Nigeria’s Deep Offshore Tax Incentives Order 2026: Eligibility, Credits And Conditions

Introduction

On 6 August 2026, President Bola Ahmed Tinubu signed the Deep Offshore Oil and Gas Projects Incentives (Tax Remission) Order, 2026 (the “Order”), made pursuant to the Petroleum Industry Act, 2021(the “PIA”) ¹ and the Nigeria Tax Administration Act, 2025 (the “NTAA”).²

The Order establishes a fiscal-incentive framework for deep offshore oil and gas project developments under production sharing contracts (“PSCs”). It provides for production tax credits (“PTCs”), a profit oil reset mechanism and Nigerian content conditions, each directed at incentivizing investments in Nigeria’s deep offshore acreages. This alert sets out the key provisions and their commercial implications for international and indigenous operators and their partners.

A unified framework to replace project-by-project negotiation

The Order continues a policy line that began with the Presidential instruments of 2024, i.e., the Oil and Gas Companies (Tax Incentives, Exemption, Remission, Etc.) Order, 2024 and the Notice of Tax Incentives on Deep Offshore Oil and Gas Production, 2024 (collectively referred to as “2024 Order”). Accordingly, the Order’s PTCs provisions take effect from 28 February 2024, while its application, approval and enforcement provisions run from the date of signing (6 August 2026).³

The immediate backdrop is the Bonga South West Aparo (“BSWA”) development, operated by Shell through its Nigerian deepwater subsidiary, which had been stalled for close to two decades, in significant part over its fiscal and commercial terms. In January 2026, the Government announced that it had agreed on a project-specific incentive package intended to move the BSWA development towards a Final Investment Decision (“FID”).⁴

However, in place of discrete, multi-year negotiations over each development, the Order fixes general eligibility criteria, credit rates and an approval process, with NNPC Limited as Concessionaire, the Nigeria Revenue Service (“NRS”) administering the credits, and the Nigerian Upstream Petroleum Regulatory Commission (the “NUPRC”) setting technical benchmarks and receiving FID notifications. In essence, terms once available only through individual negotiation are now, in substance, published as criteria open to any qualifying development.

Key Provisions of the Order

1. Standard Production Tax Credit
   The Order provides for a Standard Production Tax Credit (“Standard PTC”) applicable to project developments in deep offshore leases.⁵ For existing leases, the lessee must make a Final Investment Decision (“FID”) from the Effective Date of the Order (i.e., 28 February 2024) to 31 December 2029.⁶ Future leases awarded after the effective date also qualify for the Standard PTC subject to the fulfilment of the conditions in the Order. The Standard PTC is determined separately for each approved project development, at the rates below:
   
   While the Order largely retains the structure of the oil production tax credit under the 2024 Notice, a 50% reduction now applies for any month in which the fiscal oil price is below US$50 per barrel.⁷ Each credit is ring-fenced to the approved development, computed only on production sold from it, and reflected solely in the Contractor’s profit oil or profit gas entitlement.
2. Supplementary Production Tax Credit
   A significant innovation of the Order is the introduction of a Supplementary PTC, available in addition to the Standard PTC.⁸ The Supplementary PTC is granted on a case-by-case basis by the NRS based on the economic profile of the project development. The aggregate of the Standard PTC and Supplementary PTC are capped at US$11.50 per barrel for oil developments and US$8.00 per BOE for gas developments.
3. Profit Oil Reset
   For an eligible development, the PSC profit oil sliding scale restarts at 70:30 (Contractor to Government), notwithstanding that production elsewhere in the same contract area has already graduated the split in the Government’s favour. The Reset is ring-fenced for cost recovery and tax and requires a PSC addendum within 30 days of approval, filed with the NRS, the Commission and the Office of the President within 14 days thereafter.⁹
4. Profit gas sharing formula
   For existing non-associated gas deep offshore PSCs where the Concessionaire represents the Federation, the Government’s minimum profit gas allocation follows a sliding scale: 20% up to 1 TCF; 35% over 1–3 TCF; 45% over 3–5 TCF; 50% over 5–7 TCF; and 60% above 7 TCF, with no upper cap.¹⁰
5. Claw-back Provisions
   The Order introduces claw-back provisions empowering the NRS to withdraw approval, recompute tax, and recover wrongly utilised credits.¹¹ Triggers include false statements, misrepresentation, omission, concealment, incorrect data, artificial arrangements, prohibited tax avoidance, breach of conditions, and failure to satisfy eligibility requirements. These powers are without prejudice to criminal, civil, administrative, or regulatory action.
6. Eligibility Criteria
   The Supplementary PTC and Profit Oil Reset are confined to greenfield developments for which FID had not been taken at commencement (6 August 2026) and is taken on or before 31 December 2029, subject to force majeure extension. Existing leases that miss that deadline without an approved extension receive the Standard PTC at 50%, subject to the relevant eligibility criteria. The Reset additionally requires that the sliding scale has already progressed beyond 70:30.¹²
7. Nigerian Content Conditions
   The Order imposes Nigerian content conditions on project developments benefiting from the incentive framework.¹³ All activities relating to the project development must be performed in Nigeria, save for two limited exceptions: (i) critical path activities involving long-lead items that would significantly affect the project timeline; and (ii) activities that are 10% or more expensive to perform in Nigeria than outside Nigeria, taking into account the full cost implications. All activities performed outside Nigeria must comply with the Nigerian Content Development and Monitoring Board (“NCDMB”)-approved Nigerian Content Plan.
8. Application and administration The Order establishes a formal application process for the Supplementary PTC and Profit Oil Reset.¹⁴ An applicant much submit a full open-book economic model to the NRS, which has 45 days, in consultation with the Federal Ministry of Finance, to verify eligibility and set the Supplementary PTC level. The NRS must publish criteria and methodology guidelines within 45 days of commencement (by around 20 September 2026).
9. Computation, Carry-forward, and Restrictions
   Credits are computed monthly and reconciled annually, using the fiscal price applied for petroleum royalty, and are subject to the minimum effective tax rate under the NTA ).¹⁵ The Order also provides for a 10% reduction in credits for developments exceeding benchmarked cost levels,¹⁶ and expressly excludes combination with production allowances under the Sixth Schedule to the NTA 2025 or the Associated Gas Framework Agreement (“AGFA”).¹⁷ These provisions mark a shift from the approach under the 2024 Notice. In particular, the Order moves to monthly computation with annual reconciliation and provides for the allocation of tax credits between the Contractor and Concessionaire based on their applicable profit oil and gas sharing percentages. It also extends the carry-forward period for unused tax credit surpluses from three years under the 2024 regime to four years, while expressly subjecting the utilisation of the credits to the minimum effective tax rate under the NTA.

