Oil & Gas 2026 Comparisons

Nigeria operates a state-ownership system for hydrocarbons. This includes territorial waters, continental shelf, and the exclusive economic zone (see the Second Schedule, Part I, item 39, the Constitution of the Federal Republic of Nigeria, 1999 (as amended) (the “Constitution”); Section 1, Petroleum Industry Act, 2021 (PIA)). There is no private ownership of oil and gas in situ. This is because the Federal Government owns all hydrocarbons in situ, and grants private parties the right to explore, develop and produce them through statutory licences and leases.

Under the PIA, these include Petroleum Exploration Licences (PEL), Petroleum Prospecting Licences (PPL) and Petroleum Mining Leases (PML). Similarly, private landowners hold no rights to underlying hydrocarbons. A private company can only hold a valid mineral interest through a licence, lease or contractual arrangement granted under the PIA.

The principal regulators of hydrocarbon activities in Nigeria are:

• the Nigerian Upstream Petroleum Regulatory Commission (NUPRC);
• the Nigerian Midstream and Downstream Petroleum Regulatory Authority (NMDPRA);
• the Nigerian Content Development and Monitoring Board (NCDMB);
• the Federal Ministry of Environment;
• the National Oil Spill Detection and Response Agency (NOSDRA); and
• the Minister of Petroleum Resources (the “Minister”).

The PIA assigns regulatory responsibility principally between upstream operations (which fall within the purview of the NUPRC) and midstream operations (which fall within the purview of NMDPRA), all while the Minister retains overall policy and supervisory oversight of the sector. Its authority also extends to acreage management, licensing rounds, reservoir management, measurement and production allocation, unitisation, gas flaring and venting, upstream environmental matters, decommissioning, host community obligations and the assignment or change of control of upstream interests. The NMDPRA also regulates midstream and downstream petroleum operations under the PIA.

Furthermore, environmental regulation is principally undertaken by the Federal Ministry of Environment and the NOSDRA. The Federal Ministry of Environment administers the federal environmental impact assessment framework, while NOSDRA is responsible for oil spill preparedness, detection, reporting, co-ordination and response.

The Minister exercises overall policy and supervisory responsibility for the petroleum industry pursuant to its powers under the PIA. The Minister formulates, monitors and administers government policy for the sector and exercises general supervision over petroleum operations. The Minister also grants PPLs and PMLs on the recommendation of the NUPRC.

The NCDMB regulates Nigerian content requirements across the petroleum industry. It is established and empowered under the Nigerian Oil and Gas Industry Content Development (NOGICD) Act 2010 to implement, monitor and enforce compliance with local content targets.

Nigeria has a national oil and gas company which is the Nigerian National Petroleum Company Limited (“NNPC Limited”).

The PIA mandated the incorporation of NNPC Limited under the Companies and Allied Matters Act, 2020 (CAMA). At incorporation, all its shares were vested in the Federal Government and held in equal proportions by the Ministry of Finance Incorporated and Ministry of Petroleum Incorporated on behalf of the Federation. NNPC Limited operates as the Federal Government’s principal commercial petroleum company, participating across upstream, midstream and downstream activities, including petroleum production, gas, pipelines, refining and marketing.

Hydrocarbon in Nigeria is regulated principally by federal legislation. The PIA is the primary statute, supported by other laws dealing with pipelines, local content, taxation, environmental matters and legacy petroleum interests. The principal laws and regulations are as follows.

• PIA – this is the principal legislation governing Nigeria’s hydrocarbon industry. It applies to crude oil, natural gas and condensates across upstream, midstream and downstream operations, including both onshore and offshore activities. Furthermore, the PIA significantly overhauls the fiscal regime, unbundling the legacy Petroleum Profits Tax (PPT) into a combination of Hydrocarbon Tax (HT) for upstream operations and standard Companies Income Tax (CIT) administered by the Nigeria Revenue Service (FIRS).
• Oil Pipelines Act 2004 (OPA) – continues to regulate important aspects of pipeline infrastructure. It deals principally with permits to survey pipeline routes, pipeline licences, rights of way, access to land and compensation for persons affected by pipeline operations. The Act applies to pipeline infrastructure used for crude oil, petroleum products and natural gas and operates alongside the PIA to the extent that its provisions are not inconsistent with the PIA.
• Nigerian Oil and Gas Industry Content Development Act 2010 (the “NOGICD Act”) – regulates Nigerian content requirements throughout the oil and gas industry.

Upstream Regulations

NUPRC has issued a substantial body of regulations under the PIA governing upstream hydrocarbon activities. The important regulations include the Petroleum Licensing Round Regulations 2022, Conversion and Renewal (Licences and Leases) Regulations 2022, Nigerian Upstream Petroleum Royalty Regulations 2022, Upstream Petroleum Domestic Gas Delivery Regulations 2022, Gas Flaring, Venting and Methane Emissions Regulations 2023, Nigerian Upstream Petroleum Unitisation Regulations 2023, Nigerian Upstream Petroleum Measurement Regulations 2023, and Production Curtailment and Domestic Crude Oil Supply Obligation Regulations 2023.

Other important regulations include the Acreage Management and Petroleum Drilling Regulations 2024, the Nigerian Upstream Petroleum (Assignment of Interest) Regulations 2024, the Upstream Petroleum Environmental Remediation Regulations 2024, the Upstream Petroleum Safety Regulations 2024 and the Nigerian Upstream Petroleum Commercial Regulations 2025, together with applicable regulations on fees, rents, decommissioning and abandonment. Collectively, these regulations address matters including acreage administration, drilling, exploration, production, assignments of interests, measurement, domestic crude and gas supply obligations, unitisation, royalties, environmental protection, safety, decommissioning and commercial regulation.

Midstream and Downstream Petroleum Regulations

NMDPRA has also issued regulations governing midstream and downstream hydrocarbon activities. The principal regulations include the Midstream and Downstream Petroleum Operations Regulations 2025, Midstream and Downstream Petroleum Fees Regulations 2024, Midstream and Downstream Petroleum Environmental Regulations 2023, Midstream and  Downstream Petroleum Safety Regulations 2023, and Midstream and Downstream Decommissioning and Abandonment Regulations 2023.

Pooling and Unitisation

Nigeria does not generally use the private mineral lease pooling system. The principal mechanism for co-ordinating the development of a common petroleum reservoir is unitisation. Under the PIA, where a petroleum reservoir extends across the boundaries of two or more licences or leases, NUPRC may require the relevant licensees or lessees to develop the reservoir as a single unit.

The effect of unitisation is to ensure that a common reservoir is developed efficiently as a single petroleum unit rather than through competing operations. Production, costs, reserves and economic interests are allocated among the participating licence or lease holders in accordance with the approved unitisation arrangement. While the domestic regime for unitisation is strictly managed by NUPRC, international cross-border reservoirs (such as the Nigeria–São Tomé and Príncipe Joint Development Zone) are governed by bilateral treaties.

Private investment in Nigeria’s upstream sector may take several forms. The applicable framework is principally contained in the PIA.

