Navigating Divestment In Nigeria's Oil And Gas Sector: Regulatory Framework, Implications, And Future Prospects

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Divestment also referred to as ‘divestiture' is the process wherein a company sells a portion of its assets, often to enhance overall company value and achieve greater operational efficiency.
Nigeria Energy and Natural Resources
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Divestment also referred to as 'divestiture' is the process wherein a company sells a portion of its assets, often to enhance overall company value and achieve greater operational efficiency. This strategic plot is frequently utilized by companies to offload peripheral assets, enabling their management teams to refocus on their core business with increased precision.1 Companies evaluate the degree of operational risk associated with investments, identifying those that fall short of the designated average internal rate of return, and they can decide to move their operational portfolio to newer and more profitable operations. The initial wave of divestments in Nigeria's oil and gas sector commenced in 2010, spurred by challenges such as oil theft and militancy, alongside governmental efforts to promote local ownership of upstream assets through its indigenization policies.2

However, contemporary divestment endeavours are propelled by various factors, including ageing infrastructure, inadequate investment, vandalism, and challenging operating conditions. Additionally, there is a pressing need to align with the shift towards green energy and climate action initiatives, driven by corporate commitments to emission reduction and the ultimate goal of achieving net zero emissions by 2050. In recent times, International Oil Companies (IOCs) have divested interests in upstream petroleum assets, particularly Licenses and Leases in the onshore and shallow water terrains of Nigeria. According to a Wood Mackenzie report3, divestments in Nigeria since 2010 have totalled $21 billion, with a pending $1.2 billion ExxonMobil sale. Some of the notable divestments in Nigeria in recent years are:

  • Shell's divestment of its operated Joint Venture (JV) Licences held by its Nigerian onshore subsidiary, the Shell Petroleum Development Company (SPDC) to Renaissance, a consortium of five companies comprising four Exploration and Production (E & P) companies based in Nigeria and an international energy group. This includes a 30% interest in its 19 Oil Mining Leases (OMLs). Completion of this transaction is subject to approvals by the Federal Government of Nigeria (FGN).4
  • Mobil Producing Nigeria Limited's (MPNU) divestment of its entire share capital from Exxon Mobil Corporation to Seplat Energy.5
  • Most recently, TotalEnergies indicated interest in divesting its 10% stake in its onshore operations with SPDC to indigenous buyers following SPDC's divestiture in January.6
  • Subject to regulatory and contractual approvals, Equinor Nigeria Energy Company's (ENEC) divestment of its 53.85% interests in OML 128, and its 20.1% interests in the Agbami oil field operated by Chevron to Chappel Energies, an indigenous firm.7

Setting the Ground Rules – Regulatory Requirements for Divestments in Nigeria

The Petroleum Industry Act 2021 (PIA) empowers the Nigerian Upstream Regulatory Commission (the Commission) to regulate the technical, operational and commercial activities in Nigeria's upstream petroleum operations.8 In exercising its authority, the Commission will undertake a comprehensive Due Diligence (DD) investigation before approving any upstream asset divestment or transfer. This will involve issuing a 'Request for Information' to all relevant parties. The aim is to ensure, among other considerations, that the 'proposed assignees' or 'successor entities' possess adequate technical expertise, experience, and financial capability to effectively manage the assets and fulfill the commitments outlined in the License or Lease. Additionally, the investigation will address issues such as the resolution of cost-related concerns regarding overlapping fields, the settlement of legacy debts, and the establishment of a well-structured social inclusion and decarbonization plan by the acquiring entity. Furthermore, evidence of the capability to manage all residual aspects of the sale will be scrutinized. It is worthy of note that the Assignor is to bear the costs of the DD exercise as well as the transaction fee.9 Below are the regulatory requirements that must be considered before an asset divestment deal is approved10:

