1. General Structure of Hydrocarbon Ownership and Regulation
1.1 System of Hydrocarbon Ownership
In Nigeria, the system of hydrocarbon ownership is based on the concept of state ownership of mineral resources. The ownership of oil and gas is vested in the federal government of Nigeria (the "Federal Government"), which is vested with ultimate authority and control over the exploration, exploitation, development and production of hydrocarbon resources in the country.
However, the Nigerian Constitution acknowledges the notion of derivation, which provides for the sharing of revenue derived from natural resource exploitation among the Federal Government, state governments and local government. Since oil and gas resources are geographically and geologically situated within states in Nigeria, these states are entitled to a portion of the revenue generated from the exploitation of these oil and gas resources within their lands. Although state governments do not hold any title in oil and gas resources, they have the power to regulate certain aspects of oil and gas operations such as land use and environmental engagements.
Private hydrocarbon ownership is also recognised. Private individuals and companies can hold participating interests in oil and gas projects through joint ventures, production sharing contracts or other commercial arrangements with the Federal Government through NNPC Limited (the national oil company) and its subsidiaries.
1.2 Regulatory Bodies
The primary Federal Government agencies that regulate hydrocarbon activities across Nigeria which are governed by the Petroleum Industry Act, 2021 (PIA) include the following.
- The Minister of Petroleum Resources (the "Minister") is responsible for formulating, monitoring and administering government policies in the petroleum industry. The Minister gives general policy directives to the Commission and Authority on matters within their respective jurisdictions and matters related to co-operation among the two regulatory agencies as contemplated under the PIA. The Minister is also responsible for approving the award and/or issuance of licences, leases, permits and approvals over petroleum assets, as well as the assignment or revocation of such licences, leases, permits and approvals over petroleum assets, upon the recommendation of the Authority or Commission.
- The Nigerian Upstream Regulatory Commission (the "Commission") is responsible for the technical and commercial regulation of the upstream petroleum operations. It oversees activities such as issuing permits and licences as well as superintending hydrocarbon exploration and production operations, drilling operations, field development, environmental protection and safety. The Commission is also empowered to make regulations pursuant to the PIA on the matters within its jurisdiction.
- The Nigerian Midstream and Downstream Petroleum Regulatory Authority (the "Authority") is responsible for the technical and commercial regulation of midstream and downstream petroleum operations in the Nigerian petroleum industry. It oversees activities such as the bulk storage, distribution, marketing and transportation of petroleum products. The Authority is also empowered to make regulations pursuant to the PIA on the matters within its jurisdiction.
1.3 National Companies
Nigeria's national oil and gas company is the Nigerian National Petroleum Company Limited ("NNPC Limited") which was incorporated pursuant to the PIA. It plays a central role in the oil and gas industry and collaborates with local and international companies for the development and management of hydrocarbon resources in the country.
Prior to the enactment of the PIA, the national oil company existed as the Nigerian National Petroleum Corporation (the "Corporation"). The Corporation has now assigned all its rights and liabilities to NNPC Limited. NNPC Limited has subsidiaries and affiliates such as NNPC Exploration and Production Limited and NNPC Retail Limited that engage in various businesses across the oil and gas value chain.
1.4 Principal Hydrocarbon Law(s) and Regulations
The PIA is the primary law regulating activities in the Nigerian petroleum industry which consolidates the requirements for operating in the industry. The PIA repealed the Petroleum Act and replaced dated laws which hitherto regulated the Nigerian Oil and Gas sectors. The PIA introduces comprehensive reforms, which are aimed at enhancing transparency, promoting investment, and optimising the management of Nigeria's petroleum resources. The PIA establishes new institutions and frameworks, such as the Commission and the Authority, and also introduces fiscal reforms, which include a revised fiscal framework, royalty rates and profit-sharing mechanisms. The PIA emphasises local content development, environmental protection and community engagement, while fostering a more competitive and efficient petroleum industry in Nigeria. The subsidiary regulations, issued by the Commission or Authority pursuant to the PIA, apply to the entire value chain of the hydrocarbon industry. These regulations include:
- The Midstream and Downstream Petroleum Operations Regulations (the "MDPRO Regulations");
- Petroleum (Transportation and Shipment) Regulations; and
- Domestic Gas Delivery Regulations.
The following laws and their subsidiary legislation are also applicable throughout the subsistence and validity OR conversion of all Oil Prospecting Licences (OPL) and Oil Mining Leases (OML) (see 2.2 Issuing Upstream Licences/Obtaining Hydrocarbon Rights for notes on OPLs and OMLs).
- Petroleum Act, Cap. P10, Laws of the Federation of Nigeria 2004 ("LFN 2004").
- Oil Pipelines Act, Cap. O7, LFN 2004.
- Deep Offshore and Inland Basin Production Sharing Contracts Act, Cap. D3, LFN 2004.
Other key federal laws and regulations include the following.
- The Nigerian Oil and Gas Industry Content Development Act, Act No 2, 2010 ("Nigerian Content Act") – this act promotes Nigerian content in and the participation of Nigerian companies and citizens in the oil and gas industry. It sets out the requirements for the use of local goods and services, capacity development and overall local content in the oil and gas industry.
- Environmental Impact Assessment Act, Cap. E12 LFN 2004 ("EIA Act") – the EIA Act provides a framework for assessing and managing the potential environmental impacts of various development projects, including those in the oil and gas sector. Project proponents are required to prepare an Environmental Impact Statement (EIS) that outlines the potential impacts of the relevant projects on the environment as well as the proposed mitigation measures. The EIA is approved by the Federal Ministry of Environment.
Pooling and Unitisation
A licensee or lessee shall promptly notify the Commission of any petroleum reservoir which extends beyond the boundary of its licence/lease area. The Commission, upon receipt of such notice, may direct the applicable licensees/lessees to enter into a unit/unitisation agreement to develop the petroleum reservoir as a unit, subject to the Commission's approval. Where the petroleum reservoir extends into an area not covered by a licence or lease, the Commission may extend the boundaries of the licence or lease to the petroleum reservoir or conduct a bid round for the adjacent area. The joint development of straddling reservoirs and contiguous non-straddling reservoirs have increased the government's returns and reduced development and operating costs for licensees and lessees.
2. Private Investment in Hydrocarbons: Upstream
2.1 Forms of Private Investment: Upstream
Upon the acquisition of any of the upstream licences or leases (ie, Petroleum Prospecting Licence (PPL), Petroleum Mining Lease (PML), OPL, and OML), the licences or leases may be administered under the following contractual arrangements.
