Upstream Petroleum Taxation Under The Nigeria Tax Act – Key Imperatives

Introduction

In a strategic effort to restructure Nigeria's fiscal framework and enhance revenue collection, the Nigerian government undertook a comprehensive overhaul of the nation's fiscal system. Four tax reform bills namely: the Nigeria Tax Bill, the Nigeria Tax Administration Bill, the Joint Revenue Board of Nigeria (Establishment) Bill and the Nigerian Revenue Service (Establishment) Bill were presented and subsequently signed into law by the President on 26 June 2025. This signaled a landmark moment widely regarded as one of the most transformative milestones in Nigeria's fiscal legislative history.

Pursuant to the above, the Nigeria Tax Act ("NTA" or "the Act") was enacted to streamline the nation's tax system, address the issue of excessive/multiplicity of taxes, enhance revenue generation, and simplify compliance processes by introducing a unified fiscal legislation. The Act repeals some existing tax laws such as the Petroleum Profits Tax (PPT) Act, Companies Income Tax (CIT) Act and Value Added Tax (VAT) Act amongst others and consolidate them into a single legal framework to improve tax administration. Expectedly, some of these changes would significantly affect Nigeria's upstream sector, which is the economic backbone of the nation, particularly, as 56%¹ of the country's 2025 budgeted revenue is expected to be generated from this sector. This article focuses on the impact of the changes in the fiscal regime on the Nigerian upstream oil and gas industry. It sheds much needed light on the impact of the NTA on Petroleum Industry Act (PIA) – Hydrocarbon Tax, PPT Act (PPTA) and the Deep Offshore and Inland Basin Production Sharing Contract Act (DOIBPSCA).

Effects of the NTA on upstream petroleum taxation

• Petroleum Industry Act - Hydrocarbon Tax (HCT)

The impact of the NTA on HCT regime is discussed below:

1. Withdrawal of hydrocarbon tax (HCT) exemption for Deep Offshore Operation

One of the key changes in the NTA is the applicability of HCT to companies operating in the deep offshore area which have transitioned to the fiscal framework of the PIA, pursuant to the provision of section 65(4) of the former. The provision of this section aligns with that of section 260(3) of the current PIA, except that the NTA now excludes "deep offshore" operations from the exemption previously granted under the former. This policy somersault in less than five years of the operation of the PIA in our view, is unwarranted and not business-friendly, as operators would have built their economic model of their oil and gas assets on the assumption of an HCT-free operation.

2. Treatment of Waivers or Refund of Liabilities

The NTA also introduces a more unified and comprehensive approach to the tax treatment of waived, released, or recovered liabilities. Under section 263(2) of the current PIA, such liabilities were automatically treated as taxable income, primarily as an anti-avoidance measure. However, that provision focused largely on liabilities where deductions had previously been claimed with respect to "revenue" expenditure. It was unclear what treatment to adopt where the waiver relates to expenditure of a capital nature. The revised framework under Section 193 of the NTA has now filled the vacuum in the PIA, by broadening the scope, to apply to all waived, released, or recovered liabilities, including those of a capital nature. Specifically, section 193(2) provides that where any "liability or expenditure of capital nature" is waived, it shall be treated as chargeable gains for CGT purposes.

The above reflects the government's tougher stance on curbing incidence of aggressive tax planning and tax avoidance. By tightening these provisions, the government aims to close the gap and realize more tax revenue from the generosity of a creditor, toward the tax-payer.

3. Integration of Existing Tax Incentives

The Act also incorporates some provisions of the Oil and Gas Companies (Tax Incentives, Exemption, Remission, etc.) Order, 2024 (OGCO). Specifically, Section 85 of the NTA outlines the tax credits for Non-Associated Gas Greenfield Development, applicable to onshore and shallow water terrains that reaches first commercial gas production between January 2026 and 1 January 2029, with some provisions around the sun set date. This policy consistency is applauded and should give operators some cheery news.

