A Review Of The NERC Order Regarding The Delineation And Operational Requirements For Distribution Companies (DisCos) 2025

1.0 INTRODUCTION

Since its enactment, the Electricity Act (EA) of 2023 caused a significant shift in Nigeria's energy sector (electricity market). The decentralisation of the electricity sector in Nigeria to allow participation at the state levels is one of the key innovations and focus areas of the EA 2023,¹ and being novel, presents operational complications. It is the mandate of the EA 2023 to empower States to generate, transmit, and distribute electricity within their boundaries; by implication, States can establish their own electricity markets and regulatory commissions,² ending the federal monopoly on electricity regulation for intrastate supply. The novelty of this provision is applauded (especially) due to its consistency with Paragraph 14(a) and (b), Part II to the Second Schedule of the 1999 Constitution of the Federal Republic of Nigeria (CFRN) (Concurrent Legislative List)³ – as well as its amendment.⁴ In line with these, section 230 of the EA set the stage for the Nigerian State to take charge of its electricity sector.

Some federating States⁵ had established their own State Electricity Regulatory Commissions (SERCs) and are ready to assume regulatory oversight,⁶ making a transition framework very necessary. The precise execution of the EA's provisions and the attainment of its goals lie in the Nigerian Electricity Regulatory Commission (NERC or the Commission).⁷ Where a uniform demarcation process is absent, there could be delays and disputes over which assets (like substations, transformers, and office buildings) and liabilities (such as debts and employee obligations) should be assigned to each Subsidiary Company (SubCos). Such a lack of clarity can create operational uncertainty, hinder investment planning, and risk service interruptions for millions of electricity consumers.

The Commission in a timely move and compliance with the EA 2023, released the Order on Asset Delineation (the Order)⁸ on 28 March 2025, to establish a framework for unbundling electricity distribution companies (DisCos) into state-focused SubCos. The contents of the Order bearing the delineation are discussed and this piece attempts a brief SWOT analysis.

2.0 KEY ASPECTS OF THE NERC ORDER ON ASSET DELINEATION

2.1 Objectives of the Order

The significance of the clear objectives in interpreting and executing the central aim of the Order lies in their role to provide a structured, transparent, and fair procedural framework that guides the delineation of assets and liabilities of DisCos as regulatory oversight shifts towards state electricity markets. These objectives ensure process clarity, inclusiveness across states, standardised methodology, and clear timelines. Thus, reads as follows:⁹

1. Clarity in Process: The first listed objective of the order is that, "provide further clarity on the process for delineation of assets and liabilities of DisCos as directed in the respective transfer of regulatory oversight orders issued to date."¹⁰ We must note this to be critical, for the reason that, if there is no clarity of process, then the delineation of assets and liabilities of DisCos risks becoming inconsistent and prone to disputes, which can delay implementation and undermine regulatory compliance and investor confidence
2. Inclusiveness Across States: Secondly, the Order envisages the possibility of disparity in transition status of the federating states and then captures the objective to: "facilitate the delineation of the assets and liabilities of all DisCos along state lines irrespective of the transition status of each state, thus ensuring a smoother transition process."¹¹ Had the framework provided by the Order not been inclusive across states, some states may be left with unclear or unresolved asset and liability allocations, causing fragmented transitions, operational disruptions, and legal conflicts that hinder the overall efficiency of the electricity market reforms. A consequence that is capable of distorting the transition and warranting the burdens of other frameworks on different measurement bases.
3. Standardized Methodology: Establish a standard methodology for the delineation of DisCos' assets and liabilities to ensure fairness, equity and transparency."¹² If there is no standardized methodology, then the delineation process could lack fairness and transparency, leading to arbitrary decisions, inequitable allocations, and loss of trust among stakeholders, thereby weakening regulatory oversight and market stability.
4. Clear Timelines: Timelines afford better and consistent pattern for the transition thus, the last strand of objectives show that the Order intends to: "provide clear timelines for the delineation of assets and liabilities of DisCos to enable the state regulators that have taken over regulatory oversight of electricity markets in their respective states."¹³ Delays due to administrative inefficiency or disparity in proactiveness by states will not flourish with this objective met. If there are no clear timelines, then the transfer and regulatory oversight processes may suffer from delays, creating uncertainty for state regulators and market participants, which could stall progress in decentralizing electricity regulation and negatively affect service delivery

These objectives collectively put an orderly, predictable, and equitable obverse amid ongoing reforms. It is pertinent to add that these objectives serve as the lenses from which the assessment of the actual execution of the Order should be made as time goes on.