- Production Sharing Contracts (PSCs) – This is the most common form of contract used in Nigeria. Under a PSC, NNPC Limited, acting on behalf of the Federal Government, enters into an agreement with private investors – the contractors. The contractors bear the entire costs and risk of exploration, development and production of hydrocarbons; and in return, they receive a share of the hydrocarbon production to cover their costs and they also share in the profit as determined by the contract terms.
- Joint Venture Agreements (JVA) – Under a JVA, NNPC Limited partners with private investors through an incorporated/unincorporated joint venture. The parties contribute capital and resources to the joint venture and share in the costs, risks and benefits of the exploration and production activities, in the proportion of their participating interest. The hydrocarbon produced is shared in proportion to each party's participating interest.
- Service Contracts – These are typically entered into between NNPC Limited acting as concessionaire on behalf of the Federal Government, and a private oil company. A service contract may be a Pure Service Contract or a Risk Service Contract. Under the Pure Service Contract, the contractor is entitled to a flat fee for the service rendered, as well as recovery of its operational costs regardless of whether the project is commercially viable. On the other hand, under a Risk Service Contract, the contractor is only entitled to compensation for its risk and services when the project is declared to be commercially productive. Thus, where the project is not viable, the contractor loses all its investment.
- Concession Contracts – Historically, the Federal Government granted concessions over a specific area for a given period. The concessionaires are required to pay royalties and taxes to the Federal Government.
2.2 Issuing Upstream Licences/Obtaining Hydrocarbon Rights
A Petroleum Exploration Licence (PEL) is granted by the Commission to any qualified persons and it confers on the licence holder, a non-exclusive right to carry out petroleum operations but not the right to win, extract, work or otherwise treat petroleum discovered, in the licence area.
A PPL is obtained through a fair, transparent and competitive and non-discriminatory bidding process conducted by the Commission. The bid is conducted by the Commission in compliance with regulations and/or guidelines made pursuant to the PIA. These regulations and/or guidelines prescribe the minimum pre-qualification criteria in terms of technical and financial requirements and previous experience. The winning bidder is determined on the basis of the following bid parameters:
- a single bid parameter based on any of these parameters:
- signature bonus to be paid in full prior to the granting of the licence or lease by or on behalf of the winning bidder;
- a royalty interest;
- a profit split or profit oil split;
- a work programme commitment during the initial exploration period; or
- any other parameter as may be defined specific to a bid round; and
- the winning bidder shall be selected based on a combination of the bid parameters specified in the first bullet point above, aggregated by a points system which bidders can also assess.
Following the bid, the Commission shall recommend the winning bidder to the Minister, for an award of a PPL. The Minister shall inform the Commission of its decision within 90 days of the application, failing which, the PPL shall be deemed to have been granted.
Notwithstanding the foregoing parameters, the Federal Government may direct the Commission to negotiate and award a PPL to a qualified investor pursuant to a multilateral or bilateral treaty between Nigeria and another country.
The signature bonus payable in respect of such award shall be based on a transparent method for evaluating the acreage.
A PML may be granted by the aforementioned bid process over a previously appraised area already covered by a PPL or a surrendered, relinquished or revoked PML.
For each commercial discovery of crude oil, natural gas or both, a PML is also granted to a PPL licensee who has received approval for the applicable field development plan (FDP) from the Commission and has satisfied the conditions imposed in the PIA. The area to be derived from a PPL for the purpose of a PML award shall be proposed by the licensee based on an independent engineering report, which shall not be binding on the Commission.
It is important to mention that although OPLs and OMLs have similar terms to the PPL and PML, respectively, and were issued under the Petroleum Act regime, they will no longer be issued by the Commission, and all existing OPLs and OMLs that were not voluntarily converted to PPLs and PMLs will continue in force under until their terms expire.
In evaluating a PPL licensee's declaration of commercial discovery, the Commission shall examine the following:
- an approved Nigerian content plan pursuant to the Nigerian Oil and Gas Industry Content Development Act; and
- environmental management plan in accordance with the Environmental Impact Assessment Act.
2.3 Typical Fiscal Terms: Upstream
As an incidence of its ownership rights over natural resources, the Federal Government participates in the revenue derived from oil and gas exploration, exploitation and production activities in Nigeria through various means. The typical fiscal terms under upstream licences in Nigeria include various components and may vary depending on specific contracts and negotiations.
The fiscal terms provided in the PIA are as follows.
- Signature bonus – this is a fee paid in full prior to the granting of the PPL or PML by or on behalf of the winning bidder.
- Royalty – all production of petroleum, including production tests shall be subject to royalties calculated monthly. Royalties are levied on a non-discriminatory basis with respect to all PPLs/PMLs. Royalty rates depend on the terrain of the licensed or leased area and may be two-pronged based on production and the price of crude oil; with the exception of frontier acreages for which there shall be no priced-based royalty.
- Production-based royalty for crude oil and condensates:
- onshore areas and shallow water (up to 200m depth) – first 5,000 barrels of oil per day (bopd) –5%;
- onshore areas and shallow water (up to 200m depth) – next 5,000 bopd - 7.5%;
- onshore areas – any quantity above 10,000 bopd – 15%;
- shallow water (up to 200m depth) – any quantity above 10,000 bopd – 12.5%;
- deep offshore (greater than 200m depth) – 50,000 bopd or less – 5%;
- deep offshore (greater than 200m depth) – over 50,000 bopd – 7.5%; and
- frontier basin – any quantity – 7.5%.
- Price-based royalty for crude oil and condensates:
- price below USD50 per barrel – 0%;
- price at USD100 per barrel – 5%;
- price at USD150 per barrel – 10%; and
- price between USD50 and USD100 per barrel or between USD100 and USD150 per barrel – linear interpolation.
- Royalty for natural gas and natural gas liquids utilised in-country shall be 2.5% of the chargeable volume, while royalty for export gas shall be 5% of the chargeable volume.
- Rents – Each PPL and PML shall be subject to the annual rent as prescribed in the relevant regulations issued by the Commission from time to time.
2.4 Income or Profits Tax Regime: Upstream
Hydrocarbon Tax (HT)
Pursuant to the PIA, this tax shall apply solely to crude oil, field condensates and liquid, natural gas liquids derived from associated gas and produced in fields covered by PMLs and PPLs, upstream of the measurement points. This tax varies based on the stage of development the field is in:
- before appraisal – HT will not be levied;
- upon appraisal or commercial discovery – HT will be 15% of the chargeable income;
- upon field development or commercial production – HT will be 30% of the chargeable income.
