The Petroleum Industry Act (PIA) 2021 represents a comprehensive overhaul of Nigeria's petroleum legal framework. It repeals several existing legislations and introduces a consolidated and modernised regulatory structure to enhance transparency, efficiency, and investment in the sector.
The PIA comprises 5 Chapters, 319 Sections, and 8 Schedules. Each chapter addresses a specific aspect of the industry. A central focus of the PIA is the unbundling of the Nigerian National Petroleum Corporation (NNPC) and the creation of a unified regulatory framework for both upstream and downstream operations within the petroleum industry to enhance transparency, efficiency, and accountability across the sector.
CHAPTER 1: GOVERNANCE AND INSTITUTIONS
Chapter 1 lays the foundation for a modernised and efficient Nigerian petroleum industry. It aims to establish robust governance structures, create a commercially viable national oil company, and foster a conducive environment for both local and international investment.
It introduces the creation of a commercially driven Nigerian National Petroleum Company (NNPC) Limited, incorporated under the Companies and Allied Matters Act (CAMA). This new entity will be responsible for the exploration, production, and sale of oil and gas resources, with a focus on profitability. Any guarantee issued by the government regarding the transfer of NNPC's liabilities to NNPC Limited will be enforceable against the government. The objectives of NNPCL are thus: (1) Carrying out petroleum operations on a commercial basis; (2) Acting as concessionaire for all production contracts; (3) Remitting proceeds to government less its management fee and Frontier Exploration Fund; (4) Carrying out test marketing to determine value of crude oil; (5) Managing production sharing contracts; (6) Engaging in renewables and other energy investments; (7) Promoting domestic gas utilization; (8) Maintaining the role of NNPC; (9) Carrying out tasks requested by the Commission and (10) Engaging in activities that ensure national energy security. NNPC Limited and parties to joint operating agreements can voluntarily restructure their agreements as joint ventures carried out by way of limited liability companies, known as IJVCs. IJVCs are independent entities with a strong commercial orientation and transparent operations.
Two independent regulatory bodies are established: (1) Nigerian Upstream Regulatory Commission: This body will oversee the technical and commercial regulation of upstream petroleum operations. (2) Nigerian Midstream and Downstream Petroleum Regulatory Authority: This authority will regulate the technical and commercial aspects of midstream and downstream operations. Both regulatory bodies are exempt from corporate taxation, enabling them to focus on their core regulatory functions.
Chapter 1 of the Petroleum Industry Act (PIA) lays the groundwork for the transformation of Nigeria's petroleum sector by articulating key objectives aimed at modernising the industry. These objectives include the establishment of efficient and effective governance structures, the transformation of the Nigerian National Petroleum Company into a commercially oriented enterprise, the promotion of transparency and accountability, the creation of a conducive business environment, and the enhancement of local content development.
The Chapter further outlines the statutory powers of the Minister of Petroleum Resources, who is vested with responsibility for policy formulation and monitoring, supervisory oversight, licensing of petroleum operations, and the issuance of policy directives. The Minister also retains the right of pre-emption over petroleum and petroleum-related products in circumstances defined by the Act. Notably, failure to comply with, or obstruction of, the Minister's exercise of this right constitutes an offence, attracting a penalty of ₦10,000,000 for non-compliance and ₦5,000,000 for obstruction, along with a term of imprisonment not exceeding six months.
In addition to the Minister's powers, Chapter 1 sets out the objectives and regulatory mandate of the Nigerian Upstream Petroleum Regulatory Commission (NUPRC). The Commission is tasked with regulating upstream petroleum operations, ensuring industry-wide compliance with statutory obligations, preventing waste, and promoting environmentally sustainable practices. It is also responsible for facilitating infrastructural development, implementing government policy, and fostering an investment-friendly climate.
To discharge these responsibilities, the NUPRC is empowered to enforce regulations, seal non-compliant premises, oversee safety standards, set technological benchmarks, demand information disclosures, issue operational guidelines, recommend revocation of licenses and leases, approve lease renewals, and impose special terms and conditions. The Commission also enjoys unrestricted access to relevant information and facilities necessary for the performance of its duties.
In the execution of its special investigative and enforcement functions, the Commission may conduct surveillance and inspections of petroleum installations, access operational sites and facilities, examine corporate records, question individuals, collect and analyze samples, employ investigative tools, seize and duplicate documents, and arrest individuals suspected of violating the provisions of the Act. These wide-ranging powers are intended to ensure robust regulatory oversight and the effective administration of Nigeria's upstream petroleum industry.