• PEL – is granted by the NUPRC under the PIA. It confers a non-exclusive right to carry out petroleum exploration activities, including geological, geophysical and geochemical surveys, within the licensed area. A PEL is generally granted for an initial period of three years and may be renewed for a further three years. It does not, by itself, confer a right to commercially produce, win or dispose of petroleum.
• PPL – gives the licensee the exclusive right to drill exploration and appraisal wells and to carry out test production, together with non-exclusive exploration rights within the licensed area. Petroleum recovered during authorised test production may be carried away and disposed of in accordance with the PIA.
• PML – is generally granted following a commercial discovery and approval by NUPRC of the relevant field development plan. It therefore represents the production stage interest under the PIA.

In addition to direct licence or lease interests, the PIA recognises a number of contractual structures for private participation in upstream petroleum operations. The PIA permits arrangements including production sharing contracts, profit sharing contracts, risk service contracts and concession or joint venture arrangements, as well as other internationally recognised forms of petroleum exploration and production contracts.

Under the PIA, an assignment, novation or transfer of a PPL or PML, or an interest in either, requires the prior written consent of the Minister on the recommendation of NUPRC. The PIA also treats certain changes of control of a licence or lease holder as an assignment requiring regulatory approval. The Nigerian Upstream Petroleum (Assignment of Interest) Regulations 2024 provide further rules governing direct and indirect transfers of upstream interests.

Farmouts and Marginal Fields: Under the PIA, a farm-out is an arrangement under which the holder of an upstream interest permits another party to explore, prospect for, win, work and carry away petroleum within the relevant licence or lease area.

Historic Forms of Upstream Interests: Before the PIA, upstream rights were principally granted as Oil Prospecting Licences (OPLs) and Oil Mining Leases (OMLs) under the former Petroleum Act.

The process of obtaining an upstream licence may be through a direct application process as in PEL, or a competitive bidding process as in PPLs and PMLs. However, foreign companies must be locally incorporated under CAMA before a licence can be formally awarded.

The licensing round process is broken down into five main stages as follows:

• announcement/advertisement/portal launch;
• registration/prequalification;
• technical and commercial bid submission/evaluation;
• commercial bid conference; and
• Ministerial approval/contracting.

To participate in the licensing round, the prospective bidder must apply to the NUPRC for pre-qualification, pay the prescribed fees and satisfy legal, financial and technical criteria set out in Petroleum Licensing Round Regulations, 2022 and the applicable licensing round guidelines. These requirements may therefore vary from one licensing round to another. The bids may be submitted physically or electronically to the NUPRC. A bidder seeking more than one licence or lease must submit a separate bid for each licence or lease. A licensee/lessee may need to acquire approvals from NUPRC according to the type of operation.

Some activities may require environmental impact assessment approval under the Environmental Impact Assessment Act, 1992 and Nigerian content approval and compliance under the NOGICD Act.

In place of the previous oil prospecting licence and oil mining licence scheme, the PIA introduced the PEL, PPL and PML scheme and designated the NUPRC as the sole upstream regulator.

The primary types of government take in Nigeria’s upstream petroleum industry include royalties, hydrocarbon tax, companies income tax, rents, fees, fines, signature bonuses, profit shares, profit oil or profit gas under Production Sharing Contracts (PSCs), minimum work commitments and host community contributions, and other levies from grant, assignment, termination and breach of licences, leases and permits amongst others. Section 74(2) of the PIA is thus significant in relation to the flexibility of the current fiscal regime.

The Nigeria Tax Act, 2025 (NTA) stipulates that all petroleum production, including production tests, is subject to royalties. The production-based royalty rates for crude oil and condensates are 15% for onshore areas, 12.5% for shallow-water areas, 7.5% for deep-offshore areas, and 7.5% for frontier basins. Where the price is between USD50 to USD100 and between USD100 to USD150, the royalty rate shall be derived by linear interpolation. Natural gas and natural gas liquids are subject to production-based royalty. The applicable rate is 5%, regardless of the terrain from which the gas is produced. However, where the gas is produced and utilised in Nigeria, the royalty rate is reduced to 2.5%. There are separate royalties for crude oil and casing head petroleum spirit produced from different terrains and for onshore and shallow offshore PSCs.

Aside from royalties, hydrocarbon tax (HCT) is levied on profits of companies engaged in upstream petroleum operations in onshore, shallow-water and deep waters. As consolidated under the NTA, the applicable rate is 30% for profits from crude oil produced under a PML and 15% for profits from PPL activities in onshore and shallow-water areas.

HCT applies to crude oil, field condensates and natural gas liquids derived from associated gas and produced upstream of the measurement points (PIA, Section 65(2)(a)). HCT does not apply to associated and non-associated natural gas, condensates or natural gas liquids produced from non-associated gas in fields or gas processing plants and from associated gas at downstream facilities production downstream of the measurement points, or petroleum production from frontier and deep-offshore acreages. These are instead subject to companies income tax under the NTA.

A settlor is mandated to pay 3% of its actual annual operating expenditure for the previous financial year to the relevant Host Communities Development Trust.

Upstream petroleum operations in Nigeria are subject to HCT and companies income tax (CIT). These taxes are imposed at the federal level. States and local governments do not have the constitutional authority to tax profits from petroleum operations.

HCT was introduced by the PIA to replace the former Petroleum Profits Tax for petroleum operators under the PIA. The rate is 30% of chargeable crude oil profits for PML holders and 15% for PPL holders, with respect to onshore and shallow water.

CIT applies in addition to HCT on crude oil profits and is the main federal income tax applicable to gas profits and deep-offshore petroleum operations. The CIT rate is 30%.

State governments have limited involvement in the taxation of upstream operators by collecting Pay-As-You-Earn (PAYE) tax withheld by upstream companies from the salaries of their Nigeria-resident employees. This is a tax on the employees’ income and not a tax on the company’s petroleum profits.

Withholding tax is not a separate tax. It is a mechanism for collecting tax in advance by deducting tax from certain payments at source.

VAT is generally charged at 7.5% on goods and services. However, oil and gas exports, crude petroleum oil and feed gas for processed gas are treated as VAT-exempt supplies under the Nigeria Tax Act. Import duties generally range from 5% to 35% depending on the applicable tariff classification.

A development levy was introduced by the NTA to replace four previously separate levies, which are the Tertiary Education Tax, the NITDA information technology levy, the NASENI levy, and the Police Trust Fund levy.

Nigeria has a national oil company, NNPC Limited. Under the PIA, the government, through NNPC Limited, has a statutory right to participate in upstream petroleum contracts through a carried interest framework.

Section 85(4) of the PIA requires concession agreements to include a carried interest provision of up to 60% for the government with the right exercisable at any time from the grant of the relevant licence or lease.

Apart from this statutory participation, the PIA does not confer on NNPC Limited an automatic right to operate an upstream licence, to unilaterally take over operations, or to second personnel merely by virtue of its status as the national oil company. Operational rights are governed by the applicable licence, lease and contractual arrangements.

