GAS FLARE COMMERCIALISATION IN NIGERIA: PROGRESS, GAPS, AND WHAT OPERATORS NEED TO KNOW

1.    INTRODUCTION

Nigeria has been routinely flaring associated gas[1] for over six decades. In that time, the Federal Government has announced deadlines to end the practice,[2] enacted legislation to prohibit it,[3] and collected penalties from operators who continue regardless. None of it has worked: as of 2025, Nigeria remains one of the world’s leading gas flaring countries,[4] and the most recent data illustrates the paradox with uncomfortable precision – oil and gas operators paid approximately $646 million in gas flare penalties in 2025 the highest figure in five years, even as flaring volumes rose to 323.2 million standard cubic feet per day over the same period.[5]

Against that backdrop, 2026 marks a transition point. The Nigerian Gas Flare Commercialisation Programme (“NGFCP”) has moved from a prolonged permitting phase into physical execution. The programme was designed in three phases: competitive bidding in 2023, negotiation and permit issuance through 2024 and 2025, and physical execution beginning in 2026.[6] The Nigerian Upstream Petroleum Regulatory Commission (“NUPRC” or the “Commission”) issued Permits to Access Flare Gas (“PAFGs”) to 28 companies in December 2025, projecting $2 billion in investment and 100,000 jobs.[7]  Those developers are now in the execution phase, with contractual milestone obligations running.

The regulatory environment has also shifted. A new NUPRC Commission Chief Executive (“CCE“) assumed office in January 2026 with a stated agenda of full Petroleum Industry Act 2021 (“PIA”)compliance within 12 months, a 90-day fast-track approvals programme, and enhanced enforcement of metering and emissions reporting obligations.[8]  In April 2026, the NUPRC issued a directive requiring all upstream operators to adopt IPCC Tier 2 emissions measurement methods by Q3 2026 and to transition fully to Tier 3 measurement-based reporting by January 2027.[9]  Nigeria’s total gas reserves were formally confirmed at 215.19 trillion cubic feet in the NUPRC’s January 2026 declaration – a 2.21% increase year-on-year – underscoring the scale of the resource that continues to be wasted at the flare stack.[10]

Operators face statutory obligations to submit Flare Elimination and Monetisation Plans,[11] non-deductible penalties for continued flaring, and the prospect of the NUPRC exercising its power to compulsorily redirect associated gas to permit holders.[12] For PAFG holders, execution phase means milestone clocks are live and performance obligations have begun.

This briefing note  examines the regulatory framework, the current state of the NGFCP, and the key legal and commercial issues that will define execution risk through 2026 and beyond.

2.  THE REGULATORY FRAMEWORK: FROM PROHIBITION TO COMMERCIALISATION

a.    The Pre-Petroleum Industry Act (“PIA”) Regime

The Associated Gas Re-injection Act of 1979 permitted flaring through Ministerial certificates of exemption, which became routine commercial accommodation rather than genuine exception.[13] The 2018 Flare Gas Regulations introduced a market-based mechanism and third-party access,[14] but implementation was slow, penalties remained commercially immaterial, and no unified enforcement structure existed.

b.    The PIA 2021: A Coherent Statutory Framework

The PIA introduced a coherent legal and regulatory framework backed by clear obligations and meaningful sanctions. Under Section 104 of the PIA, routine flaring is explicitly prohibited except in emergencies, approved safety practices, or pursuant to a specific NUPRC exemption.[15] Any flaring outside those conditions constitutes a statutory offence. Penalties are payable in the same manner as royalties,[16] cannot be recovered as operating costs or deducted for tax purposes,[17] and revenues derived from them are directed toward environmental remediation and community relief.[18]

Beyond the prohibition, the PIA embeds a forward-looking compliance mechanism. Section 105(1) creates a general obligation on licensees to develop and commercialise associated gas rather than flare it.[19] Section 105(2) empowers the NUPRC to take, at no cost to the Commission, any gas destined for flaring and redirect it to an approved use,  giving the regulator an active market-making power, rather than merely a punitive one.[20] Section 108 further requires all producers to submit a Natural Gas Flare Elimination and Monetisation Plan to the NUPRC within 12 months of the PIA’s commencement, with regulatory and financial sanctions for failure to comply.[21]

The Gas Flaring, Venting and Methane Emissions (Prevention of Waste and Pollution) Regulations 2023 operationalise these statutory provisions, providing the detailed compliance, measurement, and enforcement framework through which the NUPRC implements the NGFCP and enforces flare elimination obligations across the sector.[22]

3.  THE NGFCP IN 2026: THE LAUNCH OF THE EXECUTION PHASE

The NGFCP was structured as a three-phase programme from the outset: a competitive bidding phase that produced 42 selected bidders in September 2023;[23] a negotiation and permitting phase through 2024 and into 2025 during which technical, commercial, and contractual terms were finalised; and an execution phase commencing in 2026, in which selected developers are expected to commence physical flare-out work on-site.[24] The programme targets 49 flare sites across land, swamp, and shallow offshore terrains, with aggregate gas volumes estimated at between 250 and 300 million standard cubic feet per day by 2027.[25]

In December 2025, the NUPRC issued PAFGs to 28 of the 42 selected bidders.[26] The 14 who did not advance had failed to execute one or more of the three mandatory commercial instruments required before permit issuance: a connection agreement with the upstream operator, a milestone development agreement with the NUPRC, and a gas sale agreement with a downstream offtaker. Those 14 remain eligible to complete the process but have not yet done so. The December 2025 cohort represents the programme’s first operational wave.

