Energy Focus Report Q2 2025 - Oil And Gas Sector

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REVIEW OF THE NIGERIAN UPSTREAM PETROLEUM REGULATORY COMMISSION COMMERCIAL REGULATIONS

Introduction

The Nigerian Upstream Regulatory Commission is a body of the Federal Government of Nigeria established via the Petroleum Industry Act 2021 saddled with the responsibility of regulating the operations of entities in the Nigerian Upstream Oil and Gas sector. In Pursuance of this mission and powers conferred on it by section 8 th of the PIA 2021, the Commission on 5 May 2025 issued this regulation to regulate commercial activities in the Nigerian Upstream Oil and Gas sector. Amongst others, this regulation is a step further in the Nigerian Governments strategic effort to institutionalize cost effectiveness in the Nigerian Oil and Gas sector and attract Investments. The Regulations also seeks to promote Nigerian involvement in the sector and enhance transparency.

This broad statement of the scope of this regulation signals the intent of the commission that the provisions should be far reaching (applicable to all the subsets of the Upstream sector).

This Review will be structured as follows:

1. Part A - General Review of the Regulations
2. Part B - Scope of application of the Regulations.
3. Part C - Market Implications

A. REVIEW OF THE REGULATIONS.

Regulation 1 provides the objective of the Act as being the regulation of commercial activities in the Upstream Petroleum operations.

Regulation 2 further provides that the subsequent regulation shall apply to licenses and leases granted under the Petroleum Industry Act with respect to Field Development Plans (FDPs), Annual Work Report (AWR) and Status report (SR). The regulations apply to Licenses and Leases which existed prior to the enactment of the Petroleum Industry Act (PIA) 2021 and preserved under the PIA 2021.

Regulation 3 provides for the requirements to be met when applying for an FDP or Phase Development Plan (PDP) as well as amendments to FDPs or PDPs which were granted or preserved under the PIA 2021, the basis on which the commercial aspects of proposed plans are approved and the indicators which the commission shall consider in appraising the profitability of a project. The required data to be submitted in when applying for an FDP/PDP are:

1. Scope of the FDP and work breakdown structure.
2. FDP work activities, deliverables, and milestones schedule.
3. Projected annual hydrocarbon production and price estimates for the following, as applicable: Crude oil (with fiscal price as determined by the Commission), Field condensates, Associated gas, Non-associated gas, Plant condensates, Other natural gas liquid (NGL), Domestic gas supply and Export gas supply AND
4. Annual cost estimation at Class 3 project gate of -10% lower case, base case, and +20% upper case estimate, which must consist of the Acquisition costs, Estimated oil and gas royalties at forecasted average annual fiscal prices, Estimated direct production costs (all inclusive), Estimated operating costs (all inclusive), Estimated decommissioning and abandonment costs, Estimated finance cost (including interest expenses), Estimated depreciation and amortization, Estimated capital costs (all inclusive) and a Commercial evaluation which evinces that the forecasted project expenditure based on the planned costs shall allow for maximum economic recovery from the project, based on the economic indicators specified in the Regulations (Net Present Value (NPV), Internal Rate of Return (IRR), Break-even Analysis, Return on Investment (ROI), and Economic Sensitivity Analysis).

Regulation 4 reiterates that approvals for activities relevant to the execution of an FDP/PDP should be accompanied by a summary report on the status of the projects as prescribed by the commission. The regulation also provides that where the actual or projected cost of a project exceeds the pessimistic project gates as established in Regulation 3, the licensee or lessee shall seek the prior approval of the Commission by applying for an amendment to the Field Development Plan.

Regulation 5 establishes the mandatory annual submission of an Annual Work Programme (AWP) and Status Report (SR). It sets a strict submission window (October 15th to November 16th) and defines the effective period of an approved AWPSR (January 1st to December 31st). It also prohibits Licensees and Lessors from engaging in activities without attaining prior approval except such activities relate to health and safety emergencies (which still require subsequent notification). Finally, it provides that expenditure incurred which falls outside the approved AWP and SR, which is not an emergency for which later notification was given to the commission, will not be deemed as eligible expenditure for upstream development operations under a license or lease.

Regulation 6 provides the contents of an application for approval of an annual work programme and status reports as well as the supporting documents which should accompany the application for annual work report and status report.