Also read: Rethinking Nigeria's Oil and Gas Governance for National Development
CHAPTER 2: ADMINISTRATION
Chapter 2 of the Petroleum Industry Act (PIA) 2021 establishes the regulatory framework for upstream petroleum operations in Nigeria, with the goal of promoting sustainable and responsible exploration and production of petroleum resources. It introduces a regime built on principles of transparency, safety, competitiveness, and equitable benefit-sharing. Under this framework, the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) is tasked with overseeing upstream activities, including the development of model licenses and leases. These instruments may include carried interest provisions, allowing NNPC Limited to hold up to a 60% interest in operations.
Licensing is categorised into Petroleum Exploration Licenses (PEL), Petroleum Prospecting Licenses (PPL), and Petroleum Mining Leases (PML). Only companies incorporated in Nigeria are eligible. A PEL grants non-exclusive rights to conduct exploration over a renewable three-year term, without conferring extraction rights. Data obtained during this phase belongs to the NUPRC and requires regulatory approval for third-party use. In frontier basins, PEL holders may transition to PPLs if exploration yields positive results.
A PPL grants exclusive rights to drill and test for petroleum, including limited extraction during exploration. The grant of a PPL or PML requires the recommendation of the NUPRC and approval from the Minister of Petroleum Resources. If the Minister fails to respond within 90 days, the application is deemed approved. The licensing process is competitive and transparent, with bidders evaluated based on set criteria including signature bonuses, royalty structures, and proposed work programs. PPLs may last up to six years for onshore and shallow water areas, and up to ten years for deep offshore and frontier areas.
Following a discovery, the licensee must notify the NUPRC within 180 days and may declare a discovery of interest. An appraisal program must then be submitted within a year, and the area under appraisal must not exceed the PPL's boundary. This appraisal zone may be retained for up to ten years, after which it must be relinquished if no commercial discovery is declared. Financial guarantees, such as performance bonds, must be provided to secure the appraisal obligation.
Once a commercial discovery is declared, a licensee must submit a Field Development Plan (FDP) within two years. The FDP must satisfy technical, environmental, financial, and social requirements, including eliminating gas flaring, meeting host community obligations, and complying with Nigerian content mandates. Where upstream activities are integrated with midstream infrastructure, a unified development project may be submitted. If a licensee fails to submit an FDP within the prescribed period, the area is relinquished. However, upon submission of an FDP, the license remains valid until the NUPRC either approves or rejects the application within 180 days.
Field development can proceed in phases. The first phase must be detailed, while subsequent phases may be submitted at a conceptual level and approved later. Licensees must also file annual work programs and notify the NUPRC if a petroleum reservoir extends beyond the licensed area. In such cases, the Commission may require unitization, compelling parties to enter a Unit Agreement that names a unit operator and includes technical data. If the parties fail to agree, the Commission may appoint a consultant to propose binding terms.
Where a reservoir crosses into unlicensed or adjacent areas, the Commission may expand an existing license or initiate a bid round. If production from a unitised field can continue beyond the lease term, an extension may be granted. The Commission is also empowered to issue regulations to govern unitization and ensure optimal resource recovery.
A PML is issued following the approval of a commercial FDP. Each PML relates to a specific discovery and may include appraisal phases and obligations to optimise production. Before a PPL expires, licensees must apply for PMLs for all commercial discoveries, while retaining the PPL for non-leased areas. PML boundaries must align with the original license, though adjustments may be permitted based on further data. Where multiple leases arise from a single PPL and relate to a single field, they may be treated as one. Separate leases may be granted for new discoveries in different geological formations.
PML holders have exclusive rights to develop and produce petroleum, subject to their approved FDP. The Commission monitors compliance, ensures cost control, and enforces adherence to the Act. Annual disclosures of government payments are mandatory and subject to penalties if omitted. Transparency provisions require publication of licenses and contracts and the submission of technical data to the National Data Repository. While some data remains confidential for a set time, the rest is publicly accessible for a fee.
PMLs are valid for up to 20 years, including a five-year development period for onshore areas and seven years for offshore and frontier areas. If production does not commence within the development period, the lease may be revoked unless exceptional reasons exist. Leases can be renewed for an additional 20-year term. However, leases that remain idle for 180 days or more may be revoked. Renewal applications must be filed at least 12 months before expiry and may attract revised conditions.
The Act imposes rules for relinquishment and surrender. Areas not designated as appraisal or lease zones must be relinquished before the exploration period ends. Voluntary surrender of blocks is allowed once obligations are fulfilled. After ten years, lessees must relinquish non-producing acreage beyond a producing field's boundary, and areas with undeclared discoveries must also be surrendered upon the expiration of their retention period. Relinquished areas may be reassigned to third parties. Where rights overlap, the Commission may require parties to enter cooperation agreements. A lease or license may also be surrendered with three months' notice.