Nigeria does not generally impose separate state or municipal local-content quotas on upstream petroleum investors. Under the NOGICD Act, operators are required to give first consideration to Nigerian goods and services and to Nigerians in respect of employment and training. Operators must also submit Nigerian Content Plans demonstrating how these requirements will be met, and the applicable minimum Nigerian content levels are prescribed under the Act and relevant regulations and guidelines.

The NCDMB’s Community Content Guideline, developed pursuant to the NOGICD Act, provides for the involvement of host-community businesses and persons in employment, training, procurement of goods and services, contracting and capacity-building opportunities. Sections 25 to 28 of the NOGICD Act provide the statutory basis for community participation in petroleum operations. Furthermore, under Section 104 of the Act, 1% of the value of all contracts awarded in the upstream sector must be deducted at source and remitted to the NCDMB.

Petroleum licensing and the principal authorisation of upstream drilling and production are matters within the federal regulatory framework administered by the Minister and NUPRC, not the state.

Nevertheless, the holder may need to obtain separate state or local approvals for surface activities and ancillary development works, depending on the location and nature of the project. For example, a land-based development involving substantial surface construction may trigger state physical-planning or development-permit requirements in addition to NUPRC approvals.

Field Development Plan (FDP)

Where a PPL holder (the “Licensee”) declares commercial discovery, such Licensee shall within two years of the declaration submit an FDP to the NUPRC, together with a commitment to carry out the proposed development. The NUPRC will evaluate the FDP against the requirements of the PIA to determine whether the FDP meets the technical standards required for petroleum operations based on good international petroleum industry practices; contains an Environmental Management Plan complying with Section 102 of the PIA; provides a sufficient development period for the construction of required infrastructure and development of the field amongst others.

The NUPRC must approve or disapprove the FDP within 180 days of a compliant submission and if it fails to respond within that period, the FDP is deemed approved. After the approval of the FDP and compliance with other provisions of the PIA, the licensee may be granted a PML which entitles it to proceed to development and production. Where the licensee fails to submit the FDP within the prescribed two-year period, it is deemed to have relinquished the area containing the commercial discovery.

The PIA does not establish a specific internal statutory appeal mechanism for a NUPRC decision refusing an upstream FDP. This should therefore be distinguished from the express judicial-review mechanism applicable to certain midstream and downstream licence and permit refusals under Section 111(12) of the PIA.

An FDP refusal would, however, constitute a regulatory decision of NUPRC affecting the Licensee’s rights under the PIA and its petroleum licence. The PIA provides that disputes between a licensee, lessee or permit holder and NUPRC are subject to the jurisdiction of the Federal High Court. The regulations require licensees and lessees to comply with the NUPRC’s technical and operational requirements, including requirements relating to wells, production operations, conservation, measurement and facilities.

Development wells remain subject to the NUPRC’s technical and operational regulatory regime. The PIA gives the NUPRC responsibility for regulating drilling operations and for issuing permits and authorisations necessary for upstream petroleum operations, including drilling and the design, construction and operation of upstream facilities.

In addition to the matters discussed above, some principal terms governing upstream petroleum interests in Nigeria include licence or lease duration, relinquishment obligations, termination and revocation provisions, unitisation requirements and, in the case of contractual arrangements, dispute resolution and force majeure clauses.

Term and Renewal

The duration of an upstream petroleum interest depends on the nature of the interest. A PEL is granted for an initial three-year term, renewable for an additional three years, PPL is granted for an exploration period subject to statutory renewals, while a PML is granted for the production phase with a maximum term of 20 years, subject to renewal and continuation provisions. The precise duration and any renewal rights should therefore be considered by reference to the particular licence or lease and the applicable provisions of the PIA and regulations.

Relinquishment

Upstream licensees and lessees are subject to mandatory acreage relinquishment rules. The PIA also contains specific consequences for failure to progress a commercial discovery. Failure by a PPL holder to submit the required FDP within the prescribed period may result in automatic relinquishment of the discovery area. See 2.7 Development and Production Requirements.

Termination and Revocation

A PPL or PML may be revoked or otherwise terminated where the holder fails to comply with material statutory, regulatory or licence conditions. The PIA and the relevant licence or lease determine the circumstances in which an interest in an upstream asset may terminated or revoked.

Unitisation

When a petroleum reservoir straddles the boundaries of two or more licences or leases, the NUPRC may mandate the joint development and production on a unitised basis.       

Contractual Terms: Dispute Resolution and Force Majeure

Petroleum contracts such as PSCs, joint venture agreements and risk service contracts contain distinct commercial terms governing the relationship between the parties. The dispute-resolution mechanisms are contract-specific and may range from private negotiation to expert determination and even international arbitration. The treatment of force majeure and changes in law are determined by individual contract terms and must be analysed on a case-by-case basis.

The transfer of interests in upstream petroleum licences and leases is principally governed by Section 95 of PIA and the Assignment Regulations.

Government Consent

Any direct or indirect assignment of a PPL or PML requires the prior written consent of the Minister of Petroleum Resources, issued upon the recommendation of NUPRC.

The regulatory process follows a structured multi-stage timeline as follows:

• initial notification;
• preliminary reviews;
• evaluation and shortlisting stage;
• formal application; and
• final recommendation and approval.

Unlike PPLs and PMLs, an assignment of interest in a PEL, enforcing security over a PEL, or change of control of PEL-holder does not require Ministerial consent. It only requires the prior written consent of the NUPRC.

Minimum Requirements for the Transferee

The Assignment Regulations do not prescribe a fixed financial or technical threshold for transferees. Instead, NUPRC conducts a transaction-specific due diligence. A transferee must independently demonstrate that it possesses the technical and financial capacity to execute the work obligations of the licence.

For an assignment requiring Ministerial consent, the Assignment Regulations prescribe a transaction fee equal to 7% of the total transaction value, broken down into a 2% processing fee and a 5% premium. An intra-group transfer is subject only to a 2% processing fee. The transaction value is generally the amount payable to the assignor under the transaction documentation, although NUPRC may determine the value using its prescribed valuation metrics where appropriate. 

NUPRC’s due diligence specifically considers decommissioning and abandonment, environmental remediation and host community obligations before recommending an assignment.

Transfer of Operatorship

Where an assignment also involves a transfer of operatorship, the application must contain the consent of the other parties to the licence or lease where such consent is required under the relevant agreement. It must also include NUPRC’s written approval confirming that the proposed transferee is qualified to operate the licence or lease in Nigeria.

Where the assignment is to a party other than an affiliate or subsidiary, the application must also be accompanied by an Environmental Evaluation Study (EES) for the relevant licence or lease area, subject to the requirements of the PIA.

Legal and regulatory restrictions on crude oil production rates in Nigeria apply at both the international level, through Nigeria’s participation in OPEC/OPEC+ production management frameworks, and at the national level, via production quotas and Technical Allowable Rates (TAR) administered by the NUPRC.

OPEC/OPEC+ Production Restrictions

As an OPEC member, Nigeria is bound by the crude oil production-management limits established under the OPEC+ arrangements. For 2026, Nigeria maintained a crude oil production level at approximately 1.5 million barrels per day. 

