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September 2, 2021

Nigerian Government signs Petroleum Industry Bill 2020 into Law

Executive summary

On 16 August 2021, the Nigerian President, Muhammadu Buhari GCFR, signed the Petroleum Industry Bill into law as the Petroleum Industry Act, 2021 (referred to below as the Act or PIA).

The Act which is split into four major sections seeks to adopt a commercial approach to the governance framework of the petroleum sector through a clear separation of the regulatory and commercial bodies to promote efficiency and transparency in the sector. It also sets forth the institutional framework for the Nigerian Petroleum sector.

The Fiscal section of the Act provides the framework to improve investment in the petroleum industry while ultimately generating revenue for the Government.

Also, the Act seeks to respond to the administrative challenges facing stakeholders in the industry. Accordingly, the administrative section of the PIA aims to strengthen the governing institutions, safeguard transparency and accountability and foster sustainable development in Nigeria’s Oil and Gas sector.

Given the myriad of issues between stakeholders operating in the industry and the host communities, the host community section of the PIA provides for the establishment of the host communities’ development trusts to foster sustainable prosperity, enhance peace, and good relationships between licensees, lessees, and the communities. Settlors are obliged to contribute 3% of their actual operating expense of the preceding year which will be managed by the Trust for the socio-economic development of the communities.

Accordingly, stakeholders should assess the key changes introduced by the PIA, specifically changes with the potential to significantly impact current operations. These should be appropriately measured and factored into the relevant business metrics.

This Alert summarizes the key changes introduced by the Act.

Detailed discussion

Governance and institutions

The objective of the Governance framework is to create a conducive business environment for petroleum activities through the creation of governing institutions. Highlights of the PIA in this regard are summarized below.

The Minister of Petroleum

The Act vest certain powers on the Minister of Petroleum ranging from the power to formulate, monitor and administer government policy in the petroleum industry, to the power to negotiate treaties or other international agreements on matters pertaining to petroleum on behalf of the Government.

Establishment of the Upstream Regulatory Commission

The PIA establishes the Upstream Regulatory Commission (the Commission) to regulate the technical and commercial upstream petroleum operations, and the Commission has the legal right to sue and to be sued. The objectives of the Commission are to regulate, implement and ensure efficiency in the upstream petroleum operations including the technical, operational, and commercial activities.

Establishment of Nigerian Midstream and Downstream Petroleum Regulatory Authority

The Act establishes the Nigerian Midstream and Downstream Petroleum Regulatory Authority (the Authority), which will be a body corporate with perpetual succession and a common seal. The Authority will regulate the technical and commercial operations of the midstream and downstream segments of the petroleum industry.

Establishment of NNPC Limited

The Minister of Petroleum within six months from the commencement of the Act is required to set up NNPC Limited as a fully-owned government entity whose shares shall be held by the Ministry of Finance Incorporated and the Ministry of Petroleum Incorporated in equal portions on behalf of the Government. Such shares are not transferrable in any form unless approved by the Government. Also, assets, interests and liabilities identified by the Minster of Petroleum and the Minister of Finance shall be transferred from NNPC to NNPC Limited.

Establishment of incorporated joint venture companies

The Act provides that on a voluntary basis, NNPC Limited and other parties to a joint operating agreement in the upstream sector may restructure their Joint Operating Agreement (JOA) as an incorporated joint venture (IJV) by negotiating the principles set forth in the Act. The IJV will not be subject to the provisions of the Fiscal Responsibility Act and the Public Procurement Act.


The key objectives of the Fiscal aspect of the Act is to encourage investment in the petroleum industry while optimizing revenues accruing to the Government. Highlights of the key provisions of the fiscal provisions are summarized below.