2.2 Delineation of Assets

For the purposes of delineating assets under the Order; the term asset is definitively categorized into core and non-core assets. Core assets as captured by the Order, means; "critical equipment and infrastructure that DisCos used in delivering electricity to consumers such as transformers, distribution lines, substations, meters, and safety devices like switchgear and circuit breakers."¹⁴ These are essential for efficient, reliable, and safe electricity distribution and directly tied to a DisCo's service delivery and revenue generation. On the other hand, non-core assets mean; "properties and resources owned by a DisCo but are not directly involved in delivering electricity," and examples include; "office buildings, land, non-operational vehicles, warehouses, and IT systems for non-essential functions."¹⁵ While the non-core assets do not contribute to the functionality of the electricity network, the investment usually has financial or strategic value.

On the delineation of the assets, the Order sets principles that should guide the determination of ownership of concerned assets. Vide paragraph 19 of the Order, guidelines are set, giving the type of asset, its description, and guiding principle.

The delineation of assets for the DisCos under the NERC Order follows clear principles based on asset type and their roles in electricity supply and operation:

1. Physical assets such as transformers, substations, and other equipment directly used to supply energy are assigned to the respective SubCos according to their geographic location and economic value. For lines that pass through two or more states, the assignment is prorated based on geographic boundaries, with energy offtake determined by interboundary meters at these state borders.
2. Inventory items including unallocated in-transit and stored assets like spare parts and consumables are allocated based on historical energy consumption figures already used in the Regulatory Asset Value (RAV) assessment. Assets that have been captured in the RAV are distributed to the SubCos accordingly.
3. Operational vehicles such as cars, trucks, and service vehicles used in operations and maintenance are assigned based on their operational location. Any unassigned or unserviceable vehicles are retained as assets of the Holding Company (HoldCo).
4. Information and Communication Technology (ICT) infrastructure, including hardware, software, and communication equipment, remains under the ownership of the HoldCo. The HoldCo provides these services to SubCos through shared service agreements that comply with transfer pricing regulations.
5. The Meter Acquisition Fund (MAF), which comprises funds accrued from customer tariffs for metering, is allocated to the SubCos based on their share of energy as of 31 May 2025, covering all uncommitted monies.
6. Receivables, or amounts owed to DisCos by customers, are split among the SubCos according to the location where the receivables originated, ensuring geographic alignment.
7. Common assets that are jointly used across different departments—such as head office buildings, pool vehicles, cranes, and testing equipment—are retained by the HoldCo. Utilization and associated costs are managed via shared services agreements.
8. Contingent assets, including receivables such as judgment awards, are allocated at the point of crystallization. The HoldCo must seek the approval of NERC to determine the allocation of these contingent assets between the SubCos.

These delineation principles are designed to ensure a fair, transparent, and orderly transition of assets, supporting the decentralization of electricity distribution in Nigeria's changing regulatory landscape while minimizing operational disruptions and legal uncertainties.

2.3 Delineation of Liabilities

Under the Order, liabilities extend beyond just financial debts or payments due. As defined, "liabilities of a DisCo refer to its financial obligations, or responsibilities that the DisCo is required to fulfil."¹⁶ This means liabilities encompass a broader spectrum, arising not only from financial dealings but also from "operational, contractual, and regulatory activities".¹⁷ Thus, liabilities include any duties or commitments financial or otherwise that the DisCo must address in running its operations and complying with applicable regulations. This broader view ensures that all forms of DisCo responsibilities are acknowledged in asset and liability delineation processes.