However, the other incentives such as the Midstream Capital and Gas Utilization Investment (GUI) Allowance (which was also introduced via the OGCO) and the Incentives for Deep Water Oil and Gas Projects (introduced by a Ministerial Order), which are currently in existence, have been excluded in the Act. This may signify the termination of the applicability of these incentives from January 2026. Incidentally, the claim of the GUI allowance was linked to the claim of the incentives in Section 39 of the CIT Act (i.e., available for claim upon expiration of the tax-free period granted in Section 39 of CIT Act). On the basis that Section 39 incentives would no longer be available from January 2026, it seems that the GUI allowance might have also been automatically terminated. However, as the Orders were not specifically repealed by the NTA, it is uncertain whether they may still be in effect and available to taxpayers. Where this is the case, government would need to clarify the basis for the claim.

• Petroleum Profit Tax (PPT) Act & Deep Offshore and Inland Basin Production Sharing Contracts Act (DOIBPSC)

The notable amendments introduced by the NTA to the current PPTA and DOIBPSCA are as follows:

1. Restriction on the application of reduced PPT rate

The NTA has clarified the time horizon for the application of the reduced PPT rate of 65.75%, which is currently the exclusive benefit for companies that have not fully amortised their pre-production capitalized expenditure. The provision of section 21(2) of the PPT Act has been given quite an extensive interpretation by some oil producers without limit to either the number of years for which the reduced rate should apply (i.e., as long as the company is yet to fully amortised its pre-production capitalized expenditure) or, whether it should apply to new acquirer of an interest in an oil asset whose vendor had previously enjoyed this benefit on the same asset! Section 99 of the NTA has now clarified that the reduced rate will apply for a maximum period of five years from a company's first accounting period. In addition, if an oil and gas asset is acquired from a company that has already enjoyed the reduced tax rate, the acquirer must apply the standard rate of 85% from its first accounting period.

2. Claim of Investment Tax Credit/Allowance

Investment tax credit /allowances (ITCs/ITAs) are an additional incentive to companies that operate in Nigeria's deep offshore terrain. It is computed as 50% of a company's QCE, and it is applied as an allowance (to reduce taxable profits), or a credit (to reduce tax payable), depending on when the PSC was signed. However, with the enactment of the PIA, any oil producer that has, or will convert to the fiscal incentives under that law will no longer be eligible to claim the ITC/ITA. Curiously, the NTA has only deleted the reference to ITCs and retained ITA in section 105 of Part III of the Third Chapter. This means that for companies who are yet to convert their licenses/leases under the PIA, only the ITA will apply to them. While the exclusion of ITC from the NTA is expected to resolve the issues that had arisen previously with regards to the claim of ITC (i.e. if it is dependent on when the initial or revised contracts were signed), it may open the door of controversy where an asset under PSC with ITC provision is still producing and yet to be decommissioned by 1 January 2026?

3. Royalty regime

Although, there were no changes to the royalty rates for companies under the PIA regime, the Act modifies the royalty rates structure applicable to the PPTA regime via the Seventh Schedule to the NTA. It introduces the royalty by price framework to the PPTA, under which currently, operators calculate and pay royalties only based on the location of the field, i.e., one-tier regime. Therefore, for operators that do not convert to PIA regime, it has significantly broadened the fiscal framework through the introduction of a two-tier royalty regime - based on production volumes/terrain (covering onshore, shallow water, deep offshore, frontier acreages, and inland basins) and based on price. The new provisions essentially introduce more favourable rates for low-output PSCs to encourage field development and further investment, but additional burden for operators who prefer to be taxed under the PPTA.