Companies Income Tax (CIT)
This tax is levied in accordance with the Companies Income Tax Act, as amended, and it is payable by any company involved in the upstream, midstream or downstream petroleum operations. The CIT rate is 30% of the chargeable income payable on an actual year basis.
Petroleum Profits Tax (PPT)
PPT continues to apply to OMLs and OPLs until they are converted to PPLs or PMLs.
PPT is chargeable on profits derived from crude oil and field condensates, while profits from natural gas are subject to CIT.
The principal PPT rate is 85% with the following exceptions:
- for newly licensed/leased companies within their first five years of operation – 65.75%; and
- for deep offshore profits – 50%.
Value Added Tax (VAT)
VAT is payable pursuant to the VAT Act, 2004, as amended. The tax rate is 7.5% and it is invoice based. The tax is levied at every stage of a transaction, but it is ultimately borne by the final consumer of goods and services. Upstream companies that receive services from foreign companies are required to remit VAT to the tax authorities.
Tertiary Education Tax (TET)
TET is also imposed on all categories of companies (upstream, midstream and downstream companies) at the rate of 3% of assessable profit.
2.5 Federal or State Companies
Right to be Carried
Where a model PML or PPL provides for a concession agreement which may include an incorporated or unincorporated joint venture with NNPC Limited, the concession agreement shall include a carried interest provision wherein the Federal Government through NNPC Limited has the right to participate up to 60% in the concession agreement.
Right of First Refusal
Where the Commission resolves that data acquired under a Petroleum Exploration Licence (see 2.8 Other Key Terms: Upstream) requires testing and drilling of identifiable prospects, and no commercial entity has publicly expressed an intention of testing or drilling such prospects, the Commission shall request the services of NNPC Limited to drill or test such prospects on a service fee basis. Where a commercial discovery is made in the course of rendering these services, NNPC Limited has the first right of refusal in the award of the acreage for subsequent development and other petroleum operations in such frontier acreages under the PIA.
Right to Second Personnel
Prior to the enactment of the PIA, the joint venture agreements executed by and between NNPC and the private oil companies, typically provided that the JV partners shall facilitate the training of NNPC personnel in the joint operations in accordance with a training programme and conditions approved by the parties.
2.6 Local Content Requirements: Upstream
The Nigerian Content Act was enacted to promote indigenous participation and the development of Nigerian content in the Nigerian oil and gas industry. The Nigerian Content Act mandates that all entities involved in the Nigerian oil and gas industry prioritise Nigerian independent operators in their overall project development and management approach.
The Nigerian Content Act imposes certain requirements on operators in the Nigerian oil and gas industry ("Operators") which include:
- giving first consideration to Nigerian independent operators in the award of oil blocks, oil field licences, and oil lifting licences and in all projects for which a contract is to be awarded in the Nigerian oil and gas industry;
- securing the approval of the Nigerian Content Development and Monitoring Board (NCDMB) for advertisements, prequalification criteria, technical bid documents, technical evaluation criteria and proposed bidders lists for all contracts estimated by the Operator to be in excess of USD1 million;
- submitting a Nigerian Content Plan (prepared in accordance with the Nigerian Content Act) to NCDMB when bidding for any licence, permit or interest and before carrying out any project in the Nigerian oil and gas industry, in order to demonstrate compliance with the requirements of the Nigerian Content Act;
- preparing and submitting various plans including the Employment and Training Plan and Research and Development Plan in the form prescribed by the Nigerian Content Act, to ensure compliance with the requirements of Nigerian content; and
- giving exclusive consideration for contracts and services to Nigerian indigenous service companies that demonstrate ownership of equipment, Nigerian personnel and capacity to execute such contracts and services.
The Schedule to the Local Content Act stipulates minimum Nigerian local content levels in terms of man-hours, spend, volume, usage and amounts. Nigerian indigenous companies shall not be disqualified from bids solely on the basis that they are not lowest financial bidder provided that the value does not exceed the lowest bid price by 10%.
2.7 Development and Production Requirements
A PPL holder shall commit to a work programme and other terms as the Commission shall determine.
Once a PPL holder considers that a discovery merits appraisal, the licensee shall inform the Commission within 180 days and submit the following for approval, within one year:
- a commitment to an appraisal programme of not more than three years with a scope permitting the licensee to declare a commercial discovery, where the result of the appraisal is positive; and
- the appraisal area, which shall not be larger than the outer boundary of the discovery as determined by the licensee within the confines of the area provided for in the PPL.
Upon appraisal of the submission, the Commission shall act on the approval request within 60 days of submission and, upon approval, the licensee shall carry out the appraisal programme. Where the Commission fails to respond on the submitted appraisal programme within the 60 days, the appraisal shall be deemed approved.
Upon approval, the licensee may declare a commercial discovery, a significant gas/crude oil discovery or inform the Commission that the discovery is of no interest to the licensee.
Discovery of no Interest
Where a licensee declares a discovery to be of no interest, the Commission may require the relinquishment of the parcels that cover the structure of such discovery.
In the event of a significant crude oil/gas discovery, the licensee shall be entitled to retain the area of such significant discovery pursuant to a PPL for no more than ten years from the date of the declaration, as determined by the Commission. Where the licensee has not declared a commercial discovery after the retention period, the retained area shall immediately be relinquished by the licensee and the applicable PPL shall expire.
In the event that a commercial discovery is declared, the licensee shall submit an FDP, together with a commitment to carry out the work described in the FDP, within two years of the declaration.
The Commission shall evaluate the technical and commercial terms of the FDP based on the criteria set out in the PIA, and within 180 days after the submission of the FDP, the Commission shall either approve the FDP or decline approval of the appraisal area. Where the Commission fails to respond within 180 days, the FDP shall be deemed approved and a PML shall be granted upon the approval of the FDP.
Other Development and Production Requirements
Environmental Management Plan (EMP)
The licensee/lessee is also required to submit and EMP in accordance with the EIA Act. The EMP must be submitted to the Commission within six months after the grant of the PML/PPL.
Permits issued by the National Environmental Standards and Regulations Enforcement Agency (NESREA)
See 5.1 Environmental Laws and Environmental Regulator(s).
The PML/PPL holder must obtain permits from the Commission to operate a drilling rig or to drill a well.
2.8 Other Key Terms: Upstream
The key terms of upstream licences in Nigeria vary, depending on the specific type of licence and the applicable laws and regulations. However, a general overview of some common key terms will include the following.
