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January 13, 2021

Nigeria’s Government considers Petroleum Industry Bill 2020, a new framework for the oil and gas sector

Executive summary

The Nigerian President, President Muhammadu Buhari, presented the reworked Petroleum Industry Bill (PIB or the Bill) to the Nigeria Legislature for consideration after many delays in the legislative review process over the past 15 years.

The Bill, which is intended as a complete overhaul of the Nigerian oil and gas sector, seeks to, among others, ensure an increased level of transparency and accountability in the sector by strengthening the governing institutions to attract investment capital through changes to the governance, administrative, regulatory and fiscal framework of the Nigerian oil and gas industry.

This Alert summarizes the key changes introduced to the fiscal framework of the Bill.

Detailed discussion

The key objectives of the fiscal aspect of the Bill is to encourage investment in the petroleum industry while optimizing revenues accruing to the Government. It also seeks to ensure that transparency is achieved in the administration of the petroleum sector and Nigerian content is promoted through an efficient and effective regulatory framework.

The following sections outline some of the key changes made with respect to the proposed fiscal framework of the Bill.

Introduction of a new tax regime and tax rate

The Bill proposes to replace the existing Petroleum Profits Tax (PPT) with the National Hydrocarbon Tax (NHT). According to Section 260 (1) of the Bill, the NHT is expected to be charged only to oil production, condensates, and natural gas produced from associated gas in an oil field. Associated and non-associated natural gas will not be subject to the NHT. The NHT rates are categorized below:

Fiscal regime


Shallow water

Deep offshore

New acreage




Converted acreage




In addition to the NHT, companies involved in upstream petroleum operations will also be subject to Company Income Tax (CIT) at the rate of 30%. A company that intends to be involved in all the value chains of the sector, i.e., upstream, midstream and downstream of the petroleum operations will be required to register a separate company for execution of such operations. Furthermore, the NHT will not be deductible in arriving at the CIT payable for any company.

The Bill also provides that a newly incorporated company that is yet to commence bulk or disposal of chargeable oil is now required to file its audited accounts and returns within 18 months from the date of its incorporation.

Allowable and non-allowable deductions

In addition to the requirement under the PPT Act for allowable expenses to be wholly, exclusively and necessarily incurred to be tax deductible, the Bill proposes the introduction of a reasonability test for the purpose of determining adjustable profit.

Additional deductions allowed now include:

  • Any amount contributed and approved by the Commission for the purpose of decommissioning and abandonment
  • Interest payments on loans if these amounts are payable on capital employed solely for upstream operations and they reflect market conditions
  • Any amount contributed to any fund, scheme or arrangement approved by the Commission including the Host community Development Trusts, Niger Delta Development Commission, Environmental Remediation Fund, among others

Deductions not allowed now include:

  • Expenditures and fees incurred as a penalty for flare of natural gas
  • Head office costs incurred outside Nigeria
  • Tax inputted in a contract or an agreement on a net tax basis and paid by a company on behalf of the vendor or contractor
  • Amounts incurred in respect of the tertiary education tax, CIT or any other similar income taxes


Assessable profits, chargeable profits and allowances

Section 265 of the Bill provides that assessable profit is to be determined after deducting losses incurred in prior years from the adjusted profit.

Chargeable profits is to be determined after deducting the allowances granted to the company from the assessable profits. In determining the chargeable profit, the total cost shall not exceed the cost price ratio (CPR) limit of 65% of gross revenues determined at the measurement points. Any excess costs that exceed the CPR limit upon termination of any upstream petroleum operations related to crude oil shall not be deductible for the purpose of calculating the NHT. Any unutilized cost is to be carried forward to a future period provided that the actual costs to be deducted do not exceed the actual costs.

For the acquisition cost on petroleum rights, the value of the rights and the value of the assets acquired will be reported separately. Value of the rights will be eligible for an annual allowance of 10% while the value of the assets will enjoy the usual capital allowance rate of 20% with 1% remaining until disposal.

Production incentives

In place of the current Investment Tax Credit (ITC) and Investment Tax Allowance (ITA) as applicable, there will be a production allowance for crude oil production by leases which are converted to oil mining leases based on a conversion contract and their renewals which is the lower of US$2.50 per barrel and 20% of the fiscal oil price.

The production allowance for new acreages will be determined as follows:

  • For onshore areas, the lower of US$8 per barrel and 20% of the fiscal oil price up to a cumulative maximum production of 50 million barrels from commencement of production and the lower of US$4 per barrel and 20% of the fiscal oil thereafter.
  • For shallow water areas, the lower of US$8 per barrel and 20% of the fiscal oil price up to a cumulative maximum production of 100 million barrels from commencement of production and the lower of US$4 per barrel and 20% of the fiscal oil thereafter.
  • For deep offshore areas, the lower of US$8 per barrel and 20% of the fiscal oil price up to a cumulative maximum production of 500 million barrels from commencement of production and the lower of US$4 per barrel and 20% of the fiscal oil thereafter.