  • Regulatory Consents: The Act11 requires a Licensee or Lessee to obtain the prior written consent of the Minister and the Commission in the event of any assignment of legal title or ownership interest, whether direct or indirect, in the License or Lease. This includes transfers, changes of control, novation, or the transfer of any rights, powers, or interests associated with the License or Lease. A shareholder of an Incorporated Join Venture (IJV) shall equally not sell or transfer its shares without the prior written consent of the Minister, such consent to be granted on the recommendation of the Commission. The Minister may grant consent for the assignment of a License or Lease on the grounds that the proposed transferee:
  1. Is a company incorporated in Nigeria;
  2. Is of good reputation and standing;
  3. Has sufficient technical knowledge, experience and financial resources to effectively carry out all the responsibilities of a Licensee or Lessee under the License or Lease; also;
  4. That the assignment would be of beneficial effect to Nigeria; and
  5. Is in compliance with the Federal Competition and Consumer Protection Act.12

The Licensee or Lessee wishing to transfer, assign or otherwise novate its interest must also make an application to the Commission for the approval of such, and the Commission is required to act on such application within 60 days. The consent of the Minister shall be deemed to be granted where the Minister fails to act on the recommendation by the Commission within 60 days of such recommendation.13 The consent is however granted on the condition that the Assignor pays the attached fees or bonus (usually ranging from 5% to 10% of the total value of the transaction) within 90 days of such grant or otherwise have the consent vitiated.

On confirmation of payment, the Commission shall grant the Assignor 'the Consent format document' as conclusive evidence that the Assignee is the legal title holder to the interest assigned in the Licence or Lease. The parties to the assignment have a duty to within 14 days of the grant of consent disclose the details of the transaction to the Federal Inland Revenue Service (FIRS), while the Commission publishes the same in the Federal Government Gazette.14 It is worthy of note that an application for the Minister's consent must be accompanied by the consent of the other parties to the assignment or joint interests in the License or Lease as well as their consent to the transfer of operatorship (where applicable). A Licensee or Lessee in a JV with NNPC must ensure that NNPC's pre-emptive rights are covered in the sale amongst other things.

  • Host Community Trust Fund Requirements: The Act15 mandates Licensees and Lessees carrying out upstream petroleum operations (Settlors) to incorporate Host Communities Development Trust (HCDT) for the benefit of the host communities where the Settlor is responsible, after undertaking a needs assessment that will form the basis of the Community Development Plan. The needs assessment is done preparatory to the establishment of the fund. The legal and equitable interest, rights and obligations of a divesting entity with regards to the Host Community Development Plan (HCDP) and HCDT are deemed transferred to the new entrants to the asset (Licence or Lease).16 Before approving this transfer, the Commission shall assess the status of the Assignor's HCDTF as well as ensure that the successor entity's social inclusion programme complies with the Act. The Assignee is required to make an annual contribution to each HCDTF of an amount equal to 3% of its actual annual operating expenditure from the preceding year of the upstream operations that impact the host communities. An area which hosts the Licensee or Lessee's facilities used in upstream petroleum operations forms part of its host community.

The needs assessment of each host community shall be drawn from a social, environmental and economic perspective after engagement with the affected communities (women, youth and community leaders) following which Settlor is to develop a strategy to address them. Settlors' Host Community Development Plan must specify the projects and timelines for completing the projects to meet the community needs assessment. The Plan is also required to conform with the Nigerian content requirements provided in the Nigerian Oil and Gas Content Development Act 2010 as well as provide for an ongoing review and report to the Commission, and it shall not be amended without the prior consent of the Commission. The funds of the HCDT are tax-exempt.17 Failure of Settlor to incorporate an HCTF in its area of operation attracts an administrative penalty of $2,500 per day after a 45-day notice period issued by the Commission or a revocation of License or Lease by the Minister.18