This grants the holder a non-exclusive right to carry out petroleum operations within the licensed area. The licence shall be valid for an initial term of three years and may be renewable for an additional three years subject to fulfilment of prescribed conditions. The PEL does not grant a right to win, extract or otherwise treat any petroleum discovered at the licensed area. The Commission has exclusive rights and title over any data acquired by a PEL licensee, subject to the reserved right of such licensee to grant data use licence to third parties for a fee, upon the written authorisation of the Commission.
This grants the licensee the exclusive right to drill exploration and appraisal wells and non-exclusive right to carry out petroleum exploration operations within the area provided for in the licence. The PPL also grants a right to win, extract or otherwise treat any petroleum discovered at the licensed area, subject to fulfilment of conditions imposed under the PIA.
A PPL typically includes an initial exploration period of three years – for onshore and shallow water acreages, or five years – for deep offshore and frontier acreages. The PPL may be renewed for an optional extension period of three years.
The area provided for in a PPL is limited to:
- 350 square kilometres for onshore or shallow water acreages;
- 1,000 square kilometres for deep offshore acreages; and
- 1,500 square kilometres for any frontier acreages.
A PPL requires the licensee to commit to a work programme to drill at least one exploration well to a minimum depth specified in the licence for each period, except for frontier acreages, where the work programme during the initial exploration period may only consist of geophysical work. Furthermore, the licensee shall present an annual work programme in each calendar year, containing the committed work, at a minimum.
This lease grants the lessees the right to win, work and otherwise crude oil, condensates and natural gas; drill exploration and appraisal wells and carry out related test production, all on an exclusive basis. The lessee is also entitled to carry out petroleum exploration operation on a non-exclusive basis. Upon the grant of one or more PMLs, the annual work programme and status report of a PPL licensee shall include the programme and report for each lease.
The term of a PML is a maximum of 20 years, which term shall include a development period of five years for onshore acreages, or seven years for shallow water, deep offshore and frontier acreages, unless otherwise stipulated in the PML. A PML may be renewed for one or more successive additional terms of not more than 20 years each. Where the lessee does not initiate regular commercial production within the development period, the Commission shall recommend to the Minister that the PML be revoked or the development period extended (where the lessee is able to provide a valid basis for an extension).
A PML may be renewed for one or more additional terms of not more than 20 years each, subject to the conditions set out in the PIA.
Licensees shall relinquish every area that is not an appraisal area, retention area or lease area prior to the expiration of the term of the PPL.
After ten years from commencement of a PML, the 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.
Upon conversion from an OML to a PML, the holder shall relinquish up to 60% of the leased area.
A licensee or lessee may voluntarily surrender or relinquish part or whole of the licensed or leased area in accordance with the terms of the PIA.
Domestic Gas Delivery Obligations (DGDO)
The Commission shall prescribe and allocate domestic gas delivery obligations among all lessees based on the domestic gas demand requirements determined by the Authority in accordance with the PIA. In addition to other penalties, a lessee who does not comply with their DGDOs, shall not be entitled to supply natural gas to any new midstream gas export operations.
2.9 Transfers of Interest: Upstream Licences and Assets
The holder of a PPL or PML shall not assign, novate or transfer its licence or lease, or any right, power or interest without the prior written consent of the Minister upon the recommendation of the Commission.
Where a licensee or lessee wishes to assign, novate or otherwise transfer its interest, it shall make an application for approval of transfer to the Commission in the format prescribed by the Commission. The Commission shall, within 60 days of receipt of the application, make a recommendation to the Minister to approve or disapprove the application. Within 60 days of receipt of the recommendation of the Commission, the Minister may deny or approve the application subject to any terms and conditions imposed by the Commission. Where no response on the application has been received within 60 working days, the Minister shall be deemed to have consented to the transfer.
The Minister may grant consent to an assignment, novation or transfer of interest when the transferee:
- is a company incorporated in Nigeria;
- is of good reputation and standing;
- has sufficient technical knowledge, experience and financial resources to enable it to carry out, effectively, all responsibilities of a licensee/lessee under the PPL/PML; and
- complies with the Federal Competition and Consumer Protection Act.
The holder of a PEL shall not assign, novate or transfer its licence without prior written consent of the Commission.
A percentage of the value of the transaction, determined by the Commission, shall be payable as consent fee before the Minister's consent is granted. Following the enactment of the PIA, the Commission is yet to release any regulations providing for the applicable fees for the consent of the Minister to the assignment of PPL or PML. However, pursuant to the regulations made under the Petroleum Act, which continue to apply to the transfer of OPLs and OMLs, the consent fee shall range from 5–10%.
Capital Gains Tax (CGT)
CGT applies to the disposal of assets, including shares, at the rate of 10%.
Preferential or pre-emptive rights
These rights are not mandated by statute, but may be exercised by NNPC Limited, where provided for in the contractual framework of the PML and/or the PPL.
2.10 Restrictions on Production Rates
The Commission, in conjunction with NNPC Limited, may allocate production quotas for the purpose of curtailing export of petroleum.
Being a member of the Organisation of Petroleum Exporting Countries (OPEC), Nigeria is subject to OPEC's production quota. Nigeria's OPEC quota for 2023 is 1.74 million barrels per day.
3. Private Investment in Hydrocarbons: Midstream/Downstream
3.1 Forms of Private Investment: Midstream/Downstream
Private investors may acquire equity stakes or shares in existing midstream and downstream companies (including government entities) or projects subject, however, to obtaining the requisite regulatory approvals, licences and permits.
Joint ventures are also very common forms of investment in the midstream/downstream industry. Investments can be made by forming partnerships with existing midstream and downstream entities. The Joint venture partnerships could be entered into for the purpose of construction of pipelines, storage facilities and transportation systems.
Upon formal application to the Authority by interested persons, licences may be obtained to carry out all midstream and downstream petroleum activities including the construction and operation of midstream and downstream facilities, trading in petroleum liquids and petroleum products.
Although a majority of the midstream/downstream assets are owned by the Federal Government, there is no statutorily sanctioned monopoly in the midstream and downstream sector.
3.2 Downstream Operations Run by a National Monopoly: Rights and Terms of Access
The Nigerian Gas Transportation Network Code (NGTNC), which was launched in August 2020, consists of a comprehensive set of regulations governing the transportation of gas in Nigeria. The Network Code establishes the terms and conditions for a standardised and open-access utilisation of gas transportation infrastructure that includes the Escravos-Lagos, Oben-Ajaokuta and Obiafu-Obrikom-Oben pipeline systems. The gas transportation infrastructure which is owned by the Nigerian Gas Company (NGC), is used for conveying gas by shippers in compliance with the NGTNC. Additionally, it applies to any other existing or future pipeline systems used for gas transportation.