Consolidation of costs and taxes

Companies engaged in upstream petroleum operations related to crude oil across different terrains can now consolidate costs and taxes for the purpose of the hydrocarbon tax only across assets in which it holds licenses and leases.


All production of petroleum, including production tests shall be subject to royalties. For royalty purposes, condensates shall be treated as crude oil and natural gas liquids shall be treated as natural gas.


Royalty oil

Royalty gas

Onshore area



Shallow water (Up to 200m)



Deep offshore



Frontier basin



Domestic gas



For Deep offshore fields with production during a month of not more than 15,000 barrels per day, the royalty rate will be 7.5%. Production above 15,000 barrels per day will be at the rate specified in the table above.

Royalties for onshore fields and shallow water fields, including marginal fields with crude oil and condensates production of not more than 10,000 barrels per day (bpd) during a month shall be calculated on a tranche basis as follows:

  • First 5,000 bpd   5.0%
  • Next 5,000 bpd   7.5%

In addition to a royalty payable on production, the Bill also sets aside a royalty payable based on price for crude oil and condensates:

  • Below US$50 per barrel      0%
  • At US$100 per barrel           5%
  • Above US$150 per barrel   10%

Between US$50 and US$100 and US$100 and US$150, the royalty rate by price will be determined by interpolation, e.g., if the price is US$75 per barrel, the royalty rate per price will be 2.5%. The price benchmarks are adjusted annually for inflation by adding 2% to the benchmark price and these royalties based on pricing do not apply to gas production and frontier acreages.


The Bill proposes an increase in penalties for not filing income tax returns from NGN10,000 on the first day of default and NGN2,000 for every other subsequent day to NGN10,000,000 and NGN2,000,000, respectively.

With regards to penalties on non/late payment of tax, the company will be subject to a penalty of 10% and interest at the prevailing LIBOR or any other successor rate plus 10% as against the previous rate of 5%.

Furthermore, the Bill also provides that a person who fails to comply with the provisions or any regulations therein for which no specific penalty has been provided, shall be liable to an administrative penalty of NGN10,000,000. Where default continues, there would be a further administrative penalty of NGN2,000,000 or such sum as may be prescribed by the Minister of Finance.


The following are key implications from the proposed changes under the Bill:

  1. Although the PPT was expunged and replaced with NHT & CIT for companies engaged in upstream petroleum operations, this might not be as incentivizing as it seems as it may lead to overall higher taxes for an organization engaged in both oil and gas operations.

    An example is the current practice of deducting gas expenditure against oil income which leads to a lower PPT payable and ultimately, lower taxes for an organization engaged in both oil and gas. This practice will no longer be allowed upon the enactment of the PIB. Also, companies will have to pay close attention to the computation of these taxes given that they are governed by different Acts.
  2. Considering the significant capital requirements for new projects in the oil and gas industry, restrictions on the deductibility of some valid operating expenses such as head office costs incurred outside Nigeria as well as the maximum cost recovery limit of 65% may discourage investment in this industry thereby stripping one of the major aims of attracting investment in the sector. Alternatively, incurring such expenses in Nigeria in order to meet the deductibility requirement should serve as a measure to promote local content within the industry.
  3. The replacement of ITA & ITC with production incentives might lead to a distortion in investment decisions as there will no longer be a capital uplift for companies already involved in production. Further, the Introduction of cost consolidation for companies in the upstream petroleum operations now implies that losses from some assets can be offset against the profit-making ones which should ultimately provide tax planning measures across consolidated fields.
  4. The Deep Offshore and Inland Production Sharing Contract Act, amended in 2019, specified an additional royalty based on the applicable price of crude oil, condensate and natural gas when the price exceeds US$20 per barrel for deep offshore or frontier basin. Proposed amendments in the Bill once enacted will extend the rate to productions within onshore and shallow waters with a revised price benchmark of US$50 per barrel.

It has become imperative for the Federal Government of Nigeria to ensure the passage of the Bill given the decreasing revenue base from oil activities and the immediate need to buffer this with the right policies to attract investment. It is pertinent for companies engaged in petroleum operations to begin to evaluate the impact of adopting the fiscal framework of the PIB before the mandatory adoption on their businesses and for stakeholders to continue to engage with the Government on the grey areas in the Bill before it is passed into law.


For additional information with respect to this Alert, please contact the following:

Ernst & Young Nigeria, Lagos
Ernst & Young Société d’Avocats, Pan African Tax – Transfer Pricing Desk, Paris
Ernst & Young LLP (United Kingdom), Pan African Tax Desk, London
Ernst & Young LLP (United States), Pan African Tax Desk, New York



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