Introduction of Hydrocarbon Tax and Companies Income Tax

The PIA stipulates that the Hydrocarbon Tax (HT) will only apply to petroleum operations involving crude oil and condensates and natural gas liquids produced from associated gas in an oil field. Also, the Act stipulates that upstream companies will additionally be subject to Companies Income Tax (CIT). Thus, the HT rate as specified in the Act for petroleum mining leases (PML) and petroleum prospecting licenses (PPL) across onshore and shallow water terrain will be 30% and 15%, respectively. CIT will be applicable at the rate of 20% or 30% depending on the turnover of the company. 

Consequently, HT will not be deductible in arriving at the CIT payable for any company.

Crude oil revenue

Crude oil revenue of a company is the value of chargeable oil adjusted to the measurement points based on:

  • Proceeds of all chargeable oil sold by the company
  • Value of all chargeable oil disposed by the company

Allowable and disallowable expenses

Expenses to be deducted in arriving at the adjusted profit of any company involved in upstream petroleum operations related to crude oil must meet the wholly, reasonably exclusively and necessarily incurred test. Deductions allowed now include:

  • Any amount contributed and approved by the Commission for the purpose of decommissioning and abandonment.
  • Costs of gas reinjection wells, which are re-injecting natural gas that otherwise would be flared, subject to ratification by the Commission.
  • Any amount contributed to any fund, scheme or arrangement approved by the Commission including the Host community Development Trusts, Niger Delta Development Commission, and Environmental Remediation Fund, among others.

However, deductions not allowed now include but are not limited to the following:

  • Expenditure 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 tertiary education tax, company income tax or any other income similar taxes.
  • Production bonuses, signature bonuses paid for the acquisition of, or of rights in or over, petroleum deposits, bonuses or fees paid for renewing petroleum mining lease or petroleum prospecting license or marginal field or fees paid for assigning rights to another party.
  • Any contributions to a pension, provident or other society, scheme or fund which may be approved, with or without retrospective effect, by the National Pension Commission.
  • All custom duties.


The PIA provides that all production of petroleum, including production tests will be subject to royalties payable to the Government. In order to ascertain the royalty payable, condensates will be treated as crude oil and natural gas liquids will be treated as natural gas.

Accordingly, crude oil royalties for onshore area and shallow water area will be 15% and 12.5%, respectively. For deep offshore area and frontier basin area, the royalty rate will be 7.5%.

Royalty based on production for natural gas and natural gas liquids will be at a rate of 5% of the chargeable volume. The royalty rate for natural gas produced and utilized in-country will be 2.5% of the chargeable volume.

For deep offshore fields with a production during a month of not more than 50,000 barrels per day (bpd), the royalty rate is reduced to 5%. Production above 50,000 bpd will be at the initial rate specified for deep offshore fields which is at 7.5%.

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

  • First 5,000 bpd                          5.0%
  • Production over 5,000 bpd     7.5%

Provided that fields with crude oil and condensate produce more than 10,000 barrels of oil per day (bopd) during a month, the share of the production over 10,000 bopd per month shall be at the royalty rates of 15% and 12.5% for onshore fields and shallow water fields, respectively.

The Act also establishes a royalty payable based on price for crude oil and condensates as follows:

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

Between the price range of US$50 and US$100 and also the price range of US$100 and US$150, the royalty rate by price will be determined by linear interpolation. The price benchmarks will be adjusted each subsequent calendar year for inflation by adding 2% to the benchmark price. Royalties based on pricing do not apply to gas production and frontier acreages.

Cost price ratio

The Act provides that costs eligible for deduction as specified by the Act excluding royalty, rent on PML or PPL, etc. and capital allowance shall be subject to a cost price ratio (CPR) limit of 65% of gross revenues determined at the measurement points. The total costs to be allowed as a deduction in subsequent years will be an amount that if added to the sum of the total costs to be allowed, the total costs to be deducted shall not exceed the cost price ratio limit of 65%.

Also, any excess costs that exceed the CPR limit upon termination of any upstream petroleum operations related to crude oil will not be deductible for the purpose of calculating HT.