The NGTNC establishes a contractual framework between the NGC – the sole pipeline operator currently licensed by the Authority under the NGTNC – and other entities involved in gas transportation through the pipeline systems. Its purpose is to ensure open access to the gas transportation network. Access to the pipeline system is granted through designated system entry points for gas delivery and system exit points for gas off-take.
The charges payable by shippers pursuant to the NGTNC include:
- capacity charge – a fixed charge payable based on a shipper's registered capacity. It is calculated on a daily rate in Unites States dollars per MMscf/day of the system capacity multiplied by the number of days in a year;
- commodity charge – this is a variable charge payable based on a shipper's daily quantity output (SDQO) and shipper daily quantity input (SDQI) for the gas flow day;
- overrun charge – this is payable monthly where either a shipper's capacity is negative or where SDQO/SDQI exceeds available system capacity on any gas flow day;
- cumulative imbalance charge – this is payable where there is an over-delivery or under-delivery excess;
- scheduling charge – this is payable where the shipper's SDQO/SDQI varies from nominated quantities above the 5% tolerance; and
- entry point non-compliant gas transportation charge – this is payable by all delivering shippers at a system entry point to the NGC where the NGC accepts delivery of non-compliant gas at any system entry point.
3.3 Issuing Midstream/Downstream Licences
Licences in the midstream and downstream industry are issued by the Authority for each regulated downstream/midstream activity. Applications for licences, permits or authorisations are made in a form prescribed in regulations or guidelines issued by the Authority. Currently, there is no bidding process involved in the issuance of midstream and downstream licences.
Activities for which the Authority may issue licences, permits or authorisations encompass gas operations and petroleum liquid operations and these licences, permits and authorisations include:
- establishment, design construction or operation of a gas processing facility, gas transportation and distribution system;
- wholesale/retail gas supply, trading and settlement operations;
- industrial gas storage and utilisation;
- domestic gas aggregation;
- bulk storage of gas, or petroleum liquid storage;
- operation of gas export and import terminal facilities;
- import and export of natural gas and gas products;
- establishment, design construction or operation of a hydrocarbon processing facility or petroleum liquids pipeline; and
- petroleum product distribution, amongst others.
To facilitate the acquisition of licences, permits or authorisations, applicants are required to submit specific reports and demonstrate compliance with designated requirements as outlined by the PIA, guidelines and regulations.
These requirements include the following:
- environmental impact assessment (EIA) reports;
- engineering studies, including front-end engineering design, safety studies, protection analysis, explosion studies, etc;
- submission of a decommissioning and abandonment (D&A) plan; and
- local content requirements.
Upon issuance of the relevant permit or licence of approval, the Authority may impose requirements on the licensee, including bonds or any other performance guarantees.
3.4 Fiscal Terms and Commercial Arrangements: Midstream/Downstream
Supply and Offtake Arrangements
These agreements define the terms of supply and purchase of petroleum products among producers, refineries, marketers and end-users. They provide for critical elements, including but not limited to product specifications, pricing mechanisms, delivery timetables, quality assurance protocols and payment conditions.
Storage and Terminal Services Arrangements
These contracts involve the use of storage facilities and terminal services for storing and handling petroleum products. It is typical to have upstream companies establish midstream affiliates to carry out the storage of the petroleum and gas.
The PIA specifically provides that companies involved in different streams of the oil and gas industry are required to register and use different entities for each stream.
This arrangement is entered into between the producer and the buyer for the transportation of crude oil products using pipelines. It is also relevant for the transportation of petroleum (oil and gas) products to wholesalers and/or retailers.
This involves an agreement where a crude oil processing company would process crude oil (gas or petrol) for an agreed fee.
Gas Sale Aggregation Agreements (GSAAs)
This is an agreement entered into by gas producers in fulfilment of their DGDO. The parties to this agreement are usually the gas sale aggregator – Gas Aggregation Company of Nigeria Ltd/Gte. (GACN), the gas producer as seller and the buyer. Gas pricing under the GSAAs is regulated by the PIA.
Regulation of Fiscal Terms and Terms of Service
Typically, the terms of service and fiscal provisions in commercial agreements within the midstream and downstream sector are established through mutually agreed contracts. However, specific operational aspects may be governed by pricing methodologies and tariffs. For instance, the PIA stipulates that the domestic base price for gas is determined through regulations issued by the Authority.
3.5 Income or Profits Tax Regime: Midstream/Downstream
Companies involved in midstream and downstream activities are subject to CITA, TET and VAT (see 2.4 Income or Profits Tax Regime: Upstream).
The following incentives apply to downstream/midstream activities.
- Pioneer Status – the Industrial Development (Income Tax Relief) Act Cap I7 LFN 2004, offers a tax holiday for up to five years to companies engaged in the refining of crude oil, gas production and manufacture of refined petroleum products.
- Gas Utilisation Incentives – the CITA grants a tax holiday of up to five years to companies engaged in gas utilisation in downstream operations.
- Export incentives – pursuant to the Government's Export Expansion Grant, Nigerian exporters can get an export credit certificate to the tune of 5–15% of their export, which can be used in the settlement of all government taxes.
Additionally, companies engaged in approved activities within areas designated as export processing or free trade zones, enjoy a 100% income tax holiday for their activities within the zone.
3.6 Special Rights for National Companies
There are no special rights that accrue to NNPC Limited and its affiliate entities in connection with midstream and downstream licences.
3.7 Local Content Requirements: Midstream/Downstream
See paragraph 1.4 Principal Hydrocarbon Law(s) and Regulations and 2.6 Local Content Requirements: Upstream.
3.8 Other Key Terms: Midstream/Downstream
Pursuant to the MDPRO Regulations, a licence issued by virtue of the regulations shall expire on 31 December of the year it was issued, except otherwise stated in the licence. The regulations also provide that where there is a modification of a facility with change in capacity or product slate on or before 31 December, the subsisting licence shall become invalid, and a new licence shall be issued. However, the term of a domestic gas aggregation licence shall be effective for two years.
An application for renewal of a licence, permit or authorisation shall be made not less than 30 days before the expiry of the original licence and in a manner prescribed by the Authority.
There are no specific domestic supply obligations in the midstream and downstream sector. However, the PIA provides for national strategic stocks for petroleum products which the Authority shall determine and designate the operator of a storage facility to hold and maintain.