Regulation 7 places an expectation on the Commission to approve an AWP and SR before January 1 of every year where it is satisfied of the AWP and SRs commercial and economic viability, operational feasibility and environmental sustainability, occupational safety, payment of statutory fees, and beneficial ownership information. Additionally, the commission in determining the economic and cost viability of an AWP is to consider the consider the cost estimates and ensure

1. Conformity with benchmarked costs
2. Optimal Government take and acceptable economic returns and
3. They fall within the Class 3 project gates of -10% optimal, base case, and +20% pessimistic. Where the costs are above the pessimistic project gates, they shall be considered as a new plan and shall require a fresh approval by the Commission

Regulation 8 essentially provides a structured and time-bound process for modifying AWPs. It states that AWPs may be modified by the licensee or lessee (before or after commencement) or by the commission as a directive to the licensee or lessee. Applications for modifications made by licensee or lessee need be submitted at least 30 days prior to implementation of the proposed modifications and must be accompanied by payment of requisite fees. However, where such modification is at the instance of the Commission, no fees need be paid and such modification or proposal on how the modification can be accommodated in an acceptable manner is to be made within 30 days of being notified by the commission. An application is deemed approved if the commission fails to communicate its approval or disapproval within 30 days of the application being made. 

Regulation 9 empowers the Commission to disapprove an AWP or SR if it fails to meet prescribed conditions. The Commission is required to notify the licensee/lessee in writing with reasons and may require a new application (with new fees).

Regulation 10 mandates licensees and lessees to provide a bi annual report on the implementation status of its approved AWP to the commission. It also provides for the content of what such report must include (execution details and challenges faced, compliance, significant incidents, R&D, and Nigerian content development initiatives implemented during the period etc.)

Regulation 11 outlines the duty of the Commission to evaluate AWP performance. In performing this evaluation, the commission is permitted to make visits to Licensees/Lessees sites pursuant to at least 48 hours' notice in writing to the licensee or lessee. The notice should contain a list of places to be inspected, equipment, operations and books. Upon completion of inspection, the licensee or lessee is to be notified of findings and issued directives if any to optimize its work programme implementation.

Regulation 12 encourages meaningful interaction between the Commission and operators to discuss AWP and SR implementation in a bid to ensure smooth flow. The Commission may use the information gathered through the engagement(s) to evaluate the licensee or lessee's performance and direct the licensee or lessee to modify its AWP.

Regulation 13 addresses the formal process for discontinuing an approved AWP and SR. The discontinuance is commenced by a notice which shall be in writing and submitted at least 30 days before the intended date of discontinuance, stating the reasons for the discontinuance and other relevant information about the licensee or lessee. The Commission is required to give feedback within 14 days of its receipt of the notice of discontinuance. It also provides that failure to submit a new application after discontinuance may be considered an intention to surrender the license or lease, potentially leading to the Commission directing its surrender.

Regulation 14 grants the Commission the power to request commercial details of agreements between operators and third parties. Such information may form the basis on which the Commission may issue recommendations to the operators on cost optimization in implementing the agreements.

Regulation 15 seeks to foster inter operational collaborations to drive economic recovery of hydrocarbons, environmental sustainability and infrastructural development.

Regulation 16 outlines the cause of action when a breach of these regulations occur. They include issuing a written warning or imposing an administrative penalty.

Regulation 17 details the various penalties for infractions of the regulations ranging from N10, 000,000 to N 100,000,000.

Regulation 18 details the process for applying for review of the commissions decisions regarding AWP levied. The application for review is to be submitted within 30 days of the decision being reached and the Commission shall provide a written response, replying the application for review within 30 days of receiving the application.

Regulation 19 provides reports which required to be submitted to the commission.

Regulations 20 1nd 21 are the interpretation and citation sections respectively.

B. SCOPE OF APPLICATION OF THE REGULATIONS

Primarily, this regulation applies to licensees and lessees whose licenses and leases granted prior to the enactment of the PIA was preserved under the PIA 2021 or granted anew under the PIA 2021. However, practically this regulation may have a broader reach. This may also apply to:

• Service Providers who may face indirect scrutiny per Regulation 14 which empowers the NUPRC to request commercial details of agreements between licensees/lessees and third parties for the purpose of recommending means of cost optimization. This means service providers will need to ensure their terms are competitive and justifiable, as their potential clients ability to secure regulatory approval for costs may depend on it.
• Financiers, Investors and Banks providing capital to upstream projects must now factor in the current cost controls, economic viability criteria, and detailed reporting obligations imposed by these Regulations. The regulatory oversight introduces a layer of financial scrutiny that will influence investment decisions, due diligence processes, and the terms of project financing.

