International Oil and Gas Transactions and the Emerging Trend of Upstream Divestments and Acquisitions in Nigeria.

By Tade Oyewunmi, Diran Ajayi and Iyanuoluwa Ajayi

Abstract

The recent divestments of exploration and production (E&P) interests or leases in the onshore areas of the Nigerian Niger Delta by some international oil corporations (IOCs) that operated these upstream assets for decades under a joint venture with the Nigerian National Petroleum Corporation reflects a preference to focus more on deepwater prospects and possibly due to other international energy industry developments. In the same vein, a growing number of Nigerian-owned independents show the required capacity to acquire and operate these onshore leases, thus, leading to new upstream consortiums and Joint Venture arrangements. The enactment of the Petroleum Industry Act 2021, its implications on leases and licenses granted under the previous legal framework, and the issuance of the 2021 Guidelines and Procedures for Obtaining the Minister’s Consent to the Assignment of Interests adds to the interesting dynamics of efficiently negotiating and completing the divestment and acquisition processes. Consequently, this paper highlights the legal framework governing the ownership of upstream E&P interests in Nigeria from an international petroleum transactions perspective and the assignment of such interests. Such a transfer of upstream interests could arise due to the change in control or ownership of equity in the company holding the lease or interests. It is essential to understand (i) the nature of these E&P assets, and (ii) the conditions attributable to owning such upstream petroleum assets following the divestments and acquisition process. Other noted issues include environmental concerns such as future decommissioning and carbon emissions management obligations for the acquiring party.

I. Introduction

Corporations engaged in international upstream petroleum exploration and production (E&P) operations can be broadly categorized into (i) those fully or mostly owned by national governments, and (ii) privately owned companies.¹ The government-owned group comprises the national oil companies (NOCs)² that typically have a statutory mandate from their home

* Dr. Oyewunmi is an energy and natural resources law scholar & advisor. He has held several academic positions in the US and internationally. E-mail info@tadeoyewunmi.com. Website https://www.tadeoyewunmi.com. LL.B (UI), LL.M (Aberdeen), LLD (UEF Law School).

** Managing Partner, Adesokan & Ajayi LP Lagos, Nigeria. E-mail: diran.ajayi@aalp-law.com. Website: www.aalp-law.com.

^*** Associate, Adesokan & Ajayi LP Lagos, Nigeria. E-mail: iyanuoluwa.ajayi@aalp-law.com.

1 See the International Energy Agency (IEA), The Oil and Gas Industry in Energy Transitions: World Energy Outlook special report, (IEA Publications, 2020) pp. 16-20 at https://iea.blob.core.windows.net/assets/4315f4ed- 5cb2-4264-b0ee-2054fd34c118/The_Oil_and_Gas_Industry_in_Energy_Transitions.pdf.

2 For instance, Russia’s Rosneft is considered an NOC. The NOCs in the Middle East include Saudi Aramco,

National Iranian Oil Company, and Qatar Petroleum; NOCs in Latin America include Petrobras, PEMEX, Petróleos de Venezuela, S.A. (PDVSA), while NOCs in Africa include the Nigerian National Petroleum Corporation (NNPC) (now privatised and incorporated as the Nigerian National Petroleum Company Limited), Sonatrach, and Sonangol). See Tade Oyewunmi, ‘International Petroleum Transactions and the Development of Gas-to-Power Markets in West Africa’ OGEL Energy Law Journal 1 (2019) at www.ogel.org/article.asp?key=3805; Owen Anderson et al., (eds), International Petroleum Law and Transactions (Rocky Mountain Mineral Law Foundation, 2020) at pp. 26 – 36.

government to develop national resources with a defined role and focus on domestic upstream production assets. In addition, there are international NOCs (INOCs)³ that typically have both domestic and significant international operations. The private corporations comprise the “Majors” or international oil companies (IOCs),⁴ and the independents. The “Independents” are either fully integrated companies, like the Majors but much smaller in size, or they could be independent upstream operators that farm-in into or acquire E&P assets that the Majors, INOCs, or NOCs are not interested in, whether in the shale plays of North America or mature petroleum areas in the UK, Africa, or the Middle East. Such E&P assets commonly operated by independent operators could be medium-sized declining fields, frontier areas in mature petroleum jurisdictions like Nigeria, or what is often referred to as marginal fields.⁵