The PIA expressly empowers the Minister to mandate production cutbacks to comply with international oil pricing or supply agreements supported by Nigeria.  The Crude Supply Regulations further provide that, where the Minister directs a production cutback under Section 3(2) of the PIA, NUPRC is to revise the production quotas allocated to upstream operators to conform with the Minister’s directive. 

Independently of OPEC mandates, a lessee is prohibited from conducting regular commercial production from any well without an approved TAR and a production quota issued by NUPRC. The TAR is principally determined by reference to the Maximum Efficiency Rate (MER), which the lessee must execute and submit to the NUPRC. Production quotas are also issued for periods of not more than six months.

There is also a separate domestic crude oil supply obligation (DCSO) under the Crude Supply Regulations. Crude oil produced by a lessee may be subject to a DCSO imposed by NUPRC.

There is no statutory requirement within Nigerian law to ensure that production cutbacks (whether internationally driven or domestic) are apportioned evenly or pro rata among active upstream producers.

Private investment is permitted across Nigeria’s midstream and downstream petroleum sectors. The PIA requires the NMDPRA to promote competition and private sector participation in the midstream and downstream petroleum sectors.

Midstream

Authorised midstream focus areas open to private investment include:

• gathering and transportation pipelines;
• gas processing and treatment;
• gas separation and fractionation; and
• storage and terminals.

The relevant activity and facility determine the precise regulatory authorisation required. In addition to the relevant NMDPRA licence, permit or approval, projects may require environmental approvals, environmental impact assessment approval, NCP approval or compliance, construction and planning approvals, health and safety approvals, and approvals relating to land, access and associated infrastructure.

Downstream

The core segments of downstream petroleum operations include:

• refining and petroleum processing facilities;
• petrochemical manufacturing;
• wholesale supply and marketing; and
• retail marketing.

Government Approvals and Regulatory Sanctions

Although private investment is permitted, operators must hold relevant regulatory authorisations before commencing a regulated midstream or downstream petroleum activity. The NMDPRA is the primary licensing authority, though parallel federal clearances for environmental impacts, local content quotas, construction and town planning approvals, and public health/safety rules remain mandatory, depending on the activity and facility involved.

There is no national monopoly over downstream petroleum operations in Nigeria. The PIA permits private participation in midstream and downstream petroleum operations through the licensing framework established under Parts III to V of Chapter 2.

The PIA provides for the vesting and transfer of assets, liabilities and operational continuity from the former Nigerian National Petroleum Corporation under Section 54 and permits NNPC Limited to be made supplier of last resort for security reasons, with the associated costs borne by the Federation. These provisions give NNPC Limited particular public-interest and energy-security functions, but they do not confer a general monopoly over downstream petroleum operations. 

The PIA’s general non-discrimination provision prohibits discrimination between customers or classes of customers in relation to access, tariffs, prices, conditions or standards of service. 

The NMDPRA is responsible for monitoring competition in regulated markets and preventing anti-competitive conduct, including conduct involving abuse of market power, discriminatory practices or conduct that may exclude or deter competitors. A licensee or permit holder is  prohibited from discriminating between customers, classes of customers, related undertakings or network users in respect of access, tariffs, prices, conditions or standards of service, reinforcing the foundational open-access principles of Section 116. These provisions would therefore be relevant if NNPC Limited’s particular market position or conduct were to place a private investor at an unjustified competitive disadvantage.

All midstream and downstream licensing are regulated by the NMDPRA. An application for a licence, permit or authorisation under the Midstream and Downstream Operations Regulations must be submitted in the form prescribed by the NMDPRA. Every licence, once issued, expires on December 31 of the year of issuance unless the licence explicitly states otherwise.

Applications for renewal of licences must be submitted at least 30 days prior to expiration, or earlier if required by the NMDPRA, following the prescribed procedure. Where the applicant is affiliated with a company that already holds a licence, permit or approval from the NMDPRA, that relationship must be disclosed. 

Extensions of existing licences or permits must strictly follow the procedure prescribed by the NMDPRA. Some of the principal licences issued in respect of midstream and downstream operations under the PIA include:

• wholesale gas supply licences;
• licence to establish a pipeline;
• gas processing and bulk gas storage licences;
• gas transportation and gas transportation network operator licences; 
• retail gas supply and gas distribution licences; and
• crude oil refining licences, etc.

Beyond the principal operational licences, operators also require ancillary approvals. For instance, the PIA mandates that an environmental management plan (EMP) relating to projects requiring environmental impact assessment be submitted to NMDPRA for approval. Prior to the approval of an EMP, the licensee is required to pay a prescribed financial contribution to an environmental remediation fund to address potential negative environmental impacts arising from the licence. 

The licensing categories for midstream and downstream operations have remained relatively stable. However, the NMDPRA has moved towards active enforcement of the licences. In an official circular published by the Chief Executive of the NMDPRA in May, 2026, the Chief Executive of NMDPRA declared all unlicensed midstream and downstream petroleum activities as illegal.

Typical commercial arrangements for the major types of midstream/downstream operations include the following.

• Processing agreement – usually governs the processing of crude oil or natural gas at a processing facility.
• Gas sale and purchase agreement – the principal contract for the sale and purchase of natural gas. It establishes the obligation of the seller to supply, and the buyer to purchase the specified quantities of gas over an agreed period of time.
• Offtake agreement – governs the purchase of petroleum or gas products from a producer, processor, refinery, terminal or storage facility. It is particularly relevant where a project requires certainty that its output will have a committed buyer.
• Storage agreement – governs the storage of crude oil, natural gas or petroleum products in tanks, terminals, depots, caverns or other approved storage facilities. It is commonly used by refiners, traders, marketers and other operators that require temporary custody of petroleum products before transportation or sale.

The fiscal terms and terms of service in commercial agreements under midstream and downstream operations are based on the mutual agreements between the parties to the contract. However, some terms of the agreements may be subject to government regulations or approvals. For example, the NMDPRA retains the authority to develop and enforce a framework on tariff and pricing for natural gas and petroleum products under the PIA and also by the PIA; the licensees are expected to charge tariffs for the use of their facilities and infrastructures in accordance with the methodologies set by the NMDPRA. 

The taxes that apply to companies carrying out the midstream and operations include the following.

• CIT – the standardised income tax applicable to companies operating within Nigeria’s midstream and downstream sectors. Under the current regime, the CIT rate is 0% for small companies (that is, companies with annual turnover of NGN100 million or less) and 30% for medium and large companies on their chargeable income and is payable annually.
• Development levy – a single consolidated levy on the assessable profits of companies at a flat rate of 4%. See 2.4 Income or Profits Tax Regime: Upstream. Small businesses and non-resident entities are fully exempt.
• Value-added tax – under the VAT (Modification) Order 2024, the Federal Government introduced complete VAT exemptions to key midstream and downstream energy products and infrastructure, including diesel, feed gas, LPG, CNG and LNG infrastructure.