The regulations relate specifically to the commercial aspects of FDPs, AWP and SR of the licensees and lessees. In summary, the regulations seek to govern the financial and economic viability assessments, detailed cost estimations, and the reporting mechanisms associated with these crucial operational plans.

C. OPERATIONAL IMPLICATIONS

1. Operational and Financial Implications
   • Rigorous Field Development Plan (FDP) and Phase Development Plan (PDP) Preparation: Market players must invest significantly in the area of project planning. The implication is a demand for enhanced technical and commercial forecasting capabilities, potentially requiring investments in new software tools or specialized expert consultants to meet the required level of detail and accuracy
   • Strict Cost Management and Benchmarking: The requirement for Class 3 project gate cost estimations (optimal -10%, base case, and pessimistic +20%) across all cost categories means that robust internal cost control systems are paramount. 
   • Demonstrable Economic Viability: Projects must clearly demonstrate economic viability benchmarked by certain expectations stated in the regulation. This necessitates sophisticated financial modeling and investment appraisal capabilities within operating companies. Projects that are marginally viable or carry high inherent financial risks may struggle significantly to gain the necessary regulatory approval.
2. Compliance and Reporting Burden
   • Increased Reporting Frequency and Detail: Licensees and lessees are now mandated to submit not only annual work programmes and status reports, but also half-yearly implementation reports which require extensive detail covering activities, associated costs, compliance status, significant incidents and others. 
   • Financial Penalties for Non-Compliance: Failure to submit an Annual Work Programme and Status Report (AWP/SR) in accordance with the Regulations incurs a substantial administrative penalty of ₦10,000,000, along with an additional penalty of ₦1,000,000 for every day the breach continues.
   • Enhanced Regulatory Scrutiny: The NUPRC is empowered to conduct periodic evaluations, monitoring visits, and field inspections, with the AWP serving as a key metric for performance assessment and company ranking.

Conclusion

The Nigerian Upstream Petroleum Regulatory Commission Commercial Regulations represent a significant milestone in strengthening oversight and governance of commercial activities in the upstream oil and gas sector. By establishing clear requirements for planning, reporting, approval, and compliance, these Regulations seek to enhance transparency, accountability, and operational discipline among the key players in the sector. In addition, their effective implementation will be critical in ensuring optimal economic recovery, sustainable development, and improved collaboration between operators and the Commission. To this effect, all upstream licensees and lessees must align their activities with these provisions to foster a more robust and sustainable petroleum industry in Nigeria.

REVIEW OF THE UPSTREAM PETROLEUM OPERATIONS (COST EFFICIENCY INCENTIVES) ORDER, 2025

Introduction

The Upstream Petroleum Operations (Cost Efficiency Incentives) Order, 2025 (the “Order”), which took effect on April 30, 2025, marks a significant shift in Nigeria's strategy to revitalize its vital oil and gas sector. Signed by President Bola Ahmed Tinubu, this Executive Order directly establishes a framework of incentives to promote cost efficiency, encourage discipline in expenditure, and enhance Nigeria's global competitiveness in oil and gas operations. This review examines the provisions of the Order sequentially and evaluates its practical implications for the upstream oil and gas sector.

A. General Overview of the Upstream Petroleum Operations (Cost Efficiency Incentives) Order, 2025

Primary Objective

Paragraph 1 lays out the primary objective of the Order which is to create a Cost Efficiency Incentive (CEI) framework aimed at reducing the operating costs and improve competitiveness, by encouraging stakeholders to adopt best practices. It aims to achieve these goals by reducing costs, promoting discipline, streamlining contract cycles, and maximizing economic value. Tax incentives will also be introduced for meeting or exceeding cost reduction targets as a noteworthy innovation which links regulatory compliance with direct financial benefit. 

Scope and Application

Paragraph 2 provides for the scope of application as lessees, licensees, and contractors operating in the upstream petroleum sector. Significantly, it makes clear that only entities which meet or surpass cost reduction targets as determined by the Nigerian Upstream Petroleum Regulatory Commission (the “Commission”) will be eligible for the incentives. This condition ensures that the benefits of the scheme are performance-based, thereby minimizing room for abuse.