Artificial transactions

The Act provides that transactions between related parties which are not carried out at arm’s length will be deemed to be artificial or fictitious transaction. The tax authority reserves the right to disregard the transaction or make necessary adjustments with respect to the Company’s liability to tax.

The provisions of the Income Tax (Transfer Pricing) Regulation 2018 will be the legal basis used to determine whether the transactions between related parties are artificial or fictitious in nature.

Annual allowance on acquisition of Petroleum Rights

The Act provides for the claim of annual allowance of 20% and with a retention of 1% in the last year until the asset is disposed of, on the acquisition cost of Petroleum Rights (signature bonus).

Trade or business sold or transferred

The Act provides that where a trade or business of upstream petroleum operations carried on in Nigeria by a company is sold or transferred to another company for the purposes of a better organization of that trade or business and the Federal Inland Revenue Service (FIRS) is satisfied that one of the companies has control over the other and has had so for a consecutive period of at least three years prior to the date of reorganization, the FIRS may on or before the date on which the trade or business is so sold or transferred, direct that the company acquiring the asset so sold or transferred shall be deemed to have received all allowances given to the company selling or transferring the trade or business in respect of the asset.

If the acquiring company disposes of the assets acquired within three years from the date of acquisition, any concession enjoyed will be rescinded.

Consolidation of cost and HT

The PIA provides that companies engaged in upstream petroleum operations are allowed to consolidate costs for the purpose of CIT.

A company engaged in upstream petroleum operations related to crude oil across terrains will be allowed to consolidate costs and taxes for the purposes of HT only across assets in which it holds licenses and leases in accordance with the two categories of chargeable tax across the onshore and shallow water terrain.

Production allowance

The Act provides that production allowance per field for crude oil production by a company for leases granted after the commencement of the Act will be:

  • For conversion contracts, the production allowance will be the lower of US$2.50 per barrel and 20% of the fiscal oil price.
  • 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 waters, 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, 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.

Penalty for late filing of returns

The Act specifies that the penalty for not filing estimated and actual income tax returns on or before the statutory deadline date will be NGN10 million on the first day and NGN2 million every subsequent day in which the failure occurs, or other sum as may be prescribed by the Minister of Finance by Order published in the Gazette.


In response to the challenges facing stakeholders in the industry, the Nigerian Government has long made its intention known regarding an overhaul of the petroleum industry, thereby incorporating efficiency and transparency in both upstream and downstream sectors in line with international best practices.

The highlights of the administrative framework of the PIA which aims to strengthen the governing institutions, establish a strong regulatory framework, safeguard transparency and accountability, encourage exploration & exploitation of oil resources and foster sustainable development in Nigeria’s oil and gas industry are summarized below.

Introduction of new licenses

The Act introduces the Petroleum Exploration License (PEL), Petroleum Prospecting License (PPL) and Petroleum Mining Lease (PML) which will effectively replace the Oil Exploration License, Oil Prospecting License and Oil Mining Lease. These will be granted to qualified applicants to explore, carry out petroleum exploration operations on an exclusive basis and to search for, win, work, carry away and dispose of crude oil, condensates, and natural gas respectively. 

The terms of the newly introduced license/lease are similar to the terms of the licenses to be replaced.

However, the Minister may, on the recommendation of the Commission, grant a PPL or PML to a winning bidder, provided that the winning bidder has complied with the requirements of the bid invitation. In addition, the Minister is required to inform the Commission of his decision within 90 days of the application for license or lease and where he fails to inform the Commission within the stipulated time, the license or lease shall be deemed granted.


The PIA provides that after 10 years of the commencement of a PML, the applicable Lessee shall relinquish all parcels which do not fall within the boundary of a producing field; and any formation deeper than the deepest producing formation shall be relinquished, and the deep rights shall vest in the Government.

