Introduction
As Nigeria's oil and gas production capacity continues to increase, the Nigerian Upstream Petroleum Regulatory Commission ("NUPRC") is responding with regulatory reforms aimed at improving operational efficiencies across the upstream value chain in order to sustain this growth trajectory. One of such key reforms is the Nigerian Upstream Petroleum (Commercial) Regulations, 2025 (the "Regulations") issued by the NUPRC further to its powers under the Petroleum Industry Act, 2021 (the "PIA") to regulate commercial activities in Nigeria's upstream petroleum operations. The Regulations generally provide the structure for the approval and continuous regulatory evaluation of the commercial components of upstream activities, including field development plan, annual work programme and status report, and operation budgets for upstream licences and leases granted pursuant to, and those preserved by, the PIA.
In this article, our aim is to describe and examine the key provisions of the Regulations and their potential impact on upstream petroleum operations. We conclude that the framework introduced by the Regulations is welcome, but further refinement is necessary in light of the concerns highlighted in our analysis below to ensure a more predictable investment environment, reduce administrative burdens, and better align regulatory requirements with operational realities.
Field Development Plan and Phase Development Plan
(a) Approval of Plan
A field may be developed either through a single plan or in phases1 if it is complex or expensive to complete it at once. A licensee or lessee submitting an application to the NUPRC for approval of a single-phase field development plan ("FDP") or a multi-phase field development plan ("PDP") or their respective amendments must include the (a) scope of the FDP and work breakdown structure, (b) work activities, deliverables and milestones schedule, (c) forecast annual hydrocarbon production and price estimates, and (d) annual cost estimates using a "Class 3 project gate" estimate (that is, a budget-level cost estimate for making investment decisions) to reflect pricing scenarios of a lower case of -10%, a base case, and an upper case of +20%.2 The requirement for the upper case estimate is critical, as it ensures that risks such as cost inflation, supply chain challenges, unforeseen technical and operational issues, regulatory changes, bureaucratic bottlenecks and political issues are accounted for in the FDP and PDP from the start.
The annual cost estimates in (d) above must cover (i) costs of acquiring rights to the licence or lease, (ii) estimated royalties, (iii) estimated direct production costs, (iv) estimated operating costs, including security, regulatory and statutory charges, (v) estimated decommissioning and abandonment costs, (vi) estimated financing costs, (vii) estimated depreciation and amortisation, (viii) estimated capital expenditure, and (ix) a commercial evaluation reflecting that the project expenditure allows for maximum economic recovery. 3 The Regulations define "maximum economic recovery" to mean "recovery of economically recoverable petroleum in a manner that creates the maximum project value for the investors and the State ...". 4 By implication, licensees and lessees are expected to explore strategies that balance cost-effective and optimal production with ensuring a reasonable return on investment.
In its evaluation of the FDP or PDP for approval, the NUPRC will take into account the "Class 3 project gate" pricing estimates mentioned above, allowance for maximum economic recovery, indication of a positive return on investment that accounts for opportunity cost, benchmarks against similar projects and international best practice, positive Economic Value Added5 which ensures a high return above the cost of financing, and any other relevant legal or regulatory requirement.6 By the Regulations, the regulator will also consider the profitability of the FDP or PDP using finance metricssuch as Net Present Value, Internal Rate of Return, Break-even Analysis, Return on Investment and Economic Sensitivity Analysis.7
(b) Cost Overruns
In the event a project suffers cost overrun during implementation, the prior approval of the NUPRC will be required for the amendment of the approved FDP to reflect the revised cost estimates. 8 This provision, however, adds to the existing administrative bottlenecks in the oil and gas industry and will potentially create significant delays in oil and gas contracting cycles. This is because the requirement for the NUPRC's approval for cost overrun can result in at least three (3) additional layers of approvals.
First, the approval of the management committee in a joint venture arrangement (or board of directors in an incorporated joint venture) will be required to exceed budgetary allocations and estimates. Second, the approval of the Nigerian Content Development and Monitoring Board under the contracting framework of the Local Content Act9 may also be required to alter the pricing of contracts already entered into or to be awarded. Third, under the Regulations, the NUPRC's consent is also now required to exceed cost estimates in the approved FDP and PDP. This may also inadvertently derail Mr. President's publicly-declared objective of reducing the length of the contracting cycle in the oil and gas industry.
The implication of the foregoing is that operators will now be required to obtain the NUPRC's consent for expenditure above the upper-case budget approved by the NUPRC, regardless of how minimal the amount may be. Without clear metrics to guide its decisions, the NUPRC may refuse to approve such expenditures, potentially resulting in arbitrary decisions. Such decisions (including delays in making such decisions) could impact work timelines and result in additional cost overruns.
It is very likely to be the case that the NUPRC views the Regulations as an essential tool to ensure that the Federation obtains the benefits and advantages that it should ordinarily obtain from petroleum operations in Nigeria. In this wise, the NUPRC is essentially preventing operators from "writing off" significant profits (with its impact on tax revenues and statutory charges) on the basis of uncontrolled and unjustified price escalations after securing FDP approvals.