Over the past ten years, there has been a growing trend in divestments by IOCs operating Nigeria’s onshore E&P assets, followed by acquisitions made by an increasing number of Nigerian independents.⁶ For instance, in July 2024, the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) announced its approval of upstream divestment deals by Eni and Equinor and the acquisition of the respective producing assets by Nigerian independents, Oando and Chappal Energies.⁷ Similarly, Shell announced its intention to sell its Nigerian onshore subsidiary, the Shell Petroleum Development Company of Nigeria Limited (SPDC) which holds all its onshore and shallow water JV interests and Oil Mining Leases (OMLs) to Renaissance Ltd., another Nigerian Independent. ExxonMobil’s divestment of some of its Nigerian upstream assets and acquisition by Nigerian independent, Seplat Energy Plc, has reached an advanced stage in the approval process.⁸ These complex transactions require

33 The INOCs are ideally like the NOCs in governance and ownership but have large upstream investments outside their home country, usually in partnership with host NOCs or private companies. For example, Equinor, the China National Petroleum Corporation (CNPC), Gazprom, Sinopec, the China National Offshore Oil Corporation (CNOOC), Petronas, India’s Oil and Natural Gas Corporation (ONGC), and Thailand’s PTTEP.

4 Reference to the “Majors” typically comprises the following seven IOCs- BP, Chevron, ExxonMobil, Shell, Total, ConocoPhillips, and Eni.

5 For a discussion of what assets are considered Marginal Fields see Elimma C. Ezeani and Chinwe Nwuke, ‘Local Content and the Marginal Fields Programme: Challenges for Indigenous Participation in the Nigerian Oil Industry’

OGEL Energy Journal 1 (2017) at www.ogel.org/article.asp?key=3671; Waniss Otman, ‘Developing the Libyan Marginal Fields: Opportunities and Risks’ OGEL Energy Journal 1 (2006) at www.ogel.org/article.asp?key=2080; Jerome Okoro and Peter Chukwuma Obutte, ‘Mergers and Acquisition as a Tool for Marginal Field Development in Nigeria OGEL Energy Journal 4 (2018) at www.ogel.org/article.asp?key=3775. See also the Nigerian Marginal Fields Operations (Fiscal Regime) Regulations 2005; and the Department of Petroleum Resources, Guidelines for the Award and Operations of Marginal Fields in Nigeria, 2020 at https://www.nuprc.gov.ng/wp-content/uploads/2020/08/Guidelines-for-the- Award-and-Operations-of-Marginal-Fields-in-Nigeria.pdf.

6 Gail Anderson, Shell to divest its entire Nigeria joint venture portfolio, (Wood Mackenzie, 16 August 2021) at

https://www.woodmac.com/news/opinion/shell-to-divest-its-entire-nigeria-joint-venture-portfolio/ (accessed 25 August 2024); Africa Oil + Gas Report, NNPC to Hold 70% of the JV as the ExxonMobil/Seplat Transaction Comes to a Close, at https://africaoilgasreport.com/2024/05/farm-in-farm-out/nnpc-to-hold-70-of-the-jv-as-the- exxonmobil-seplat-transaction-comes-to-a-close/?mc_cid=8be%E2%80%A6 (accessed 25 August 2024); SPDC, Shell sells stakes in Nigerian oil leases, (01 December 2011) at https://www.shell.com.ng/media/2011-media- releases/oil-leases-sales.html (accessed 25 August 2024); SPDC, Shell agrees to sell Nigerian onshore subsidiary, (15 January 2024) at https://www.shell.com/news-and-insights/newsroom/news-and-media-releases/2024/shell- agrees-to-sell-nigerian-onshore-subsidiary-spdc.html (accessed 25 August 2024); Petlong Dakhling, Shell to Finalize $2.4bn Nigeria Asset Sale by June, (African Energy Council, April 30, 2024) https://africanenergycouncil.org/shell-to-finalize-2-4bn-nigeria-asset-sale-by-june/ (accessed 29 August 2024).

7 See Charlie Mitchell, Nigeria oil regulator approves Eni, Equinor divestment deals, (S&P Global, 04 July 2024)

at https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/oil/070424-nigeria-oil- regulator-approves-eni-equinor-divestment-deals (accessed 29 August 2024).

