Business
Nigeria’s oil output wobbles after 10yrs of increase in rigs
lOutput drops 20.8% in five mature assets — Report lNigeria’s influence within OPEC+ declines lWe are committed to optimising output — Renaissance, Eni lBad omen requiring urgent steps — Experts
By Udeme Akpan, Energy Editor
There are indications that increased deployment of oil rigs in Nigeria has not translated into corresponding rise in crude oil production.
Rig count, an important indicator of exploration and production activities, is generally expected to support higher crude oil output as operators drill new wells, maintain existing assets and develop additional reserves.
But official records show that oil output has stagnated over the period since 2016 when rig count was at its peak in Nigeria’s oil fields.
Industry experts told Financial Vanguard that the situation is attributable to a declining output from oil wells described as mature fields as well as slow development of new wells.
According to data obtained from the Organisation of Petroleum Exporting Countries, OPEC, a total of 2,099 rigs were deployed in Nigeria between 2016 and 2026, representing investments running into billions of USDollars.
The data showed that 360 rigs were utilised in 2018, the highest annual deployment during the period, while 87 rigs were recorded in 2021, the lowest.
Checks by Financial Vanguard indicated that deepwater drilling can cost between US$400,000 and US$600,000 per day for the rig alone, excluding drilling mud, casing, cementing, logistics, helicopters, supply vessels, insurance and other services.
A single offshore exploration well can cost between US$50 million and more than US$150 million, depending on water depth and complexity, meaning that Nigeria’s exploration campaigns have involved investments running into billions of dollars.
Despite the spending, Nigeria recorded its highest crude oil output (excluding condensate) amounting 1.734 million barrels per day, bpd, in 2019, a figure that is significantly below annual budget projection.
It even declined to 1.143 million bpd in 2022.
Output drops 20.8%
in five mature assets — Report
Meanwhile, Nigeria’s average oil output from five mature producing fields fell 20.8 per cent year-on-year, YoY, to 10,930 bpd in June 2026 from 13,794 bpd in June 2025, highlighting the pressure on national production and revenue.
A mature oil asset is a field that has produced for many years and moved beyond its early development and peak production stages. Such fields typically experience declining reservoir pressure, increasing water production and falling output, requiring additional investment and enhanced recovery measures to sustain production.
Data obtained from the Nigerian Upstream Petroleum Regulatory Commission, NUPRC, showed that Abo oil field, operated by Eni/Agip and producing since 2003, recorded a 39.2 per cent YoY decline to 6,870 bpd in June 2026 from 11,297 bpd in June 2025.
Pennington, operated by Pennington Producing Limited, fell 45 per cent to 3,880 bpd from 7,107 bpd, while Ugo Ocha, also known as Jones Creek, declined 16.6 per cent to 26,900 bpd from 32,246 bpd.
Sea Eagle, operated by Renaissance Energy, dropped 8.3 per cent to 14,570 bpd from 15,886 bpd, while Okwori, operated by Antan Producing Limited, declined marginally to 2,430 bpd from 2,435 bpd.
Investigations across Abia, Akwa Ibom, Bayelsa, Cross River, Delta, Edo, Imo, Ondo and Rivers states showed that many fields have experienced significant depletion since Nigeria’s first commercial oil discovery in 1956.
While some operators have invested in additional wells, workovers and other measures to sustain production, others have struggled to commit the required capital, contributing to declining and unstable output.
We are committed to optimising output — Renaissance, Eni
Responding to Financial Vanguard’s enquiries, Renaissance Africa Energy, operator of Sea Eagle, said the field’s decline was consistent with its maturity.
“Sea Eagle, a Renaissance JV asset, is a mature field and its production performance remains broadly in line with expectations set out in the approved Field Development Plan. As is typical for mature assets, the field is experiencing a natural production decline associated with field life cycle progression.
“The current production profile of Sea Eagle has been factored into Renaissance’s business and growth plans and has not had a material impact on the company’s operations. Sea Eagle represents a relatively small proportion of Renaissance’s overall production portfolio.
“Renaissance continues to evaluate and implement opportunities to optimise production and maximise value from its assets in line with approved development plans, regulatory requirements and long-term business objectives. The company remains focused on sustaining operational reliability and pursuing initiatives that support the efficient development of its asset base.”
Similarly, Eni stated in an email response to Financial Vanguard: “Nigeria’s deep offshore Abo field produced its first oil in April 2003 and has remained consistently in production for the past 23 years, a remarkable achievement. This longevity is further evidenced by its current production performance, which aligns with the asset’s maturity. To sustain this, output optimisation measures are being implemented, including upgrades to gas compressors.”
