As the escalating conflict in the Mideast Gulf disrupts energy flows through the Strait of Hormuz and tightens global LNG markets, the fragility of gas supply chains has once again come into focus. For gas-rich but infrastructure-constrained countries like Nigeria, these dynamics underscore both the opportunity and the risk inherent in an export-led strategy.

With reserves estimated at over 210 trillion cubic feet, Nigeria is often seen as a gas province with some oil. Yet, it has long failed to harness sufficient gas for its domestic economy or export market. Now, with the population nudging 250 million and set to double by 2100, expanding access to electricity at home is imperative for economic, environmental and public health reasons. If the government doesn’t act more effectively, 100 million Nigerians could still be without electricity by 2030.

Successive governments have set unrealistic targets during the last 20 years from Gas Master Plans to the Decade of Gas set out as Nigeria’s approach to the Energy Transition in 2021. Back in 2010, former oil minister Diezani Allison-Madueke projected gas production would more than triple to 15 billion cubic feet per day by 2017 and stop flaring. Fifteen years later output was hovering at only 7.41 Bcf/d in 2025, and (albeit less) gas was still being flared.

Over the same period, four big LNG plants were touted: the 10 million ton per year Brass LNG, the 12.5 million ton/yr Olokola LNG, the 9 million ton/yr West Niger Delta LNG and NLNG Trains 6 and 7 to boost capacity to 30 million tons/yr. Of these, only Train 6 has been completed, while Train 7 is delayed and scaled back. NNPC’s latest Gas Master Plan, published in January 2026, has dusted off OK LNG — targeted for the home region of current President Bola Tinubu claiming, strong prospects for final investment decision (FID) within 12 months.

Yet, the current disruption to Gulf LNG exports also highlights the volatility of relying on external markets. With Qatari volumes constrained and shipping risk premiums rising, global buyers are being pushed back into tighter spot markets — reinforcing both the potential upside of new suppliers and the exposure to geopolitical shocks.

Integrating Gas and Renewables

Nigeria’s domestic power sector is a picture of failure: While installed generating capacity has risen over the period to 13,000 megawatts, electricity production still hovers between 4,000 and 5,000 MW, and the national power grid collapses several times per year. This has left Nigerians reliant on pollutive off-grid diesel generators, which have five times as much capacity as grid supply. Households and small businesses spend around $12 billion annually to import and maintain these generators.

While the country’s gas lobby wants to double down on upstream development and projects, environmentalists want to roll back fossil fuels and go all out for renewables, which are expanding but not yet financially self-sustainable or capable of lifting the majority out of energy poverty in the near future.

Nigeria’s dependence on gas will remain important but carries growing limits and risks as the global energy transition gathers force. The Tinubu government should rationalize its gas agenda to a shorter list of feasible projects, review its priorities between the export and domestic markets, and focus on integrating gas fired power with renewables, a growing number of energy watchers argue.

Gas projects are increasingly struggling to attract funds as the energy transition shrinks the pool of external lenders and investors. International oil companies (IOCs) who divested from Nigeria’s onshore/shallow water, are still financing some upstream gas fields — with three FIDs by Shell and TotalEnergies in the past two years expected to bring 1 billion standard cubic feet/d of gas: Shell approved the Bonga North and HI schemes, and TotalEnergies green-lighted development of the Ubeta gas field. Local firms who bought the IOCs’ onshore/shallow water assets are also funding some projects, but most lack the funding capacity to invest in very large gas upstream projects.

On the other hand, capital from foreign national oil companies and the Mideast Gulf has not materialized. This leaves a few export credit agencies, the Africa Export Import Bank, Nigerian banks — who are already over-exposed to oil and gas — and the much touted but yet to materialize African Energy Bank.

Dysfunctional Domestics 

Nigerian governments producers and investors have always prioritized gas supply to LNG and industry at the expense of the power sector because NLNG pays in dollars and enjoys a more reliable client base.

Right now, the domestic market gets just 28% of produced gas, while exports mop up 36%. The balance is used for fuel and reinjection (29%) and flaring (7.1%), according to government data.

Reliance on gas as the main fuel for power generation has become a bottleneck.