We are of the view that the approval levels for additional expenditure should be layered into two (2) tiers. The law should allow licensees and lessees to incur costs above the upper case, up to a specified cap, exercising good judgment and only as long as such decision is in the best economic interest of the relevant licensee or lessee. Where the expenditure is likely to exceed the cap, then the licensee or lessee must apply to the NUPRC for further approval.
Further, the Regulations fail to provide for a timeframe for the approval of a revised cost estimate in the FDP by the NUPRC. We do not consider the timeline provided in regulation 8(5) for the NUPRC's approval or disapproval of amendment to an annual work programme and status report as extending to the amendment of an FDP to accommodate cost overruns. This lack of clarity on timelines is likely to create uncertainty for licensees and lessees. It also raises critical questions concerning the potential disruption of contractual arrangements with supply chain providers and other third party contractors, impact of the delay in approval on projected production volumes and financing repayment schedules, and whether deemed consent may apply if the NUPRC fails to respond within a reasonable time, as is provided under regulation 8(5).
Pending revisions to the Regulations, licensees and lessees in the oil and gas industry can mitigate the impact of the Regulations on cost increases by ensuring that cost estimates adopt an upper case that correctly reflects escalation risks (such as delay, inflation, FX fluctuations legal changes, and macroeconomic shocks).
Annual Work Programme and Status Report
(a) Submission Obligation and Process
The Regulations mandate licensees and lessees to submit annual work programme and status reports on the licence or lease area in the format prescribed by the NUPRC together with the payment of the requisite application fee.10 The operator in a joint licence or lease is responsible for the submission of the annual work programme and status report on behalf of the non-operating licensee(s) orlessee(s). 11 The application for approval must be made between October 15 and November 16 in each year, and the NUPRC's approval will be valid for the entirety of the following year.12 The Regulations prohibit licensees and lessees from carrying out any activity listed in the annual work programme and the status report without the NUPRC's prior approval.13
Where there is a health and safety emergency, the licensee may take any step in accordance with the annual work programme and the status report pending NUPRC approval. The licensee or lessee must, however, notify the NUPRC within forty-eight (48) hours of that activity.14 The licensee or lessee will also be required to provide the details and cost implication of the emergency event by way of an application to the NUPRC to amend the approved work programme.15
(b) Submission Checklist
A licensee or lessee is required to include, in its application to the NUPRC for approval of an annual work programme and status report, the following information: (i) list of proposed activities and timelines, as well as activities relating to host community development, local content programmes, and manpower development; (ii) work breakdown plan; (iv) estimated costs; (v) requisite regulatory approvals; and (vi) an evaluation of the licensee or lessee's performance in the prior year in the prescribed manner.16
he application will also be accompanied by details of the concession (licence or lease) situation; evidence of payment of statutory fees, rents and royalties; statement of reserves situation or reservoir studies; details of production status and forecast; details of any injunction or court orders affecting the operations; organisational structure and statement of staff disposition; and five-year strategic plan for the development of the licence or lease area.17
In implementing the project, an application submitted for approval of the milestone engineering design, fabrication, construction and other similar activities must include a summary report on the status of the project.18
The Regulations' comprehensive approach for approving work programmes and status reports is commendable, as it ensures (a) a holistic project governance approach which promotes long-term project viability and mitigates risks that could jeopardize the operations of licensees and lessees, (b) the promotion of socio-economic development by mandating licensees and lessees to demonstrate a clear commitment to contributing to the national economy, and (c) accountability for optimal resource management. However, there is no doubt that these measures add administrative bottlenecks. Licensees and lessees in the oil and gas industry (including their service providers) must therefore factor the approval cycles of the NUPRC in project planning and timelines.
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Footnotes
1. See generally, the PIA s. 79(14).
2. Regulation 3(1).
3. Regulation 3(1)(d).
4. Regulation 20.
5. Ibid. Economic Value Added (EVA) is defined in the Regulations as "the assessment of the value created above the required return on invested capital... A positive EVA signifies that the project is expected to generate returns exceeding its cost of capital, thereby adding value." 6 Regulation 3(2).
7. Regulation 3(3). "Return on Investment" measures the profit or loss generated by a project in comparison to the total capital investment. (See regulation 20). The Regulations, however, leave the other finance metrics undefined. Summarily, Net Present Value measures the total value of all future cash flows over the entire life of the project by answering the question of whether the project's future profit is worth more than its initial cost. Internal Rate of Return is a capital budgeting measurement used to determine the profitability of an investment or project over its lifetime based on predicted cashflows. Break-even Analysis indicates the point at which a project's total revenue equals the total costs incurred. Economic Sensitivity Analysis tests how a project's results might change if important variables such as future oil prices, production volume, drilling costs, or interest rates change, in order to determine the project's resilience and impact on the project's overall value. These definitions are generally illustrative and not authoritative.
8. Regulation 4(2).
9. Nigerian Oil and Gas Industry Content Development Act, 2010.
10. Regulation 5(1)-(3).
11 Regulation 5(4).
12. Regulation 5(5)-(6).
13. Regulation 5(7).
14. Regulation 5(8).
15. Regulation 5(9).
16. Regulation 6(1).
17. Regulation 6(2).
18. Regulation 4(1).
The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.
