INTRODUCTION
Nigeria’s deep offshore petroleum sector has long presented a paradox. Despite the country’s significant offshore petroleum resources, the development of deep offshore projects has been constrained by high capital requirements, technical complexity and long investment horizons. In an increasingly competitive global investment environment, improving the commercial viability of these projects remains critical to attracting new upstream investment.
Against this backdrop, the Federal Government has introduced the Deep Offshore Oil and Gas Projects Incentives (Tax Remission) Order, 2026 (the “Order”), pursuant to Section 3(1)(e) of the Petroleum Industry Act, 2021 and Section 77(1) of the Nigeria Tax Administration Act, 2025 (“NTAA”). The Order establishes a framework of tax remission incentives for qualifying deep offshore oil and non-associated gas developments, including a Standard Production Tax Credit (“Standard PTC”), a Supplementary Production Tax Credit (“Supplementary PTC”) and, for qualifying projects, a Profit Oil Reset.
With the Federal Government projecting that the framework could unlock up to US$50 billion in deep offshore investment, the Order represents a significant attempt to improve the economics of new offshore developments. This briefing note considers the key incentives under the Order and whether the framework provides the fiscal certainty and commercial predictability required to translate Nigeria’s deep offshore potential into investment.
A NEW FRAMEWORK FOR NEW DEVELOPMENTS
The Order is deliberately targeted at new developments. The Standard PTC applies to qualifying project developments in existing deep offshore leases where the lessee takes a Final Investment Decision (“FID”) between the effective date of the Order and December 31, 2029. It also applies to qualifying developments in future leases awarded after the effective date.[1]
The 2029 deadline introduces a degree of urgency for projects currently at the pre-FID stage. For existing leases, the lessee must take FID between the effective date of the Order and 31 December 2029. Where the lessee is unable to commit to FID within this period due to force majeure, it may apply to the Nigerian Upstream Petroleum Regulatory Commission for an extension of the FID timeline. Where the lessee fails to meet the prescribed FID criteria and no extension is granted, the Standard PTC will apply at 50% of the applicable rate, provided the project otherwise satisfies the eligibility conditions under the Order.
The focus on new developments is equally important. The Order defines “project development”[2] around the development of a greenfield crude oil or non-associated gas field, or group of greenfields, pursuant to an approved field development plan. Activities such as infill drilling, workovers, recompletions, debottlenecking, routine facility upgrades and enhanced recovery from existing producing fields are excluded. The Order is therefore not intended to provide a general tax benefit for all activities undertaken within deep offshore leases. Rather, it seeks to improve the economics of new developments and encourage projects that have yet to reach FID to proceed to development.
THE STANDARD PTC: IMPROVING PROJECT ECONOMICS
For qualifying deep offshore oil developments, the Standard PTC is calculated from the commencement of production.
Where the producible reserves of a project do not exceed 400 million barrels of crude oil equivalent, the credit is US$3.00 per barrel or 20% of the fiscal oil price, whichever is lower, up to cumulative production of 150 million barrels. For projects with producible reserves exceeding 400 million barrels of crude oil equivalent, the credit increases to US$4.50 per barrel or 20% of the fiscal oil price, whichever is lower, up to cumulative production of 500 million barrels.[3]
Future leases may benefit from an additional Standard PTC of US$1.00 per barrel, subject to the applicable production thresholds. Where the fiscal oil price falls below US$50 per barrel in a particular month, the applicable credit for that month is reduced by 50%.[4] The structure of the Standard PTC is significant because the benefit is linked directly to production. It is not an upfront payment or cash subsidy. The Order expressly provides that the tax credit is not a grant, subsidy, cash payment, refundable credit or transferable instrument.[5] Its economic value will therefore depend on the project’s ability to reach production and generate sufficient tax liabilities against which the credit can be utilised. The headline PTC rate cannot, consequently, be considered in isolation. Production profile, fiscal oil price, project costs and the timing of taxable income will all influence the actual value of the remission.
EXTENDING THE INCENTIVE TO GAS
The Order similarly provides a Standard PTC for qualifying deep offshore non-associated gas developments.
