Nigeria on Track for 2.5m bpd as NUPRC Pushes Deepwater and Marginal Field Reforms

Nigeria is moving to lift crude output to 2.5 million barrels per day by 2026, according to the Nigerian Upstream Petroleum Regulatory Commission (NUPRC).

NUPRC Chief Executive Gbenga Komolafe outlined the plan in Abuja at the 2025 PENGASSAN Energy and Labour Summit.

Commission data show output has already risen from a 1.46 million bpd baseline in October 2024 to about 1.8 million bpd, helped by asset re-entry work, improved recovery programmes and faster project execution.

The regulator is coordinating an industry-wide “Project One Million Barrels Per Day” push focused on incremental volumes.

A central pillar is a cluster and nodal development approach that uses shared subsea infrastructure and tiebacks to existing FPSOs—including Bonga, Egina and Agbami—to cut costs, compress cycle times and lower risk for investors.

The model targets short lead-time barrels and aims to unlock stranded reserves that are economical only when combined across fields.

Deepwater is set to carry more weight in the output mix following a recent Deepwater Technical Stakeholders’ Workshop, the commission and operators agreed a work programme designed to unlock more than 810,000 bpd in potential peak volumes from approved offshore plans.

The emphasis is on high-impact wells, brownfield expansions, debottlenecking, and standardized subsea kits to shorten installation windows.

Regulatory changes are part of the production recovery. The Petroleum Industry Act (PIA) 2021, complemented by recent Presidential Executive Orders, has cut the average contracting cycle from 36 months to roughly six months, according to the NUPRC.

Fiscal adjustments under the PIA have also sharpened project economics, particularly for frontier and marginal assets, while the commission’s streamlined approvals are intended to reduce uncertainty and capital drag.

On marginal fields, the regulator has completed a case-by-case technical review for assets due for renewal. NUPRC says each award is assessed against milestone-based criteria set out in law, with an expert team scoring operators on deliverables such as work-programme execution, funding capacity, HSE compliance and production readiness.

Results have been submitted to the Minister of State for Petroleum (Oil) for approval; fields that meet the benchmarks are expected to secure renewals. The aim is to channel licences toward credible work plans and prevent asset dormancy.

Global energy dynamics remain a factor. Low-carbon investment exceeded $1.7 trillion in 2023 and accelerated by 24% in 2024 to around $2.1 trillion, underscoring the pace of energy transition.

NUPRC’s position is that, while transition capital is rising, hydrocarbons will continue to meet a large share of demand in Africa and Asia for years.

Nigeria’s path is framed as gas-centric decarbonisation—expanding domestic gas for power and industry, cutting flaring, and using gas as a transition fuel while the country builds out renewables and grid stability.

The production roadmap rests on five practical levers:

1. Deepwater execution discipline: Prioritise projects with near-term facility access, standardized subsea equipment, and tieback routes to reduce per-barrel costs.

2. Brownfield and improved recovery: Target workovers, waterflood optimisation, gas lift tweaks and digital surveillance to lift base production with lower capital intensity.

3. Dormant field reactivation: Enforce timelines on idle assets; reassign or cluster fields that cannot meet milestones to unlock collective economics.

4. Contracting speed and clarity: Maintain six-month contracting targets, predictable approval gates and stable fiscal terms to keep EPC and subsurface schedules on track.

5. Security and uptime: Sustain gains in pipeline integrity, community engagement and metering transparency to limit losses and improve terminal receipts.

If the programme holds, Nigeria’s supply profile would tilt back toward the 2.0–2.5 million bpd range seen in prior up-cycles, strengthening government revenues, bolstering foreign-exchange supply and improving feedstock availability for domestic refining.

For operators, dependable approvals and tieback economics reduce exposure to cost creep and schedule slippage; for financiers, milestones and transparent metering are intended to de-risk cash flows.

Risks remain. Execution slippage, price volatility, security incidents, and any reversal in contracting speed could slow the ramp.

The marginal-field renewal process will also test policy credibility: timely, merit-based decisions are crucial to keep smaller operators funded and drilling.

In deepwater, rig availability and subsea supply-chain tightness could pressure costs; maintaining standardisation and framework agreements will be key to preserving unit economics.

Still, the policy direction is clear: shorten cycles, aggregate infrastructure, and push barrels that can move quickly.

With production back at  1.8 million bpd, sanctioned deepwater work in view, and a pipeline of reactivated fields, the NUPRC’s 2026 target is now anchored to concrete operational levers rather than aspirational guidance.