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<\/figure>\n\n\n\nNigeria\u2019s oil problem is larger than production<\/h3>\n\n\n\n
The Central Bank of Nigeria (CBN) reported provisional gross Federation Account receipts of \u20a68.31 trillion in the second quarter of 2025, with oil revenue contributing \u20a63.24 trillion, or 38.97 per cent, while non-oil revenue accounted for 61.03 per cent.<\/p>\n\n\n\n
Yet crude oil remained responsible for 62.89 per cent of Nigeria\u2019s total exports in the first quarter of that year, compared with 15.38 per cent for non-oil exports. The figures show why increasing production can improve export earnings while not necessarily translating into a proportionate increase in government revenue.<\/p>\n\n\n\n
The export figures, however, do not capture the full fiscal exposure. The International Monetary Fund (IMF) 2026 Article IV assessment puts oil and gas revenue at 3.1 per cent of GDP and non-oil revenue at 6.8 per cent in its 2025 estimate. It also estimates that the consolidated government deficit reached 4.4 per cent of GDP in 2025 and says oil and gas revenue fell short of budget expectations.<\/p>\n\n\n\n
At the Federal Government level, interest payments absorbed 53.2 per cent of Federal Government revenue in 2025. A fall in petroleum receipts would therefore occur within a fiscal system that already has a substantial financing requirement and a high debt-service burden.<\/p>\n\n\n\n
The debt burden adds another layer to the exposure. The IMF estimated public gross debt at 36.1 per cent of GDP at the end of 2025, while the Central Bank of Nigeria reported total public debt of \u20a6152.40 trillion at the end of June 2025. The figures use different reporting dates and methodologies, but both show that the government would have to manage any decline in oil receipts alongside existing debt obligations.<\/p>\n\n\n\n
There is another distinction that matters: production does not equal government revenue. The state\u2019s take depends on production costs, royalties, taxes, contractual arrangements, and the price at which the crude is sold.<\/p>\n\n\n\n
For instance, three million barrels per day sold at $60 per barrel would represent about $65.7 billion in gross annual market value. That figure is not government revenue. The amount ultimately available to government would depend on the applicable fiscal terms, costs, royalties, taxes, profit-sharing arrangements, and actual realised prices.<\/p>\n\n\n\n
There is also evidence that Nigeria has reduced the share of oil in Federal Government revenue compared with earlier periods, although petroleum receipts remain significant. CBN data shows that oil accounted for 72.4 per cent of total Federal Government revenue in 2014 and 56.5 per cent in 2022. By the second quarter of 2025, oil accounted for 38.97 per cent of federally collected revenue. This represents a decline of 33.43 percentage points between 2014 and the second quarter of 2025.<\/p>\n\n\n\n
Oil remains disproportionately important to Nigeria\u2019s exports and foreign exchange earnings, regardless of recent changes.<\/p>\n\n\n\n
There are also signs that Nigeria has rebuilt part of its external buffer. The IMF reported that gross international reserves increased from $40 billion at the end of 2024 to $46 billion at the end of 2025, while net international reserves rose from $23 billion to $35 billion.<\/p>\n\n\n\n
The improvement was supported by the current-account surplus, foreign portfolio inflows, and a $2.3 billion Eurobond issuance. The stronger reserve position provides some capacity to absorb external pressure, but it does not remove the fiscal exposure created by weaker oil receipts.<\/p>\n\n\n\n
The IMF also says reforms since 2023, including the removal of fuel subsidies, tighter monetary policy, and exchange-rate liberalisation, have reduced some fiscal vulnerabilities, rebuilt external buffers, and improved foreign-exchange market functioning. But, the IMF also notes that oil revenue remained below budget expectations in 2025. Nigeria\u2019s preparedness is therefore mixed: some macroeconomic buffers have improved, while the fiscal position remains exposed to revenue shortfalls and high debt-service costs.<\/p>\n\n\n\n
The potential scale of a longer-term revenue shock is illustrated by research published by the World Resources Institute (WRI). WRI, drawing on Coffin et al. (2021), compared a business-as-usual case using a long-term oil price of $60 per barrel with the IEA Sustainable Development Scenario, which assumed a long-term oil price of $40 per barrel.<\/p>\n\n\n\n
