Nigeria stands at a pivotal moment in its oil and gas history.
With reforms under the Petroleum Industry Act (PIA) 2021, the country aims to modernise its contractual and regulatory framework, attract investment, and fulfill both its energy security and development goals.
As global energy dynamics shift, investors, domestic and foreign, must understand not only the geology, but how different contract types allocate risk, expenses, profits, and control.
This article walks through the key upstream contracts in Nigeria – Joint Ventures, Production Sharing Contracts, Service Contracts, and Marginal Field Agreements, and explains how PIA has reshaped them, highlights recent deals, provides expert insight, and lays out what investors should watch for.
The legal & fiscal reset
For decades, Nigeria’s oil industry operated under legacy models that often-placed heavy obligations on the state, especially funding its share of JV operations through cash calls.
This model worked when oil prices were high and state revenues steady, but over time, delays, underfunding, environmental challenges, and community conflict exposed weak spots.
The PIA seeks to change that.
It reorganised regulatory authorities and clarified fiscal terms.
It also strengthened local content requirements and demanded better environmental and host community protections.
In addition, it introduced incentives to make Nigeria’s upstream sector more transparent and attractive.
Notably, recent PSCs now include provisions tailored to gas development and delineate roles and obligations more clearly.
The first fully oil and gas PSC under this new model was signed in early September 2025 with TotalEnergies and Sapetro.
Gbenga Komolafe, CEO of the Nigerian Upstream Petroleum Regulatory Commission (NUPRC), said of that deal: “This new PSC represents a policy shift, in line with the PIA, which aims to unlock Nigeria’s gas potential and support the transition to a gas-powered economy.”
Some analysts remain cautious, however.
For instance, Ayodele Oni, a Lagos‑based energy lawyer and partner at Bloomfield Law Firm said, “The real challenge lies in the detail of cost recovery, particularly the timing, scope, and administrative process.”
Joint ventures (JVs): shared ownership, shared risk
Joint Ventures are the oldest contract model in Nigeria’s upstream sector.
Under a JV, the Nigerian government, through NNPC, now NNPC Limited, takes a majority equity stake (typically 55–60%) in partnership with international oil companies (IOCs), who hold the remainder.
Partners share both the costs (exploration, development, production) and the rewards accordingly.
Under a typical JV:
- Payment responsibilities (called “cash calls”) are divided in proportion to ownership.
- All partners share operational decision-making, based on a Joint Operating Agreement.
- Produced oil is split according to equity shares after deducting royalties, taxes, and cost recovery (if structured that way).
That model offered stability and control to the state, but over time became strained.
NNPC often failed to meet its funding obligations on schedule, resulting in project delays and sometimes contract renegotiations or even disputes.
With PIA, reforms seek to reduce those risks.
The commercialisation of NNPC Limited in 2021 gives it more operational autonomy; new funding models and clearer obligations aim to ensure that state partners can meet their equity contributions more reliably.
For investors, this reduces but does not eliminate risks tied to partner funding shortfalls.
Governance remains key: efficiency, transparency, and operational capacity will distinguish profitable JVs from challenging ones.
Production sharing contracts (PSCs): risk, upside & modern templates
Where JVs share ownership upfront, PSCs allocate more risk to the contractor.
The contractor invests in exploration, takes the risk of finding or not finding commercially exploitable oil or gas.
If successful, production is divided to recover costs (“Cost Oil”), pay royalties and taxes, and then split profit oil.
Key features of the new law
- Cost Recovery: Under newer PSCs, cost oil is capped, often around 80% of production in a given period.
This ensures that a portion of production always flows to government revenue or royalties. - Profit Splitting: After cost recovery, profit oil is split between contractor and state under agreed percentages. Those percentages can slide depending on production volume, oil price, or other contract triggers.
- Royalties & Bonuses: Effective royalties vary by water depth and field type. Deepwater or frontier areas often receive lower royalty rates or exemptions. Signature/production bonuses are also common.
- Taxation: Under PIA, contractors pay hydrocarbon tax and corporate income tax. Previous structures, such as Petroleum Profits Tax (PPT), gave different terms historically.
Recent PSC deal: TotalEnergies + Sapetro: A case study
The recent agreement between Nigeria’s NNPC, TotalEnergies, and Sapetro offers a good example of how a Production Sharing Contract (PSC) works.
The deal covers oil blocks PPL-2000 and PPL-2001, awarded in the 2024 licensing round. Together, they span about 2,000 km² in the Niger Delta and will be developed under PSC terms.
TotalEnergies holds an 80% stake, while Sapetro owns the remaining 20%.