8 Ibid.

parties to conduct comprehensive due diligence exercises to gather material information for determining the terms and conditions upon which the acquisition will be made, as well as to examine the scope of the property rights and interests in the underlying assets and any relevant legal or equitable encumbrances. The due diligence process would typically involve an analysis of (a) any joint venture (JV) arrangements and other material contracts, oil and gas titles, and associated assets relevant to the transaction; and (b) the legislative framework surrounding the key areas that may contribute to project risk assessments and valuations.⁹ In Nigeria, all such transactions are subject to pre-authorizations and other regulatory approvals from both the Nigerian Upstream Regulatory Commission and the Minister for Petroleum Resources.¹⁰

For a better understanding of the property rights, interests, and assets being transferred by the divesting party and acquired by the buyer, it is useful to expound on how these assets were created in the first place and the legal framework under which they were being operated. The international oil and gas industry emerged in the 1900s as US and European companies acquired petroleum exploration and production rights in countries such as Saudi Arabia, Iraq, Venezuela, and Nigeria.¹¹ Outside of the US,¹² it is typical for the ownership and property rights in all mineral resources, including petroleum, within the relevant land territory to be vested in the State or Host Government – be it a national or subnational government. In Nigeria, such rights are exclusively vested in the federal government. Thus, leases, concessions, or rights to enter a portion of the land and take minerals or petroleum are granted by the government according to the relevant constitutional or statutory provisions. For instance, following an exploration licence to prospect for oil throughout Nigeria in November 1938, the first commercial oil and gas field was discovered in 1956 by Shell D’Arcy of the Royal Dutch/Shell Group.¹³ This initial form of ‘old concession’ or E&P licence granted absolute control and ownership of land and hydrocarbons within vast areas of the state’s territory to IOCs who bear all attendant risks and rewards. In this scenario, the host government has little

9 Michael Brady and Regina Yap, Legal due diligence: oil and gas, Practical Law ANZ Practice Note w-024- 5412; Practical Law Corporate, Legal due diligence: asset purchases, Practical Law ANZ Checklist w-005-9126. 10 As of 27 October 2024, of all the listed transactions, regulatory consents have been granted for the following transactions: NAOC – Oando, Equinor – Chappal, and Total Energies – Chappal, Mobil – Seplat. The regulator declined to consent to the Shell – Renaissance transaction.

11 Companies like Standard Oil which eventually evolved into the likes of Exxon Mobil, Texaco, and Chevron,

Royal Dutch Shell, Anglo-Persian Oil Company (now BP), and Compagnie Française des Pétroles (now TotalEnergies) comprised the early international oil and gas industry. See the Library of Congress, Oil and Gas Industry: A Research Guide, at https://guides.loc.gov/oil-and-gas-industry/history (accessed 02 March 2024).

12 In the US, most oil and gas resources are situated within beneath lands owned by private individuals and

therefore leasing is mostly between landowners and private E&P companies. The US federal and state governments own just about 30 percent of all mineral rights. See John Lowe, Oil and Gas Law in a Nutshell (Nutshells) (p. 1). West Academic Publishing. Kindle Edition; MK Woodward, ‘Ownership of Interests in Oil and Gas’ (1965) 26(3) Ohio State Law Journal 353-369; Bruce M. Kramer and Owen Anderson, ‘The Rule of Capture

– An Oil and Gas Perspective’ (2005) 35(4) Environmental Law 899-954.

13 See the History of Shell in Nigeria at < https://www.shell.com.ng/about-us/shell-nigeria-history.html> (accessed 02 March 2024). The name changed to Shell-BP Petroleum Development Company of Nigeria Limited in April 1956. The first shipment of oil from Nigeria was in February 1958. The first participation agreement relating to the Shell concessions with the Federal Government of Nigeria (FGN) was in April 1973. Later, the FGN acquired 35% shares in the Oil Companies in April 1974 leading to a Second Participation Agreement with Shell. In July 1979 the FGN, through the Nigerian National Petroleum Corporation (NNPC), increased its equity in upstream concessions to 55% leading to a Third Participation Agreement. The FGN/NNPC equity was increased to 60% in August 1979, thus a Fourth Participation Agreement and BP’s shareholding was nationalized creating an equity structure of 80% and 20% in NNPC and Shell Joint Ventures (NNPC/Shell JV) which are operated by Shell’s subsidiary in Nigeria i.e. Shell Petroleum Development Company of Nigeria Limited (SPDC).

or no managerial or commercial rights and interests relating to the petroleum resources in situ apart from receiving royalties or rents.

Modern concessions, licenses, or leases evolved following the formation of the Organization of the Petroleum Exporting Countries (OPEC) in 1960, and host governments began forming NOCs to proactively participate and acquire commercial interests in E&P assets.¹⁴ Consequently, NOCs like the Nigerian National Petroleum Corporation (NNPC) were created, thus, entering into JV and participation agreements with the IOCs holding the E&P assets or leases.¹⁵ Examples of such unincorporated JVs include the NNPC and ExxonMobil JV, the NNPC and Chevron JV, and the NNPC and Total E&P Nigeria Limited JV. For several decades, the NNPC and Shell-operated JV (comprising NNPC – 55%, Shell – 30%, Elf – 10%, and Agip – 5%) accounted for more than 40% of Nigeria’s total oil production from about eighty fields.¹⁶ Some of the key issues arising from the flurry of divestments and acquisitions are- what legal framework governs ownership of the E&P assets? What is the nature of these interests and conditions attributable to owning the interests following the divestments and acquisition process? What are the environmental considerations such as future decommissioning and carbon emissions management obligations for the acquiring party? This article will discuss these issues as applicable under current Nigerian oil and gas law and contractual frameworks governing the ownership, divestments, and acquisition of the highlighted E&P interests and assets.