Across 40 highly fiscally dependent oil and gas producers, the study estimated an average 46 per cent decline in revenues between 2021 and 2040 under that scenario. For Nigeria, it estimated that average annual oil and gas revenues could fall by 69 per cent compared with the country\u2019s 2015\u201319 revenues.<\/p>\n\n\n\n
That 69 per cent figure is a scenario estimate, not a forecast of what Nigeria will actually lose. It assumes a particular demand and oil-price pathway and illustrates the scale of fiscal exposure under sustained lower prices and weaker demand.<\/p>\n\n\n\n
For Nigeria, the evidence points to a fiscal system that has made some progress in reducing oil dependence and rebuilding external buffers, but remains vulnerable to a sustained fall in petroleum receipts. Higher output can strengthen foreign-exchange earnings and government receipts, yet the underlying exposure to oil prices and international demand remains.<\/p>\n\n\n\n The type of project being developed also matters. In July 2026, ExxonMobil and its partners announced a $1 billion investment in the Usan Infill project on OML 138, which is expected to produce about 40,000 barrels per day. The NUPRC has described the project as a short-cycle development. Its exposure is different from that of a large greenfield development requiring many years and billions of dollars before production begins.<\/p>\n\n\n\n Bonga South-West Aparo represents a much larger and longer-duration commitment, with estimated investment of $15 billion to $21 billion and peak production of 175,000 barrels per day. The larger capital requirement increases exposure to the price environment during the period in which the project is recovering its investment. Demand, regulation, operating costs, financing conditions, fiscal terms, and competing supply can all affect the period available for capital recovery.<\/p>\n\n\n\n ExxonMobil has also continued to consider developments such as Owowo alongside further drilling at Usan. NUPRC has said the Owowo project could involve an investment of about $7 billion to $8 billion and contain about one billion barrels of developed resource.<\/p>\n\n\n\n A discovery or resource, however, is not the same as a producing asset. Appraisal, commercial agreements, infrastructure, financing, development decisions, and capital expenditure are still required before production can begin. The economic value of the resource therefore depends not only on how much oil is underground, but on the cost and terms under which it can be brought to market.<\/p>\n\n\n\n A slowly growing oil market could make the timing of those developments more important, and Nigeria is not facing this exposure alone. The IMF\u2019s 2026 Article IV assessment of Angola says a significant decline in oil production weakened its fiscal and external positions in 2025, while lower oil revenues contributed to a fiscal deficit of 4.1 per cent of GDP.<\/p>\n\n\n\n The IMF describes a medium-term outlook shaped by a structural decline in oil revenues and says economic growth will depend partly on the success of diversification efforts.<\/p>\n\n\n\n Algeria provides another example of the pressure that weaker hydrocarbon performance can place on fiscal and external buffers. The IMF\u2019s 2026 Article IV assessment says large fiscal deficits have depleted fiscal buffers and that hydrocarbon exports declined, contributing to significant reserve losses. It identifies a sharp decline in hydrocarbon prices as a downside risk and calls for stronger non-hydrocarbon revenue mobilisation, fiscal consolidation, and further diversification.<\/p>\n\n\n\n The competitive pressure described in these cases also features in E3G\u2019s Oil EndGame simulation, which examines possible producer responses to changing oil demand between 2028 and 2040. The exercise is a simulation, not a forecast, of how governments and producers might respond under different market conditions. It considers responses including protecting market access, competing for market share, maximising short-term revenues, and investing in other sectors.<\/p>\n\n\n\n For Nigeria, that would make the cost and timing of new projects more important. The IEA\u2019s distinction between projected demand and production capacity is relevant here because additional capacity does not guarantee that every producer will sell its maximum potential output. Nigeria therefore needs barrels that can remain commercially competitive as the market changes.