Where hydrocarbon liquids (“HCL”) content does not exceed 30 barrels per million standard cubic feet, the credit is US$1.00 per thousand standard cubic feet (“mscf”) of gas sold or 30% of the fiscal gas price, whichever is lower, up to cumulative sales of 5 trillion cubic feet (“TCF”). Where HCL content exceeds 30 barrels per mmscf but does not exceed 100 barrels per mmscf, the credit reduces to US$0.50 per mscf or 30% of the fiscal gas price, whichever is lower. Projects with HCL content exceeding 100 barrels per mmscf are not eligible for the Standard PTC.
The Order also introduces a profit gas sharing formula for existing non-associated gas deep offshore production sharing contracts (“PSCs”), with the Government’s minimum profit gas allocation ranging from 20% for production of up to 1 TCF to 60% for production exceeding 7 TCF.
The inclusion of gas is significant in the context of Nigeria’s broader efforts to increase gas development and monetisation. By recognising the distinct economics of gas projects, the Order seeks to provide a defined fiscal incentive for qualifying deep offshore gas developments.
SUPPLEMENTARY PTC AND PROFIT OIL RESET: ADDITIONAL INCENTIVES FOR QUALIFYING PROJECTS
The Order goes beyond the Standard PTC by introducing two additional incentives for qualifying projects: the Supplementary PTC and the Profit Oil Reset.
The Supplementary PTC allows the Nigeria Revenue Service (the “Service”) to grant an additional tax credit based on the economic profile of an eligible project. The aggregate Standard PTC and Supplementary PTC is capped at US$11.50 per barrel for oil developments and US$8.00 per barrel of oil equivalent for non-associated gas developments.
The Supplementary PTC is available only to qualifying greenfield projects for which FID had not been taken as at the commencement of the Order and where FID is taken on or before 31 December 2029, subject to any approved force majeure extension.
An applicant is required to submit a full open-book economic model setting out the relevant cost, price, production and fiscal assumptions. The Service is required to consider a complete application within 45 days and determine the applicable Supplementary PTC within the prescribed ceiling. The Order further requires the Service to publish guidelines setting out the criteria and methodology for determining the level of the Supplementary PTC.
This is potentially significant for projects that are technically viable but remain commercially challenging. A project-specific assessment allows the incentive to take account of differences in development costs, production profiles and other economic characteristics.
At the same time, the case-by-case nature of the Supplementary PTC makes administrative certainty particularly important. Investors making multi-billion-dollar commitments require visibility on the likely value of fiscal incentives before committing capital. The methodology to be published by the Service will therefore be central to determining whether the Supplementary PTC provides genuine certainty or introduces another layer of negotiation.
RESETTING THE PROFIT OIL EQUATION
The Profit Oil Reset addresses a different aspect of project economics.
For qualifying projects within existing PSC areas, the Order permits the applicable profit oil sliding scale to be reset, such that the allocation begins at 70:30 in favour of the Contractor and Government respectively, notwithstanding that production from another field within the same contract area may have caused the applicable sliding scale to progress to a less favourable ratio.
The qualifying project is also ring-fenced for cost recovery and tax purposes.
This could have particular significance for new developments within mature contract areas. Without a reset, the production history of an existing field could affect the economics of a new development, potentially subjecting a capital-intensive project to a less favourable profit oil allocation from the outset. The Profit Oil Reset seeks to separate the economics of the new development from that historical production.
The incentive is, however, subject to specific eligibility requirements, including that the applicable profit oil sliding scale has progressed beyond the 70:30 Contractor-Government split.
Taken together, the Supplementary PTC and Profit Oil Reset could materially improve the economics of qualifying projects. Their ultimate effectiveness will, however, depend on how the relevant approval and determination processes operate in practice.
INCENTIVES WITH CONDITIONS
The additional incentives do not come without corresponding obligations.
Access to the Supplementary PTC and Profit Oil Reset is tied to Nigerian content and in-country execution requirements. As a general rule, activities relating to the project development are required to be performed in Nigeria. Exceptions apply to activities on the critical path, including certain long-lead items that significantly affect the project timeline, and activities that are more than 10% more expensive to execute in Nigeria after taking relevant costs into account. Activities undertaken outside Nigeria must also comply with an approved Nigerian Content Plan.