  • Environmental Obligations: As a signatory to the 2015 Paris Agreement, Nigeria is obligated to promote initiatives that effectively reduce greenhouse gas emissions, thereby facilitating the attainment of the country's Nationally Determined Contributions (NDCs). The PIA thus provides robustly for environmental management which the new entrants or successor entities must commit to. In this scenario, the Licensee or Lessee, referred to as the Assignor, is required to possess an Environmental Management Plan (EMP).19 This plan will serve as the foundation for environmental considerations during project execution. The Commission will approve the EMP if it is convinced that the Licensee or Lessee has the capacity to mitigate and manage environmental impacts across all project phases, from inception to decommissioning. A condition for the approval of an EMP is the payment of the prescribed financial contribution to an Environmental Remediation Fund (ERF) established by the Commission or the Authority to be applied to the management of the environmental impact of Licensee or Lessees operations.20 The EMP shall cover matters ranging from methane emissions management, greenhouse gas (GHG) management, waste management, abandonment and decommissioning of facilities, oil spill management, environmental audits and reviews, etc.

At the point of divestment, the Assignor is required to conduct an Environmental Evaluation Studies (EES) and document the state of the environment at the time of the divestment which shall be approved by the Commission Chief Executive before finalising any divestment agreements.21 The new entrants may remodify and resubmit a new EMP in line with the Act.22 The Act also mandates Licensees or Lessees who produce flare gas to submit a Flare Elimination and Monetisation Plan for the approval of the Commission. The plan shall cover gas assets overview, gas reserves and commitment status, compliance with domestic gas delivery obligations, gas monetisation projects and development strategies, and timelines amongst others, all to be reflected in the Licensee or Lessees work program.23

  • Decommissioning and Abandonment Obligations: Licensees and Lessees are required to establish a Decommissioning and Abandonment (D & A) programme in accordance with good international petroleum industry practice. The Commission will grant approval for the D & A, contingent upon compliance with pertinent environmental, technical, and commercial regulations and standards.24 The Commission may recall a Licensee or Lessee to carry out an obligation with respect to its D & A commitments under its License or Lease after the divestment or transfer of its interest or equity. Upon obtaining approval from the Commission for the divestiture, the successor entity shall inherit all corresponding obligations, relieving the Licensee or Lessee of any further responsibilities.25 Each Licensee or Lessee is required to set up and maintain a D & A Fund to be funded based on the D & A Plan approved by the Commission.
  • Other Obligations: A Licensee or Lessee who confirms that a petroleum reservoir in a geological trap in its Licence or Lease straddles one or more adjoining licenses and leases shall promptly notify the Commission of such discovery. Subsequently, a comprehensive report about each straddling petroleum reservoir must be submitted to the Commission. Additionally, notice must be given to the Licensee or Lessee of the adjoining License or Lease. In such circumstances, the Commission will direct parties to enter into a unitization agreement for the joint development of the reservoir. Following this, the Licensee or Lessees shall submit a Field Development Plan for the straddled fields under the unitized operations to be approved by the Commission.26 Successor entities taking on divested assets will also take on the titles to the working interests under the unitization operations and undertake all obligations under the unitization agreements of the divesting Licensee or Lessee. It is also worthy of note that the title to any data and its interpretation relating to upstream operations is vested in the Federal Government of Nigeria and administered by the Commission.27 Consequently, the Licensee or Lessee divesting its interests must return all geological, geophysical, and geotechnical data obtained during its operations to the Commission prior to divestment approval. Prior to granting approval for the divestment, the Commission must ensure that the divesting party has resolved all labour union matters stemming from the divestment. This includes confirming that relevant parties have signed a "Certificate of Settlement."

Positive Implications of the Divestments

Indigenous Exploration and Production (E&P) companies presently contribute 30% of Nigeria's crude oil and 20% of its gas production, along with 40% of crude oil and 32% of gas to the country's reserves.28 The divestments offer a remarkable chance for local firms to lead in onshore and shallow water exploration and foster the Nigerian onshore market. Consequently, this creates avenues for boosting local content, as there's a higher probability of utilizing local talent. Such initiatives empower Nigerians to advance in oil and gas technology and ascend to prominent positions within the global oil and gas sector.