II. International Oil Companies and Nigerian Upstream Concessions

Upstream petroleum operations, including developing new fields in existing licenses or leases, are risky, capital-intensive, and complex processes. Hence, companies and their NOC partners typically adopt commercial structures such as unincorporated JVs in conjunction with a Joint Operating Agreement (JOA) to define the allocation of equity ownership interests, spread the risk and reward, and encourage technical and operational collaboration.¹⁷ Among other things, the arrangements provide for the rights and obligations of the operator who will operate the field once production starts, as well as sole risk operations by non-operating parties, and conditions for assigning interests to third parties. In reality, the influence of the more technically savvy or financially buoyant IOCs and Independents is often greater than their equity interests. For example, according to the IEA, the IOCs hold stakes in fields that produce over 10 million barrels per day (mb/d) of crude oil that they own.¹⁸ Around 40% of oil production that is owned by Independents comes from fields in which one of the Majors holds

14 Tade Oyewunmi, Regulating Gas Supply to Power Markets: Transnational Approaches to Competitiveness and Security of Supply (Kluwer Law International, 2018) 323 at 16 – 18; Luis E. Cuervo, ‘OPEC: From Myth to Reality’, (March 2008) 30(2) Houston Journal of International Law 433-615.

15 The Nigerian Petroleum Act of 1969 established the Oil Prospecting License (OPL) and the Oil Mining Lease

(OML), while the NNPC Act was enacted. The NNPC itself was originally a merger between the Ministry and the Nigerian National Oil Corporation, which was created in 1971.

16 Oyewunmi (n2).

17 See Oyewunmi (n2) on International Petroleum Transactions; Anderson et al., (n2) at 294-344; Anna Nerush, Haynes and Boone LLP, International joint ventures: oil & gas, (Practical Law UK Practice Notes, 2019) at uk.practicallaw.com/w-004-2060.

¹⁸ The International Energy Agency (IEA), The Oil and Gas Industry in Energy Transitions: World Energy Outlook special report (IEA Publications, 2020) pp. 22 – 24 at https://iea.blob.core.windows.net/assets/4315f4ed-5cb2-4264-b0ee- 2054fd34c118/The_Oil_and_Gas_Industry_in_Energy_Transitions.pdf (accessed 12 February 2023).

a stake.¹⁹ The figures are lower for INOCs (24%) and NOCS (18%), but these still represent significant volumes.²⁰ In 2018, the Majors had equity ownership of around 10 mb/d of crude oil production, but they operated fields that produced around 13 mb/d.²¹ By contrast, the NOCs owned 36 mb/d of production, while they operated fields that produced around 32 mb/d of crude oil.²² In essence, the IOCs often serve as operators of fields and concessions that they won less equity compared to NOCs and the Host Government, thus, gaining all the additional benefits of operatorship in most cases.

The property rights in E&P assets are reflected in the license or lease empowering a private corporation to enter, find, and produce oil and gas within the relevant acreage as granted by the host government. The following contractual structures are usually formed to define the terms of engagement between the licensed private corporations and their government-owned NOC or INOC partners regarding such property rights: (1) the JV/JOA, (2) the Production Sharing Contract (PSC), (3) the Risk or Pure Service Contract, and hybrid Model Agreement used in jurisdictions such as Ghana and Mozambique. Note some countries such as the UK, Norway, and Russia use a licensing regime in which the IOC or local independent gets a license and forms a JOA with other private companies to develop the oil and gas resources.