You can read the full details here.
The contract includes minimum work programmes, required investments, signature and production bonuses.
It also covers environmental safeguards, host community obligations, and gas development incentives.
Together, these reflect the PIA’s shift toward more detailed and enforceable agreements.
Service contracts: specialist tools & narrow windows
Service contracts take a different shape.
The investor or contractor does not hold equity in the oil or gas.
Instead, they provide either technical services (pure service contracts) or investment with cost recovery under risk service contracts, often in marginal, small, or technically challenging fields.
In Nigeria, these have been less common for major field developments, but examples do exist.
Fields like Okono and Okpoho were developed under risk service negotiations with NPDC and Agip.
Agip initially took a large share of early production (70%) in return for developing the field, before later stepping down.
These agreements are suited to contractors confident in their execution capability and costs discipline.
They bear more operational risk (including cost overruns or geological surprises) but benefit from being more flexible and having fewer joint governance hurdles.
For investors seeking upside without sharing equity (and with lower scale), service contracts may offer good value, so long as contract terms are tight, payment obligations are reliable and exit or profit share conditions are clearly defined.
Marginal field agreements: local players & small fields
Moreover, marginal Fields are those discovered but undeveloped for at least ten years, which the government declares eligible to be farmed out to indigenous firms (often with technical partners).
Key features:
- Ownership: Operators must be majority Nigerian (≥51%). Foreign technical partners may hold up to 49%.
- Financial terms: Historically, these fields enjoyed lower tax burdens (e.g. PPT of ~55% vs 85% in many JVs) and modest royalties. Overriding royalties (2-5%) may apply to the original leaseholder (farmor).
- Obligations: Signature bonuses, minimum work programmes, environmental and community obligations similar to larger contracts.
Performance has been mixed.
Many marginal fields take longer than projected to reach production due to limited access to finance, shallow reserves, infrastructure constraints, and community tensions.
But success stories (e.g. Waltersmith’s Ibigwe, Midwestern Oil’s Umusadege) show that with suitable finance, technical capacity, and strong community engagement, marginal fields can reward investors.
Under PIA, no new fields will be designated “marginal” per se; existing marginal fields are being converted to Petroleum Mining Leases under the new fiscal regime.
Overriding royalties payable to the farmor are being phased out, improving economics for marginal field operators.
Where Nigeria stands in 2025
Despite challenges, recent signals suggest Nigeria is back on investors’ radars.
According to Wood Mackenzie, Nigeria led the continent in upstream Final Investment Decisions in 2024, attracting billions in investment under reformed policy settings.
Another external factor is climate and ESG pressures.
Starting January 2025, Nigeria will require all upstream licence applicants to show evidence of low carbon emissions and have renewable energy programs.
Its Upstream Petroleum Decarbonisation Template (UPDT) demands methane leakage controls, energy efficiency, and environmental safeguards.
Contract types compared: advantages, trade-offs & fit
To decide which contract type best suits an investor’s strategy, here are comparisons:
| Contract Type | Best For | Key Risks | What to Demand in Contract |
| JV | Large capital players seeking equity, reserve booking, influence over operations | Partner funding risk (cash calls); political or regulatory interference; delays | Clear cash-call schedule; governance arrangements; force majeure/stabilisation clauses |
| PSC | Deepwater, offshore, large risk projects; firms with strong technical & financial capacity | Cost recovery caps; royalty/tax burdens; geological uncertainty; regulatory changes | Strong cost audit rights; realistic work programme; environmental and host community obligations; good exit terms |
| Service Contract | Specialized firms, lower scale, technical services; investors wanting fee-based returns without reserve ownership | Limited upside; reliance on contractor payment; fewer strategic control elements | Tight timelines; payment guarantee clauses; defined cost vs reward sharing; risk of overruns |
| Marginal Field | Local or smaller firms; investors seeking entry-level upstream exposure | Financing constraints; infrastructure gaps; smaller scale; sometimes lower profitability | Clear terms for overriding royalty; assurance of infrastructure access; strong community / environmental planning; fiscal stability under PIA terms |
Checklist for investors: What to watch
As you evaluate opportunities, ensure you consider:
- Fiscal and Royalty Terms – cost oil caps, profit oil splits, royalty rates (especially by water depth), corporate and hydrocarbon tax rates.
- Regulatory Certainty – clarity on contract enforcement, role of regulator vs operator, licensing timelines, conversion of legacy contracts under PIA.
- Environmental, Social & Governance (ESG) – climate commitments, community obligations, decommissioning plans, emission controls.
