Nigeria’s deep offshore petroleum sector is entering a potentially significant new phase of investment. The development of the Bonga Southwest project, estimated at approximately US$20 billion, illustrates both the scale of capital required to develop Nigeria’s deep offshore resources and the importance of a competitive and predictable fiscal framework in securing Final Investment Decisions (‘FID’).
In March 2026, NNPC Limited announced that Presidential approval had been secured for a targeted fiscal incentive intended to unlock the Bonga Southwest project.
Against this backdrop, the Federal Government has now introduced the Deep Offshore Oil and Gas Projects Incentives (Tax Remission) Order, 2026 (the ‘Order’). Made on 6 August 2026 under the Petroleum Industry Act, 2021 (‘PIA’) and the Nigeria Tax Administration Act, 2025, the Order establishes a new incentive framework for qualifying deep offshore oil and non-associated gas developments, adopting the incentive structure established under the Notice of Tax Incentives on Deep Offshore Oil and Gas Production, 2024 (the ‘Notice’) issued by the Minister of Finance in February 2024.
For holders of existing or future deep offshore Petroleum Mining Licences, Greenfield Project Developers, and PSC Contractors, the significance of the Order goes beyond the headline tax credits. It introduces production tax credits, supplementary incentives and a potential reset of the profit oil sharing scale, while imposing important conditions relating to FID timing, project classification, Nigerian content, project economics, technical costs and tax-credit utilisation.
Key Highlights of the Order
Establishment of Standard PTC and Supplementary PTC
The Order creates two principal categories of production tax credit:
a. Standard Production Tax Credit (‘Standard PTC’), which applies automatically to qualifying project developments subject to the conditions of the Order; and
b. Supplementary Production Tax Credit (‘Supplementary PTC’), which may be granted on a case-by-case basis to qualifying projects.
The Order is directed at project developments, rather than an entire lease or contract area, as the Standard PTC is to be determined separately for each approved project development.
This is particularly important for investors considering acquisitions, or developments within existing deep offshore leases. The fact that a lease qualifies as a deep offshore lease does not, by itself, mean that every activity undertaken within it will qualify for the incentives.
a. Standard PTC
For qualifying deep offshore oil developments, the Order provides a Standard PTC calculated from the commencement of production. Although, the Notice does not contain the term ‘Standard PTC’, the Oil and Gas Production Tax Incentives align with the benefits provided under the Standard PTC, but only to the extent of the period within which a Final Investment Decision (‘FID’) should be taken. While the Notice requires the FID to be taken between the Effective Date and 1 January 2029, the Order extends this to 31 December 2029.
The Order limits computation of Standard PTC to crude oil produced and sold solely from the project development, reflected only in the Contractor’s profit oil entitlement.
Its significance for Stakeholders lies in the direct improvement of the production economics.
The Order also creates a separate Standard PTC for marketable non-associated gas sold from qualifying projects identical to the position under the Notice.
b. Supplementary PTC
The Order empowers the Nigeria Revenue Service (‘NRS’) to grant a Supplementary PTC on a case-by-case basis, having regard to the economic profile of the relevant project. This is an innovation with no equivalent under the Notice.
For oil developments, the combined Standard PTC and Supplementary PTC cannot exceed US$11.50 per barrel, while the aggregate credit for non-associated gas developments is capped at US$8.00 per barrel of oil equivalent.
The Supplementary PTC introduces fiscal flexibility for projects whose economics may not be supported under the Standard PTC alone.
For qualifying greenfield projects seeking the Supplementary PTC or Profit Oil Reset, FID must be taken on or before 31 December 2029, subject to limited extensions for force majeure. Investors approaching the deadline should ensure that their corporate approvals, financing arrangements, EPC or construction commitments and other relevant documentation are sufficiently developed to demonstrate that a valid FID has occurred.
The Order also requires notification of FID to the Commission within 30 days where the lessee wishes to benefit from an incentive, which is a practical compliance point for project closing checklists.
2. The Profit Oil Reset
This relief, unavailable under the Notice, addresses a structural issue under PSCs.
A contractor’s share of profit oil generally reduces as production milestones are reached under the applicable sliding scale. Meaning a new development within an existing contract area may face a less favourable profit oil allocation because production from other fields has already caused the sliding scale to graduate.
The Order addresses this issue by permitting an eligible project development to restart the profit oil sliding scale at 70:30 in favour of the contractor, notwithstanding that existing production elsewhere in the contract area has already moved the PSC to a higher step.
This could materially improve the economics of a new deep offshore development and is particularly relevant to a new greenfield development within a mature PSC area where the historical production performance of other assets could adversely affect project economies.