<\/p>\n\n\n\n The risk does not require global oil demand to disappear. However, slower demand growth, weaker prices, increased supply, or competition from lower-cost producers could all reduce the amount of time available for expensive projects to recover their capital. The issue is therefore not simply whether Nigeria can produce more oil, but whether the new production can remain competitive for long enough to justify the investment.<\/p>\n\n\n\n That leaves the question of what Nigeria does with the income generated while hydrocarbons remain important. Diversification becomes meaningful when sectors such as agriculture, manufacturing, services, and other productive activities generate foreign exchange, government revenue, investment, and employment at a scale that reduces dependence on crude oil.<\/p>\n\n\n\n There are signs of a broader revenue base, but the evidence needs to be measured against the scale of petroleum exposure. By Q2 2025, non-oil revenue represented 61.03 per cent of federally collected revenue, according to the CBN, while NBS data show non-oil exports represented only 15.38 per cent of total exports in Q1 2025. The two figures measure different things, but their contrast is significant: diversification in government receipts has progressed further than diversification in merchandise exports.<\/p>\n\n\n\n The investment challenge extends beyond oil and gas. The IEA\u2019s 2019 Nigeria Energy Outlook estimated cumulative energy-supply investment needs of $445 billion between 2019 and 2040 under its Stated Policies Scenario, with almost 80 per cent directed to upstream oil and gas. The estimate reflected the policies and measures in place or announced when the outlook was prepared, and therefore described an investment requirement under a particular policy and energy-demand pathway rather than a guaranteed amount of capital Nigeria would attract.<\/p>\n\n\n\n The IEA also examined a more ambitious development pathway, which points to a wider investment opportunity. Under its Africa Case, investment in electricity networks would be 85 per cent higher than under the Stated Policies Scenario, while investment in renewables would be 165 per cent higher. The assessment therefore linked Nigeria\u2019s energy investment needs not only to oil and gas production, but also to electricity access, networks, renewable energy, and the infrastructure needed to support economic development.<\/p>\n\n\n\n The IEA\u2019s assessment identified several areas where investment could affect the wider energy system. It said oil-sector reforms could help revive production, while successful implementation of the gas master plan could support gas-to-power, industrial development, and expansion of the gas network to industrial hubs.<\/p>\n\n\n\n It also identified improvements in power-sector management and governance as important to reducing outages and transmission losses, which constrain industrial activity and leave businesses and households dependent on back-up generation.<\/p>\n\n\n\n The 2019 estimate should therefore be read as historical context rather than a current 2026 investment forecast. What remains relevant is the structure of the opportunity identified by the IEA: Nigeria requires capital not only to develop its hydrocarbon resources, but also to improve electricity infrastructure, expand energy access, develop gas infrastructure, and support a more productive energy system.<\/p>\n\n\n\n Nigeria\u2019s 2026 relationship with the IEA also points to priorities beyond upstream production. When the country joined the IEA Family as an Association country in 2026F, the agency identified the need to mobilise investment and expand access to reliable and affordable electricity and clean cooking among Nigeria\u2019s energy priorities.<\/p>\n\n\n\n Its first Joint Work Programme with Nigeria covers energy security, energy investment, data and statistics, energy efficiency, clean cooking, policy advice, data cooperation, and training. The programme covers investment and energy security alongside infrastructure, efficiency, data, and access. The scale of Nigeria\u2019s current upstream push is therefore taking place alongside a much wider energy investment requirement.<\/p>\n\n\n\n The scale of Nigeria\u2019s current upstream push is clear. More than $57 billion in Field Development Plans have been approved since 2024, while the NUPRC expects 22 offshore projects between 2026 and 2030 with estimated investment of $30 billion to $50 billion. At the same time, crude oil remains responsible for 62.89 per cent of Nigeria\u2019s total exports. Increasing production is therefore economically important.