Editor's Note: Uzoma Johnpaul Ajugwe is a member of the TWA Editorial Board and a contributing author of previous TWA articles.
Since the discovery of commercial oil in Oloibiri, Niger-Delta, Nigeria has grown into Africa’s largest oil producer, with petroleum being 90% of its foreign exchange and 70% of its government revenue (Ubodiom & Charles Ariye, 2024).
Deepwater operations are managed by production-sharing contracts (PSCs), where the government retains ownership of the oil resources, while private companies provide the capital and expertise needed to explore and produce oil (Innocensio, 2021). In return, the oil produced is split between the government and oil company based on a pre-negotiated formula. However, Nigeria’s 2019 amendment to the Deep Offshore Act and the passage of the Petroleum Industry Act (PIA) was the most significant reform in decades (Amieibibama, 2022).
This article analyzes fiscal framework by examining its legal foundations, the practical operation of PSCs, and the allocation of financial risk between the government and international oil companies (IOCs). The goal is to describe the current system and assess its suitability for attracting long-term investment in a capital-intensive sector while ensuring that Nigeria receives a fair share of its resource wealth.
Legal and Regulatory Framework
The Deep Offshore and Inland Basin PSC Act
Nigeria’s deepwater petroleum system is built on the Deep Offshore and Inland Basin PSC Act, which was first enacted in 1993. The act was introduced to attract foreign investment into frontier offshore areas that were then considered risky and commercially uncertain. To encourage investment, the government offered relatively generous terms to IOCs companies: low royalty rates, high limits on Accelerated Cost Recovery System (ACRS), and profit-oil-sharing structures designed to reflect the higher risks associated with deepwater exploration (Amieibibama, 2022).
A particularly important provision was that of the 1993 Act, Section 16, which required the fiscal terms to be reviewed if oil prices rose above $20/bbl for a sustained period or if cumulative production reached certain levels. Between 2003 and 2016, during one of the most profitable oil price booms in modern history, Nigeria did not enforce this review clause, resulting in significant revenue losses (Iledare, 2008).
This oversight was partially corrected by the Deep Offshore (Amendment) Act of 2019, which reintroduced royalties for ultradeepwater blocks and shifted part of the fiscal framework from solely water-depth benchmarks to cover production-based benchmarks (Ogolo et al., 2020a).
The Petroleum Industry Act (PIA) 2021
The PIA signed into law by the late President Muhammadu Buhari in August 2021, is to date the most comprehensive reform of Nigeria’s petroleum laws. It reorganized the sector around four major pillars: governance, administration, fiscal terms, and host community development. On the fiscal side, the PIA introduced a hydrocarbon tax (HT) for upstream operations, replacing the long-standing Petroleum Profits Tax (PPT) which had been in place since 1959 (Borha & Olujobi, 2023).
For deepwater PSCs, the PIA maintains existing contracts but introduces new fiscal terms for future agreements, including a corporate income tax rate of 30% and an HT of 15%. Together, this produces an effective tax rate lower than the previous 50% PPT applicable to PSC profits (Danfulani et al., 2026).
Previously, NNPC Ltd.’s funding shortfalls frequently delayed projects and created financial tensions with private contractors. Under the new structure, NNPC is expected to finance its obligations commercially, which will in turn reduce disruptions and improve operational efficiency.
Structure of PSCs in Nigeria
Cost Oil Recovery
A PSC creates a structured partnership in which oil production is divided according to a contractual formula before any government revenue is calculated. The first step in this process is cost oil recovery.
The oil company (the contractor) is entitled to recover its exploration, development, and operating expenditures from a portion of production designated as cost oil. The maximum percentage of total production that can be allocated to cost recovery is historically 80% in Nigerian PSCs (Jibril & Fishim, 2023). This means that, up to 80% of total barrels produced could first go toward recovering the contractor's costs before the remaining production is shared between the government and the contractor as profit oil (Ogolo et al., 2020a).
Cost oil recovery is calculated on an actual cost basis, meaning contractors recover the actual costs they incur rather than a standardized rate. While this provides flexibility, it also creates a significant auditing challenge for the state, especially where information asymmetry between the contractor and NNPC makes independent verification of expenditures difficult. This asymmetry is the structural precondition for what is commonly described as gold-plating—the inflation of recoverable costs to maximize cost oil take or profits, thereby taking advantage of the PSC (Jibril & Fishim, 2023).
