Nigeria’s gas problem is not geological. It is contractual, regulatory and commercial — and the next decade will decide whether the country fixes it.
Nigeria holds the largest proven natural gas reserves in Africa. In January 2026, the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) declared national gas reserves of 215.19 trillion cubic feet as the official reserves position — up from 210.54 trillion cubic feet a year earlier, and comfortably ahead of Algeria and Egypt. Yet gas shortages continue to constrain electricity generation across the country, while the nation simultaneously pursues expanded liquefied natural gas (LNG) export ambitions.
The distribution of that gas explains the paradox more sharply than any reserve figure. On government data, the domestic market receives roughly 28 per cent of produced gas. Exports absorb about 36 per cent. The balance goes to fuel and reinjection, with a further portion still flared. A country with the continent’s deepest reserves therefore delivers barely a quarter of its own output to its own consumers.
How does that happen? The answer lies not beneath Nigeria’s soil but in the legal, commercial and regulatory architecture that governs how gas moves from producer to end user.
As Nigeria pursues its energy transition objectives, natural gas is expected to play a central role. It can support industrialisation, expand electricity access, deliver lower carbon intensity than coal and liquid fuels, and generate foreign exchange. Achieving those objectives will require more than abundant reserves. It will require legal certainty, commercially viable market structures, bankable payment security and coordinated implementation.
This is where gas aggregation becomes decisive.
Four Bottlenecks Slowing Domestic Gas Aggregation
Four constraints, in my assessment, hold the domestic gas market back. They are interconnected. Progress in one area without corresponding improvement in the others will deliver only incremental results.
1. Regulatory Fragmentation and an Unfinished Institutional Transition
Nigeria has made significant progress since the Petroleum Industry Act (PIA) was signed into law in August 2021. The Act established a statutory framework for domestic gas aggregation:
sections 154 and 155 govern the functions and establishment of the domestic gas aggregator, while section 110(1) empowers the NUPRC to prescribe and allocate Domestic Gas Delivery Obligations (DGDOs) annually, based on the Domestic Gas Demand Requirement determined by the Nigerian Midstream and Downstream Petroleum Regulatory Authority (NMDPRA). The Domestic Gas Delivery Obligation Regulations 2022 supply the operating detail.
Legislation alone, however, does not create market confidence. A single gas-to-power project may answer to the NUPRC upstream, the NMDPRA in the midstream and downstream, the aggregator on allocation and settlement, and the Nigerian Electricity Regulatory Commission on the offtake side. Each mandate is defensible. The cumulative effect is a sequence of touchpoints that a project sponsor must navigate before first gas.
The institutional transition contemplated by the Act also remains unfinished. The Gas Aggregation Company Nigeria Limited, formed under the Nigerian Domestic Gas Supply and Pricing Regulations 2008 to implement the Gas Master Plan, continues to perform the aggregation function. The PIA envisages a domestic gas aggregator constituted as a not-for-profit company limited by guarantee under the Companies and Allied Matters Act, holding a licence renewable in two-year terms, assuming the functions previously discharged under the 2008 framework. Completing that handover cleanly is not an administrative formality. For capital-intensive projects, certainty in execution is every bit as important as certainty in law.
2. Commercial Viability of Domestic Supply Obligations
Nigeria’s commitment to prioritising domestic gas utilisation is both necessary and commendable. A reliable domestic market is essential to electricity generation, manufacturing and economic growth, and the DGDO framework properly reflects that policy objective.
The long-term success of the framework depends on maintaining an appropriate commercial balance, and the pricing regime is where that balance is struck. Under section 167 of the PIA and the Gas Pricing and Domestic Demand Regulations, the NMDPRA sets a Domestic Base Price annually. With effect from 1 April 2026, that price stands at US$2.18 per MMBtu, up from US$2.13, with commercial users at US$2.68 and gas-based industries operating within a band floored at US$0.90.
The adjustment is deliberately modest, and the regulator’s caution is understandable given the fragility of the downstream power market. But the statutory test in section 167(1) is whether the price is sufficient to attract voluntary supply from upstream producers. That test must be measured against full-cycle development cost, not against last year’s benchmark. Where commercial returns become uncertain, investment capital will gravitate towards markets offering greater pricing certainty and contractual stability.
It is worth remembering that the framework is transitional by design: the PIA contemplates that DGDOs will be discontinued once the domestic market attains full market status. The policy task is to make the path to that destination credible.
3. Offtaker Credit and Payment Security
This, in my view, is the binding constraint, and it receives the least attention. More than 70 per cent of Nigeria’s electricity is generated from gas, yet the generation companies that consume it remain financially impaired, carrying disputed liabilities running into trillions of naira. Price signals cannot substitute for payment. No producer commits reserves to a long-term domestic gas sales agreement it does not expect to be paid under.