The delineation of liabilities under the Order is categorized into several types, each described and specific principles prescribed for allocation of the typified liability among the DisCos and their SubCos.¹⁸

1. Market Shortfall: This represents the liability of DisCos to the electricity market for unsettled invoices which are not covered by tariff shortfalls. The liability is assigned among the SubCos based on the historical energy delivered to each state between January and December 2024, ensuring geographic alignment.
2. Payroll-related Liabilities: These liabilities include accrued pensions and other employee benefits such as post-gratuity. They are allocated according to the employee's location, meaning the SubCo where the employee receives benefits will bear the corresponding liabilities, reflecting actual employment distribution.
3. Existing Tax Obligations: Tax liabilities such as property tax, legacy VAT, company income tax, and capital gains tax that have accrued are allocated among the SubCos based on the historical energy delivered to each state within the same January to December 2024 period.
4. Contingent Liabilities: These are potential obligations that may arise if certain future conditions are met. Their allocation will be decided at the time of crystallization. The HoldCo must seek approval from the NERC on its proposed approach for distributing these contingent liabilities among the SubCos.

2.4 Legacy Commitments and Contractual Obligations

The delineation of legacy commitments and contractual obligations under the Order addresses important financial and contractual responsibilities of the DisCos as they transition their operations along state lines.

Regarding loans and advances, being; short-, medium-, and long-term borrowings obtained from the Central Bank of Nigeria (CBN), commercial banks, investors, and others.¹⁹ Notably, some of these loans, which finance critical investments such as metering and network infrastructure, have repayment factored into the DisCos' revenue requirements and end-user tariffs, consistent with the loan terms.²⁰

The liabilities associated with these loans will be allocated to the various SubCos based on the historical energy delivered to each state from January to December 2024. The Commission acknowledges that the repayment and administration of these loan facilities are governed by contractual agreements with CBN and other financial institutions.²¹ Consequently, the detailed mechanism for transferring the repayment obligations and ensuring full repayment will ultimately be determined by the CBN.²²

In relation to legacy contracts tied to bulk energy purchases, after the 2013 privatization, the successor DisCos' Holding Companies entered into Vesting Contracts with the Nigerian Bulk Electricity Trading Plc (NBET). NBET, in turn, engaged in Power Purchase Agreements (PPAs) with generation companies and independent power producers (Gencos/IPPs). These contracts are legally protected under Nigerian law and include clear arbitration procedures even beyond Nigeria's borders to uphold the sanctity of the agreements. As NBET eventually exits the structure, these PPAs are expected to be novated, or formally transferred, to the DisCos, making them obligatory for both HoldCos and their constituent SubCos.²³

The Order firmly maintains that all existing contractual obligations must be respected and honoured, therefore, these responsibilities will be assigned equitably among the SubCos.²⁴ The DisCo minimum energy off-take obligations for 2025 represents a total of 3987 megawatt-hours per hour (MWh/h).²⁵ Furthermore, the Commission insists that upon completion of asset transfer, the HoldCo should not retain any "stranded capacity." This means that the collective energy off-take obligation of a DisCo's SubCos must equal or exceed the DisCo's current minimum off-take obligation as specified in the regulatory framework.²⁶

To operationalize this, each DisCo is required to transfer its total off-take obligation²⁷ to its SubCos proportionally, according to the historical energy delivered to each state between January and December 2024.²⁸ This allocation is calculated by the formula:

Vested Energy (SubCo X) = (Energy Delivered to State X [Jan–Dec 2024] ÷ Energy Delivered to DisCo [Jan–Dec 2024]) × DisCo Offtake Obligation²⁹

In simpler terms, each SubCo receives an energy obligation that corresponds to its share of the DisCo's total energy delivery based on past consumption in its state.