Profit Oil Sharing
Once cost oil has been deducted, the remaining production (profit oil) is divided between the government and the contractor according to a production-based sliding scale. Under Nigerian model PSC terms, the government's share of profit oil increases as daily production rises. At lower production levels (typically below 10,000 B/D), the contractor may retain between 40 and 50% of profit oil. At higher production levels (above 100,000 B/D), the government's share may rise to between 75 and 80% (Hassan, Amuda, Dhali, et al., 2023).
This sliding scale is designed to ensure that highly productive fields generate proportionally greater revenue for the state. However, the productivity thresholds in Nigerian PSCs have not always kept pace with actual offshore production volumes, meaning that as Nigerian deepwater output increased significantly from the early 2000s, the government did not always capture the proportional uplift the sliding scale was intended to deliver (Okoro, Okoye, et al., 2021).
Royalties and Signature Bonuses
Signature bonus is a lump-sum payment made when contracts are awarded. They provide immediate revenue to the government, regardless of whether oil production occurs or not. While attractive from the government’s perspective, high signature bonuses can discourage early-stage exploration by increasing costs before a commercial discovery is confirmed (Mohamed et al., 2024).
Fiscal Regime Analysis
Government Revenue Take
A practical way for a host government to measure the effectiveness of a petroleum fiscal system is to calculate “government take.” This is the percentage of the total economic value generated by an oil project that goes to the host government. It comprises all revenue streams, including royalties, profit oil, taxes, and signature bonuses (Ogolo et al., 2020b).
Research on Nigeria’s deepwater PSCs shows that government take has ranged between 55 and 75%, depending on oil prices and production levels (Iledare, 2008). However, during the high-oil-price period of the mid-2000s, Nigeria did not activate its fiscal review mechanism, so while contractor profits grew substantially, the government’s share stagnated (Ogolo et al., 2020a).
The 2019 amendment to the Deep Offshore Act and the PIA 2021 was introduced to address this imbalance. By reintroducing royalties on ultradeepwater blocks and redesigning parts of the tax system, these reforms aimed to increase government revenue, particularly during periods of high oil prices.
Competitiveness of Nigeria's Fiscal Terms
Deepwater investment is global, and IOCs compare multiple countries before deciding where to invest. If a country’s fiscal terms impose a heavier burden than other comparable oil-producing states, it may discourage new investment and even push companies to withdraw from existing operations.
Risk Allocation Under Nigerian PSCs
Exploration and Development Risk
The fundamental principle of the PSC model is the carried interest—the contractor assumes exploration risk and handles the cost of operations in exchange for the right to recover costs and share in production if oil is found (Kishk, 2009). In Nigeria’s deepwater PSCs, the IOCs bear all pre-production exploration costs and if exploration fails, the contractor absorbs the loss entirely.
This arrangement makes economic sense given the technical capacity and capital that IOCs bring to deepwater exploration and the limited risk appetite of the government. However, problems arise when cost recovery rules become more restrictive. If the government lowers cost recovery caps, narrows the categories of recoverable costs, or applies strict auditing standards, the contractor’s effective risk increases beyond what was originally anticipated. IOC contractors have argued that changes like these alter the economic balance of the agreements by increasing financial exposure without adjusting other contractual benefits (Ole & Herbert, 2022).
Political and Regulatory Risk
In addition, investors also face political and regulatory risk, such as the government may change the rules after companies have already committed capital. This risk type is particularly serious in deepwater oil projects, which require large upfront investments and long-term planning. Investors base their decisions on expectations about stable fiscal conditions over decades.
Nigeria’s history in this regard is complicated. The retroactive application of new royalty rates under the 2019 amendment was perceived by many IOCs as a unilateral change to previously agreed terms. The government defended its action by pointing to the review clause in Section 16 of the original act. However, IOCs argued that more than 2 decades of non-enforcement had created legitimate expectations of stability (Jibril & Fishim, 2023).
This dispute reflects a broader contradictory tension that also exists in many resource-rich countries.
- The state has the sovereign right to adjust fiscal terms in public interest.
- Investors require predictability and stability to justify large capital commitments.
The PIA 2021 attempts to manage this tension. It protects the terms of existing PSCs while offering companies the option to voluntarily convert to the new fiscal regime in exchange for specific incentives (Ole & Herbert, 2022).
Price and Cost-Recovery Risk
Oil prices are volatile, and neither governments nor companies can control global price fluctuations. But the PSC design is what determines how price risk is shared between both parties. Under Nigerian PSCs, price risk is partly managed through the profit-oil sliding scale. When oil prices rise and production increases, the government takes a larger profit share. When prices fall, the profit share of IOCs decreases (Peters, 2021).
If oil prices fall so low that total revenue cannot cover costs within the cost oil cap, contractors may experience under-recovery, where they cannot fully recover their investment within the contractual limit. Nigerian PSCs typically allow unrecovered costs to be carried forward into future accounting periods (Kishk, 2009).
