The Petroleum Industry Bill (PIB) is currently under deliberation for passage at the National Assembly after the numerous setbacks to its enactment since 2007. The latest version of the Bill proposes several significant changes to the fiscal framework for the taxation of oil exploration and production (E&P) companies operating in Nigeria. One of such proposed changes is the introduction of the cost-price ratio (CPR) limit for E&P companies.

This article evaluates the potential implications of the CPR limit introduced in the PIB, vis-à-vis the practice obtainable in other jurisdictions.

What is the Cost Price Ratio?

Section 266 (2) of the PIB provides that "in determining the chargeable profit, the total cost shall not exceed the cost price ratio as determined in the Sixth Schedule"

Following from the above section, Paragraph 2 of the Sixth Schedule to the PIB provides that "All costs prescribed under Section 263 and the First Schedule to this Act in an accounting period the sum of which is eligible for deduction under the hydrocarbon tax shall be subject to a cost price ratio limit of 65% of gross revenues determined at the measurement points".

The Sixth Schedule further stipulates that any excess costs not deductible in a particular year of assessment may be carried forward to subsequent years. However, where any costs exceed the cost price ratio limit upon the termination of upstream petroleum operations related to crude oil, such costs shall not be deductible for purposes of calculation of the Hydrocarbon Tax (HT).

One obvious objective of this provision is to increase the tax collection by the government, as the restriction of deductible costs will result in higher tax payable for most companies.

Implications of the Cost Price Ratio Limit

Based on the aforementioned provisions, affected E&P companies will only be able to deduct up to 65% of the gross revenue as total costs in ascertaining the taxable profit for HT purposes. This implies that companies will be subject to minimum tax to be computed by applying the HT rates to 35% of the gross revenues for the relevant year. Meanwhile, the tax payable as a result of the Cost Price Ratio limit may not reflect the underlying profitability profile of the relevant companies, and this could effectively result in paying taxes on capital. In essence, an E&P company with profit margins of less than 35% would have to source for funds to pay HT despite its profits not being reflective of the taxes payable.

It appears that this provision may have been introduced to incentivize cost efficient production which though laudable, may be unattainable in the short term or in periods of low prices or attacks on oil installations. For instance, at current oil prices of about $60 per barrel (bbl), the total deductible costs per barrel to ensure recoverability would have to be only $39/bbl (65% of $60). However, this may not be achievable in the short term, given that the breakeven price for major proposed projects in Nigeria hovers around $48/bbl and can be as high as $93/bbl in extreme cases. Therefore, achieving significantly reduced cost of production should be through a holistic medium to long-term approach focused on operational efficiency and enhanced oil recovery technologies, and not necessarily by introducing a Cost Price Ratio limit.

Furthermore, some of the costs incurred by Nigerian E&P companies are unavoidable and not necessarily within the control of the affected companies. More so, these costs are typically scrutinised prior to approval. For instance, the Joint Operating Agreements governing joint venture operations, establish the powers and duties of the Operating Committee, which typically covers the final approval, revision, and/or rejection of all proposed programs and budgets after they have been reviewed and approved by any of the relevant sub-committees. This suggests that the approved costs are typically validly incurred, and the relevant companies should be able to recover such costs within the shortest possible time.

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