Responsibilities of the Conmission

Paragraph 3 details the responsibilities of the Commission, particularly in benchmarking and target setting. Amongst others, it provides: 

1. That the Commission must annually evaluate and compare the costs of "upstream operational activities" and "Unit Operating Costs" for the different types of upstream oil and gas environments (onshore, shallow water, and deep offshore);
2. That the Commission shall determine cost benchmarks vide guidelines issued under the Petroleum Industry Act. The issuance of such guidelines is subject to consultation with relevant stakeholders.
3. That the Commission shall annually set specific targets for reducing Unit Operating Costs for each terrain (onshore, shallow water, deep offshore), considering the unique aspects of their operating environment and production volume.
4. The Commission will conduct annual reviews, aligned with the tax return cycle, of the performance of lessees or licensees (oil and gas companies), with the primary metric being Unit Operating Costs, to determine if they are attaining the set targets.

These provisions introduce a dynamic, data-driven mechanism for setting cost expectations, with stakeholder consultation and publication of methodology, constituting an attempt at enhancing transparency. In addition, sub (3) and (4) incentivizes achieving and exceeding cost performance targets by providing tax incentives.

Tax Credit Incentives

Paragraph 4 speaks to the tax credit incentives. Under this Order, companies that maintain operating costs below the commission's benchmarks will be allowed to claim a tax credit which reflects a portion of the incremental government share arising from cost reductions. The tax credits shall be applied against the overall tax liability of the tax payer's relevant asset and calculated as provided in subsequent paragraph 5 without compromising existing government revenue expectation. Adopting this tax credit system cleverly aligns private incentives with public fiscal interests, as it ensures that cost savings are shared between operators and the government. Additionally, the incentive framework is time-bound, expiring in 2035 unless renewed.

Computation of Cost Efficiency Incentive (CEI)

Paragraph 5 provides the formula for computing the CEI as follows:

CEI = (CS)* RTR * 50%

CS= (TOC – AOC) *V

Key:

CS = Cost Savings

RTR = Referenced Tax Rate

AOC = Actual Operating Costs

TOC = Target Operating Cost

V = Annual Fiscal Sales of Hydrocarbons

50% = the ceiling for the CEI.

Global Alignment and Incentive Cap

Paragraph 6 provides that the cost reduction targets shall be set with the intention of aligning Nigeria's upstream petroleum operating costs with global standards and best practices. Effectively eliminating the cost premium in Nigeria's oil and gas sector and establishing targets drive year-on-year improvements in cost efficiency. This paragraph also sets a cap of 20% of the taxpayers' total tax liability as the incentive claimable in a financial year and provides essentially that UOC utilized for tax credit eligibility status must have been the same utilized for computing adjusted profits for tax purposes. Tax credit granted under this Order is valid for offsetting income tax liability in the year they occur and utilized within three years of issuance.

Implementation Guideline

Paragraph 7 mandates the issuance of implementation guidelines within thirty (30) days, with detailed benchmarks to be published within ninety (90) days of the start of each calendar year. It also provides for annual publication of qualifying companies. These requirements enhance transparency and give operators clear expectations.

Effective Date

th Paragraph 8 provides the effective date of the Order to be April 30^th, 2025.

Interpretation

Paragraph 9 offers Interpretation of certain key terms.

Short Title

Paragraph 10 provides the short title of the Order, formally designating it as the Upstream Petroleum Operations (Cost Efficiency Incentives) Order, 2025.

B. SCOPE OF APPICATION

The Upstream Petroleum Operations (Cost Efficiency Incentives) Order, 2025, specifically applies to lessees, licensees, and contractors operating in the upstream petroleum sector.

C. IMPLICATIONS

This order has some implications on the market players whom it applies to. Some of them include:

• Incentivized Cost Reduction:It directly encourages applicable entities to actively reduce their operating costs and adopt more efficient practices.
• Increased Profits: Companies that successfully meet or surpass cost reduction targets, as determined by the Commission will be eligible to claim a tax credit which ultimately means more money retained by the company.
• Enhanced Competitiveness: By driving down costs, the Order aims to make Nigerian operations more globally competitive, potentially attracting more investment.
• Increased Transparency and Predictability: The mandated annual benchmarking, target setting, stakeholder consultations, and publication of qualifying companies provide greater transparency and clearer expectations for operators.
• Dual Benefits: The tax credit system ensures that the financial benefits derived from cost savings are shared between the operators and the government, aligning private and public fiscal interests.

Conclusion

The Order represents a well-conceived and strategically timed intervention in Nigeria's petroleum regulatory landscape. Its strength lies in its performance-based incentive structure, multi-agency coordination, and focus on transparency and discipline. If properly implemented, it could lower Nigeria's cost of production, attract investment, and improve returns to the state. However, its success will ultimately depend on institutional capacity, especially the effectiveness of the Commission and FIRS in benchmarking, monitoring, and enforcement.

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