Tax Law: Nigeria’s Deep Offshore Tax Remission Order 2026 including Petroleum Act.

For nearly two decades, Shell’s Bonga South West Aparo development sat stalled, not for lack of oil, but because the fiscal terms never quite worked. It’s a story that’s played out across Nigeria’s deep offshore acreage more than once: proven reserves everyone agrees are worth developing, but negotiations that drag on for years because every project has had to fight for its own bespoke deal. On 6 August 2026, President Bola Tinubu signed an Order meant to end that pattern for good.

The Deep Offshore Oil and Gas Projects Incentives (Tax Remission) Order, 2026 replaces years of one-field, one-operator negotiation with a published set of eligibility criteria, credit rates, and an actual approval process open to any qualifying development. The Presidency has framed this as unlocking up to $50 billion in new investment, and with NUPRC already tracking 22 offshore projects worth an estimated $30 to $50 billion expected between 2026 and 2030, the opportunity was never really in question. What’s actually being tested is whether this Order removes enough of the friction to turn that potential into signed final investment decisions.

Where This Order Comes From

The Order builds on incentives President Tinubu first introduced through two 2024 instruments, the Oil and Gas Companies (Tax Incentives, Exemption, Remission, etc.) Order and the accompanying Notice of Tax Incentives on Deep Offshore Oil and Gas Production. It’s made under Section 3(1)(e) of the Petroleum Industry Act, 2021, which empowers the Petroleum Minister to promote an enabling investment environment, and Section 77(1) of the Nigeria Tax Administration Act, 2025, which gives the President authority to remit tax where it’s just and equitable to do so. Its production tax credit provisions actually take effect retroactively from 28 February 2024, while everything around application and enforcement runs from the date it was signed.

The Standard Production Tax Credit

At the core of the framework sits the Standard Production Tax Credit, a per-barrel deduction against tax liability, sized differently depending on how large the reserve is. For oil developments with reserves of 400 million barrels of oil equivalent or less, the credit is the lower of $3.00 per barrel or 20% of the fiscal oil price, capped at 150 million barrels of cumulative production. Larger developments above that threshold get a bigger credit, up to $4.50 per barrel, capped at 500 million barrels. Future leases awarded after the Order’s effective date get an additional dollar on top of whatever rate applies. Non-associated gas developments follow their own scale based on hydrocarbon liquids content, with the credit dropping to zero once liquids content exceeds 100 barrels per million standard cubic feet.

One meaningful change from the 2024 framework: if the fiscal oil price falls below $50 a barrel in any given month, the credit for that month is automatically cut in half. It’s a built-in adjustment that ties the size of the incentive to how much the government actually needs to offer to keep a project economically viable in a lower price environment.

Where It Gets More Interesting: The Supplementary PTC

The genuinely new piece of this Order is the Supplementary Production Tax Credit, granted case-by-case rather than at a fixed rate. Where the Standard PTC applies uniformly to every qualifying development, the Supplementary PTC lets the Nigeria Revenue Service assess a specific project’s economics and decide whether it needs additional relief beyond the standard rate to actually reach a final investment decision. Combined, the two credits are capped at $11.50 per barrel for oil and $8.00 per barrel of oil equivalent for gas.

This isn’t available to everyone. Only genuinely new, greenfield developments qualify, ones where a final investment decision hadn’t been taken as of 6 August 2026, and must be taken by 31 December 2029 (with room for extension if force majeure gets in the way). To get it, an operator has to submit a full open-book economic model to the NRS, which then has 45 days, working with the Ministry of Finance, to verify eligibility and set the actual credit level. It’s a meaningful departure from a purely rules-based system toward one where the regulator exercises real discretion, which cuts both ways: it lets the incentive respond to a project’s genuine economics, but it also introduces the kind of uncertainty that investors typically try to avoid.

The Profit Oil Reset

Alongside the Supplementary PTC sits a second, complementary mechanism worth understanding on its own terms. Under a typical production sharing contract, the split between contractor and government shifts progressively in the government’s favour as cumulative production rises. The problem this creates is that a brand-new development sitting inside an already mature contract area can inherit a profit-oil split that’s already tilted heavily toward government, even though the new project hasn’t produced a single barrel yet.