Interaction with the PIA and the 2025 Tax Acts

The Order does not operate as a standalone tax regime. Its practical significance lies in how the incentives it introduces interact with the petroleum fiscal framework under the PIA, the tax regime established by the NTA, and the administrative provisions of the NTAA.

The Order operates within the production sharing contract framework established under the PIA. One of its most significant features is the Profit Oil Reset, which allows an eligible greenfield development to restart the applicable profit oil sliding scale at a 70:30 contractor-government ratio. This is particularly relevant where a new development is located within an existing producing contract area and historical production levels have already shifted the profit oil split to less favourable levels for the contractor. The Reset improves project economics by ensuring that the contractor's share of profit oil during the early stages of a new development is not penalised by legacy production elsewhere in the same contract area.

The Order also expressly prohibits the tax credits granted under it from being combined with the production allowance incentives under the Sixth Schedule to the NTA or with incentives under the Associated Gas Framework Agreement. This anti-stacking rule means that the practical question for a qualifying project is which package (the Order’s PTCs or the NTA’s Sixth Schedule production allowances) yields the better outcome on its particular profile, while the minimum effective tax rate sets a floor on how far the credits can reduce the overall burden.

The Order applies to petroleum mining leases granted under the PIA and to oil mining leases under PSCs preserved by it. Section 101 of the NTA extends the deep offshore PSC provisions to contracts yet to convert under the PIA, so both converted and unconverted leases are covered.

Practical Recommendations for Investors and Operators

1. Assess FID Timelines: Assess FID timelines against the 31 December 2029 deadline. Review development schedules against the deadline and engage the NUPRC early if there is any force majeure situation.
2. Model the Supplementary PTC and prepare for open-book review: Build the economic case for the additional relief and assess the implications of full-cost disclosures.
3. Assess the Profit Oil Reset where the scale has moved beyond 70:30: Evaluate the uplift and engage NNPC Limited early on any required PSC addendum.
4. Plan Nigerian content compliance: Align procurement, fabrication and engineering with the in-country requirement, and document any critical-path or cost-differential justification for out-of-country work.
5. Model the combined fiscal position: Assess the PTCs against the NTA production allowances and the minimum effective tax rate, together with the ring-fencing and technical-cost benchmark, to establish true post-incentive economics.
6. Monitor the NRS implementation guidelines: The methodology, computation templates and utilisation rules due within 45 days of the commencement of the Order (20 September 2026) will materially affect outcomes and should be closely monitored.
7. Regulatory Engagement: In light of the 45-day review timeline, pre-application consultations with the NRS and other relevant stakeholders may assist in understanding expectations and ensuring submissions meet the requisite standards.

Conclusion

The Order re-frames the fiscal terms for deep offshore developments in Nigeria and consolidates the 2024 measures into a single instrument under the new 2025 tax architecture. Its benefits (the Standard and Supplementary PTCs and the Profit Oil Reset) come with corresponding obligations: greenfield eligibility, a firm FID deadline, Nigerian content conditions, open-book disclosure, and claw-back exposure, with the NRS exercising discretion over the Supplementary PTC. Because the credits offset, but do not displace, the wider PIA and NTA framework, operators and investors should model the Order together with those instruments and position early for the application process and the forthcoming guidelines.

Footnotes

1 Section 3(1)(e) of the PIA.

2 Section 77(1) of the NTAA

3 Paragraphs 17 – 19 of the Order.

4 NNPC Limited press release, “NNPC Secures Presidential Approval for $20 Billion Final Investment Decision on Bonga Deepwater Project” (10 March 2026).

5 Paragraph 1(1) of the 2026 Order.

6 The Order creates an avenue for seeking extension of time where FID is unattainable as a result of force majeure.

7 Paragraph 2(3) of the 2026 Order.

8 Paragraph 6(1) of the 2026 Order. This is unlike the 2024 Order which provided a single tier of production tax credits, with no mechanism for additional case-by-case fiscal relief calibrated to a project’s specific economic profile.

9 Paragraph 7 of the Order.

10 Paragraph 4 of the Order. The 2024 Notice capped the top tier at “7 to 9 TCF”; the Order applies the 60% minimum to all cumulative production over 7 TCF, with no upper limit.

11 Paragraph 11 of the 2026 Order.

12 Paragraph 8 of the Order.

13 Paragraph 9 of the 2026 Order.

14 Paragraph 10 of the 2026 Order.

15 Paragraph 12 of the 2026 Order.

16 Paragraph 13 of the 2026 Order.

17 Paragraph 14 of the 2026 Order.