• Provisions of the NTA applicable across various tax regimes

1. Amendment of the Deductibility Test

A timely change introduced by the Act is the adjustment to the tax-deductibility framework for business expenses. A joint reading of Sections 20(1), 68 and 92 of the Act shows that the focus of tax-deductibility is now on whether the expense is "wholly and exclusively" incurred in generating the business income – for CIT, Hydrocarbon Tax (HCT) and Petroleum Profit Tax (PPT) purposes. The current framework under the CIT regime allows expenses that were "wholly, reasonably, exclusively, and necessarily" incurred to be deductible for tax purposes, while the PPT regime references "wholly, exclusively, and necessarily' incurred as its overall cost-deductibility parameter. There have been conversations on the need for the removal of the 'reasonability' parameter especially in the oil and gas sector, given its peculiarity. It appears that the drafters of the NTA have now considered the merits of these arguments in excluding the "reasonability and necessity" tests for deductibility purposes, given this background.

A similar update has also been introduced to the treatment of pre-production costs for upstream petroleum operations, as Section 74 of the Act now aligns with Section 68 by removing the "reasonability and necessity" tests. The authors believe that the elimination of these two tests would significantly reduce disputes and controversies between taxpayers and tax authorities that often stem from the subjectivity in determining whether an expense is reasonable and/or necessary for the operation of an oil and gas company.

2. Taxation of Non-Resident Companies

Taxation of non-resident companies (NRCs) is a major theme of the NTA. The Federal Government in what could be termed as concerted efforts to prevent base erosion and profit shifting (BEPS), has introduced various tax measures to ensure that revenues earned or derived by NRCs in Nigeria are fully taxed in the country. These include taxation on capital gains from indirect share transfers, taxation of foreign subsidiaries operating in Nigeria, and restrictions on certain deductible costs. It also covers the top-up tax mechanism aligned with the OECD's BEPS Pillar 2 framework, requiring member entities of MNEs, including those in free trade zones, and companies with a minimum turnover of ₦50 billion, to pay an effective tax at the rate of 15% of their net income. The implication of these measures is that upstream companies that have non-resident related parties or non-resident service providers operating in the country would need to review their operations in Nigeria to assess their tax footprints and the impact of the NTA.

3. Development Levy

Section 59 of the NTA introduces a new levy known as 'Development Levy", calculated as 4% of the assessable profit of all companies (excluding small companies and NRCs). This levy replaces the other taxes and levies currently being paid by companies such as Tertiary Education Tax, National Information Technology Development Agency (NITDA) Levy and the National Agency for Science and Engineering Infrastructure (NASENI), amongst others. This levy is not imposed on assessable profits calculated for HCT purposes. By streamlining the multiple levies and taxes into one, it will ease the administration of the levies by the tax authority and reduce compliance burdens on taxpayers. Also, the levy is tax-deductible for PPT purposes pursuant to the provision of section 92(1)(n) of the NTA.

4. Decommissioning and Abandonment Fund

Section 86 of the Act now requires companies to deposit 30% of their decommissioning and abandonment fund with an accredited Nigerian bank, for their decommissioning and abandonment expense to qualify for tax-deduction purposes. While the PIA was silent on the percentage of the fund that needed to be deposited into the account, the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) via the Nigeria Upstream Decommissioning and Abandonment Regulations 2023 (and the proposed amendments detailed on its website), has suggested a minimum of 15% for select parties. The NTA by this provision has now introduced a general threshold for companies under the PIA regime and tied it to tax-deductibility. This suggests that a company would be unable to claim a deduction until the amount in the dedicated account is not less than 30% of the approved fund amount. The introduction of this provision may constitute significant cash flow and compliance implications for companies in the upstream sector, and they would need to commence planning, strategically, to meet these obligations.

In contrast, Section 92(l) of the NTA gives a less stringent condition for the tax-deducibility of a similar expense incurred by companies under the PPTA regime, by hinging it only on the approval of the scheme or fund by the NUPRC. The disparity in the treatment of the same expense across different tax regimes does not provide a level-playing field for all operators. Nonetheless, producing companies need to ensure that they abide by the law as it impacts their operation.