The MDPRO Regulations provide that crude oil, condensates, liquid petroleum products and natural gas liquids shall not be exported from Nigeria without a valid Wholesale Petroleum Liquid Supply Licence from the Authority and export permit from the customs authority.
Furthermore, licensees bear D&A responsibilities, encompassing the implementation of an authorised D&A programme as approved by the Authority. Licensees are also required to establish a dedicated D&A Fund (see 5.4 Decommissioning Requirements).
Finally, a licence or permit holder who has commenced activities and has ongoing operations shall, except where a shorter period is stipulated in the licence or permit, give the Authority a minimum of 12 months' notice in writing of its intention to cease its activities where the licensed activity is no longer permitted or economically justifiable. The holder of the licence or permit has to demonstrate that the requirements of the law in respect of relinquishment, decommissioning and abandonment of installations and reclamation of land have been complied with.
3.9 Condemnation/Eminent Domain Rights
The acquisition of surface rights is conducted in accordance with the provisions outlined in the Land Use Act (LUA). The LUA is administered by the governor of each state in accordance with the relevant state land laws and regulations.
Licences or permits issued by the Authority are subject to the applicant's compliance with the provision of the LUA in respect of compensation for midstream and downstream operations. The Governor of a state where land is required for activities licensed by the Authority may issue a certificate of occupancy (a leasehold title under the LUA) in respect of the land.
Subject to any terms prescribed by the Authority, licensees or permit holders are entitled to surface rights such as rights of way and easements for their midstream or downstream operations. For efficiency, the Authority may also preserve such rights so that they may continue to enure for the benefit of subsequent licensees or permit holders.
3.10 Laws and Regulations Governing Transportation
Transportation of hydrocarbons is regulated by the Authority at the federal level and there is no separate municipal authority for this activity.
The PIA and the Petroleum (Transportation and Shipment) Regulations, 2023 are the principal regulation that governs the transportation, loading, lifting, shipment and export of natural gas or its derivatives, petroleum liquids, petroleum products or any other form of petroleum liquids throughout Nigeria. These activities are subject to the terms and fees prescribed by the permits, licences or authorisations issued by the Authority and there is no difference in regulatory treatment of intra-state and interstate pipeline systems.
3.11 Third-Party Access to Infrastructure
The Authority may grant a transportation pipeline licence with open access provisions in favour of third parties (ie, the licensee shall be a common carrier).
Where such provisions are included in the licence, the open access shall be provided:
- by the licensee on a non-discriminatory basis between system users with similar characteristics;
- in respect of any available capacity where the capacity is not subject to prior contract; and
- in accordance with the NGTNC or any separate network code issued by the Authority for the common carrier.
As stated above, licences are issued separately for transportation of petroleum liquids and transportation of gas. Furthermore, where a company intends to provide services in multiple segments of the market, different entities must be registered and used for each stream of operation – ie, a company intending to operate in the midstream and downstream sector is required to register a midstream company and a downstream company separately for that purpose.
3.12 Restrictions on Product Sales: Local Market
To engage in the sale of petroleum products within the local market, it is imperative to acquire the necessary licence from the Authority as provided for in the PIA and the MDPRO Regulations.
Subject to federal anti-competition laws and the requirement that each incorporated entity must not operate in both the upstream and midstream/downstream sector, there is no restriction on participation in different aspects of the petroleum value chain.
3.13 Laws and Regulations: Imports and Exports
The laws and regulations governing the export of crude oil, natural gas and petroleum products include:
- the PIA and its subsidiary legislation;
- Nigeria Customs Service Act, 2022;
- Customs, Excise Tariff, etc (Consolidation) Act 2004;
- Nigerian Export Promotion Council Act Cap 306, LFN, 1990 as amended by Act No 64 of 1992 (the "NEPC Act");
- the Oil and Gas Export Free Zone Act, 1996;
- the Nigerian Export Processing Zone Act, 1992; and
- the Foreign Exchange Monitoring and Miscellaneous Provisions Act, 1995 Cap. F34 LFN 2004.
Wholesale supply licence – this is obtained from the Authority and is required for exporting natural gas or gas derivatives as well as petroleum products.
Certificate of quantity and quality – this is issued by the Authority for the wholesale supply of petroleum liquids.
Export Approvals – this will be obtained from the Nigerian Export Promotion Council, or where the applicant is operating within an export processing zone or free trade zone, the applicant will be required to follow custom procedures established by the relevant zone authority.
Lifting Identification Number (LIN) – in accordance with the Petroleum (Transportation and Shipment) Regulations, exporters of natural gas or its derivatives or any other form of petroleum liquids shall submit an Advance Lifting Schedule to the Authority and the Authority shall issue a LIN for the specific cargo to be exported.
DGDOs (see 2.8 Other Key Terms: Upstream).
The PIA does not provide for cross-border pipelines and historically, such pipelines are negotiated between NNPC and the relevant foreign government or entity.
3.14 Transfers of Interest: Midstream/Downstream Licences and Assets
Transfer and assignment of interests in midstream and downstream operations and assets are subject to the prior written approval of the Authority. The process for obtaining approval is provided in the Assignment or Transfer of Licence and Permit Regulations 2023 and outlined as follows.
- Notification of intention to assign or transfer a licence or permit by the transferor. Within 21 days of receiving the notice, the Authority shall communicate to the applicant regarding whether or not they may proceed to the next stage, failing which, the applicant may proceed.
- Application for assignment or transfer by the transferee accompanied by the requisite documents, information and application fees. The Authority shall communicate its decision within 90 days of the application, failing which the application shall be deemed approved.
Where the application is refused, the Authority shall state its reason, and the applicant may make further representation within 21 days of the refusal being communicated.
4. Foreign Investment
4.1 Foreign Investment Rules Applicable to Domestic Investments in Hydrocarbons
The Companies and Allied Matters Act, 2020 (CAMA) provides that for a company to carry on business in Nigeria, the company must be incorporated in Nigeria. Additionally, Foreign Participation in a Nigerian company is also governed by the Nigerian Investment Promotion Commission Act (the "NIPC Act").
Incentives and Protections for Foreign Investment
Section 26 of the NIPC Act recognises arbitration within the framework of any bilateral or multilateral agreement on investment protection executed by Nigeria and the investor's country of origin. The NIPC Act also guards against the nationalisation, expropriation or compulsory acquisition by the government except in cases of national interest or public purpose, in which case, fair and adequate compensation is provided.
Foreign investors who import capital into Nigeria through Authorised Dealers (ie, deposit money banks) and obtain a Certificate of Capital Importation from the Authorised Dealer, are guaranteed the unconditional transferability of their imported capital in freely convertible currency.