Incentives and exemptions include the following.

• Economic Development Tax (EDT) Incentive – Midstream and downstream operators engaged in crude oil and gas refining are eligible for the EDT Credit incentive. The incentive applies to companies in electricity and gas supply, gas production and utilisation, purification and blending of gaseous fuels, transportation and distribution of gas, and refining of crude oil and other energy related operations. 
• Gas Pipeline Investment Tax Free Period – is an incentive which grants investors in gas pipelines a five-year, tax-free period, commencing after the expiration of their economic development incentive certificate. 
• Export Processing and Free Trade Zone Entities – see 4.1 Foreign Investment Rules Applicable to Domestic Investments in Hydrocarbons.

NNPC Limited is not granted any special statutory rights or exemptions in relation to the midstream and downstream licensing. Under the PIA, the NNPC Limited and its subsidiaries are mandated to conduct their operations in a commercial, profitable and efficient manner without recourse to government funding. It further provides that, where NNPC Limited holds a wholly owned or participating interest in any asset or operational licence, it is fully obligated to pay its share of all fees, rents, royalties, profit oil shares, taxes and other required statutory payments to the government on the same terms as any private company operating in Nigeria. 

The NOGICD Act establishes a framework for maximising Nigerian content in the Nigerian oil and gas industry and applies to operators, contractors and subcontractors, including those undertaking midstream and downstream activities. 2.6 Local Content Requirements: Upstream applies to midstream and downstream operations. 

For projects, contracts, subcontracts and purchase orders exceeding USD1 million, operators must obtain the board’s approval for the advertisements, pre-qualification criteria, technical bid documents, technical evaluation criteria and proposed bidders’ lists. 

For positions occupied by expatriates, operators must submit a succession plan providing for qualified Nigerians to understudy each expatriate for a maximum of four years, after which the position must be occupied by a Nigerian citizen.

Local content requirements further extend to professional and financial services. They must similarly utilise Nigerian financial institutions or organisations, except where the board considers this impracticable, and submit a Financial Services Plan every six months. Finally, all operators, project promoters, contractors and other entities engaged in the Nigerian oil and gas industry are required to undertake fabrication and welding activities within Nigeria.

The PIA establishes separate licensing regimes for midstream and downstream gas operations and for midstream and downstream petroleum liquids operations.

The PIA adopts an activity-specific licensing regime. For gas operations, licensable activities include gas processing, bulk gas storage, gas transportation pipelines and networks, wholesale and retail gas supply and gas distribution. For petroleum liquids, licences are required for activities including crude oil refining, bulk storage, transportation pipelines and networks, bulk supply, petroleum-product distribution and retail operations. 

The obligations attaching to a licence depend on the activity concerned. Infrastructure licensees are generally required to operate and maintain their facilities safely, reliably, economically and in an environmentally sustainable manner and, where applicable, provide services on a non-discriminatory or open-access basis. Similarly, bulk storage and transportation pipeline licences may be granted either for the licence’s own account, subject to third-party access requirements, or on an open-access/common-carrier basis, as stipulated in the licence. 

Domestic Supply Requirements

The PIA establishes a domestic gas supply framework to ensure the availability of natural gas for Nigeria’s strategic sectors. The domestic gas demand requirement comprises the total quantity of marketable natural gas required by wholesale customers in the strategic sectors.

Withdrawal and Termination

A holder that has commenced operations must generally give the NMDPRA at least 12 months prior written notice of its intention to cease operations, unless a shorter period is stipulated in the licence or permit. Separately, NMDPRA may revoke a licence or permit on specified grounds. Prior to a revocation decision, NMDPRA must issue a formal notice specifying the default and allow the holder of the licence 60 days to remedy it, where the default is remedied, the revocation process terminates, but where it remains unremedied at the expiry of that period, the licence or permit is terminated.

A private investor constructing midstream or downstream petroleum infrastructure does not have independent compulsory acquisition or eminent domain rights. Acquisition of land for midstream/downstream operations is subject to the Land Use Act and applicable compensation requirements.

Under the Land Use Act, the Governor may revoke a right of occupancy for overriding public interest and by extension includes land required for petroleum operations or related purposes subject to the payment of a fair and adequate compensation. 

The PIA also provides for rights of way for petroleum infrastructure under Sections 127 and 176, while Sections 128 and 177 address the preservation of rights of way, easements and other surface rights.

The transportation of hydrocarbons in Nigeria is principally regulated under the PIA, together with regulations made pursuant to the Act. The NMDPRA is responsible for regulating bulk storage, distribution, marketing and transportation pipelines for petroleum products and is empowered to issue regulations governing midstream and downstream petroleum operations. 

The PIA establishes licensing requirements for gas and petroleum liquids transportation pipelines and provides for third-party and open access to qualifying transportation infrastructure. The OPA also remains relevant to pipeline transportation, particularly in the upstream sector.

Access to transportation infrastructure and the associated commercial costs are subject to tight federal regulatory oversight. The PIA requires transportation tariffs to be cost-reflective, provide a reasonable return on investment and remain non-discriminatory. For natural gas pipelines, the Natural Gas Pipeline Tariff Regulations 2023 establish the applicable tariff framework, including capacity and commodity charges.

Significantly, Nigerian petroleum law does not make a fundamental distinction based solely on whether a pipeline is intra-state or interstate. Unlike jurisdictions where interstate pipelines may be subject to federal regulation while intra-state pipelines are regulated principally at state level, petroleum transportation in Nigeria is generally subject to federal regulation, with the applicable regulator determined primarily by whether the activity falls within the upstream or midstream/downstream sector.

The PIA provides a robust statutory framework for third-party and open access to certain privately constructed midstream and downstream infrastructure. For gas processing facilities, bulk gas storage infrastructure, and gas transportation pipelines operated on an own-account basis, licensees are legally mandated to provide third-party access in an equitable manner. 

Where third-party access applies, access must generally be provided on a non-discriminatory basis, particularly between users with similar characteristics, and is subject to available capacity that is not already committed under an existing contract.

The PIA does not impose a general requirement for complete unbundling of all midstream/downstream services, nor does it require every operational component to be provided separately. An open-access gas processing licensee is prohibited from processing gas on its own account, while a common-carrier gas transportation pipeline licensee cannot commercially supply natural gas to customers on its own account. 

There is therefore no blanket prohibition on the same entity providing services across multiple market segments. Certain forms of vertical integration are permitted, but remain subject to third-party access, non-discrimination and competition requirements. Licensees are prohibited from engaging in activities that may prevent, restrict or distort competition. 

To safeguard local energy security and ensure adequate supplies to domestic refineries, the PIA mandates the NUPRC to enforce a domestic crude oil supply obligation on upstream lessees. Failure to meet domestic supply obligations may result in penalties, restrictions on exports, and regulatory sanctions.

Regarding downstream market participation, the PIA strictly prohibits informal operations. No person is permitted to engage in the distribution, midstream bulk supply, or retail supply of natural gas unless that individual is a qualified entity and has been formally issued the requisite operational licence by the NMDPRA. 