5. Treatment of Asset Disposed

The NTA also includes gains from the disposal of assets in the computation of a company's revenue for CIT purposes. Under the current tax administration, balancing adjustment is used to calculate the gains and losses for tax purposes (and where required, capital gains would apply), while "revenue" was limited to proceeds / income earned by the company. However, the Act makes no reference to balancing adjustments in the First Schedule to the Act but expands the revenue scope by incorporating gains from "asset" disposal. Section 39 of the NTA details the approach for computing the gains that would be subject to tax. However, there is no reference to capital losses in the Act. Thus, in instances where companies make a loss on disposal, it is not clear what the expected treatment would be. Is the company expected to claim the loss on disposal amount / capital loss as a deductible expense? Or is there no relief for losses on disposal? Section 28(3) provides that loss on disposal of assets being deductible for individuals, but there is no similar provision for companies. Also, Section 21(k) of the Act deems any expense allowable as a deduction in determining chargeable gains as non-tax deductible for CIT purpose, suggesting that there is no deductibility for capital loss. The lack of specific provision for treatment of capital loss may be unduly punitive for tax-payers. It is hoped that the law makers will propose amendments to the NTA to close this gap.

6. Business Restructuring Provisions

The NTA also revamps business restructuring and reorganization rules for the upstream petroleum sector by replacing Sections 17 and 18 of the PPT Act with new provisions, particularly under Section 190(2), which governs the transfer of a trade or business to a new company. This section stipulates that the acquiring company's accounting period begins on the transfer date or a date within the same month, with tax authority's approval, and ending on December 31 of that year. This provision also attributes any gap between the old and surviving business as part of the new or surviving entity. The NTA further broadens the restructuring framework to include merger transactions and asset transfers with or without cessation, thereby allowing surviving entities in mergers to retain unutilized capital allowances, unabsorbed losses, and unclaimed Withholding Tax (WHT) credits, where certain conditions are met. It also exempts restructuring transactions from VAT.

It is hoped that with the simplification and clarification of the tax rules around business restructuring and oil assets portfolio alignment, operators would go through such processes in future, seamlessly.

7. Value Added Tax Test for Deductibility.

In several sections of the NTA {for example, 21(p), 27(2), 69(p), 71(4), 95(1l), 98(6)}, the deductibility of costs for income tax purposes is premised on their VAT chargeability. These sections stipulate that those expenses on which VAT is not charged and import duty / levy is not paid (for imported items) would not be considered allowable tax deduction, even if they are legitimately incurred for business purposes. This has also been extended to QCE, as capital allowance would not be allowable for claim on such costs except VAT has been accounted for on the QCE. The use of the words 'charged' and 'paid' for in the different instances in the above sections may suggest that where VAT is charged on an item but not paid, it would still be allowable for tax purposes. However, in the "reverse charge" case where a company self-accounts for the VAT and pays it, it is unclear whether such cost would still be disallowed for tax purposes? In any case, this provision suggests that a company may be held accountable for any inaction or non-compliance by its suppliers or service providers, emphasizing the importance of due diligence in vendor relationships.

8. Retention Requirements for Qualifying Capital Expenditures (QCEs)

Under the current administration, companies are expected to retain 1% of the value of QCE in the final year of claim until the asset is sold. However, the NTA appears to have deleted that requirement. Section 71(1)(c) of the Act clarifies that the annual allowance of 20% continues until the value of the acquisition costs for petroleum rights is fully written off. Additionally, the First Schedule to the Act explicitly states that the depreciation of acquired assets shall follow the rates specified in the schedule (which is 20% each for five years). The reference to the 1% retention is defined as a notional amount retained for statistical purposes only. This suggests that companies are now expected to claim 100% of their QCE as deductible, but compute 1% of the value of the asset for record purpose only. Companies must exercise care to delineate between the actual tax written down value (TWDV) of QCEs carried forward post-NTA yet to be claimed, capital allowances (CA) on new QCEs and the 1% calculated for statistical purposes to ensure appropriate computation of the CA claimable.