Oil and gas companies situated in the export free zones are allowed to repatriate foreign capital investments and are exempted from taxes, levies, duties and foreign exchange regulations otherwise applicable in Nigeria. They are also permitted to employ foreigners within the export free zones without regard to local content requirements.
There are no sanctions in place with respect to investing in oil and gas assets in foreign jurisdictions.
5. Environmental, Health and Safety (EHS)
5.1 Environmental Laws and Environmental Regulator(s)
Please see 1.2 Regulatory Bodies.
The principal environmental laws and regulators that have jurisdiction over upstream, midstream and downstream operations include the following.
The PIA is the primary legislation governing the Nigerian Petroleum Industry. The PIA makes numerous provisions on the environmental regulation of oil and gas activities. To mention a few, the PIA requires licensees and lessees to conduct an EIA and submit for approval an Environmental Management Plan to the Commission or Authority. The PIA further establishes an Environmental Remediation Fund (EMF) for the remediation of environmental damage which has occurred while carrying out hydrocarbon activities.
Operators are also mandated to conduct environmental audits and reviews, maintain an Environmental Risk Register for proposed projects and submit an Environmental Management Plan for approval. The regulations address various aspects of environmental management, including waste management, point source registration, spill contingency planning and reporting, remediation of impacted areas and decommissioning of facilities. The regulations also specify processing fees for regulatory deliverables and outline penalties for non-compliance.
The EIA Act establishes a framework for conducting EIAs for proposed projects that may have significant environmental effects. It emphasises the importance of environmental protection, conservation and sustainable resource management. The regulatory body responsible for implementing and enforcing the provisions of the Act is the Federal Ministry of Environment, specifically the Department of EIA and Audit.
Environmental Guidelines and Standards for the Petroleum Industry in Nigeria 2018 (EGASPIN)
This guideline was issued by the Minister through the defunct Department of Petroleum Resources (DPR) and it provides a comprehensive set of regulations and practices aimed at minimising the environmental impact of petroleum operations in the country. These guidelines and standards cover various aspects such as exploration, production, refining, transportation and storage of petroleum products, addressing issues like air and water pollution, waste management, biodiversity conservation and ecosystem protection.
This act establishes NESREA, which is the agency responsible for protecting the environment and enforcing compliance with statutory requirements on pollution. NESREA is empowered to issue permits and certificates such as an Eco-Guard Certificate, Waste and Toxic Substances Disposal Permit and Noise Permit, for the disposal of certain types of waste (including those emanating from oil and gas activities) and to carry out certain activities that may impact the environment.
National Oil Spill Detection and Response Agency (NOSDRA) (Establishment) Act 2006
The NOSDRA Act is legislation aimed at addressing and managing oil spills in Nigeria, which establishes NOSDRA as the regulatory body responsible for preventing, detecting, responding to and mitigating the impacts of oil spills on the environment. The powers and functions of NOSDRA include the establishment of spill response mechanisms, co-operation with relevant stakeholders, enforcement of regulations, and provision of compensation for affected persons. The NOSDRA Act emphasises the need for prompt and effective response to oil spills, ensuring the protection of the environment, human health and the livelihoods of communities impacted by such incidents.
5.2 Environmental Obligations for a Major Hydrocarbon Project
Please see 2.7 Development and Production Requirements, 3.3 Issuing Midstream/Downstream Licences and 5.1 Environmental Laws and Environmental Regulator(s).
Host Communities Development Fund
Every operator in the oil and gas sector is required to establish a host communities development trust fund in accordance with the PIA and any regulations made by the Commission or Authority, as the case may be. The trust fund would be for the benefit of the communities affected by the operator's activities. Each operator is required to make an annual contribution of 3% of its operating expenditure in the preceding financial year.
5.3 Offshore Environmental, Health and Safety (EHS) Requirements
In addition to the requirements stated in 2.7 Development and Production Requirements, 3.3 Issuing Midstream/Downstream Licences and 5.1 Environmental Laws and Environmental Regulator(s), the Environmental Guidelines and Standards for the Petroleum Industry in Nigeria (EGASPIN) and the Guidelines and Procedures for Travel to Offshore/Swamp Locations and Obtainment of Offshore Permit ("Offshore Permit Guidelines"), issued by the former DPR, remain applicable.
Full Offshore Safety Permit (OSP)
The Offshore Permit Guidelines establish an OSP as a way to monitor operators working onshore and offshore. Any person travelling to an offshore/swamp facility, a marine vessel, a barge or gig operated in the Nigerian oil and gas industry must possess an OSP. To obtain this OSP, the personnel must fulfil certain requirements; have a valid offshore medical certificate, have completed mandatory intentionally recognised safety survival training, hold a valid work permit visa for non-Nigerian citizens, and paid the applicable fees.
Spill Contingency Plan
The EGASPIN requires all oil and gas operators in Nigeria to develop and implement a spill contingency plan as part of their environmental management practices. The plan is a comprehensive document that outlines pre-established measures and procedures to be taken in the event of an oil, gas, chemical or hazardous substance spill. It covers aspects such as spill response, containment, clean-up, waste management and monitoring. The plan aims to ensure swift and effective response to spills, minimise their environmental impact, protect human health and comply with relevant regulations and best practices. Operators are required to regularly review and update their spill contingency plans to incorporate new technologies, lessons learned and emerging industry standards.
5.4 Decommissioning Requirements
D&A activities on land and offshore are to be conducted in accordance with good international petroleum industry practice and regulations and guidelines issued by the Commission or Authority; provided that the guidelines shall meet the standards prescribed by the international maritime organisation on offshore petroleum installations and structures.
A D&A plan is required to obtain the Commission's approval of an FDP and the Authority's approval of any application for a permit, licence or approval.
The specific requirements for decommissioning (including plugging and abandoning), can vary depending on the type of facility, the location and the nature of the operations.
Some key aspects of the decommissioning requirements in Nigeria are as follows.
- Approval Process – A D&A shall not take place without the prior written approval of the Commission or Authority. A licensee or lessee may, by written notice, inform the relevant regulator of its intention to decommission and abandon. Prior to the approval of an application to decommission or abandon, the Commission or Authority shall ensure compliance with all relevant environmental, technical, commercial and regulatory requirements and environmental standards. The approval process may involve consultations with stakeholders and may require revisions or additional information from the operator.