Nigeria’s influence
within OPEC+
declines
Checks by Financial Vanguard also showed that Nigeria’s influence within OPEC and the broader global oil market has weakened as production has remained below its historical levels.
Nigeria’s crude oil production peaked at about 2.5 million bpd in November 2005, according to historical production data, making the country a major force within OPEC and the international oil market.
However, despite post-Petroleum Industry Act, PIA, investment efforts, national output, including condensate, has not gone beyond 1.7 million bpd. Nigeria was also not among the seven OPEC+ countries that held a virtual meeting on August 2, 2026, to review global oil market conditions and the production outlook.
According to OPEC: “In their collective commitment to support oil market stability, the seven participating countries decided to implement a production adjustment of 188 thousand barrels per day from the additional voluntary adjustments announced in April 2023.
This adjustment will be implemented in September 2026.
“The seven OPEC+ countries also noted that this measure will provide an opportunity for the participating countries to accelerate their compensation.
The seven countries reiterated their collective commitment to achieve full conformity with the Declaration of Cooperation, including the additional voluntary production adjustments that will be monitored by the Joint Ministerial Monitoring Committee (JMMC).
“They also confirmed their intention to fully compensate for any over-produced volume since January 2024. The seven OPEC+ countries will continue to hold monthly meetings to review market conditions.”
The seven OPEC+ countries are Saudi Arabia, Russia, Iraq, Kuwait, Kazakhstan, Algeria, and Oman.
The latest OPEC+ production adjustment has underscored Nigeria’s limited capacity to take advantage of higher production opportunities. Industry analysts have warned that the country risks losing significant revenue because ageing fields, underinvestment, crude theft, pipeline vandalism and delays in developing new projects continue to constrain output.
While several OPEC+ members are adjusting production to influence global prices and maximise revenues, Nigeria continues to struggle to produce enough crude to meet its OPEC allocation and growing demand from new domestic refineries.
Bad omen requiring urgent steps — Experts
An industry expert who pleaded anonymity said Nigeria must combine exploration with aggressive field development and enhanced recovery from existing assets.
“Exploration must be accompanied by aggressive field development, enhanced recovery from mature assets, improved security, infrastructure upgrades and faster regulatory approvals.
“Nigeria already possesses substantial proven reserves, and the greater challenge is converting those reserves into sustained production rather than simply discovering additional hydrocarbons.
“Unless these structural constraints are addressed, increased exploration spending alone is unlikely to deliver the higher crude oil output needed to boost government revenue, improve foreign exchange earnings and strengthen Nigeria’s position in the global oil market.
“Efforts should also be intensified to complete some planned oil and gas projects, including Bonga North, Southwest/Aparo,f Zabazaba, and Etan in order to enhance Nigeria’s oil output.”
In a telephone interview with Financial Vanguard, Chairman/Chief Executive Officer of Brittania-U, Catherine Uju Ifejika, stressed the importance of additional investment in mature assets, citing the company’s Ajapa field.
She said more than $400 million was invested after Brittania-U acquired the asset from Chevron, including the drilling of additional wells and deployment of a Floating Production, Storage and Offloading, FPSO, facility.
According to her, the investment enabled Ajapa to commence production at about 2,300 bpd in 2010, followed by increased and more stable output.
Also speaking with Financial Vanguard, Wumi Iledare, Professor Emeritus of Petroleum Economics, said the NUPRC’s findings on mature and declining fields highlighted a structural challenge that affects both production and public revenue.
“Declining production translates directly into reduced government revenue, weaker external reserves, lower foreign-exchange inflows, and diminished economic value creation. The policy response should therefore go beyond passive acceptance of natural decline.
“Nigeria must actively optimise remaining production through faster regulatory approvals, incentives for re-entering selected abandoned wells, infill drilling, workovers, artificial-lift optimisation, and deployment of proven enhanced oil recovery technologies where commercially viable.
“The Petroleum Industry Act (PIA) already recognises the maturity profile of Nigeria’s oil fields. Its production allowances and progressive royalty structure reflect a key petroleum-economic principle: fiscal terms must balance government take with the need to sustain investment in recovering remaining reserves.
“A barrel that remains underground due to commercial or regulatory disincentives generates no revenue for government, no return for investors, and no value for the economy.
The core challenge, therefore, is not simply increasing production, but maximising economic recovery from existing assets within their remaining productive life.”
He added: “This is the essence of petroleum asset optimisation — and ultimately, public value optimisation.”
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