- Local Content & Workforce Participation – requirement for Nigerian ownership, local procurement, technical partner roles.
- Profit Repatriation & Currency Risk – legal protections for foreign exchange; real-world payment delays; hedging options.
- Work Programme & Minimum Commitments – signature bonuses, seismic or drilling programmes, timeline for deliverables.
- Legal & Dispute Resolution Provisions – stabilization clauses, arbitration options, dispute history in PSCs or JV contracts.
Recent deals that illustrate the new normal
- TotalEnergies & Sapetro PSC (2025): As described, this contract is now seen as a benchmark for future PSCs under PIA: explicit gas incentives, environmental guards, host community obligations. Investor and government statements suggest this deal will guide terms going forward.
- Shell Onshore Exit / Asset Sales: Shell sold a large portion of its onshore operations in the Niger Delta to local firms (Renaissance Africa Energy consortium), signalling a trend of divestment and increased indigenous participation. Shell retains deepwater and integrated gas positions. This reflects both strategic repositioning and response to communities, governmental and investor pressure to clean environmental legacies. Also, critics urged that environmental damage in the Niger Delta must be addressed.
Feedback for investors
Nigeria’s oil and gas sector offers both promise and complexity.
The country is among Africa’s largest oil producers; its reforms under PIA 2021 provide more transparent legal frameworks, better fiscal clarity, and new incentives, especially for frontier basins and gas. But investor success will depend more on execution than law alone.
Takeaways:
- Model Contracts Matter: Choose Wisely
The PSC signed with TotalEnergies/Sapetro shows what newer contracts look like: clearer gas terms, incentives, environmental obligations, minimum work programmes, and tougher compliance demands. Investors should prioritize contracts that reflect these features, not older, looser templates. - Assess Contract Stability & Legislative Risk
Proposals to amend PIA (such as giving NUPRC both regulatory and commercial roles) are raising alarm among experts.
This could reduce confidence, lead to disputes, or deter capital. Investors must examine whether contracts include stabilization clauses or protections against adverse legal shifts. - Budget Real Costs Including Community, ESG, and Decommissioning
Contracts increasingly require obligations for host community development, environmental remediation, and decommissioning funds.
These are not side issues—they affect cost curves and IRR significantly. Projects that ignore these costs face financial and reputational risk. - Frontier Basins Present Upside and Risk
The mandate under PIA to allocate 30% of certain profits to frontier basin explorations may create lucrative opportunities in under-explored areas. But geology is uncertain, and infrastructure often lacking. Risk of cost overruns or failure is higher. Model your risk and returns accordingly. - Gas is Becoming Strategically Important
With global energy transitions, gas is gaining priority. Nigeria’s new PSCs and fiscal incentives for gas highlight this shift. Investors with experience in gas monetization, LNG, compressed natural gas, or domestic gas supply stand to benefit. But gas projects face particular regulatory, logistical, and infrastructure hurdles (e.g. pipelines, flaring regulation). - Local Content & Capacity are Non-Negotiable
Legal requirement aside, strong local partners, local supply chains, technical training, and engaging host communities aid timelines, reduce opposition, logistic delays, and improve social licence to operate. - Financial Structuring must be Robust
Deepwater PSCs or large JVs mean big CAPEX outlays, long lead times, and exposure to oil price volatility.
Investors should model cash flows under adverse scenarios (lower oil price, delays, higher taxes or royalties). Currency risk and FX policy (legal vs. practical ability to repatriate profits) must be built in. - Enforcement and Regulatory Track Record Count
It’s not enough to have favourable contract terms.
Investors need to see that regulators enforce minimum work obligations, royalty/tax regimes, environmental rules. Delays in approvals, disputes over cost recoverability, lagging enforcement of host community obligations can erode value.
Final thoughts
Nigeria’s oil & gas sector stands at an important crossroad.
The PIA created legal and fiscal reforms that restore confidence, offer transparency, and introduce incentives that align with global trends. New PSCs like the TotalEnergies/Sapetro deal show that opportunities under the new regime are real.
But old challenges, funding reliability (especially in JVs), regulatory ambiguity (especially if proposed amendments succeed), community and environmental risk, currency risk still persist.
To succeed, investors must combine legal and technical due diligence with strong local partnerships, robust financing, and built-in flexibility for changing laws or market conditions.
For investors with long-term horizons, strong balance sheets, and a tolerance for risk, Nigeria remains one of the most compelling upstream investment destinations in Africa.
For those newer to the sector or with shorter timeframes, marginal fields or gas PSCs with favourable terms may offer entry points.