- Decommissioning Plans – the lessee or licensee is required to submit a programme to the Commission or Authority before undertaking any D&A activities. The programme should include the following details:
- an estimate of the cost involved in implementing the proposed measures;
- specific measures to be taken for the shutdown of operations and decommissioning of unused installations, structures or assets related to petroleum operations;
- clear descriptions of the methods and techniques to be employed, adhering to international petroleum industry practices and environmental standards;
- steps to be taken to ensure the maintenance and safeguarding of any disused installations, structures or pipelines, including the liability of the licensee or lessee for any remaining risks;
- an assessment of the environmental and social impact associated with the decommissioning and abandonment activities; and
- the annual amount to be contributed to the D&A Fund.
- Timing and Execution – Decommissioning activities should be carried out in a timely manner and in accordance with the approved D&A plan. The exact timing of decommissioning depends on factors such as the cessation of production, expiration of the licence or other operational considerations. Operators are expected to execute the D&A activities safely and efficiently.
- Security Requirements – Each lessee and licensee is required to establish and maintain a D&A Fund. This fund shall be used exclusively for D&A costs and shall be held by a financial institution that is independent of the lessee or licensee and takes the form of an escrow account. The amounts shall be computed in accordance with the PIA, based on the type of operations being carried out. The Commission or Authority has access to this account as outlined in the escrow agreement. Any funds accrued prior to the effective date will be included in the D&A Fund. The purpose of this fund is solely to cover the costs associated with decommissioning and abandonment activities.
- Prior-Owner Liability – In the event of an expired or surrendered licence or lease, or when a licensee or lessee transfers or divests its interest or equity, the Commission or Authority has the authority to request the responsible party to fulfil their D&A obligations. However, where a new company assumes such obligations and receives approval from the Commission or Authority upon the transfer or divestiture, the former licensee or lessee will be relieved of any further responsibilities.
5.5 Climate Change Laws
The Climate Change Act 2021 (CCA) applies to all Ministries, Departments and Agencies in Nigeria as well as private and public entities in Nigeria. The primary aim of the CCA is to develop and implement mechanisms that will foster low carbon emission and develop a sustainable environment in the country. The CCA establishes a Climate Change Fund which shall comprise of any funds appropriated from the National Assembly, as well as any carbon tax and emissions trading, and/or fines levied on the contravention of the CCA.
Regulatory activity flowing from the CCA is still in its nascent phase, as the legislature and regulators are yet to make significant regulations on the matters provided for in the CCA.
5.6 Local Government Limits on Development
Local governments do not have the authority to unilaterally limit or prohibit oil and gas development. The exploration and production of oil and gas resources in Nigeria are primarily regulated by federal laws and regulations, and the government retains exclusive control over petroleum resources.
6. Additional Information
6.1 Unconventional Interests: Upstream
There are no special laws or regulations relating to unconventional upstream interests.
6.2 Liquefied Natural Gas (LNG)
In addition to the incentives identified in 3.5 Income or Profits Tax Regime: Midstream/Downstream, the Nigeria Liquefied Natural Gas (Fiscal Incentives, Guarantees, and Assurances) Act (the "NLNG Act") was enacted with the aim of conferring enhanced protection and incentives on NLNG Limited. These additional provisions were deemed necessary to assure investors of investment security, given the substantial capital investment required to initiate operations.
Some of the incentives include:
- pioneer status – exemption from customs duties in respect of the import of machinery used in NLNG Limited's business;
- tax incentive granted for a period of ten years commencing from the date of commercial delivery of LNG to a purchaser;
- exemption from payment of interest in respect of any loan or other financial arrangement payable to any company other than a Nigerian company; and
- establishment of a mechanism for resolving disputes between the shareholders and the government through arbitration before the International Centre for the Settlement of Investment Disputes.
There is no special treatment for other LNG projects.
6.3 Energy Transition Considerations
Renewable energy and natural gas are projected to become the primary sources of global energy production by 2040. Nigeria plays a significant role in this context, as it currently possesses around 31% of Africa's proven gas reserves. However, transitioning from crude oil reliance to gas-powered energy and renewable sources presents substantial challenges. Consequently, Nigeria continues to heavily rely on crude oil production to sustain its economy and invests significant resources in oil and gas infrastructure development.
Nonetheless, the Federal Government is actively working towards enhancing the gas sector by increasing proven gas reserves from 200 trillion cubic feet (tcf) to 600 tcf. This involves prioritising domestic utilisation and export, with 20 critical gas projects identified for potential implementation.
Supported by the Decade of Gas Initiative and clear gas fiscal provisions in the PIA, initiatives include the establishment of an energy island in northern Nigeria, deploying a major gas turbine in Abuja, and revitalising industries through the Ajaokuta-Kaduna-Kano (AKK) Natural Gas Pipeline. Progress is also being made in constructing the Trans-Saharan Gas Pipeline, with feasibility studies and funding discussions with European partners underway.
6.4 Unique or Interesting Aspects of the Hydrocarbon Industry
Fuel subsidy was implemented by the Federal Government as a mechanism to maintain a capped price for Premium Motor Spirit (PMS), deemed affordable for the majority of the population, irrespective of market forces. To achieve this price uniformity, the government bridged the gap by financing the deficit between the actual supply cost (including a fair return for participants in the supply value chain) and the retail price in the domestic market. In 2020, the Federal Government reportedly spent around NGN750,810 million on subsidising PMS.
On 29 May 2023, the President of the Federal Republic of Nigeria, President Bola Ahmed Tinubu, during his inaugural speech, announced the removal of the subsidy on PMS. This announcement was made pursuant to the PIA on the deregulation of the midstream and downstream sector. Particularly, the PIA in Section 205 provides that wholesale and retail prices of petroleum products shall be based on unrestricted free market pricing conditions. The implication therefore is that the pricing of all petroleum products would be subject to market forces, rather than being regulated by the Federal Government.
6.5 Material Changes in Law or Regulation
The PIA was enacted in August 2021, bringing about substantial modifications to the legal, regulatory and fiscal structure of the oil and gas industry.
In the past year, the Commission and Authority have enacted new regulations pursuant to the PIA to give effect to the innovative provisions of the PIA including:
- Nigerian Upstream Petroleum Host Communities Development Regulations 2022;
- Petroleum Royalty Regulations 2022;
- Conversion and Renewal Regulations 2022;
- Midstream and Downstream Penalties and Enforcement Mechanisms Regulations 2023;
- Midstream and Downstream Petroleum Alternative Dispute Resolution Regulations 2023;
- Petroleum (Transportation and Shipment) Regulations, 2023; and
- Assignment or Transfer of Licence and Permit Regulations, 2023.
Originally published by Chambers and Partners.
The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.