<\/p>\n\n\n\n Higher production, however, does not resolve the longer-term question. The IEA and OPEC present substantially different views of future oil demand, and neither outlook can establish exactly what the global market will look like over the full life of a Nigerian offshore project.<\/p>\n\n\n\n The IEA\u2019s 2025 Oil outlook sees global demand reaching around 105.5 million barrels per day by the end of the decade, while its World Energy Outlook\u2019s Stated Policies Scenario sees demand reaching around 102 million barrels per day around 2030 before declining. OPEC\u2019s 2026 outlook instead projects 124 million barrels per day by 2050.<\/p>\n\n\n\n What Nigeria can influence is the amount of capital it commits, the terms under which investment is attracted, the cost of production, and the pace at which projects reach the market. Each project therefore has to remain competitive long enough to recover its capital and generate value under the fiscal terms agreed with government. Slower demand growth, weaker prices, increased supply, or lower-cost competing producers could shorten that period.<\/p>\n\n\n\n Nigeria therefore faces two related calculations. The first is whether new oil and gas projects can generate sufficient returns and public revenue while international demand remains strong enough to support them. The second is whether the country can use continued petroleum income to strengthen non-oil sources of revenue, exports, foreign exchange, and employment before the global market becomes less favourable.<\/p>\n\n\n\n Nigeria can continue developing its oil resources while using the revenue and investment generated by the sector to build other sources of economic activity. The country\u2019s reserves are large, but their value will ultimately depend on when they are developed, what they cost to produce, the fiscal terms under which they are developed, and how they compete with other barrels entering the global market.<\/p>","protected":false},"excerpt":{"rendered":" Nigeria is offering fiscal incentives under the Deep Offshore Oil and Gas Projects Incentives (Tax Remission) Order, 2026, to attract investment in qualifying offshore developments, advancing the Bonga South-West Aparo project towards a final investment decision, and targeting oil production of three million barrels per day by 2030. The strategy is built around increasing production […]<\/p>\n","protected":false},"author":21,"featured_media":8651,"comment_status":"open","ping_status":"open","sticky":false,"template":"","format":"standard","meta":{"saved_in_kubio":false,"footnotes":""},"categories":[19,30,27],"tags":[],"class_list":["post-8506","post","type-post","status-publish","format-standard","has-post-thumbnail","hentry","category-economy","category-governance","category-infrastructure"],"_links":{"self":[{"href":"https:\/\/openafricantribune.com\/fr\/wp-json\/wp\/v2\/posts\/8506","targetHints":{"allow":["GET"]}}],"collection":[{"href":"https:\/\/openafricantribune.com\/fr\/wp-json\/wp\/v2\/posts"}],"about":[{"href":"https:\/\/openafricantribune.com\/fr\/wp-json\/wp\/v2\/types\/post"}],"author":[{"embeddable":true,"href":"https:\/\/openafricantribune.com\/fr\/wp-json\/wp\/v2\/users\/21"}],"replies":[{"embeddable":true,"href":"https:\/\/openafricantribune.com\/fr\/wp-json\/wp\/v2\/comments?post=8506"}],"version-history":[{"count":2,"href":"https:\/\/openafricantribune.com\/fr\/wp-json\/wp\/v2\/posts\/8506\/revisions"}],"predecessor-version":[{"id":8677,"href":"https:\/\/openafricantribune.com\/fr\/wp-json\/wp\/v2\/posts\/8506\/revisions\/8677"}],"wp:featuredmedia":[{"embeddable":true,"href":"https:\/\/openafricantribune.com\/fr\/wp-json\/wp\/v2\/media\/8651"}],"wp:attachment":[{"href":"https:\/\/openafricantribune.com\/fr\/wp-json\/wp\/v2\/media?parent=8506"}],"wp:term":[{"taxonomy":"category","embeddable":true,"href":"https:\/\/openafricantribune.com\/fr\/wp-json\/wp\/v2\/categories?post=8506"},{"taxonomy":"post_tag","embeddable":true,"href":"https:\/\/openafricantribune.com\/fr\/wp-json\/wp\/v2\/tags?post=8506"}],"curies":[{"name":"wp","href":"https:\/\/api.w.org\/{rel}","templated":true}]}}![\"\"](\"https:\/\/openafricantribune.com\/wp-content\/uploads\/2026\/10\/Bloomberg-George-Osodi-1-1024x698.webp\")
<\/figure>\n\n\n\nNot all new oil carries the same risk<\/h3>\n\n\n\n
The question is timing<\/h3>\n\n\n\n