For more than a decade, Nigeria’s biggest oil and gas discoveries have sat undeveloped offshore, victims of a fiscal regime that turned every major project into a bespoke, years-long negotiation between government and driller.
On Tuesday, President Bola Tinubu tried to change that narrative by approving the new regime and replacing the project-by-project haggling that has defined Nigeria’s relationship with international oil companies since the country’s last major deepwater sanction.
The Deep Offshore Oil and Gas Projects Incentives (Tax Remission) Order, 2026, signed on August 6 and gazetted on August 10, replaces project-by-project haggling with a fixed, published set of tax credits and profit-sharing terms available to any qualifying developer.
It is, by the government’s own count, the tenth major oil-sector policy directive of Tinubu’s presidency, and potentially the one with the most money attached, as the federal government said the framework could unlock as much as $50 billion in investment, starting with Shell’s roughly $10 billion Bonga South West project.
Why it matters
Nigeria’s deepwater fields, in water depths beyond the reach of most onshore-style contracting, are technically some of the richest in West Africa.
But they are also among the most expensive to develop, and for years majors weighed them against cheaper opportunities in Guyana, Brazil and offshore Namibia. Angola and other regional rivals sweetened their own terms; Nigeria largely didn’t, and investment stalled.
The new order is meant to close that gap by giving companies something negotiations never reliably delivered: certainty.
‘The countries that attract long-term investment are not necessarily those with the greatest natural resources,’ Tinubu said in a statement released through his spokesman, Bayo Onanuga. They are, he added, the ones that offer predictability.
What the order actually does
For Shell, the immediate beneficiary is Bonga South West Aparo, the project the government has repeatedly cited as the framework’s first test case.
But BusinessDay’s analysis showed the tax relief extends across the rest of the deepwater acreage that has sat on operators’ books for years.
For instance, ExxonMobil’s Owowo, Bosi and Uge fields could move now that the fiscal terms are fixed rather than negotiated project by project.
Chevron’s long-delayed Nsiko development is another candidate, as is TotalEnergies’ Ina shallow-water project, which has waited years for a Final Investment Decision.
Eni’s ZabaZaba/Etan field, one of Nigeria’s largest undeveloped deepwater discoveries, is arguably the biggest prize the order could unlock.
BusinessDay’s findings showed the qualifying oil projects get a Standard Production Tax Credit of $3 to $4.50 a barrel, depending on reserve size, plus an additional $1 a barrel for future leases.
Layered with a discretionary Supplementary Production Tax Credit, assessed case by case by the Nigeria Revenue Service, the total can reach $11.50 a barrel for oil and $8 per barrel of oil equivalent for gas.
If oil prices fall below $50 a barrel in a given month, the credits are cut in half. None of it is refundable, transferable or sellable, it only offsets a company’s own tax liability.
Secondly, under Nigeria’s production-sharing contracts, the government’s share of profit oil rises in steps as a field matures.
That has discouraged operators from greenlighting new developments inside already-producing contract areas, since fresh output would instantly be taxed at the higher, later-stage rate.
The reset lets an eligible new project restart that scale at a 70:30 split favouring the contractor, treated separately for cost recovery, effectively letting a new field be taxed like a new field, not an appendage of an old one.
To lock in the standard incentives, BusinessDay findings showed companies must reach a Final Investment Decision by December 31, 2029, a clock explicitly designed to pull forward investment decisions that might otherwise drift for years.
The local-content trade-off
In exchange for the incentives, the order leans harder on domestic content than prior frameworks.
Companies chasing the supplementary credits or the profit-oil reset must perform project activities inside Nigeria unless doing so is more than 10 percent costlier or involves long-lead items on the critical path – and even those exceptions require an approved Nigerian Content Plan.
‘Projects qualifying under the framework will maximise execution within Nigeria wherever commercially and technically feasible, strengthening domestic engineering, fabrication, marine logistics, technical services and project management,’ said Olu Arowolo-Verheijen, the President’s special adviser on oil and gas.
She added, ‘The objective is not only to increase investment and production, but also to create skilled jobs, deepen local supply chains and position Nigeria as Africa’s regional hub for deep offshore project execution.’
What to watch
The Nigeria Revenue Service has 45 days to rule on supplementary-credit applications once a company submits a full open-book economic model, a compliance burden some investors may find as consequential as the credits themselves.
And with Bonga South West cited as the framework’s proof case, its progress toward FID will likely serve as the market’s first read on whether Nigeria has actually solved its credibility problem, or just rebranded it.