Voluntary conversion of an oil prospecting license to a petroleum prospecting license or oil mining lease to petroleum mining lease

The Act provides that companies can voluntarily convert to the terms of the PIA. To convert to PIA terms, the license holder will be required to enter into a conversion contract which will contain a termination clause of all outstanding arbitration and court cases related to the respective OPL or OML and for the avoidance of doubt any stability provisions or guarantees provided by NNPC in respect of OPL and OML will be void.

License holders have an option to convert at the earlier of 18 months after the commencement of the Act or the expiration date of the OML or date of conversion of the OPL to OML.

Relinquishment upon renewal or conversion of an oil mining lease

The Act provides that a holder of an OML, including an OML subject to a production sharing contract, will at the renewal date applicable to the OML or at the conversion date, designate each area and zone of the OML as areas and zones:

  • Which, in the opinion of the holder, merit appraisal and for which the holder of the OML is prepared to present an appraisal program.
  • For which the holder is prepared to make a declaration of a commercial discovery.
  • For which the holder is prepared to make a declaration of a significant gas discovery or a significant crude oil discovery.
  • For which development of a field is underway based on prior approvals after having declared the discovery commercial or if no such declaration was made after having made a final investment decision to develop the field.
  • For which regular commercial production is occurring.

The Act also provides that where the total acreage selected is less than 40% of the area to which the applicable OML applies, the holder may select additional areas covered by the OML for conversion to a PPL in such a manner that the total of all areas selected shall not be more than 40% of the OML and where the total acreage selected is more than 40%, the holder shall be entitled to keep such larger area, consisting solely of the selected areas.

Marginal field

The PIA provides that a discovery declared as a marginal field prior to 1 January 2020 and is not producing shall be converted to a PPL and shall benefit from the PIA terms for a new acreage. Some of the PIA terms include HT rate of 15%, CIT rate at 30% and royalty rates ranging from 5% to 15% depending on the level of crude oil production per day.

Midstream and downstream gas infrastructure fund (MGIF)

The Act provides for the establishment of the MGIF, to be funded by a levy of 0.5% derived from the wholesale price of petroleum products sold in Nigeria and natural gas produced and sold in Nigeria. The MGIF will be collected on a wholesale basis.

The levy is due and payable into the MGIF within 21 days from the sale of the product. The Minister of Petroleum is also empowered to issue regulations, among other things, for the imposition of penalties for late and or non-payment of the levy or submission of false information in respect of the levy.

Activities requiring a license for midstream and downstream gas operations

The Act provides that a person shall not undertake the following activities with respect to midstream gas operations - establish, construct or operate a facility for the processing of natural gas; establish, construct or operate a facility for the storage of natural gas; etc. except in accordance with an appropriate license issued by the Authority. Such license will include:

  • Gas Processing License
  • Bulk Gas Storage License, Gas Transportation Pipeline License
  • Wholesale Gas Supply License
  • Retail Gas Supply License
  • Gas Distribution License

Activities requiring a license for midstream and downstream petroleum liquids operations

The PIA provides that a holder of a subsisting lease, license or permit who is engaged in the above listed activities in midstream or downstream petroleum liquids operations prior to the effective date of the Act will within 24 months from the effective date, apply to the Authority for issuance of the applicable license. Such licenses will include:

  • Crude Oil Refiner License
  • Bulk Petroleum Liquids Storage License
  • Petroleum Liquids Transportation Pipeline License
  • Transportation Network Operator License
  • Wholesale Petroleum Liquids Supply License
  • License for Distribution of Petroleum Products, etc.

Licensees are required to undertake the activities contemplated by the license in a manner that best complies with the regulations issued by the Authority.

Host Community Development (HCD) for petroleum operations

Incorporation of host communities’ development trust

The Act provides for the incorporation of the host communities’ development trust for the benefit of the host communities for which the settlor is responsible. For settlors operating in shallow water and deep offshore, the littoral communities and any other community determined by the settlors will be host communities for the purposes of the Act.