The Profit Oil Reset addresses this directly: for a qualifying new development, the sliding scale restarts at 70:30 in the contractor’s favour, regardless of how far production elsewhere in that same contract area has already pushed the split. It requires NNPC Limited and the relevant contractor to sign a formal addendum to the underlying PSC within 30 days of approval, which then has to be filed with the NRS, NUPRC, and the Office of the President within 14 days after that. In effect, government and NNPC are trading a smaller near-term take for the prospect of new reserves and production growth over a longer horizon, a deliberate bet that will need results to keep justifying itself.

Nigerian Content Isn’t Optional Here

Access to both the Supplementary PTC and the Profit Oil Reset comes with a real local content condition attached. All project activities must be performed in Nigeria, with only two narrow exceptions: critical-path activities involving long-lead items where doing them abroad is genuinely necessary to protect the project timeline, or activities that would cost at least 10% more to perform domestically once full costs are considered. Anything legitimately performed outside Nigeria still has to comply with a Nigerian Content Plan approved by the NCDMB. For operators planning procurement and engineering work, this needs to be built into project planning from the outset, not bolted on afterward.

The Government Also Gets Sharper Terms On Gas

It’s not all incentive; the Order also tightens the government’s position on existing non-associated gas PSCs. The minimum government share of profit gas now follows a clear sliding scale: 20% for cumulative production up to 1 trillion cubic feet, rising through 35%, 45%, and 50% at successive thresholds, and reaching 60% for anything above 7 TCF, with no ceiling. This closes a genuine gap in the 2024 Notice, which never specified what happened above 9 TCF, and gives large-scale gas developments considerably more certainty about their long-term fiscal exposure.

Nothing Here Is Free Money

Credits under this Order are strictly ring-fenced to the specific approved development that earned them. They’re computed only against production actually sold from that project, reflected solely in that project’s own profit-oil entitlement, and they cannot be used to shelter income from a company’s other, already-producing assets. They’re also non-refundable and non-transferable outright.

The NRS retains real teeth to claw this all back. Where approval was obtained through false statements, concealment, artificial arrangements, or a breach of the Order’s conditions, the NRS can withdraw approval entirely, recompute the tax owed, and recover credits already used, entirely separate from any criminal, civil, or regulatory consequences that might also follow.

How This Interacts With The Rest Of Nigeria’s Tax Framework

The Order doesn’t operate in isolation, and understanding how it fits alongside existing law matters as much as understanding the Order itself. Credits are computed monthly and reconciled annually as part of a new “tax incentive return” filing requirement under the NTAA, separate from a company’s ordinary annual tax return. Crucially, the whole framework is subject to the 15% minimum effective tax rate under the Nigeria Tax Act, which applies to multinational groups earning above €750 million and Nigerian companies above ₦50 billion in turnover, effectively setting a floor on how far these credits can push a qualifying operator’s tax liability down.

There’s also an explicit anti-stacking rule: these credits cannot be combined with the production allowance incentives under the Sixth Schedule to the NTA, or with benefits under the Associated Gas Framework Agreement. For any qualifying project, this turns into a genuine modelling exercise, working out which incentive package, this Order’s credits or the NTA’s production allowances, actually produces the better outcome for that specific project’s economics. Unused credit surpluses can be carried forward, but only for four years before they lapse, an improvement on the three-year window under the 2024 regime, though arguably still tight for mega-projects with genuinely long construction timelines.

What Happens Next

The Supplementary PTC and Profit Oil Reset can’t be fully implemented until the NRS publishes detailed methodology and computation guidelines, due within 45 days of the Order’s commencement, putting the deadline at roughly 20 September 2026. Until those guidelines land, operators are working with the framework’s broad strokes rather than its operational detail, which is exactly why early engagement with the NRS and NUPRC, rather than waiting for every question to be answered on paper, is likely to matter for anyone seriously pursuing an FID before the 2029 deadline.

Conclusion

Whether this Order genuinely accelerates Nigeria’s stalled deep offshore projects or simply redistributes value that would have flowed anyway is still an open question, and one that will only be answered by what actually gets sanctioned over the next few years. What’s clear already is that the rules have changed meaningfully: a published, rules-based framework has replaced years of bespoke negotiation, real fiscal relief is on the table for genuinely new investment, and it comes bound to firm deadlines, local content obligations, and a regulator with real discretion and real clawback power.

If your business is assessing eligibility under this Order, structuring a PSC addendum, or simply trying to understand how these incentives interact with your existing fiscal position, reach out to us via the contact details on our website www.bamandgadsolicitors.com.ng . We are here to help you work through it and give you top expert legal advice on Energy Law as the best tax lawyers in Lagos Nigeria. 

Thank you for reading.