The divestitures also present an opportunity for indigenous firms to attain global recognition. For example, Seplat Energy Plc, listed on both the Nigerian Stock Exchange (NGX) and the London Stock Exchange, has experienced record-high share prices in 2024, with its market valuation surpassing $1 billion in recent periods.29 In addition to former President Muhammadu Buhari's declaration of 2020-2030 as 'the Decade of Gas', President Bola Tinubu has underscored Nigeria's transition to natural gas as a key priority. This initiative presents an opening for indigenous E&P companies acquiring divested assets to concentrate on expanding gas reserves and production. Recent research indicates a notable rise in their contribution to gas production.30


Divestments within Nigeria's oil and gas sector are expected to persist, particularly in light of the prevailing operational and regulatory environment. However, there is concern about how indigenous firms can secure sufficient financing during the energy transition era to acquire and invest in the challenging portfolio of swampy assets that are being divested. As an illustration, Shell's divested Joint Venture (JV) portfolio holds a potential of up to 4 billion barrels of oil equivalent (boe), with a net share of 30%. However, only approximately 20% of this potential is deemed commercial, primarily due to factors such as insufficient investment, crude theft, security concerns, and constraints in the gas market.31 The extent to which the resource base of the portfolio can be commercialized and the ability of new owners to adhere to their field development plans, environmental management plans, work programs, as well as fiscal and other commitments will hinge upon the availability of funding. While Shell has consented to lend the consortium $1.2 billion to address funding needs, along with offering an additional $1.3 billion to finance its stake in the Joint Venture (JV) with NNPC and other stakeholders, covering supply commitments to the Nigeria Liquid Natural Gas (NLNG) plant as well as certain decommissioning and restoration costs, the challenge remains significant for the acquiring consortium and transferees in accessing loans from international banks, lenders, and foreign exchange, which will likely pose obstacles in managing these assets effectively.32 Reports33 indicate that divestments in Nigeria over the last decade have resulted in adverse outcomes for communities and the environment. Local companies acquiring assets in the Niger Delta have been slow to respond to oil spills. Moreover, there has been a notable surge in gas flaring following the takeover, as transferees typically make fewer environmental commitments and set lower reporting standards. However, through collaborative efforts among asset managers, indigenous companies, regional banks (tasked with embedding climate standards into tangible transactions), private equity firms, and civil society organizations, the potential stewardship risks associated with these divestments can be mitigated.


1. accessed 12th March 2024.

2. accessed 12th March 2024.

3. accessed 14th March 2024.

4. accessed 12th March 2024.

5. acquisition-of-mobil-nigeria-from-exxonmobil.html?tztc=1 accessed 12th March 2024.

6.,following%20Shell's%20divestiture%20in%20January. Accessed 12th March 2024.

7. accessed 13th March 2024.

8. PIA 2021, s. 6.

9. The Nigerian Upstream Petroleum Assignment of Interest Regulations 2023 (Draft), s. 10 (f).

10. accessed 14th March 24.

11. Ibid, s. 95(1)(2) (3) &(13).

12. Ibid, s. 95(11).

13. Ibid, (7).

14. Ibid, n. 4.

15. Ibid s. 235.

16. Ibid, s. 237.

17. Ibid, s. 256.

18. The Nigerian Upstream Petroleum Host Communities Development Regulations, 2022, s. 9.

19. Contents of the EMP shall be as provided in the Upstream Environmental Guidelines and Standards for the Petroleum Industry in Nigeria (UEGASPIN).

20. Ibid, ss. 102 and 103.

21. The Upstream Petroleum Environmental Regulations 2022, s. 8.

22. Ibid, s. 34.

23. Gas Flaring, Venting & Methane Emissions (Prevention of Waste and Pollution) Regulations 2022, s. 14.

24. PIA 2021, s. 232 (8).

25. Ibid, s. 232 (13).

26. Nigerian Upstream Petroleum Unitisation Regulations 2023, s. 6.

27. PIA 2021, s. 68(1).

28.,following%20Shell's%20divestiture%20in%20January accessed 12th March 2024.

29. accessed 12th March 2024.

30. accessed 12th March 2024.

31. accessed 14th March 2024.

32.,following%20Shell's%20divestiture%20in%20January. Accessed 12th March 2024.

33. accessed 14th March 2024.

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.

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