In fields with declining production, these carried-forward balances can accumulate significantly, leading to extended cost-recovery periods that distort project economics and delay the timing of government revenue (Ole & Herbert, 2022).
Challenges and Criticisms of the Existing Regime
Cost Inflation and Oversight Deficits
A persistent challenge in Nigeria’s PSC system is cost inflation. This may occur through inflated procurement prices, the use of affiliated service companies charging above market rates, or the misclassification of operating and capital expenses (Okoro, Okoye, et al., 2021). The scale of cost inflation is difficult to measure precisely because regulatory institutions often face technical and resource constraints (Peters, 2021).
The PIA 2021 aims to strengthen oversight in this regard by establishing new regulatory bodies, including the Nigerian Upstream Petroleum Regulatory Commission. These reforms are partly designed to improve transparency and auditing capacity (Amieibibama, 2022).
IOC Divestment and Investment Stagnation
Another major concern is the growing trend of IOC divestment from Nigeria. During the 2010s and early 2020s, major oil companies such as Shell, ExxonMobil, and Eni divested substantial onshore and shallow-water Nigerian assets. Although deepwater operations have seen less divestment, the broader pattern suggests that these IOCs are reassessing Nigeria’s investment climate compared to other global opportunities (Bodo, 2025).
Additionally, several deepwater blocks awarded in earlier PSC rounds remain undeveloped, a key reason being financing disputes between NNPC and contractors over cash call obligations. Under the previous system, NNPC’s funding shortfalls frequently delayed projects.
Comparative Analysis
Assessing Nigeria’s deepwater fiscal regime independently can lead to incomplete conclusions. A clearer understanding emerges when Nigeria is compared with other countries that share similar characteristics, particularly Angola, Ghana, Mozambique, and Namibia. We will now examine how Nigeria’s system compares with these countries' jurisdictions, identifying where it performs well, where it faces weaknesses, and what lessons can be drawn for reform.
Angola
Angola is Nigeria’s closest point of comparison. The key difference lies in how profit-oil shares are adjusted over time. Angola uses an R-factor mechanism—a formula based on the ratio of cumulative revenues to cumulative costs. As a project recovers its investment and becomes more profitable, the R-factor rises automatically. When this happens, the government’s share of profit oil increases without requiring legislative changes or contract renegotiation (Adeyemo, 2016). In contrast, Nigeria’s pre-2019 system relied on fixed terms that did not automatically adjust to changing economic conditions, resulting in economic loss.
Angola’s fiscal regime has also been regarded as more institutionally stable than Nigeria’s, particularly in avoiding retroactive fiscal changes (Ekeinde & Okujagu, 2024). However, Sonangol, the state-owned national oil company, plays both a commercial and quasi-regulatory role, which limits independent oversight and raises transparency concerns (Adeyemo, 2016).
Ghana
Ghana’s Petroleum (Exploration and Production) Law created a transparent legal framework that reduced regulatory ambiguity (Omolara, 2010). The Jubilee PSC incorporated price-banding provisions in more recent contract versions and included a defined cost-recovery audit structure, features Nigeria only moved toward with the PIA 2021 (Kankam & Ackah, 2014).
Unlike Nigeria which layered petroleum profit tax, investment tax credits, royalties, and PSC-profit splits in complex ways, Ghana’s fiscal structure is simpler and easier for investors to evaluate. But its smaller domestic market gives it less bargaining power than larger producers (Omolara, 2010).
Mozambique
Mozambique’s fiscal framework includes production-based profit-oil splits like Nigeria’s, with the government’s share increasing as production rises (Zanoli et al., 2025).
However, its relatively new regulatory institutions struggled to audit and enforce cost-recovery provisions against experienced IOCs, and disputes over recoverable costs also delayed final investment decisions on major LNG projects (Moyo et al., 2021).
Namibia
Namibia’s PSC framework is governed by the Petroleum (Exploration and Production) Act of 1991, and administered by NAMCOR, the national oil company (Scholvin, 2021). Deepwater royalty rates were initially set at 5%, mirroring Nigeria’s experience of fiscal terms being negotiated before large discoveries are confirmed, which often undervalues the resource once its true size is determined.
Comparative Overview
First, the most effective deep offshore fiscal regimes incorporate automatic economic sensitivity into their design.
Second, cost recovery oversight is a shared challenge across all five countries. IOCs possess superior technical knowledge of deepwater operations, giving them an advantage in cost-recovery disputes.