Funding for gas to power is far more elusive than for LNG. Most of Nigeria’s gas to power capacity was built between 2010-15, with the last FID on a major project — the Azura Independent Power plant in Edo state — in 2016.

Government efforts to boost capacity — with the issue of 645 licenses for on- and off-grid plants and captive generation for industries — have worked only on paper, with few projects materializing.

The power sector is marred by weak economics and finances. Generating companies (gencos) paid only 40% of their bills to gas suppliers in 2024, not least because they don’t get paid by their electricity distribution company customers. Gencos have estimated legacy bills at 6 trillion naira ($4.4 billion), with some debts going back a decade or more. The government, which recently audited the claims ahead of arranging a bond issue to help repay the debt, estimates them at 2.8 trillion naira ($2.1 billion).

Yet, even if these arrangements were to cover the arrears of the distribution companies — low electricity tariffs, low collections and metering rates will continue to undermine their ability to pay the gencos, which will remain unattractive customers for gas suppliers.

The key challenge is how to revise expectations for gas while supporting the development of alternative technologies and renewables. “The government’s current integration framework is new, with no action plan,” says Aaron Sayne of the Natural Resource Governance Institute in Washington. “There is a need to align gas and renewables within a least cost, least risk time-bound energy transition pathway.”

Nigeria’s renewables sector is dynamic but growing off a small base. This has seen the government back new hydro assets and promote the expansion of solar home systems and mini grids to supply electricity to millions of people barely or not connected to the main electricity grid.

Renewables have the advantage of attracting more development finance than fossil fuels, and Nigeria is also attracting private finance. In 2024, it was ranked the 10th largest emerging market recipient of renewable energy investment worldwide for projects valued at $2 billion.

A recent survey reported at least 175 mini grids and 11 MW of solar photovoltaic (PV) capacity in 2025, which, together with stand-alone systems, connected around 6 million people.

Scaling Up

The key challenge here is that many mini-grid operators are struggling and have yet to become financially self-sustainable. Mini grids are difficult to scale up in sparsely populated rural areas, as project operators struggle to recover high up-front costs and operational expenses in small markets.

In more populated areas, private investors and development institutions have started on several schemes to interconnect mini grids to the main national grid. These projects, combining solar PV plus battery storage with grid power, can improve quality and reliability, and ultimately lower costs. However, they will need appropriate tariff setting to enable utilities to recover costs, clear regulation and upgrades to the main grid at point of interconnection.

Oil Market Report – March 2026

The IEA Oil Market Report (OMR) is one of the world’s most authoritative and timely sources of data, forecasts and analysis on the global oil market – including detailed statistics and commentary on oil supply, demand, inventories, prices and refining activity, as well as oil trade for IEA and selected non-IEA countries.

Highlights

• The war in the Middle East is creating the largest supply disruption in the history of the global oil market. With crude and oil product flows through the Strait of Hormuz plunging from around 20 mb/d before the war to a trickle currently, limited capacity available to bypass the crucial waterway, and storage filling up, Gulf countries have cut total oil production by at least 10 mb/d. In the absence of a rapid resumption of shipping flows, supply losses are set to increase.
• Global oil supply is projected to plunge by 8 mb/d in March, with curtailments in the Middle East partly offset by higher output from non-OPEC+ producers, Kazakhstan and Russia following disruptions at the start of the year. While the extent of losses will depend on the duration of the conflict and disruptions to flows, we estimate global oil supply to rise by 1.1 mb/d in 2026 on average, with non-OPEC+ producers accounting for the entire increase.
• The conflict is also having a significant impact on global product markets, with export flows through the Strait at a near standstill. Gulf producers exported 3.3 mb/d of refined products and 1.5 mb/d of LPG in 2025. More than 3 mb/d of refining capacity in the region has already shut due to attacks and a lack of viable export outlets. Runs elsewhere will be increasingly limited due to feedstock availability.
• IEA Member countries unanimously agreed on 11 March to make 400 mb of oil from their emergency reserves available to the market to address disruptions stemming from the war in the Middle East. Global observed oil stocks were 8 210 mb in January, their highest level since February 2021. The OECD accounted for 50%, Chinese crude stocks 15%, oil on water 25%, with the remainder in other non-OECD countries.
• Widespread flight cancellations in the Middle East and large-scale disruptions to LPG supplies are expected to curb global oil demand by around 1 mb/d during March and April compared to previous estimates. Higher oil prices and a more precarious outlook for the global economy pose further risks to the forecast. Global oil consumption is now set to increase by 640 kb/d y-o-y in 2026 – down 210 kb/d from last month.
• Oil prices have gyrated wildly since the United States and Israel launched joint air strikes on Iran on 28 February. Disruptions to Middle Eastern supplies due to attacks on the region’s oil infrastructure and the cessation of tanker traffic through the Strait of Hormuz sent Brent futures soaring, trading within a whisker of $120/bbl. Prices subsequently eased with Brent around $92/bbl at the time of writing – up $20/bbl for the month.