However, the Profit Oil Reset is not available to every project. The applicable sliding scale must already have progressed beyond the 70:30 contractor-government split, and the project must be ring-fenced for cost recovery and tax purposes, and satisfy the other eligibility requirements for the incentive as stated in paragraph 8 and 9 of the Order.
The relevant PSC, development structure, field development plan and contractual allocation mechanisms should be carefully reviewed before an investor assumes that the Profit Oil Reset will be available.
3. Technical cost of development
The Order recognises the potential for abuse of the reliefs by qualifying development projects. Where a development project’s unit technical cost of exceeds the benchmarked cost levels as determined by the Nigeria Upstream Petroleum Regulatory Commission (‘NUPRC’), in a provision carried over from the Notice, the applicable tax credit may be reduced by 10%.
Contrary to the assumption that higher project costs attract higher relief, a project exceeding its cost benchmark will instead suffer a reduced tax relief. The cost elements considered will be specific to the relevant project development. The implication is that cost control of all elements must be a constant priority.
This provision functions as an encouragement for cost-efficiency. While the NUPRC recognises that certain expenses will be incurred in the structuring and operationalisation of a development project, those expenses must remain proportional and reasonable.
4. Claw-Back and Recovery of Incentive
The Order includes an anti-abuse safeguard applicable to the Supplementary PTC. Where the NRS determines that an applicant obtained, utilised or benefitted from this tax credit through false statements, misrepresentation, incorrect data, or any other means which breaches an approval condition, it may withdraw the approval and recompute the tax payable to recover the amount wrongly benefitted.
Penalties may extend beyond repayment of the improperly received credit to penalties and interest prescribed under the Nigeria Tax Administration Act 2025 and other applicable legislation. The Applicant or any person deemed responsible may also be the subject of separate criminal, civil, administrative or regulatory actions.
There is a continuing compliance obligation which must always be fulfilled by all parties involved. The NRS retains the right to ascertain fulfilment of eligibility requirements at any time, so investors and applicants must be thorough in confirming the accuracy of their Supplementary PTC applications.
5. Tax Credit Surplus
Tax Credit Surplus may occur where the tax liability falls below the tax reliefs which have been granted in respect of a development project. Any surplus may be carried forward, but only for a maximum period of four years, after which any unutilised tax credit shall be rendered ineffective. Formerly, the Notice allowed the excess to be carried forward for a maximum of three years.
This surplus cannot be transferred or assigned, neither can it be set-off against the tax, liability, arising from a person or project outside of the qualifying project development which has been approved.
The Order provides some flexibility to developers, and comfort to investors knowing that this no-transferrable relief need not be fully utlised immediately.
A further restriction applies across the Order. Tax credits under the Order cannot be combined with the production allowance incentives provided under the Nigeria Tax Act, 2025 or the Associated Gas Framework Agreement (AGFA). This restriction, mirrored in the Notice, ensures that no development project enjoys multiple tax credits simultaneously and requires the Developer to choose the incentive best believed to suit the project development.
Conclusion
The Deep Offshore Oil and Gas Projects Incentives (Tax Remission) Order, 2026 represents a significant attempt to address one of the central challenges facing Nigeria’s deep offshore petroleum sector: the economics of developing capital-intensive projects under increasingly competitive global investment conditions.
The combination of Standard PTCs, potentially substantial Supplementary PTCs and the Profit Oil Reset provides investors with multiple mechanisms through which the economics of qualifying projects may be improved.
The Order is also notable because it seeks to link fiscal support to actual investment and production. The incentives are directed at qualifying project developments, particularly greenfield projects, and are conditioned on FID, Nigerian content, cost discipline, economic disclosure and continuing compliance.
For investors, this creates a more attractive proposition, but it also requires a more sophisticated approach to due diligence and project structuring.
The immediate opportunity is clear. Nigeria has substantial deep offshore resources, and projects such as Bonga Southwest demonstrate the scale of investment that can be unlocked when fiscal and commercial constraints are addressed. If the implementation guidelines provide the clarity contemplated by the Order, and if the incentive approval process operates predictably and transparently, the framework could materially improve Nigeria’s competitiveness for deep offshore capital.
The Order should be viewed not merely as a tax incentive, but as a new project-development and investment framework. Investors considering entry into Nigeria’s deep offshore sector should assess the incentives from the outset of project structuring, rather than as an afterthought once the project has already been designed.
Ozioma Agu is a Partner at Stren and Blan Partners and supervises the Firm’s Energy, Finance and Infrastructure Sector. Anjoreoluwa Boluwajoko and Olaore Akinyemi are Associates in the Firm’s Energy, Finance and Infrastructure Sector.
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