Third, Mozambique and Namibia show that Nigeria’s challenges are not unique to mature producers. They are structural features of PSC-based deepwater development in contexts where governments lack equal negotiating and enforcement capacity.
Recommendations
The following recommendations address the structural weaknesses identified across the preceding analysis and are directed at three levels: fiscal design, institutional reform, and contract governance.
1. Nigeria should implement automatic fiscal adjustment within PSC agreements to adjust royalties and profit shares based on oil price and production thresholds.
2. To improve fiscal oversight, Nigeria should empower the Nigerian Upstream Petroleum Regulatory Commission with the funding and standardized data necessary to conduct independent cost audits.
3. To ensure NNPC consistently meet its financial obligations, Nigeria should establish a dedicated capital fund financed by signature bonus and isolated strictly from the budget.
4. Nigeria should enhance transparency by publishing the full fiscal terms of individual PSCs, which are currently withheld from public view.
Conclusion
The evolution of Nigeria’s deepwater fiscal regime since 1993 highlights a balancing act between massive foreign investment and maximizing state revenue. Important milestones, such as the 2019 deep offshore act amendment and the PIA 2021, helped modernized the sector by transforming the NNPC into a more commercially disciplined institution.
This analysis highlights that effectiveness of a fiscal regime is determined more by its execution than its statutes. While the design of Nigeria’s PSC framework is important, its impact is consistently undermined by the big four institutional challenges: weak auditing, regulatory instability, and underfunding of NNPC obligations.
The focus of Nigeria’s oil sector has shifted from legislative reform to operational as the legal framework is already in place. The primary challenge is bridging the gap between statutory promises and institutional performance to ensure the oil sector delivers its economic value.
For Further Reading
A Comparative Study of the Petroleum Fiscal Systems of Nigeria and Angola by V. Adeyemo, South America University.
The Impact of the Amended Deep Offshore and Inland Basin Production Sharing Contracts Act on the Economics of Oil Production in Nigeria by A. Joseph and I. Omonghegbe, University of Port Harcourt.
Divesting Nigeria’s Niger Delta Oil Blocks: Challenges, Solutions, and Strategic Implications by T. Bodo, Rivers State Ministry of Environment.
An Examination of the Petroleum Industry Act 2021: Prospects, Challenges, and the Way Forward by D. Borha and O. Olujobi, Afe Babalola University.
An Investigation of the Petroleum Industry Act 2021 in the Management of Social Security in Nigeria by R. Danfulani, Z. Islam, University of Abuja; H. Basaka, Nigerian Midstream and Downstream Petroleum Regulatory Authority, et al.
Implementation of the Petroleum Industry Act, 2021: Available Prospects for a Better Oil and Gas Industry in Nigeria by A.O. Dokpesi and G. Godwin, University of Benin.
Redefining the Legal Issues and Fiscal Responsibility Challenges of Deep Offshore Production Sharing Contracts in Nigeria Oil Industry by Z. Jibril and J. Fisham.
The Optimal Petroleum Fiscal Regime for Ghana: An Analysis of Available Alternatives by D. Kankam, SDC Finance and Leasing Company Ltd., and I. Ackah, University of Portsmouth.
Risk Assessment and Allocation in Nigerian Oil and Gas Projects by M. Kishk and B. Oladunjoye, Robert Gordon University.
A New Progressive and Efficient Production Sharing Contract for Upstream Oil and Gas Industry by I. Mohamed, H. Khattab, S. El-Sayed, Suez University, et al.
The Growing Crisis in Mozambique: Local Peacebuilders Response by N. Moyo, A. Larue, and A. Huits.
Assessing the Impact of Deep Offshore and Inland Basin Production Sharing Contract Amendments on the Economics of Deep Offshore E&P Assets in Nigeria by O. Ogolo, University of Nigeria; O. Iledare, University of Cape Coast; P. Nzerem, University of Nigera; et al.
Nigeria Deep Offshore Inland Basin Production Sharing Contract Acts: Evaluating Contractor's Take by E. Okoro, J. Echendu, L. Okoye.
The Nigerian Offshore Oil Risk Governance Regime: Does the Petroleum Industry Act 2021 Address the Existing Gaps? by N. Ole and E. Herbert.
Production Sharing Agreements: Learning Lessons from Russia and Nigeria by M. Peters.
An Historical Analysis Of Crude Oil Exploration and Its Impact on Human Development in Bayelsa State by E. Ubodiom and E. Ariye, Isaac Jasper Boro College of Education.
Assessment of the Projects’ Prospects in the Economic and Technological Development of the Oil and Gas Complex in the Republic of Mozambique by T. Semenova and N. Churrana, Saint Petersburg Mining University.