Rights of way for infrastructure development may be granted, provided they do not compromise health, safety, or environmental standards. Licensees may object to reservations and the Commission may review its decision.
License and lease holders may access designated lands for petroleum operations, subject to compliance with environmental and legal standards. The PIA allows for the conversion of existing Oil Prospecting Licenses (OPLs) and Oil Mining Leases (OMLs) into PPLs and PMLs. Conversion contracts enable holders to adopt the PIA's fiscal regime, benefit from new incentives, and terminate prior legal disputes. Conversion must occur within 18 months of the Act's commencement or before the original title expires. If a holder declines conversion, existing terms continue to apply, although certain PIA provisions may still take effect.
The conversion process preserves the original duration of an OPL when it becomes a PPL. OML holders must designate areas for appraisal, production, or retention based on operational status. A maximum of 40% of the lease area may be selected for conversion to PPLs. If more than 40% is selected, only the specified blocks are retained. Remaining acreage must be relinquished at the point of renewal or conversion.
Relinquished areas are reclassified by the Commission as either PPLs or PMLs. Appraisal and discovery zones become PPLs under new fiscal terms. Producing areas are converted into PMLs, subject to Section 267 and Chapter 4 of the PIA. In production sharing contracts, profit oil is consolidated across PMLs, while royalties are assessed separately.
Holders of OPLs may also voluntarily convert selected zones to PPLs for further exploration or to PMLs for production. Zones not selected remain subject to exploration obligations. If NNPC held vested rights to gas before the PIA took effect, those rights are preserved unless explicitly relinquished. Where relinquished, compensation is payable at market value.
Marginal fields, defined as small but potentially profitable assets requiring targeted development, are subject to a compulsory conversion process. Producing marginal fields must convert to PMLs within 18 months and retain their existing royalty terms while conforming to the new regulatory regime. Non-producing marginal fields declared before January 1, 2021, convert to PPLs and are subject to new acreage regulations. If a marginal field is deemed commercially unviable, the government may reclaim it and reassign it through competitive bidding.
Leaseholders discovering a marginal field must submit an FDP within three years. They may farm out the field to third parties with Commission approval or relinquish the field to the government, in which case it becomes vested in the state.
Also read: Refining Nigeria's Oil Sector: Legal Reforms and the Path to Increased Domestic Production
Transfers of PPLs and PMLs are strictly controlled. No transfer, assignment, or novation is valid without the written consent of the Minister based on the Commission's recommendation. A change in control of a titleholder is deemed a transfer. Applications must meet prescribed criteria, including the transferee's Nigerian incorporation, technical and financial competence, and compliance with competition law. The Minister must respond within 60 working days, failing which consent is deemed granted. Transfers involving security interests, such as pledges or mortgages, also require prior approval. Transfer fees are calculated as a percentage of the transaction value and are not tax-deductible. All transfers must be disclosed to the Federal Inland Revenue Service and published in the Federal Government Gazette.
The Petroleum Industry Act (PIA) 2021 provides a structured legal framework for the revocation of Petroleum Prospecting Licences (PPLs) and Petroleum Mining Leases (PMLs), empowering the Minister of Petroleum Resources to revoke these titles based on the recommendation of the Nigerian Upstream Petroleum Regulatory Commission (NUPRC). Revocation is triggered by infractions such as failure to commence exploration or production within the statutory timelines, breach of environmental or safety standards, default on financial obligations, corrupt acquisition of rights, non-compliance with host community or judicial requirements, or failure to meet domestic gas supply mandates.
Before a revocation is effected, the NUPRC must issue a formal Notice of Default to the licensee or lessee, stating the reasons for the proposed revocation and granting a minimum remediation period of 60 days. This notice may be served through multiple recognised means, including delivery to the last known address of the titleholder, publication in the Federal Government Gazette, or on the Commission's website. If the default is not remedied within the stipulated period, the revocation proceeds. However, this does not extinguish the licensee's or lessee's outstanding obligations to the government or third parties. The revocation decision is then published in the Gazette and recorded in the Commission's register.
Where the revoked lease is a producing asset, the Minister may, within 30 days of the revocation, appoint an interim operator on the advice of the NUPRC to ensure that production continues uninterrupted. This appointment is temporary and governed by a service contract while the NUPRC conducts a transparent bid process to reassign the lease. In cases of joint ownership, revocation may apply solely to the defaulting party, allowing non-defaulting parties to assume the defaulting party's interest with Commission approval. If the remaining parties fail to meet the obligations, the Minister may extend the revocation to them as well.