While the PIA permits participation across multiple value chains of the oil and gas industry, participation is subjected to obtaining separate licences for each operation whether it is upstream, midstream or downstream operation.

The exportation of crude oil, natural gas and petroleum products from Nigeria are highly regulated under the PIA and associated regulations, with oversight by agencies such as the NMDPRA for refined products, the NUPRC for crude oil and gas liquids, and the Federal Ministry of Industry, Trade and Investment (FMITI).

In addition, crude oil, condensate, and natural gas liquids (NGL) exports require an export permit, vessel clearance, and an electronically imprinted Unique Identification Number (UIN) from the NUPRC before leaving any terminal.

Additionally, the Pre-Shipment Inspection of Exports Act, 1996 requires all exports from Nigeria to undergo inspection to be conducted by the appointed inspection agent prior to their shipment to ascertain their quality and quantity and for price comparison.

Under the PIA and the Gas Delivery Regulations, gas producers are required to prioritise supply to the domestic market. Advance cargo declarations, environmental permits, and other statutory approvals may be required depending on the product and destination.

Transfer of interests in the midstream and downstream operation or assets will require the approval of the NMDPRA.

Asset sales trigger direct regulatory transfer requirements; share sales are often used precisely to avoid re-applying for licences, though NMDPRA consent is increasingly required even for indirect changes of control.

The PIA and the Midstream and Downstream Petroleum Operations Regulations 2025 prohibit any assignment or transfer of a licence or permit, or any right or obligation arising from it, without the prior written consent of NMDPRA. A licensee must obtain NMDPRA’s prior written consent before assigning, transferring or novating a licence or interest, and in granting consent NMDPRA assesses the transferee’s technical competence, operational experience, financial capacity and regulatory compliance capability, may impose public-interest conditions, assess competition risk, and confirm that environmental, abandonment and decommissioning liabilities are properly assumed by the transferee.

Legacy liabilities, decommissioning, abandonment and environmental remediation obligations must be expressly allocated in the transfer documents, since NMDPRA will not approve a transfer unless it is satisfied the transferee can assume them.

Pursuant to the Companies and Allied Matters Act 2020 (CAMA), any foreign company intending to carry on business in Nigeria must formally incorporate a local subsidiary with the Corporate Affairs Commission (CAC) before commencing operations.

For foreign direct investment (FDI), the investor (foreign enterprise or an individual) must incorporate a local Nigerian entity with the CAC. Upon registration of the company, the entity must secure a Nigeria Investment Promotion Commission (NIPC) Business Registration Certificate alongside the specific licences and permits required to carry out operations in the targeted sector.

To guarantee seamless fiscal mobility, any foreign investor importing equity capital or debt financing (including specialised refinery equipment) must obtain an electronic Certificate of Capital Importation (CCI) from an Authorised Dealer, typically a commercial bank licensed by the Central Bank of Nigeria. Export free trade zones (FTZ) enterprises are permitted to fully repatriate foreign capital investments and enjoy sweeping exemptions from domestic taxes, local levies, customs duties, and standard foreign exchange regulations. However, investors must note that the NOGICD Act explicitly overrides FTZ exemptions.

Foreign investors and multinational corporations can invest in oil and gas assets in Nigeria. To operate legally within the sector, these entities must obtain the requisite licences, permits and regulatory approvals stipulated by applicable laws, including executing all operations through a locally incorporated Nigerian subsidiary.

For instance, an operator is strictly prohibited from establishing, constructing or operating a pipeline or facility network for the transportation and distribution of petroleum liquids, natural gas or its derivatives without an appropriate licence granted by the NMDPRA.

The environmental regulation of petroleum operations in Nigeria is governed by a multi-agency framework.

Pursuant to its powers under the PIA, the NUPRC has issued subsidiary regulations addressing various aspects of environmental management in upstream operations, including the NUPRC, the Nigerian Upstream Petroleum Decommissioning and Abandonment Regulations, 2023, the Nigerian Upstream Petroleum Host Communities Development Regulation, 2022, and the Gas Flaring, Venting and Methane Emissions (Prevention of Waste and Pollution) Regulations, 2023.

The NMDPRA’s principal environmental instruments include the Midstream and Downstream Petroleum Environmental Regulations 2023, the Midstream and Downstream Environmental Remediation Fund Regulations 2023, the Midstream and Downstream Decommissioning and Abandonment Regulations 2023, and the Midstream and Downstream Petroleum Safety Regulations 2023. The NMDPRA is also empowered to monitor and enforce compliance with applicable regulatory requirements, including through inspections and audits.

In addition to the aforementioned laws and regulations, further principal federal environmental laws applicable to petroleum operations include the: (i) PIA; (ii) Environmental Impact Assessment Act No 86 of 1992 (the “EIA Act”); (iii) Environmental Guidelines and Standards for the Petroleum Industry in Nigeria, 2018 (the “EGASPIN 2018”); (iv) Climate Change Act 2021; (v) Harmful Waste (Special Criminal Provisions) Act, 1988 (the “Harmful Waste Act”); and (vi) Oil Pipelines Act, 2004.

The PIA provides the overarching statutory framework for environmental regulation of petroleum operations, while subsidiary instruments issued by the NUPRC and NMDPRA establish more detailed Environmental, Health and Safety requirements applicable to particular segments of the petroleum value chain.

A private investor proposing to undertake a major hydrocarbon project in Nigeria will generally be required to undertake environmental assessment and obtain the relevant environmental and petroleum-sector approvals before commencing the relevant project. An investor must therefore obtain the relevant environmental approval from the Federal Ministry of Environment before commencing a project for which an EIA is required.

For upstream projects, the requirements are supplemented by the Upstream Petroleum Environmental Remediation Regulations 2024. A licensee, lessee or operator must prepare and submit an Environmental Management Plan (EMP) addressing the environmental risks and impacts of its proposed petroleum operations. The EMP is subject to approval by the NUPRC. Importantly, EIA approval and an EMP do not exhaust the environmental authorisations that may be required for upstream operations.

The Upstream Petroleum Environmental Regulations expressly require operators to obtain specific permits and approvals from the NUPRC for certain activities. These include: an Environmental Permit for seismic activities, which must be obtained before commencement of seismic operations; for midstream and downstream projects, the investor must comply with the environmental requirements administered by the NMDPRA, including the Midstream and Downstream Petroleum Environmental Regulations 2023, as well as the general federal environmental framework.

A critical point for an investor is that these requirements are front-loaded. The EIA and relevant environmental studies should be undertaken during the project-planning and pre-construction stage, rather than after construction or operations have commenced. Similarly, the relevant EMPs and activity-specific environmental permits must be obtained before undertaking the activities for which they are required.

Offshore petroleum operations in Nigeria are subject to environmental, health and safety requirements under the PIA, applicable environmental legislation and regulations and guidelines issued by the relevant regulators.

A licensee or lessee engaged in upstream or midstream petroleum operations to submit an environmental management plan for projects that require an environmental impact assessment. The PIA also prohibits the use of chemicals in upstream petroleum operations without the applicable permit and approval.