Dire straits

The global oil market is contending with the ramifications of the war in the Middle East. Beyond the direct damage to energy infrastructure in the region, the crisis has led to a near halt in tanker movements through the Strait of Hormuz. With nearly 20 mb/d of crude and product exports currently disrupted and limited alternative options to bypass the world’s most critical oil transit chokepoint, producers and consumers globally are feeling the strain. Benchmark crude oil prices have surged by $20/bbl to $92/bbl since the outbreak of hostilities on 28 February, with even bigger increases across product markets.

With few ships currently able or willing to load cargoes at port, and domestic storage tanks filling up, producers in the region are reducing or shutting in production. While the situation on the ground is fast evolving and at times opaque, we estimate that crude production is currently being curtailed by at least 8 mb/d, with a further 2 mb/d of condensates and NGLs shut in. Major supply reductions are seen in Iraq, Qatar, Kuwait, the UAE and Saudi Arabia.

Disruptions are not limited to upstream production and exports, with several refineries and gas processing facilities shut down due to attacks or for safety concerns. The closure of the Strait is also forcing export-oriented refineries to cut runs or shut completely as product storage tanks top up, with more than 4 mb/d of refining capacity at risk. Gulf producers exported roughly 3.3 mb/d of refined products, and 1.5 mb/d of LPG in 2025. While additional throughputs in other regions are possible, feedstock availability will be a limiting factor. This has prompted some countries to implement product exports restrictions. Diesel and jet fuel markets look to be particularly vulnerable to an extended loss of Middle East production and exports, given limited flexibility elsewhere to increase output.

Meanwhile, the suspension of flights at major airports in the Middle East, with a knock-on effect on hubs elsewhere, has materially reduced global jet fuel demand. Plunging LPG and naphtha supplies are already forcing petrochemical plants to curb their production of polymers, aggravating the loss of Gulf petrochemical flows. LPG use in cooking and heating, especially in India and East Africa, is also at risk. More broadly, higher oil prices and a deteriorating economic outlook have begun to erode demand across the product spectrum. In this context, we have reduced the forecast for global oil demand growth in March and April by more than 1 mb/d on average – and for 2026 as a whole by 210 kb/d to 640 kb/d.

Consumer countries have significant amounts of oil in storage to bridge temporary supply losses. Global observed inventories of crude and products are currently assessed at more than 8.2 billion barrels, the highest level since February 2021. Roughly half of these are held in OECD countries, of which 1.25 billion barrels by governments for emergency purposes, with a further 600 million barrels of industry stocks held under government obligation.

IEA member countries agreed on 11 March to make available an unprecedented 400 mb of oil from their emergency reserves available to the market to mitigate the negative impact on economies from the supply disruptions. These additional oil supplies will be offered to the market by implementing emergency stock draws or other measures, according to national circumstances.

The co-ordinated emergency stock release provides a significant and welcome buffer, but in the absence of a swift resolution to the conflict, it remains a stop-gap measure. The ultimate impact on oil and gas markets and the broader economy from the conflict will depend not only on the intensity of military attacks and any damage to energy assets, but also, crucially, on the duration of disruptions to shipping through the Strait of Hormuz. Adequate insurance mechanisms and physical protection for shipping are key to the resumption of flows, which is of paramount importance for the oil market.

Global Energy Shock: Why Gas Prices Jumped 50% and What It Means for Nigeria

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