Licensees and lessees are expected to meet their financial obligations, including royalties, rents, fees, and production shares. Any default that persists for over 30 days becomes a debt to the NUPRC and accrues interest at the Central Bank of Nigeria's prevailing rate. If the debt remains unpaid, the Commission may enter the defaulting party's premises, seize and sell their assets, and apply the proceeds to recover the amount due. Any surplus must be returned to the licensee. These payments are compulsory and not subject to waiver or discount.
The Act also places operational restrictions on petroleum activities in sensitive areas such as sacred sites, public utility zones, cultivated land, and private property without prior approval from the Commission. If operations are to be carried out on private land, the licensee must give written notice, outline the intended activities, and pay adequate compensation to the landowner. Disputes over compensation or land ownership are resolved by the Federal High Court, with an interim deposit ordered by the court to be made while litigation is pending.
Environmental protection is central to the PIA's compliance regime. Licensees and lessees must avoid damaging valuable trees, structures, or culturally significant objects and must not unduly disturb land surfaces. Where damage occurs, compensation must be paid within 30 days as assessed by the Commission. To support environmental accountability, operators must submit an Environmental Management Plan (EMP) demonstrating compliance with applicable laws and detailing strategies for environmental rehabilitation. Approval of the EMP is conditional on a contribution to an environmental remediation fund, sized according to the risk and scale of the operation. The Commission may audit these contributions or appoint assessors to verify their sufficiency. If a licensee fails to mitigate environmental damage, the Commission may draw from the fund to conduct remediation after notifying the defaulting party.
Gas flaring and venting are strictly prohibited except in emergencies or under specific exemptions approved by the Commission. Unauthorised flaring constitutes an offence, with fines imposed that cannot be deducted for tax purposes. These penalties support environmental remediation efforts. Flaring must be measured using Commission-approved metering equipment, and failure to install such meters is an offence. Licensees are also required to submit a Gas Flare Elimination and Monetisation Plan within 12 months of the PIA's commencement, outlining steps to reduce or utilise flared gas. In limited instances, permits may be issued for flaring during facility commissioning or strategic testing.
To support domestic gas utilisation, the PIA introduces the Domestic Gas Delivery Obligation (DGDO), under which the Commission allocates gas supply volumes annually in line with national demand forecasts. Lessees must fulfil these obligations either directly or via contracts with wholesale gas suppliers. Only after meeting DGDO commitments may licensees sell excess gas to the domestic market or export it. Non-compliance attracts a penalty of US$3.50 per MMBtu for undelivered gas, with possible additional sanctions such as disqualification from future export participation. Exemptions may apply in cases of force majeure, buyer default, or transport limitations. When the gas market achieves full commercial maturity, the Authority may suspend DGDO enforcement. Following allocation, licensees must submit a Natural Gas Production and Supply Plan aligned with their delivery obligations.
The Act also enumerates specific regulatory offences to enforce industry discipline. These include obstruction or assault of regulatory officers, denial of access to facilities, refusal to obey lawful orders, unauthorised operations, vandalism, misinformation, interference with investigations, and violation of network codes. Section 229 outlines penalties for such offences, including general fines and operational suspension until safety is restored following infrastructure damage. The Commission may adjust penalty amounts based on inflation or other relevant factors. Separate provisions penalise delays in submitting required information, false declarations, and obstruction of information-gathering processes. Non-compliance following a warning may attract enhanced penalties. In all such cases, the Commission must serve a written notice of the offence and proposed penalty, giving the alleged offender 30 days to respond. After review, a final penalty decision is issued.
The PIA provides detailed procedures for decommissioning and abandonment of petroleum infrastructure. These processes must conform to international best practices, particularly the standards of the International Maritime Organisation for offshore installations. Prior written approval from the Commission or Authority is required, and it may also direct the commencement of decommissioning when necessary. Operators must submit a comprehensive decommissioning programme detailing cost estimates, dismantling procedures, and social and environmental impact assessments. They are further obligated to safeguard disused installations, especially in deep or ultra-deep water, and remain liable for any residual risks.
To finance these obligations, licensees and lessees must establish a decommissioning and abandonment fund held in escrow by an independent financial institution. The Commission may access the fund if the licensee fails to act, following a formal notice and an opportunity to remedy the breach. Contributions to the fund are determined by an approved decommissioning plan, which must be submitted as part of the field development plan. Where no such plan existed prior to the Act's commencement, licensees are required to submit one within one year. This plan forms the basis for the calculation of financial contributions and ensures the availability of resources to responsibly wind down petroleum operations at the end of their productive life.
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