the Niger Delta. Parties can bid for a maximum of two blocks. Signature bonuses have been reduced to between $3m and $7m, versus $10m in 2024. The round will “reposition Nigeria’s upstream sector for serious business”, Oritsemeyiwa Eyesan, CEO of the Nigerian Upstream Petroleum Regulatory Commission (NUPRC), told a briefing. Investors “are not navigating uncertainty”, but an environment designed to create confidence, she said.


“I expect that Nigeria will be facing steep competition in attracting attention” Gbakon, NNPC

Globally, a range of licensing rounds has been taking place—including in Libya, Mauritania, Egypt, Equatorial Guinea and Guinea-Bissau in Africa alone—noted Kaase Gbakon, a Nigerian energy economist formerly with the Nigerian National Petroleum Corporation. Many of the rounds are focused on offshore deepwater and natural gas assets. “I expect that Nigeria will be facing steep competition in attracting attention.”


Production costs are a hurdle. The head of the inland service told lawmakers in 2024 that oil companies had given their average cost of production as $48.71/bl. In parts of the Middle East, production costs can be less than $10/bl. A group of indigenous producers said in February that oil and gas operating costs are about 40% higher than in comparable non-shale jurisdictions, due to factors including multiple regulatory fees and security spending in the Niger Delta.


Production has shown a slight improvement. NUPRC data show crude output averaging 1.46m b/d as of September, versus 1.32m b/d a year earlier. Analysts at investment management firm CardinalStone see “modest upside” in 2026, supported by Shell’s Bonga northwest expansion, ExxonMobil’s $1.5b deepwater programme and the restoration of idle wells by indigenous player Seplat.


Nigeria’s bid round is a “referendum on the country’s credibility as an upstream investment destination”, said Thomas Balogun, founder of NovaCore Explorations, which advises on energy and mining investment in Africa. The era in which majors aggressively competed for Nigerian acreage “has largely passed”, Balogun said. Nigeria, he noted, is competing not just with African jurisdictions, but with frontier success stories such as Guyana and established destinations such as Brazil. The licensing round, he said, is likely to see “measured” participation. The country’s challenge is “not simply to offer acreage but to demonstrate that it can compete on a risk-adjusted basis. Geology alone is no longer sufficient”.


Taxation and domestic supply

The 2021 Petroleum Industry Act has strengthened fiscal transparency by harmonising the tax framework, said Eyitayo Ajisafe, an associate at the Tope Adebayo law firm in Nigeria. The act replaced the previous petroleum profits tax regime with a Companies Income Tax (CIT) and a Hydrocarbon Tax (HCT), cutting headline rates from as high as 85% on chargeable profits to 15–30% for HCT and 30% for CIT, she said. There are tax credits for operators who meet cost-efficiency benchmarks, and for non-associated gas development projects, she noted.


There is also the issue of the Domestic Crude Supply Obligation (DCSO). This is not fixed and is determined by the NUPRC. While the DCSO is mandatory, it is designed to operate on a willing buyer–seller basis, Ajisafe said. Regulatory intervention is limited to supply shortages where commercial negotiations fail, except in cases of unreasonable conduct by the local refiner. The DCSO “does not necessarily function as a rigid constraint on investors”, she said.


Similar outcomes in competing jurisdictions are often achieved through production-sharing contracts, Ajisafe said. Still, she noted, the HCT has been extended beyond its original PIA scope to include deep offshore areas. She also sees concerns around producers’ ability to realise equivalent value from sales to domestic refineries versus international markets, and the potential impact of a non-static DCSO quota on offtake arrangements. “Further well-tailored fiscal incentives may be necessary to enhance project bankability relative to peer jurisdictions like Angola, Namibia and Mozambique.”


Factors such as the DSO complicate the outlook for investors, Balogun said. The hydrocarbon tax adds to an already complex fiscal structure, while the DSO obligation means uncertainty around pricing and offtake reliability, he argued. Nigeria does not need to be the lowest-tax jurisdiction but must ensure the government’s share reflects risks to investors, he said. Many investors, he argued, are willing to accept a higher government take if the framework is transparent and stable. “The challenge Nigeria faces is that investors remain wary of policy slippage and post-investment fiscal creep.” The country “must send a consistent signal that once capital is committed, the rules will not change arbitrarily”.


Improved security

Organised theft of crude oil has dogged the sector for decades. Ajisafe said there has been measurable progress in reducing it, through coordination between the NUPRC, security agencies and private sector partners. Crude oil theft has declined from about 102,900b/d in 2021 to about 9,600b/d by mid-2025, the lowest in 16 years. Factors behind the improvement, Ajisafe said, include enhanced military patrols, the use of advanced cargo declaration systems and community-based development programmes.


The government in 2025 approved 37 new crude oil evacuation routes, including pipelines and barging paths, giving producers more options to transport oil to domestic refineries and ports for export. Still, oil theft and infrastructure vandalism remain concerns, especially in onshore and shallow-water operations, Ajisafe said.


A key question is whether security improvements can be sustained, Balogun said. “Investors will want evidence that security gains are embedded in governance structures rather than dependent on ad hoc enforcement or individual contractors.” Ajisafe argued that managing community-related risks remains critical. While the government has increased engagement with host communities, she sees a need for active enforcement of contributions to funds for host community development and environmental remediation. Ajisafe also said she wanted to see consistent application of gas flare penalties. Such steps would “mitigate unrest and create a more stable and predictable environment for upstream investments”.


Source: Petroleum Economist