Several significant developments have followed. In January 2026, the new CCE unveiled a three-pillar vision centred on production optimisation, regulatory predictability, and sustainable operations,[27] supported by the 90-day fast-track approvals programme already underway. In February 2026, the NUPRC and Nigerian National Petroleum Company  Limited  formalised a collaboration to improve regulatory efficiency, with the NNPC Gas Master Plan presented and progress on the Obiafu-Obrikom-Oben (OB3) and Ajaokuta -Kaduna-Kano (AKK) pipelines confirmed.[28] If those pipelines deliver on schedule, they will expand the downstream market available to NGFCP permit holders and materially improve the bankability of gas sale agreements. The NUPRC’s April 2026 Tier 2/3 emissions directive directly affects flare gas projects by setting the standard against which flare volumes will be measured – which in turn determines the penalty assessment baseline and the volumetric data underpinning PAFG project economics.[29]

4.  KEY LEGAL AND COMMERCIAL ISSUES

a.    The Three Mandatory Agreements

A PAFG is only issued upon execution of three commercial instruments. The connection agreement governs the physical and operational interface between the PAFG holder’s capture and processing infrastructure and the upstream operator’s existing facilities. It covers access rights, infrastructure integration standards, liability for damage or interruption, and the terms on which associated gas is made available at the flare point. The milestone development agreement sets out the construction and commissioning timeline that the PAFG holder must meet, with the NUPRC as counterparty, and contains provisions dealing with extensions, defaults, and the consequences of missing agreed flare-out dates. The gas sale agreement governs the downstream arrangement, covering pricing, delivery obligations, and offtake commitments with the relevant buyer.

For the 28 permit holders now in the execution phase, these agreements are signed and performance obligations are live. The structuring priority has shifted from negotiation to execution risk management. For the 14 remaining bidders and any future NGFCP participants, understanding and properly structuring these three instruments remains the foundational legal task.

b.    Third-Party Access Rights and Metering

Where a PAFG has been issued over a flare site on or adjacent to an operator’s licence area, the operator is legally required to facilitate access to flare infrastructure, provide volumetric data, and where necessary integrate the PAFG holder’s gathering systems into existing operational facilities. That obligation, however, does not resolve itself at the contract level. Access negotiations have historically been one of the most persistent sources of delay in upstream gas infrastructure projects in Nigeria, and the NGFCP has not been an exception. Connection agreements must therefore specify access timelines with precision, agreed technical integration standards, step-in rights in the event of operator default, and a clear escalation mechanism where bilateral negotiations fail.

Closely related is the question of metering. The commercial viability of any PAFG project depends on reliable data about the volume of associated gas available at the flare site. Those volumes determine the penalty baseline against which captured gas is credited, the offtake quantities committed in the gas sale agreement, and the revenue assumptions on which the project’s financial model is built. The NUPRC’s April 2026 directive requiring upstream operators to adopt IPCC Tier 2 measurement methods by Q3 2026 and to transition to Tier 3 measurement-based reporting by January 2027[30] raises the technical floor against which those volumes will be assessed. PAFG holders negotiating connection agreements now must ensure that the metering standard the operator is required to maintain is explicitly specified and consistent with current NUPRC requirements. Independent volumetric assessments of target flare sites before financial close are not optional; they are a condition of bankable project documentation.

c.    Host Community Obligations

The PIA imposes substantive obligations on upstream operators in relation to host communities, the most significant of which is the requirement to establish and fund a Host Community Development Trust (“HCDT“). Under Section 235 of the PIA, operators – described in the PIA  as settlors – are required to incorporate an HCDT for the benefit of the host communities within their licence area.[31] Section 240(2) requires each settlor to make an annual contribution equal to three percent (3%) of its actual operating expenditure from the preceding financial year into the applicable trust fund, to be administered in accordance with a community development plan and overseen by a board of trustees registered with the Corporate Affairs Commission.[32] Failure to establish or fund an HCDT within the prescribed timelines attracts regulatory sanctions.[33]

For flare gas commercialisation projects, this framework creates a structural question that the NGFCP’s commercial architecture has not yet fully resolved: where the PAFG holder is a third-party developer distinct from the upstream operator, which party bears the HCDT contribution obligation in respect of the new gathering and processing infrastructure being introduced into the community? The PIA’s HCDT provisions are framed around the upstream operator as the primary obligor. A PAFG holder constructing new infrastructure within or adjacent to that operator’s licence area may not fall squarely within the statutory definition of a settlor, but will nonetheless carry a practical community engagement obligation that, if unmanaged, creates the same operational consequences as a formal legal default. Community resistance to construction, interference with infrastructure, and damage to financing structures are all real and live exposures that must be addressed at the project formation stage.[34]

5.  CONCLUSION

Nigeria’s gas flare commercialisation framework is now operational. The PIA provides a clear statutory foundation, 28 PAFGs have been issued, and the NUPRC has signalled accelerated enforcement for 2026. Yet the fundamental paradox remains: $646 million in penalties collected in 2025 alongside rising flaring volumes. The penalty regime collects revenue but does not deter. For upstream operators, the cost of inaction has risen – including the real prospect of compulsory redirection of gas under section 105(2) of the PIA. For PAFG holders, the opportunity is real but requires disciplined execution: the three mandatory agreements are now performance contracts with running clocks, metering standards must align with the April 2026 Tier 2/3 directive, and host community obligations must be addressed at formation. The framework is ready. Delivery now depends on execution, not new rules.

Please do not treat the foregoing as legal advice, as it only represents the public commentary views of the authors. All enquiries on this should be directed to the key contacts.

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