President Bola Ahmed Tinubu approved a standardised deep offshore investment framework on 11 August 2026, targeting USD 50 billion in new oil and gas investment through tiered production tax credits, a profit oil reset mechanism, and mandatory local performance conditions, with companies required to reach final investment decisions by 31 December 2029 to access maximum incentives.

RF Report

The Nigerian State House has announced that President Bola Ahmed Tinubu approved a new deep offshore investment framework on 11 August 2026.

The reform seeks to attract up to USD 50 billion in new investment into Nigeria’s oil and gas sector by replacing project-by-project negotiations with standardised rules, while also promoting local employment and industrial development.

The new framework is established through the Deep Offshore Oil and Gas Projects Incentives (Tax Remission) Order, 2026, which was published in the Official Gazette on 10 August 2026.

The decree introduces a tiered system of Standard and Supplementary Production Tax Credits for both crude oil and non-associated gas developments. These financial incentives are tied to specific production thresholds and investment timelines, requiring companies to reach final investment decisions by the end of 2029 to qualify for maximum benefits. The order also implements a “Profit Oil Reset” to improve the commercial viability of new greenfield projects within existing contract areas. To ensure national benefit, the document mandates that most project activities occur within Nigeria and provides strict regulatory oversight for tax remission eligibility and recovery.

The reform also establishes a transparent, rules-based investment framework capable of supporting the next generation of deep offshore developments, beginning with the approximately USD 10 billion Bonga South West project, while strengthening Nigeria’s competitiveness for globally mobile investment capital.

Standard production tax credit (Standard PTC)

The Standard PTC establishes a direct, volume-based incentive structure tailored separately for oil and gas projects to incentivise deep offshore investments:

  • Crude oil projects:
    • Reserves up to 400 million barrels: For project developments with producible reserves of crude oil equivalent up to 400 million barrels, the credit is USD 3.00 per barrel or 20% of the fiscal oil price, whichever is lower. This is capped at a cumulative production of 150 million barrels.
    • Reserves exceeding 400 million barrels: For larger developments with reserves exceeding 400 million barrels of crude oil equivalent, the incentive rises to USD 4.50 per barrel or 20% of the fiscal oil price, whichever is lower, up to a cumulative production of 500 million barrels.
    • Future leases: Leases awarded after the effective date (including those derived from existing or future licenses awarded after the effective date) receive an additional Standard PTC of USD 1.00 per barrel. This applies from the commencement of production up to the applicable 150-million or 500-million-barrel cumulative limit.
    • Low-price safeguard: To shield the government’s fiscal position during downturns, if the fiscal oil price drops below USD 50 per barrel in any month, all oil-related tax credits under these provisions (including the future lease addition) are halved (applied at 50% of the rate) for that month.
    • Application boundary: The credit is calculated strictly on crude oil produced and sold from the approved project development. Its application is structured so that the entire benefit is reflected solely in the Contractor’s profit oil entitlement.
  • Non-associated gas projects:
    • Low hydrocarbon liquids (HCL) content: For fields where the HCL content does not exceed 30 barrels per million standard cubic feet (MMSCF), the credit is USD 1.00 per thousand standard cubic feet (MSCF) of gas sold or 30% of the fiscal gas price, whichever is lower. This is capped at a cumulative volume of 5 TCF.
    • Medium HCL content: For fields with HCL content between 30 and 100 barrels per MMSCF, the credit is USD 0.50 per MSCF of gas sold or 30% of the fiscal gas price, whichever is lower, up to a cumulative volume of 5 TCF.
    • High HCL content exclusions: If the HCL content exceeds 100 barrels per MMSCF, the gas production does not qualify for any Standard PTC.
    • HCL determination: The HCL content is restricted to the upstream petroleum sector and determined based on guidelines issued by the Nigerian Upstream Petroleum Regulatory Commission (the Commission).