NUPRC’s Health, Safety, Environment, and Community (HSEC) framework requires operators to identify, mitigate and manage risks associated with petroleum operations. The Petroleum Safety Regulations, 2022 also impose further requirements on operators in relation to health and safety.

The PIA places environmental management obligations on the relevant licensee or lessee. It does, however, require each licensee and lessee to establish and maintain a decommissioning and abandonment fund in an escrow account with a financial institution that is not an affiliate of the licensee or lessee. Ultimately, offshore developments require deeply front-loaded environmental approvals, rigorous structural risk management, and continuous personnel safety controls.

The PIA requires the decommissioning and abandonment of petroleum wells, installations, structures, utilities, plants and pipelines to be carried out in accordance with good international petroleum industry practice and guidelines issued by the relevant regulator.

Decommissioning and abandonment cannot take place without the prior written approval of the NUPRC or the NMDPRA, as applicable. For upstream operation the applicable regulation is the Nigeria Upstream Petroleum Decommissioning and Abandonment Regulations 2026 while the Midstream and Downstream Decommissioning and Abandonment Regulations 2023 apply to midstream and downstream operations.

The PIA also requires each licensee and lessee to establish and maintain a decommissioning and abandonment fund in the form of an escrow account with a financial institution that is not its affiliate. Where no plan exists and the field is already in development or production, the lessee must submit a plan based on the requirements in Section 232(6) of the PIA within one year of the commencement of the PIA. The cost estimate must be approved by NUPRC or NMDPRA, as applicable. The relevant regulator may require a former licensee or lessee responsible for a decommissioning and abandonment programme to return and perform outstanding obligations, including where the interest has been transferred or divested.

The principal climate change legislation in Nigeria is the Climate Change Act 2021. See 6.1 Energy Transition Laws and Regulations.

The oil and gas industry is heavily regulated and is subject to additional climate-related requirements under the PIA. The Gas Flaring, Venting and Methane Emissions (Prevention of Waste and Pollution) Regulations, 2023, impose obligations on operators to prevent and reduce emissions and to comply with applicable monitoring and reporting requirements.

The Guidelines for the Management of Fugitive Methane and Greenhouse Gases in the Upstream Oil and Gas Sector, 2022 also establish requirements for the measurement and management of methane and other greenhouse gas emissions from upstream operations.

NUPRC has introduced additional decarbonisation requirements for upstream operations. Applicants for upstream licences and permits are required to demonstrate measures for reducing carbon emissions and to provide for renewable energy as part of their proposed operations. NUPRC has also introduced requirements for the measurement, reporting and verification of methane and greenhouse gas emissions from upstream operations.

Nigeria adopts the domanial system of petroleum ownership, under which petroleum resources are vested in the government of the Federation. Section 44(3) of the Constitution provides that the entire property in and control of all minerals, mineral oils and natural gas in, under or upon any land in Nigeria is vested in the government of the Federation.

The PIA provides for federal regulatory regime for petroleum operations, administered principally by the NUPRC and the NMDPRA. As such, local governments therefore do not have an independent power to grant, regulate, suspend or revoke petroleum licences, leases or permits. A local government also cannot impose a requirement that conflicts with the PIA or regulations made under it. However, those powers must be exercised consistently with the Constitution and applicable federal legislation.

Environmental regulation of petroleum operations is principally governed by federal legislation and the regulatory framework administered by the relevant federal authorities.

Major laws or government programs focused on Energy include the following.

• Climate Change Act, 2021 (CCA) – Nigeria’s principal legal framework for the energy transition is the CCA which establishes a framework for national climate governance, including the development of a National Climate Change Action Plan and measures for achieving Nigeria’s climate objectives.
• The Energy Transition Plan (ETP) – launched in 2022, Nigeria’s ETP sets out a pathway toward net-zero emissions by 2060, covering power, cooking, oil and gas, transport and industry. 
• The Electricity Act, 2023 (EA) – came into force in June 2023, and was passed in light of the Federal Government’s initiatives to accelerate Nigeria’s energy transition process and consolidate regulation of the Nigerian Electricity Supply Industry, repealing the Electric Power Sector Reform Act 2005. The EA also creates generation, transmission, system operations, trading and distribution/supply licences for private investors, plus feed-in tariffs guaranteeing fixed prices for renewable electricity fed into the grid, alongside tax incentives.

Complementary instruments such as the National Renewable Energy and Energy Efficiency Policy (2015), the Rural Electrification Strategy, the National Energy Masterplan, and Nigeria’s Renewable Energy Roadmap, 2023 flesh out targets and implementation detail, and NERC’s 2026 Mini-Grid Regulations have further expanded the space for distributed renewable projects.

Oil and gas upstream and midstream assets are increasingly being used or utilised to support energy-transition objectives.

A clear Nigerian example is the Nigerian Gas Flare Commercialisation Programme (NGFCP), originally launched in December 2016 and relaunched as NGFCP 2022, to offer flare sites to technically and commercially competent third-party investors through a competitive and transparent bid process, with the objective of ending gas flaring in Nigeria. By October 2023, NUPRC had announced successful bidders, and across the 49 flare sites awarded to 42 bidders. The permitted portfolio could capture and commercialise approximately 250–300 MMscf/d of currently flared gas and eliminate approximately 6 million tonnes of CO₂ annually. In December 2025, Nigeria issued Permits to Access Flare Gas to 28 successful awardees, with the projects expected to unlock nearly 3 gigawatts of power generation potential, attract up to 2 billion dollars in investment, and produce around 170,000 metric tonnes of LPG annually enough for clean cooking access for roughly 1.4 million households.

On the regulatory side, an industry survey confirms NUPRC has gazetted a number of regulations to operationalise several PIA provisions, but comprehensive hydrogen or CCUS-specific legislation had not yet materialised as a standalone framework; these technologies are referenced mainly in the Energy Transition Plan's long-range roadmap rather than in binding law.

The most visible impact of energy transition has been a structural reordering of who owns and operates upstream assets, driven partly, though not solely, by transition pressure. Nigeria has seen a wave of major IOC divestments from onshore and shallow-water assets: Shell’s roughly USD2.4 billion sale of its onshore portfolio to the Renaissance Consortium completed in February 2025 (after NUPRC initially rejected the deal in August 2024 over regulatory-compliance concerns), ExxonMobil’s USD1.28 billion divestment to Seplat Energy approved in March 2025, and TotalEnergies’ proposed USD860 million sale to Chappal Energies.

Indigenous firms have stepped decisively into the gap: Nigeria’s rig count rose from eight in 2021 to 69 by October 2025 (a 762.5% increase), and indigenous companies now contribute over 50% of Nigeria’s crude oil production, having added significant output and attracted billions in fresh investment.

Similarly, capital and strategic focus within the sector is bifurcating between “cleaner” offshore/gas assets and higher-risk onshore ones. Climate considerations and the global shift toward renewable energy are cited as one of several factors accelerating IOC divestment of onshore assets, alongside regulatory uncertainty and economic/security concerns, even though the enactment of the PIA did not fully stem this trend.