Aggregation is, at bottom, a credit intermediation function. Its success depends on instruments that lawyers, not engineers, build: enforceable escrow arrangements, take-or-pay provisions with workable make-up rights, credit support and guarantees at the offtake end, transparent settlement, and dispute resolution that concludes within commercially meaningful timeframes. The PIA anticipates escrow arrangements around the aggregator. The work now is to make them operational and enforceable in practice.
4. Infrastructure
Gas aggregation cannot succeed without sufficient processing facilities, pipelines, compression systems, storage and secure transportation networks. Even the most carefully negotiated agreement cannot overcome physical limitations that prevent molecules from reaching power plants and industrial consumers when required. Contractual allocation of risk is not a substitute for capacity, and security of infrastructure remains a live commercial variable rather than a background condition.
What Should Happen Next
For policymakers, the priority should be consistent implementation. The PIA has already supplied most of the legal building blocks required to strengthen the domestic gas market. The focus should now shift from introducing new initiatives to ensuring that existing frameworks are implemented consistently, transparently and in ways that inspire investor confidence. Completing the aggregator transition and clarifying the institutional perimeter between regulators would do more for investment sentiment than any further legislation.
Regulatory institutions function best when their roles are clear, coordinated and predictable. That is the environment in which long-term infrastructure investment flourishes.
For investors and project sponsors, legal and regulatory strategy should form part of project development from the outset. Successful gas projects are rarely distinguished solely by technical excellence or financial modelling. They succeed because legal risk allocation, contractual structure, regulatory compliance and commercial objectives are aligned from the earliest stage. Addressing those issues early is almost always less costly than resolving them after execution has begun.
Looking Beyond Today’s Challenges
The International Energy Agency’s World Energy Outlook 2025 offers a more textured picture than is usually quoted. Under the Stated Policies Scenario, global gas demand continues to grow into the 2030s; under the Current Policies Scenario, it grows to mid-century. Under the Net Zero Emissions Scenario, the space for gas is sharply constrained. Across every scenario, the Agency identifies failure to reduce methane leakage as a material downside risk to gas uptake, and it projects a substantial LNG supply surplus around 2030.
The strategic implication for Nigeria is direct. The export window is favourable but not indefinite, and it is contested by producers with lower costs and shorter shipping routes. The more durable prize is a functioning domestic market: demand that does not have to be won afresh each year, priced in an economy that Nigeria controls, supporting industrial output that compounds.
Nigeria has the resources, the legislative framework and growing investor interest. The real challenge is converting those advantages into a domestic gas market that is reliable, commercially sustainable and capable of supporting industrial growth. Gas aggregation remains central to that objective. It supplies the legal and commercial architecture through which domestic demand, infrastructure investment and supply obligations can be aligned to the benefit of producers, consumers and the wider economy.
The next decade presents Nigeria with an opportunity to redefine its position — not simply as a country endowed with abundant gas reserves, but as one that has built the institutions and market structures necessary to unlock their full value. That, in my view, is where the real energy transition begins.
If you work in gas supply, power generation, LNG, infrastructure development, or energy regulation, I would be interested in hearing your perspective. What do you consider the single biggest obstacle to building a resilient domestic gas market in Nigeria: pricing, payment security, infrastructure, or regulatory coordination? To share your perspective or continue the conversation, please contact dapo.akinosun@scp-law.com.
Sources Relied Upon
Where an outlet requires hyperlinked or footnoted sourcing, the following support the factual claims in the article.
- NUPRC — National Petroleum Reserves Position, 1 January 2026 (215.19 tcf): https://www.nuprc.gov.ng/
- Petroleum Industry Act 2021 (ss. 110, 153–155, 167): https://ngfcp.nuprc.gov.ng/wp-content/uploads/2022/09/Petroleum-Industry-Act-2021-pdf-searchable.pdf
- Domestic Gas Delivery Obligation Regulations 2022: https://www.nuprc.gov.ng/wp-content/uploads/2022/11/Domestic-Gas-Delivery-Regulations-2022-pdf-1.pdf
- NMDPRA — 2026 Domestic Base Price and wholesale gas pricing framework: https://businessday.ng/energy/oilandgas/article/nigeria-raises-gas-price-for-power-companies-to-2-18-mmbtu/
- IEA — World Energy Outlook 2025 (scenario outlook for natural gas and LNG): https://www.iea.org/reports/world-energy-outlook-2025
- Domestic vs export gas allocation and power sector constraints: https://www.energyintel.com/0000019d-0019-d051-ab9d-b37dcc480000
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