Supplementary production tax credit (Supplementary PTC)

Designed to support marginally economic or high-barrier projects, the Supplementary PTC is an additional tax remission incentive determined on a case-by-case basis:

  • Eligibility and application: This credit applies only to greenfield project developments where a Final Investment Decision (FID) has not been taken as of August 6, 2026, but is scheduled to be taken on or before December 31, 2029. The operator must apply to the Nigeria Revenue Service (the Service) with a full open-book economic model (including cost, price, and production assumptions) to demonstrate eligibility.
  • Combined credit caps: The sum of the Standard and Supplementary PTCs cannot exceed:
    • USD 11.50 per barrel for crude oil developments.
    • USD 8.00 per barrel of oil equivalent (BOE) for non-associated gas developments.
  • Allocation rules: Unlike the Standard PTC (which benefits the Contractor’s profit oil entitlement directly), Supplementary PTCs must be allocated between the Contractor and the Concessionaire (NNPC Limited) in proportion to the applicable profit oil and gas sharing percentages for that period.
  • Timeframe constraints:
    • For future leases, the Supplementary PTC is only available if the project reaches commercial production within seven years from the date the lease was awarded.
    • It is subject to the same volume thresholds, low-price halving (below USD 50/bbl), and missed FID penalty structures as the Standard PTC.

Profit oil reset and gas sharing

These mechanisms structurally alter production sharing contracts (PSCs) to improve project economics:

  • Profit oil reset:
    • Restarting the scale: Under existing PSCs, cumulative production may have already graduated the profit oil split in favour of the government. For eligible greenfield developments, the sliding scale restarts at a ratio of 70% for the Contractor and 30% for the government.
    • Eligibility condition: This reset is only available if the PSC’s sliding scale has already progressed past a 70:30 contractor-government split.
    • Contractual and ring-fencing rules: The approved development must be fully ring-fenced for cost recovery and tax purposes. To secure the reset, the Contractor and Concessionaire must execute a formal PSC addendum within 30 days of approval and submit it within 14 days to the Service, the Commission, and the Office of the President.
  • Minimum government profit gas sharing: For existing deep offshore PSCs where the Concessionaire (NNPC Limited) represents the Federation, a progressive sharing scale is established based on cumulative gas production:
    • Up to and including 1 TCF: 20% minimum government allocation.
    • Over 1 TCF and up to 3 TCF: 35%.
    • Over 3 TCF and up to 5 TCF: 45%.
    • Over 5 TCF and up to 7 TCF: 50%.
    • Over 7 TCF: 60%.

Exclusions, penalties, and carry forwards

Strict rules govern compliance, double-dipping, and operational boundaries:

  • Missed FID deadline penalty: For existing leases, the lessee must declare an FID between the effective date and December 31, 2029. If they fail to commit to the FID by this deadline, and no force majeure extension is approved by the Commission, the Standard PTC rate is permanently slashed by 50% for that project.
  • Technical cost penalty: To control cost inflation, if the project’s Unit Technical Cost (the sum of unit operating and capital costs) exceeds the periodic benchmarked cost levels set by the Commission, the tax credits are reduced by 10%. Only elements approved by the Commission and communicated to the Service can be counted in this cost.
  • Local performance conditions: To access the Supplementary PTC or Profit Oil Reset, all development activities must be performed in Nigeria. The only exceptions are critical path items (such as long-lead items) or activities that are at least 10% more expensive to execute domestically than abroad, both of which must comply with a Nigerian Content Plan approved by the NCDMB.
  • Carry Forward & lapsing: Tax credit surpluses can be carried forward to subsequent years, but only for a maximum of four years, after which any remaining surplus lapses.
  • Exclusions & double-dipping: Tax credits cannot be combined with the production allowance incentives under the Sixth Schedule of the Nigeria Tax Act, 2025, or the Associated Gas Framework Agreement (AGFA).
  • Non-transferability: PTCs are non-refundable, non-transferable, and non-assignable. They cannot be set off against royalties, penalties, or liabilities of any other person, project, lease, or contract area.
  • Clawback & recovery: If the Service determines that an applicant secured or utilised tax credits via false statements, misrepresentation, omission, concealment, incorrect data, artificial arrangements, or prohibited tax avoidance schemes, it can withdraw approval, recompute the tax, recover the utilised credits, and apply penalties and interest.

General implementation rules and timeline

The framework uses the same fiscal price for calculating tax credits as for determining petroleum royalties under Nigeria’s tax laws. Credits are calculated monthly and reconciled annually through tax returns, subject to the applicable minimum effective tax rate. Standard PTCs and related rules apply retroactively from 28 February 2024, while Supplementary PTCs, the Profit Oil Reset, application procedures, performance conditions and clawback provisions take effect from 6 August 2026.