Looking ahead, the Electricity Act 2023 envisages a more evolved stage of the Nigerian Electricity Supply Industry (NESI), where direct bilateral electricity trade between DisCos and GenCos will occur.³⁰ At that point, DisCos will be able to novate PPAs directly to their SubCos. However, since this stage has not yet been reached, the current mechanism for electricity trade between DisCos and their SubCos remains through vesting contracts.³¹ The minimum energy volume vested to each SubCo for this interim arrangement will continue to be calculated using the formula above.³²

In summary, the delineation respects existing financial liabilities and contractual commitments, promotes fairness by allocating obligations based on historical state-level energy delivery, and sets a clear framework for managing legacy arrangements during this complex transition process.

2.5 Mandate of DicCos

The Commission has issued a directive requiring each DisCo to delineate its franchise areas along state boundaries and undertake specific organizational, operational, and reporting measures. The table below sets them out:

The goal of the provisions of the table above is to ensure clear operational segregation of DisCos' networks and functions at the state level, facilitate transparent regulatory oversight, and promote efficient electricity distribution services across the country.

3.0 A SWOT COMMENTARY

Strengths

1. Standardized Methodology
   The Order establishes a uniform framework for asset/liability delineation, reducing arbitrariness through pro-rata allocation based on 2024 state-level energy consumption (Equation 1).³³ This ensures equity in distributing RAV and liabilities.
2. Contractual Continuity
   Existing PPAs and vesting contracts are preserved,³⁴ minimizing disruptions to bulk electricity supply during the transition.
3. Asset Classification Clarity
   Clear definitions of core (transformers, distribution lines) and non-core assets (office buildings, IT systems)³⁵ prevent operational ambiguities. Shared infrastructure, like ICT systems, is retained by HoldCos under service agreements,³⁶ ensuring continuity.
4. Regulatory Alignment
   Directly implements the EA 2023's mandate for state-level electricity markets,³⁷ demonstrating responsiveness to legislative reforms.

Weaknesses

1. Static Data Dependency
   Reliance on 2024 consumption data for RAV allocation³⁸ risks inequities if demographic or economic shifts alter future energy demand. No mechanism exists in the Order for dynamic adjustments.
2. Implementation Hurdles
   Mandating interstate boundary meters³⁹ faces logistical challenges, as DisCos lack existing infrastructure for granular grid segmentation.⁴⁰ Delays here could stall transitions.
3. Contingent Liability Ambiguities
   Deferring decisions on contingent liabilities (e.g., lawsuits) until "crystallization"⁴¹ creates financial uncertainty for SubCos, potentially deterring investors.
4. Workforce Gaps
   While employees are allocated by location,⁴² the Order lacks provisions for retraining or addressing redundancies during restructuring.

Opportunities

1. State-Level Regulatory Innovation
   The framework enables SubCos to tailor operations to local needs, fostering experimentation in tariff design and service delivery under state commissions.⁴³
2. Investment Clarity
   Transparent asset/liability delineation⁴⁴ could attract private capital by reducing perceived regulatory risks for SubCos.
3. Market Evolution
   The interim vesting contract mechanism⁴⁵ provides a bridge to future bilateral GenCo-SubCo agreements, aligning with the EA's vision for decentralized markets.
4. Sector-Wide Precedent
   The methodology could guide asset unbundling in other infrastructure sectors (e.g., gas) facing similar reforms.

Threats

1. Transition Delays
   Prolonged metering infrastructure deployment⁴⁶ could derail timelines, delaying state-level regulatory takeovers and wearing away stakeholder confidence.
2. SubCo Financial Fragility
   Possibility that states like Yola (with smaller 113 MWh/h off-take obligation)⁴⁷ may struggle with proportional debt allocations, risking operational viability and service quality.
3. Legal Challenges
   Deferred contingent liabilities⁴⁸ could lead to protracted disputes between HoldCos and SubCos, especially if liabilities disproportionately affect specific states.
4. HoldCo Inefficiencies
   Retaining non-core assets without a divestment timeline⁴⁹ risks creating underutilized portfolios, draining HoldCo resources and complicating governance.

4.0 CONCLUSION

The Order provides a structurally sound foundation for Nigeria's power sector transition as engineered by sections 230 (4) and (5) of the EA but requires complementary policies to address data rigidity, implementation bottlenecks, and financial risks. Proactive measures which include phased metering rollouts and dynamic RAV adjustments, could amplify its strengths while mitigating weaknesses.

