Decoding Capital Allowances: A Comprehensive Guide to the Nigeria Tax Act, 2025 for Petroleum Operations

Decoding Capital Allowances: A Comprehensive Guide to the Nigeria Tax Act, 2025 for Petroleum Operations

The Nigeria Tax Act, 2025 provides a vital fiscal roadmap for the oil and gas industry, setting clear rules for cost recovery and tax compliance. Part III – Capital Allowance for Petroleum Operations is a cornerstone of this legislation, establishing the framework for companies subject to both the Petroleum Profits Tax and the regulations governing Deep Offshore and Inland Basin Production Sharing Contracts. This detailed analysis from Bahas Books explores the full scope of these provisions, from fundamental definitions to asset disposal mechanisms.

Defining the Tax Landscape: Concessions, Leases, and Qualifying Costs

Understanding the definitions within the Act is the first step toward compliance. The term "concession" is defined broadly to cover all legal instruments granting rights to petroleum, encompassing an Oil Exploration License, an Oil Prospecting License, and an Oil Mining Lease. Crucially, it extends to any right, title, or interest in the oil itself, including the right to acquire such interests.

A "lease" is defined to include any agreement for a lease whose term has commenced, any tenancy, and any agreement for the letting or hiring of an asset, but it explicitly excludes a mortgage or similar financial agreements. To maintain tax continuity, the Act includes provisions that deem a lease to continue even when a lessee remains in possession after termination without a new grant. Furthermore, if an old lease ends and a new lease is immediately granted to the same party for the same asset, the new arrangement is treated as a continuation of the first lease.

The concept of "qualifying expenditure" is the foundation for all cost recovery. It represents capital expenditure incurred in an accounting period and is divided into four distinct categories:

  1. Qualifying Plant Expenditure: Spending on assets such as plant, machinery, and fixtures.

  2. Qualifying Pipeline and Storage Expenditure: Investment in pipelines and storage tanks.

  3. Qualifying Building Expenditure: Costs for the construction of permanent buildings, structures, or works not covered in the first two categories.

  4. Qualifying Drilling Expenditure: This covers all other capital expenditure connected to petroleum operations, specifically including costs for acquiring petroleum deposits/rights, searching for, discovering, and testing deposits, and constructing works or buildings that are likely to have little or no value once the associated petroleum operations cease. A critical restriction ensures that any amount already deductible under section 92 of the Act cannot also be classified as qualifying expenditure.

The Two Pillars of Allowance: Standard and Investment Rates

The Act provides two distinct allowances for companies incurring qualifying expenditure.

First, the Petroleum Investment Allowance (Table I) is a special, supplementary allowance granted when an asset is first used for petroleum operations. This allowance varies based on the operational environment, rewarding deeper and offshore operations:

  • 5% for Onshore operations.

  • 10% for operations in territorial waters and continental shelf areas up to and including 100 metres of water depth.

  • 15% for operations in water depth between 100 and 200 metres of water depth. This is claimed in addition to the standard capital allowance.

Second, the standard Capital Allowance (Table II) is the primary mechanism for cost recovery. A company is due this allowance from the accounting period in which the qualifying expenditure was incurred. The rates are fixed at a uniform 20% for the 1st, 2nd, 3rd, 4th, and 5th years across all four categories of qualifying expenditure. For internal statistical purposes, a notional 1% of the qualifying capital expenditure must be recorded, though this figure does not alter the actual allowance claimable.

A significant provision covers Exploration expenditure, allowing the cost of the first and second appraisal wells in the same field during the pre-production period to be claimed as a 100% deduction in the year the cost is incurred. Any remaining amount of this specific expenditure is then amortised at the 20% per annum capital allowance rate, commencing from the start of the relevant accounting period.

It is critical to note that capital allowance for hydrocarbon tax computation is not available for cost recovery in production sharing contracts, as these agreements are governed by their own model contract provisions.

Asset Usage, Disposal, and Pre-Commencement Rules

The Act provides detailed rules governing asset status, partial use, and disposal.

The Residue of an asset is defined as the total qualifying expenditure incurred on the asset minus the total capital allowance already made. This residue is the foundation for the Disposal without change of ownership rule: if an asset is disposed of but the owner retains ownership, the owner is deemed to have bought the asset back immediately for a price equal to the residue at the disposal date, ensuring the allowance process continues seamlessly. Furthermore, an asset for which capital allowance has been granted cannot be disposed of without a Certificate of Disposal issued by the Commission.

An asset is deemed "in use" even during a period of temporary disuse. For assets acquired for petroleum operations but not immediately used for that purpose, they are deemed to be in use on the date the expenditure was incurred. A crucial time limit is enforced: if an allowance has been claimed but the asset is not put to use within five years from the date the expenditure was incurred, the capital allowance claimed shall be withdrawn and added back to tax. This rule requires the Service’s approval to apply.

For assets used partly for petroleum operations and partly for other purposes, the allowance is computed as if the expenditure and asset were used wholly and exclusively for upstream petroleum operations. The resulting allowance must be treated as just and reasonable by the Service, taking all circumstances into account.

The Act specifies conditions for the Disposal of qualifying expenditure. For permanent works, disposal includes sale, expiration of the interest, termination of a leasehold interest without the reversionary interest holder acquiring the right to possess the land, or demolition/cessation of use. Plant, machinery, or fixtures are disposed of if sold, discarded, or if their use ceases. Drilling-related assets are disposed of if sold, cease to be used, or if the company stops operations and receives insurance or compensation.

The Value of an asset at disposal is its net proceeds of sale, or, if not sold, the open market value estimated by the Service, minus reasonable selling expenses. Insurance or compensation monies are typically treated as net proceeds. However, if compensation is used for the replacement of the lost asset, it is not treated as net proceeds, and the allowance for the new asset is granted based on the replacement cost, factoring in the residual or scrap value of the old asset.

The rules for pre-commencement expenditure state that any qualifying expenditure incurred before a company's first accounting period (excluding the specific drilling activities) is deemed to be incurred on the first day of its first accounting period. If an asset is disposed of before the first accounting period begins, any resulting loss incurred is deemed to be qualifying petroleum expenditure incurred on that first day, while any profit realised is treated as income of the company in its first accounting period.

Finally, the Act addresses issues of complexity and exclusion. Apportionment of value between a qualifying and non-qualifying asset, or for a Part of an asset (including undivided joint interests), must be made justly and reasonably by the Service. Assets purchased or disposed of in one bargain are treated as purchased or disposed of together. Notably, any expenditure allowed as a deduction under any other provision of the Act is excluded from qualifying expenditure, as is expenditure on an ocean-going oil tanker plying between Nigeria and any other territory.

For more insights into the fiscal and legal landscape of Nigeria’s energy sector, visit bahasbooks.com

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