9. Additional Administration Requirements for Companies

The Nigeria Tax Administration Act (NTAA) introduces additional administration tasks for companies ranging from monthly and annual royalty returns (Sections 18 and 19, NTAA), and notification of tax planning initiatives (Section 30, NTAA) amongst others, reiterating the government's commitment to data collection which is necessary to strengthen compliance within the system. Sections 158 of the NTA and 23 of the NTAA also mandate the implementation of a fiscalisation system, which has commenced with the introduction of the national e-invoicing system. It is a phased implementation that has begun with large taxpayers, defined as those with revenue above five billion Naira (N5,000,000,000, approximately, US$3,200,000). These taxpayers must integrate their invoicing system with the FIRS' Merchant Buyer Solution (MBS') platform to enable real-time invoice generation, validation, and transmission through the designated e-invoicing channels. This system/regime essentially underscores the tax authorities' tilt towards the digitization of tax administration, to promote transparency, efficiency and enhanced compliance.

Commentaries and Smart Fixes: Turning Changes in the NTA into Opportunities?

The enactment of the NTA has overhauled the country's tax system. Concurrently, some of the changes may inadvertently expose companies in the oil and gas sector to additional tax burdens. These misgivings occasioned by the changes in the NTA call for actionable steps to manage the potential impact.

One of the biggest headaches of the NTA on upstream companies is the repeal of the exemption from HCT available to PIA-transitioned deep offshore operations. Companies impacted may need to engage with the government to revisit this policy somersault and its potential implications going forward, before it comes into effect in January 2026. This is because the exemption under the PIA has driven substantial investment in the deep offshore segment. Similarly, the integration of some existing tax incentives in the OGCO into the NTA and the exclusion of some of the incentives need to be addressed. One of the cannons of taxation is clarity and thus, it is hoped that the Federal Government will clarify the validity or otherwise of the tax incentives not incorporated into the NTA.

Another critical element of the NTA is the introduction of the development levy, for which certain categories of companies that were previously exempt from payment of some of the levies (e.g., NASENI and NITDA levies) by virtue of the nature of their businesses, would now be assessed to the levy. However, the impact of the higher rate would depend on the profitability of such companies, and it can be argued that streamlining of the levies into one would reduce administrative burdens (not financial impact) for most companies.

Several taxpayers have kicked against the VAT test included for tax-deductibility purposes. Non-compliance with the provisions on VAT already has steep penalties and extending the penalties to income tax non-deductibility may be unduly punitive for taxpayers. In some developed and developing economies, income tax deductibility does not strictly depend on VAT being charged/paid on an expense. Thus, the drafters of the law should consider reassessing the interaction of VAT with tax-deductibility to ensure that the provisions are reflective of the nation's current economic realities as well as align with the underlying objectives of the NTA.

Conclusion

The introduction of the NTA has sent ripples through the upstream sector due to the various and potentially contentious amendments to the fiscal space. As the government strives to position Nigeria as a frontrunner in fiscal best practices across Africa, and a preferred investment destination (by tackling tax revenue leakages and fostering investment opportunities), these changes demand attention. For companies in the sector, the time is now to thoroughly assess the NTA's provisions, anticipate their potential impact on business operations, and implement robust, tax-compliant systems ahead of the Act's commencement date. Engaging with tax authorities to seek clarity on the most challenging provisions, and proposing timely amendments where necessary will be crucial, to ensure a seamless transition and sustained growth in the long run.

Footnote

1. https://niser.gov.ng/v2/wp-content/uploads/2025/01/2025-FGN-PROPOSED-BUDGET-NISER-BRIEF.pdf

The opinion expressed in this article is solely personal and does not represent the views of any organization or association to which the authors belong.