The JOA outlines the contractual framework for the management and operation of the E&P asset and sets out the rights and obligations of each party regarding the other joint venture parties. The party designated as ‘operator’ is typically responsible for day-to-day technical operation and management of the asset as well as communication and engagement with third parties (for example, the government and contractors) on behalf of all joint venture partners. The scope of the Operator’s duties and its discretionary powers are set out in the JOA, with ultimate decision-making (subject to matters reserved for Management Committee approval under the PSC) delegated to the operating committee consisting of a representative from each party.²³

In unincorporated JVs, the liability of each partner is limited by reference to the overall percentage of interest allocated to it under the relevant host government agreement, subject to any subsequent partial divestment or increase, as was the case in Nigeria when NNPC’s stake in the SPDC JV increased from 55% to 60% in 1979. Another example is when Chinese-owned Addax acquired a 40% interest in oil mining licenses held by Esso Exploration and Production Nigeria-Sao Tome (One) Ltd in 2008.²⁴ The interest held by Addax (an independent owned by China’s state-backed Sinopec) has now been transferred to and acquired by NNPC Ltd. It should be noted, however, that most host government contracts provide for joint and several liability of the joint venture partners with the State and will often require a further level of protection by seeking guarantees from their respective ultimate parents to secure their obligations. Although the liability of the JV partners concerning one another and certain third parties may be limited in the JOA, the liability of the JV partners regarding the State is frequently joint and several.

¹⁹ Ibid.

20 Ibid.

²¹ Ibid.

²² Ibid.

23 Nerush (n17).

24 Energy Voice, Addax ends Nigeria saga with NNPC transfer, (01/02/2023) at https://www.energyvoice.com/oilandgas/africa/ep-africa/479830/nigeria-addax-nnpc-licences/

The concept of ‘ownership’ in property law, presupposes that the owner has a right of possession, and control, to exclude others from accessing or use, the right of enjoyment, and the right to dispose or transfer such assets or property unless prohibited or restricted by an applicable law or encumbrances recognized in equity, such as liens.²⁵ Some of the main property rights implications of having ownership interests and the correlation between E&P assets and the applicable unincorporated JV contractual arrangements are that: (i) JV parties are in a position of co-owners and tenants-in-common concerning the underlying E&P assets relating to the license or lease;²⁶ (ii) common participation in the control of, and contribution to the costs relating to working/developing the assets; (iii) the rights and entitlements for each party to a proportion of the production is typically pro-rata to its participating interests share in the profits, losses, and liabilities.

1. Transfer of Interests in Concessions and E&P Assets

International upstream E&P operations are typically subject to the national constitutions, petroleum laws, policies, and regulatory oversight of the host government.²⁷ Parties to a JV/JOA arrangement hold exploration and production interests in an underlying concession or lease as stipulated in the agreement and recognized under the law. Divestments and acquisitions of the E&P interests or the corporate entities holding such interests would typically bring up the question(s) of how and on what terms and conditions transfers and assignments can be carried out. Apart from the fiscal and commercial considerations for the transfer and assignment, the following restrictions may be applicable: (i) consent by non-transferring JV parties under the JOA; (ii) consent by the State under the Production Sharing Contract (PSC) and/or local law; (iii) anti-monopoly or other government agency consents or approvals; (iv) the rights of pre-emption by non-transferring JV parties under the JOA; (v) Rights of pre- emption by the State under the PSC and/or local law.²⁸

For instance, the provisions of the Model Egyptian Concession Agreement for Petroleum Exploration and Exploitation (“Model E&P Agreement”), a hybrid form of a modern concession and a PSC exemplify the scenarios in which the transfer or assignment of E&P interests could occur. The Model E&P Agreement involves the Egyptian Government as represented by the Minister of Petroleum and Mineral Resources, the Egyptian General Petroleum Corporation (EGPC) which holds the concession and executes the agreement with a private petroleum producer which could be an IOC, INOC or independent as a Contractor. Article XXI of the Model E&P Agreement stipulates the terms and conditions under which an assignment or interest may be carried out by providing as follows-

25 For further discussion on the nature of ownership and property, see Christopher Serkin, The Law of Property, (2nd Edition, Foundation Press, 2016) at pp. 7 – 10; Investopedia, Bundle of Rights Definition in Real Estate and What’s Included, (February 28, 2022) https://www.investopedia.com/terms/b/bundle-of-rights.asp (accessed 21

August, 2024);

26 Under the common law principles of ‘property’, a tenancy-in-common refers to a form of concurrent ownership in property in which each co-tenant has an undivided interest in the whole property, owns that share outrightly, and can do whatever he/she wants with such undivided share or interest. Each co-tenant typically has a right to use the whole property, but if the property is sold or generates income, then such money accruing will be divided proportionally based on each person’s undivided ownership interests or stake. See. Serkin (n20) ibid at 89-90.

27 Tade Oyewunmi, ‘Stabilisation and Renegotiation Clauses in Production Sharing Contracts: Examining the

Problems and Key Issues’ OGEL Energy Law Journal 6 (2011) at www.ogel.org/article.asp?key=3184 (accessed 12 January 2023).