The requirement reflects a broader policy objective. The Government is seeking not only to attract capital and increase production, but also to ensure that deep offshore investment generates wider economic benefits through increased in-country execution, domestic engineering, fabrication, marine logistics, technical services and project management.
For operators, Nigerian content considerations will therefore need to be incorporated into project planning and economic modelling from an early stage. The ability to demonstrate compliance with the applicable requirements may also become an important consideration in securing the additional incentives.
COST EFFICIENCY AND UTILISATION OF CREDITS
The incentives are also subject to a cost-efficiency requirement. Where a project’s unit technical cost exceeds the benchmark determined by the Commission, the applicable tax credits are reduced by 10%.
This introduces an important qualification to the headline incentive rates. The value of the tax remission will depend not only on production and fiscal prices, but also on the project’s ability to operate within the applicable cost parameters.
The treatment of unused credits is similarly relevant. A tax credit surplus may be carried forward for a maximum of four years. However, the credit is not refundable, transferable, assignable or saleable and cannot be used to offset liabilities relating to another person, asset, project, lease or contract area. Any unutilised tax credit surplus remaining after the four-year carry-forward period will lapse and cease to be available for utilisation.
For projects with significant credits but limited tax liabilities during their early production years, the timing of production and taxable income may therefore affect the extent to which the full benefit of the incentive can be realised.
Fiscal Certainty: The Real Test
The Government has positioned the Order as a move towards a more transparent and predictable framework for deep offshore investment, replacing project-by-project negotiations with defined eligibility criteria and implementation processes.
For deep offshore developments, where investment decisions can involve billions of dollars and extend over several years, this objective is important. Investors need to understand the fiscal consequences of a project before committing capital, particularly where project economics are sensitive to changes in costs, production and commodity prices.
The Order provides some degree of certainty by setting out the applicable PTC rates, eligibility requirements, FID deadlines and production thresholds. It also requires the Service to publish a methodology for determining the Supplementary PTC.
However, the implementation phase will be critical.
The Service is required to issue guidelines addressing matters including the application process, documentation requirements, economic valuation methodology, computation and utilisation of the incentives. The quality and clarity of these guidelines will influence how readily investors can incorporate the incentives into project economics.
Institutional coordination will also be important. The framework requires interaction between the Service, the Commission, the Nigerian Content Development and Monitoring Board (“NCDMB”) and, where applicable, the parties to the relevant PSCs. The Federal Government has also indicated that NNPC Limited, as the Government’s nominated counterparty under the PSCs, may proceed with the necessary amendments to eligible PSCs to implement the framework.
The effectiveness of the Order will therefore depend not simply on the incentives provided, but on whether they can be accessed and administered with the certainty required for long-term investment decisions.
CONCLUSION
The Order represents a significant attempt to improve the commercial framework for Nigeria’s deep offshore petroleum developments.
Rather than relying on a single fiscal concession, the Order combines Standard PTCs with a project-specific Supplementary PTC and, for qualifying PSC developments, a Profit Oil Reset. These incentives are complemented by FID deadlines, Nigerian content requirements, cost-efficiency safeguards and project-specific ring-fencing.
The potential prize is substantial. The Federal Government estimates that the framework could unlock up to US$50 billion in deep offshore investment, beginning with major developments such as the Bonga Southwest project. However, US$50 billion is a projection, not committed capital. The real test of the Order will be whether it changes investment decisions and moves projects from the pre-FID stage to development and production.
For investors and operators, the immediate priority should therefore be to assess existing and prospective developments against the Order’s eligibility requirements, economic parameters and applicable timelines. Projects approaching FID will need to consider the 31 December 2029 deadline carefully, while sponsors seeking the Supplementary PTC will need to prepare robust economic models capable of supporting their applications.
Ultimately, the success of the Order will depend not merely on the generosity of the incentives, but on the certainty with which they can be accessed and the efficiency with which the framework is implemented.
Nigeria has gone deep on incentives. Whether it can go deep on investment will now depend on how effectively the framework moves projects from opportunity to FID, and from FID to production.
Please do not treat the foregoing as legal advice, as it only represents the public commentary views of the authors. All enquiries on this should be directed to the key contacts.
Please do not treat the foregoing as legal advice as it only represents the public commentary views of the authors. All enquiries about this should please be directed at the key contacts