Footnotes

1. Gabriel Onojason, Ngozi Ole and Lynda Ezike, 'Electricity Act 2023: A New Dawn for Nigeria's Power Sector' (Lexology, 13 June 2024) https://www.lexology.com/library/detail.aspx?g=7ed74ca2-ccba-47fd-9786-37efa8565357 accessed 17 June 2025.

2. EA, section 2(2).

3. This empowers the House of Assembly to make laws for the State with respect to electricity and the establishment in that State of electric power stations and on the generation, transmission, and distribution of electricity to areas not covered by a national grid system within that State.

4. Which deleted the proviso – "areas not covered by a national grid system within that State."

5. Including; Ekiti, Enugu, Imo, Kogi, Ondo, Oyo, and Lagos.

6. Nigerian Electricity Regulatory Commission, 'NERC Holds Meeting With State Electricity Regulators To Discuss Milestones, Prospects' (NERC, no date) https://nerc.gov.ng/media/nerc-holds-meeting-with-state-electricity-regulators-to-discuss-milestones-prospects/ accessed 24 July 2025.

7. EA, sections 33 - 62.

8. ORDER NO: NERC/2025/028.

9. Paragraph 12 of the Order.

10. Ibid, sub-para (a).

11. Ibid, sub-para (b).

12. Ibid, sub-para (c).

13. Ibid, sub-para (d).

14. Paragraph 13 of the Order.

15. Ibid.

16. Paragraph 20 of the Order.

17. Ibid.

18. Paragraph 21 of the Order.

19. Paragraph 22 of the Order.

20. Ibid.

21. Paragraph 23 of the Order.

22. Ibid.

23. Paragraph 24 of the Order.

24. Paragraph 25 of the Order.

25. DisCos have specified minimum energy offtake obligations measured in megawatt-hours per hour (MWh/h). These obligations for each DisCo are as follows: Abula is required to offtake 611 MWh/h, Benin 325 MWh/h, Eko 513 MWh/h, Enugu 310 MWh/h, Ibadan 478 MWh/h, Ikeja 603 MWh/h, Port Harcourt 283 MWh/h, Jos 225 MWh/h, Kaduna 258 MWh/h, Kano 268 MWh/h, and Yola 113 MWh/h. When combined, the total minimum offtake obligation across all these DisCos amounts to 3,987 MWh/h

26. Paragraph 26 of the Order.

27. Paragraph 27 of the Order.

28. Ibid.

29. The amount of energy to be allocated or assigned (vested) to a specific subsidiary company (SubCo X) is determined by calculating the proportion of energy that was historically delivered to the state where that SubCo operates, relative to the total energy delivered by the entire Distribution Company (DisCo) during the period from January to December 2024. This proportion is then multiplied by the overall energy off-take obligation of the DisCo.

30. Paragraph 28 of the Order.

31. Ibid.

32. Ibid.

33. Paragraphs 17-18 of the Order.

34. Paragraph 24-25 of the Order.

35. Paragraph 13-14 of the Order.

36. Paragraph 19 (d) of the Order.

37. Paragraph 3 of the Order.

38. Paragraph 18 of the Order.

39. Paragraph 19(a)(ii) of the Order.

40. Noelle Okwedy, 'How Do Mini-Grids Provide Electricity in Cities?' (Stears, 4 October 2022) https://www.stears.co/article/how-do-mini-grids-provide-electricity-in-cities/ accessed 29 July 2025.

41. Paragraph 21(d) of the Order. See also 19(i).

42. Paragraph 19(h) of the Order.

43. Paragraph 5 of the Order.

44. Paragraph 12 of the Order.

45. Paragraph 28 of the Order.

46. Paragraph 19(a)(ii) of the Order.

47. Table 1 to paragraph 25 of the Order.

48. Paragraph 21(d) of the Order.

49. Paragraph 19(g) of the Order.

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