28 Nerush (n17) ibid.

Neither EGPC nor CONTRACTOR may assign to a person, firm, or corporation, in whole or in part, any of its rights, privileges, duties or obligations under this Agreement either directly or indirectly (indirect assignment shall mean, for example, but not limited to, any sale, purchase, transfer of stocks, capital or assets or any other action that would change the control of CONTRACTOR/CONTRACTOR MEMBER on its share in the company’s capital) without the written consent of the GOVERNMENT, and in all cases priority shall be given to EGPC, if it so desires, to obtain such interest intended to be assigned (except assignment to an Affiliated Company of the same CONTRACTOR Member).
Without prejudice to Article XXI (a), CONTRACTOR may assign all or any of its rights, privileges, duties, and obligations under this Agreement to an Affiliated Company of the same CONTRACTOR/ CONTRACTOR Member, provided that CONTRACTOR shall notify EGPC and the GOVERNMENT in writing and obtain the written approval of the GOVERNMENT on the assignment… In the case of an assignment either in whole or in part to an Affiliated Company, the assignor together with the assignee shall remain jointly and severally liable for all duties and obligations of CONTRACTOR under this Agreement provided such Affiliated Company remains in the same capacity as an Affiliated Company.²⁹

Generally, some jurisdiction-specific issues may arise in a transfer of participating interests in a JV/JOA scenario. Note that a model commonly used and adopted in jurisdictions like Nigeria is the Model JOA agreement developed by the Association of International Energy Negotiators (AIEN) (formerly the Association of International Petroleum Negotiators). The 2012 version of the AIEN Model JOA,³⁰ which is based on common law principles, provides inter alia that pending the State approval to a transfer of interests, the transferring party holds such participating interests in trust for the non-transferring party or parties, with parties issuing powers of attorney to implement the transfer.³¹

Given the rise in divestments and acquisitions in the Nigerian upstream petroleum sector over the past decade, there are several examples of how issues such as governmental approval or the consent of the non-transferring JV/JOA party to a transfer or assignment of E&P interests held by an acquired or divesting JV/JOA party can play out. For instance, ExxonMobil recently sold its equity interests in Mobil Producing Nigeria Unlimited (MPNU) to Seplat Energy. In this scenario, MPNU was the Nigerian subsidiary of ExxonMobil through which it held and operated (i) oil mining leases (OML) 67, 68, 70, and 104, comprising more than 90 platforms and 300 producing wells, (ii) the Qua Iboe export terminal, (iii) the Bonny River terminal, and natural gas processing facilities in Nigeria.³² Before the Seplat acquisition of controlling equity

29 Authors Copy. See also the OGEL Energy Law Journal Legal and Regulatory Database at https://www.ogel.org/legal-and-regulatory-countries-browse.asp?country=62 (accessed 12 January 2024).

30 The Association of International Energy Negotiators (formerly the Association of International Petroleum Negotiators) at https://www.aien.org/model-contracts/.

31 Nerush (n17) ibid.

³² See the Africa Oil+Gas Report, NNPC to Hold 70% of the JV as the ExxonMobil/Seplat Transaction Comes to a Close, (December 2024) at https://africaoilgasreport.com/2024/05/farm-in-farm-out/nnpc-to-hold-70-of-the-jv- as-the-exxonmobil-seplat-transaction-comes-to-a- close/#:~:text=NNPC%20and%20ExxonMobil%20announced%2C%20on,Settlement%20agreement%20betwee n%20NNPC%20Ltd (accessed 12 December 2024); Charlie Mitchell, Nigeria’s Seplat completes acquisition of ExxonMobil oil assets (S&P Global, December 12, 2024) at https://www.spglobal.com/commodity- insights/en/news-research/latest-news/crude-oil/121224-nigerias-seplat-completes-acquisition-of-exxonmobil- oil-assets (accessed 12 December 2024).

interests in MPNU, the E&P assets were operated by MPNU under a JV/JOA with NNPC i.e., the national oil corporation in a 40% – MPNU and 60% – NNPC, participating interest ratio. Following the acquisition of MPNU by Seplat, a new JV/JOA arrangement was expected and eventually emerged leading to NNPC holding 70% and Seplat holding 30% participating interests in the E&P Assets.³³ The Nigerian petroleum law and regulations (to be discussed further below) recognize a change in ownership and control of a company holding E&P interests such as MPNU as an assignment that requires ministerial approval.³⁴ Likewise, the JV/JOA arrangement would also include provisions reflecting the pre-emption rights of the non-transferring party (i.e. NNPC in this instance) concerning the participating interests in the E&P assets held by the party being acquired.³⁵