Sources of funding for petroleum host communities’ development trust

The Act provides that a settlor shall make annual contribution of 3% of its actual annual operating expenditure in the preceding calendar year in respect of upstream petroleum operations affecting the host communities.

Deduction of payment for petroleum host community development

The Act provides that where in any year, an act of vandalism, sabotage or other civil unrest occurs that causes damage to petroleum and designated facilities or disrupts production activities within the host community, the community shall forfeit its entitlement to the extent of the cost of repairs of the damage that resulted from the act.


Key implications from the changes in the Act include:

  • Establishment of the Commission and Authority should effectively repeal the Acts establishing current regulators of the upstream and downstream sector of the Nigerian oil and gas industry such as the Department of Petroleum Resources and the Pipeline and Products Marketing Company (Nigeria).
  • Current petroleum operations involving a joint operating agreement with the NNPC have in the past been challenged with the issue of cash calls. Therefore, the variation using the IJV structure should help mitigate the lingering issues resulting from the inability of the NNPC to honor its cash call obligations and the administrative burden from dispute settlements in recovering the huge arrears owed to operators and other JV partners.
  • The HT rates specified in the PIA are significantly lower than the current petroleum profit tax rate even with the inclusion of the CIT for all upstream operations across different terrains. Notwithstanding, operators and contractor parties may need to assess the impact of the change in rate across the different portfolio of assets held in specific terrains as this should aid the decision of voluntarily converting to the PIA terms before the expiration of the licenses held. Also, operators will be required to register a separate company for execution of such operations.
  • With respect to contributions, consistent with the tax deductibility of general provisions, only actual contributions made to the relevant funds indicated in the Act should be allowed for tax purposes. Effectively, where a provision is made, the provision will be disallowed for tax purposes accordingly. Also, production and signature bonuses as well as license renewal fees paid by the companies in the ordinary course of business will not be allowed for tax purposes. Accordingly, this should increase the effective tax rate of the relevant companies in any year of assessment. Notwithstanding, the PIA characterize some of these costs as qualifying capital expenditure and as such, they should be eligible for a capital allowance deduction.
  • It is pertinent for related parties operating in the Nigerian oil and gas industry to review their transfer pricing compliance so as to avoid adjustment of transactions between related parties.
  • Considering the PIA’s requirements to report separately the value of the rights and assets, and the grant of annual allowance on the value of these rights, companies intending to dispose of assets may need to consider the potential impact of a claw back on capital allowance initially claimed on the entire acquisition cost of the asset before disposal.
  • The impact of the grant of production allowance compared to the investment tax allowance and credit on license and lease holders is not clear and might lead to a distortion in investment decisions as it suggest that there will no longer be a capital uplift for companies already producing.
  • With respect to the conversion of licenses, existing license holders will need to evaluate the extent of the PIA fiscal terms on their license interest and decide if it is beneficial to continue to operate under the PPTA regime within the voluntary period of 18 months after the commencement of the Act or at the expiration of the license, whichever occurs first. This should be assessed against the consequences of conversion, including the relinquishment of acreages and forfeiture of any dispute resolution with the Government.
  • In light of the current responsibilities, companies operating in the industry already have regarding corporate social responsibility initiatives which are directed at some of these host communities, it is important for companies to understand how it will implement the transition of these initiatives to the HCDF.
  • Vandalization of oil facilities has been an issue for the petroleum industry, the reduction of the contribution due to the host communities to the extent of the disruptions caused as a result of acts of vandalism, sabotage or other civil unrest should help reduce the operator’s huge cost outlay associated with disruption of production facilities on the field.

The reforms by the PIA constitute an overhaul of the legislation governing the Nigerian oil and gas industry. Although there are still uncertainties as to the implementation of certain provisions of the Act and its potential to attract foreign direct investments, stakeholders should evaluate the impact of the provisions of the PIA on their current operations with a view to map out strategies that maximize the benefits and also mitigate any downside as reflected in the Act.


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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