Nigeria does not maintain a specialised or separate regulatory scheme tailored to unconventional upstream petroleum assets. Unconventionals are absorbed into the general PIA framework. Conventional Niger Delta oil and associated/non-associated gas remain overwhelmingly dominant.

Investors pursuing coal-bed methane must navigate a distinct jurisdictional boundary overlap: while the extracted gas falls under the PIA and the purview of the NUPRC, the underlying coal substrate remains subject to the Nigerian Minerals and Mining Act 2007, administered by the Ministry of Solid Minerals Development, creating potential dual-licensing frictions over the same acreage.

There is no standalone prohibition or moratorium on hydraulic fracturing, but no dedicated fracking regulation exists either. Licensees and lessees extracting natural gas through fracking are generally required to comply with generic federal environmental laws rather than a specialised code addressing deep-well water sourcing, chemical disclosure, flowback wastewater disposal, well-bore isolation integrity, or induced-seismicity monitoring.

While fracking is not prohibited by law, any commercial fracking operations must comply with standard industry frameworks.

There is no one stand-alone statutory regime that governs all LNG projects in Nigeria. LNG projects are mainly governed by the PIA, as well as the regulations governed by the NMDPRA. Section 110(15) of the PIA stipulates that the approval for the supply of natural gas for an export project will be contingent on the fulfillment of domestic gas delivery obligations by the lessee.

The 2024 Oil and Gas Companies (Tax Incentives, Exemption, Remission, etc) Order made provisions for tax credits and allowances for new NAG greenfield developments in onshore and shallow-water areas. Under the 2024 incentive scheme, there is a production tax credit of USD1.00 per Mscf or 30% of the fiscal gas price, whichever is lower, for sales up to cumulative 5 Tcf, where the hydrocarbon-liquid content is 30 barrels per MMscf; USD0.50 per Mscf or 30% of the fiscal gas price, whichever is lower, where the HCL content is more than 30 but less than 100 barrels per MMscf.

The upstream development process will require the approval of the NUPRC, including field development and production requirements. In relation to the LNG plant and the midstream facilities, the project developer will require the appropriate NMDPRA licence. The Authority’s present regulatory framework includes the Midstream and Downstream Petroleum Operations Regulations 2025, environmental, safety regulations, decommissioning and other facility-specific regulations. NMDPRA has electronic licensing systems for its midstream and gas-export approvals.

Host Community Development Trusts Fund

By October 2025, the fund had reached NGN373 billion across 536 projects, with 103 trusts fully incorporated as of early 2024. This is directly relevant to any upstream JV, farm-out or asset-transfer advisory, since HCDT obligations transfer with the licence.

Gas Flare Penalties as a Dedicated Environmental Fund, Not General Revenue

Carbon-emission and gas flare penalties are statutorily designated as environmental restoration funds to be utilised exclusively for ecological remediation and infrastructure development within impacted host communities. Between 2021 and 2025, approximately NGN1.67 trillion was collected in gas flare penalties nationwide.

Frontier Basin Exploration Funding

The PIA provides for 30% of NNPC Ltd’s profit oil/gas derived from its production sharing contracts to be dedicated specifically for frontier exploration (frontier basins like the Chad Basin, Benue Trough).

Gas-Focused Fiscal Reform Via Bespoke PSCs

Nigeria’s 2025 production-sharing contract with TotalEnergies was described as a new template reflecting the PIA’s recognition that gas economics differ fundamentally from oil economics.

There have been material changes in oil and gas laws and regulations in Nigeria over the past year. Notable amongst these changes are as follows.

• The new Nigerian Upstream Petroleum Decommissioning and Abandonment Regulations, 2026 (the “2026 Regulations”), which repeal and replaces the 2023 Regulations, after implementation exposed key flaws: rigid, undifferentiated timelines for submitting Decommissioning and Abandonment (D&A) Plans; an overly tight 90-day funding window with Fund custody restricted solely to the Central Bank of Nigeria and a fixed IOC contribution schedule; and an inflexible three-year well-suspension cap. The 2026 Regulations address these by tying D&A Plan submission to project milestones (Work Programme approval for PPL holders, Field Development Plan approval for PML holders); extending the Fund-establishment window to 180 days while allowing escrow accounts at any Nigerian or foreign institution with a minimum A+ credit rating; and replacing the fixed suspension cap with separate, extendable limits:  one year for shut-ins and four years for suspended wells  while retaining NUPRC’s enforcement power to access the Fund and appoint a third party if an operator fails to abandon a well on time.
• Institutional leadership also changed hands, with implications for regulatory tone going forward. A new Commission Chief Executive, Eyesan, took charge of NUPRC in December 2025, promising a “bold reset” of the upstream sector, and January 2026 saw renewed formal collaboration between NUPRC and NMDPRA, the two agencies agreeing to quarterly co-ordination meetings aimed at resolving the regulatory overlaps that had prompted the PIA Amendment Bill in the first place. Meanwhile, legislative oversight has intensified: in December 2025, the House of Representatives Ad-hoc Committee on Decommissioning and Abandonment criticised both NUPRC and NMDPRA for allegedly failing to comply with key PIA decommissioning provisions, scrutinising operators’ financial provisions including escrow account adequacy.
• A draft Petroleum Industry Act (Amendment) Bill, 2025, which would substantially restructure NNPC’s governance and the NUPRC/NMDPRA regulatory split was approved by President Tinubu for early implementation talks that would tilt Nigeria’s oil architecture towards a finance-led state owner and a strengthened regulator, with the most consequential change seeing NUPRC replace NNPC Ltd as the government’s concessionaire in existing production, profit-, and risk-service contracts. As of mid-2026 this remains a bill, not yet enacted law, but it represents the most significant proposed structural change to the PIA framework since 2021.
• On the regulatory (rather than statutory) side, NUPRC and NMDPRA have continued issuing implementing regulations and directives. The Midstream and Downstream Operations Regulations, 2025 were gazetted, and now require a licensee or permit holder applying to surrender its licence or permit to submit a report containing a detailed plan for decommissioning, abandonment and environmental remediation, where applicable. NUPRC also introduced a new Measurement, Reporting and Verification (MRV) directive requiring operators to report emissions using IPCC Tier 2 methodologies from Q3 2026, moving to full IPCC Tier 3 or equivalent measurement-based systems by January 2027, tied explicitly to Nigeria’s Net Zero by 2060 and Zero Routine Flaring by 2030 commitments.
• President Tinubu’s Executive Order on Direct Remittance of Oil and Gas Revenues (February 13, 2026) (the “Order”) was signed pursuant to Section 5 of the Constitution and anchored on Section 44(3) which vests ownership, control, and derivative rights in all minerals, mineral oils, and natural gas in the government of the Federation. The Order requires all operators/contractors of oil and gas assets held under production sharing contracts to pay Royalty Oil, Tax Oil, Profit Oil, Profit Gas and other government-entitled revenues directly into the Federation Account, rather than through NNPC Limited as intermediary