Under an ideal JV/JOA scenario, there are necessary contractual obligations that arise while a change in control of a party is being finalized and before the corresponding assignment or transfer of any underlying E&P assets and changes in participating interests can be completed. The acquired party is often required to disclose to the other non-transferring parties how and to what extent the terms and conditions of the change in control impact its participating interests. The non-transferring parties would typically have pre-emptive rights to make an offer for all or a portion of the participating interests or the E&P Assets of the acquired party within a specified time frame. The change in control and its effect of assigning ownership of the underlying E&P assets would typically be deemed complete if none of the other parties choose to exercise such pre-emptive rights or accept the terms and conditions of the transfer of the assets to the acquiring party. It is noted that one of the major issues that led to a delay in the final approval and completion of Seplat’s acquisition of MPNU was a legal action filed by NNPC against ExxonMobil and Seplat Energy, contending that a dispute had arisen with MPNU over its pre-emption rights under the JOA.³⁶ The case focused on the sale of all the shares in MPNU, by its shareholders, Mobil Development Nigeria and Mobil Exploration Nigeria to Seplat Energy. Following several negotiations, NNPC eventually dropped its legal challenge in June 2024 and the parties agreed to the new JV/JOA arrangement between NNPC and Seplat.

III. Nigerian Upstream Petroleum Operations and Commercial Ventures

In discussing the statutory and contractual frameworks that govern upstream E&P operations in Nigeria, it is important to note that before the enactment of the Petroleum Industry Act (PIA) 2021, the primary legal framework was provided under the Petroleum Act of 1969, the Petroleum (Drilling and Production) Regulations of 1969, and the NNPC Act. Based on this

³³ The Africa Oil+Gas Report (n32).

³⁴ See the Department of Petroleum Resources (now NUPRC), Guidelines and Procedures for obtaining Minister’s Consent to the Assignment of interest in oil and gas assets (2021) at www.nuprc.gov.ng/wp- content/uploads/2021/04/DPR-Guidelines-on-Asset-Divestment-2021.pdf (accessed 12 December 2024). See also the ruling of the Nigerian Federal High Court in the case Moni Pulo Limited v Brass Exploration Unlimited & 7 Ors, (2012) 6 CLRN pg. 153-235; Damilola Salawu and Mayowa Kalesanwo, ‘The Guidelines and Procedures for Obtaining Minister’s Consent to Assignment of Interest in Oil and Gas Assets: A Short Commentary’ OGEL 6 (2015) at www.ogel.org/article.asp?key=3582 (accessed 14 February 2023).

³⁵ The AIEN’s 2012 Model JOA defines ‘Change in Control’ as a direct or indirect change in control of a party (whether through merger, spin-off, sale of shares or other equity interests, or otherwise) through a single transaction or series of related transactions, from one or more transferors to one or more transferees, in which the market value of the party’s participating interest represents more than a specified percentage of the aggregate market value of the assets of the party and its affiliates that are subject to the change in control.

³⁶ Clause 12.3 of the AIEN’s 2012 Model JOA, for instance, provides that “… A Party subject to a Change in Control shall obtain any necessary Government approval with respect to the Change in Control and furnish any replacement Security required by the Government or the Contract…”

legal framework, the Federal Government participates in upstream petroleum operations via two main forms of contractual arrangements, i.e. the JV/JOAs and PSCs.³⁷ In addition, the PIA introduced an innovation that allows for the voluntary restructuring of JVs/JOAs to operate as limited liability companies. In this model, Government participation may be through the NNPC in the form of incorporated joint venture companies, offering an alternative operating model.³⁸

Until 1992/1993, almost all of Nigeria’s upstream operations were carried out under the JV/JOA arrangements between the NNPC and IOCs or other Nigerian-owned or foreign independents. For example, Chevron Corporation (USA) through its subsidiary in Nigeria, i.e. Chevron Nigeria Ltd, currently operates and holds a 40% participating interest in eight concessions under a JV/JOA arrangement with the NNPC. As discussed earlier, other major Nigerian JV/JOA arrangements during this period include the Shell Petroleum Development Company of Nigeria Limited (SPDC)/NNPC JVA,³⁹ Mobil Producing Nigeria / NNPC JV,⁴⁰ And the NNPC/Total JV. In 2005, the FGN introduced PSCs, mainly to reduce its exposure to E&P financing risks and difficulties meeting cash call obligations under the JV/JOAs. The PSCs were awarded in relation to the more capital-intensive and riskier shallow and deep offshore acreages, which were largely under-explored at the time.⁴¹ This move paid off since a significant portion of Nigeria’s current petroleum production comes from the offshore and deep-offshore areas covered in such arrangements.

1. Regulating Assignments, Divestments, and Acquisitions of E&P Assets

According to the Petroleum Act of 1969, the entire property in petroleum resources within Nigeria is vested in the Federal Government. That legal framework empowered the Minister of Petroleum Resources to grant the (i) Oil Exploration Licence (OEL); (ii) Oil Prospecting Licence (OPL); and (iii) Oil Mining Lease (OML).⁴² Upstream petroleum taxation was

37 Yinka Omorogbe, Oil and Gas Law in Nigeria (Malthouse Press, 2003); Oyewunmi (n14), Regulating Gas Supply to Power Markets, pp. 132-141.

³⁸ See section 65 of the Petroleum Industry Act 2021. The incorporated joint venture companies are a new legislative addition created by the Petroleum Industry Act 2021.

39 The Shell-operated JV accounts for over 40% of Nigeria’s total oil production from about eighty fields. The JV

is composed of the NNPC (55%), Shell (30%), Elf (10%) and Agip (5%). Over the last couple of years, the IOCs in the Shell-Elf-Agip/NNPC JV have divested their 45% stake in several concessions to various Nigerian independents, see the Energy Mix Report, ‘Upstream Assets Divestment In Nigeria: Update, Outlook And Challenges’, 1 July 2014, available at <http://energymixreport.com/upstream-assets-divestment-in-nigeria- update-outlook-and-challenges/> (accessed on 11 November 2014). Such divestments have led to the emergence of JVs between Nigerian-owned independents and NNPC like NNPC and SEPLAT and NNPC and NECONDE JVs.

40 An ExxonMobil-operated JVA in which the NNPC has a 60% interest and Mobil has a 40% interest. Other

IOC/NNPC JVs include JVs with the following compositions: (i) the NNPC (60%), Agip (20%), Phillips Petroleum (20%); (ii) the NNPC (60%) and Total E&P Nigeria Limited (TEPNG) (40%); (iii) the NNPC (60%), Texaco (20%) and Chevron (20%). See the NNPC, ‘Joint Venture Operations’, available at

<www.nnpcgroup.com/NNPCBusiness/UpstreamVentures.aspx> (accessed on 4 January 2015).

41 Offshore Magazine, Nigerian production sharing contracts hold key deepwater producing fields, Aug. 15, 2022 https://www.offshore-mag.com/deepwater/article/14281338/nigerian-production-sharing-contracts-hold-key- deepwater-producing-fields; Toyin Akinosho, ‘Nigeria: Deepwater PSC Incentive Turns On Its Head’, African Oil and Gas Report, 30 December, 2013, available at <http://africaoilgasreport.com/2013/12/in-the-news/nigeria- deepwater-psc-incentive-turns-on-its-head/> (accessed 23 February 2014). Currently, about 95% of Nigerian upstream petroleum operations are carried out under PSCs and the JV/JOAs, while service contracts, sole risk contracts and marginal field licences constitute about 5% collectively. 42 Under section 70 of the recently enacted Petroleum Industry Act 2021, the licenses and leases that can now be obtained are Petroleum Exploration License, Petroleum Prospecting License, and Petroleum Mining lease.

regulated pursuant to the provisions of the Petroleum Profits Tax Act 1959. The OML confers on the holder the exclusive right within the leased area to conduct exploration and prospecting operations and to win, get, work, store, carry away, transport, export, or otherwise treat petroleum (including natural gas) discovered in or under the leased area for a maximum duration of 20 years subject to renewals.⁴³ However, ten years after the grant of an OML, one- half of the area of the lease must be relinquished. The relinquished areas may, of course, include any undeveloped gas fields and reservoirs.

The PIA was enacted in 2021 following the industry reforms that lasted over a decade. As a result, a new upstream exploration and production licensing regime was established among other things. The Nigerian Upstream Petroleum Regulatory Commission (the “Commission” or “NUPRC”) is responsible for granting the Petroleum Exploration Licence (PEL); and the Minister, upon the recommendation of the Commission, is responsible for the grant of a Petroleum Prospecting Licence (PPL) and a Petroleum Mining Lease.⁴⁴ (PML). Essentially, the OML or PML creates what can be called in property law parlance a profit a prendre (i.e., the right to take)⁴⁵ gives the holder (e.g. an IOC or Independent) the right to enter the land or acreage upon which the grant covers to find and win, work, carry away, and dispose of oil subject to the provisions of the Act (including being subject to the powers granted to the NMDPRA), any applicable rules and regulations and contractual frameworks defining the interests in such license or lease.

The interests held under the grant of an exploration and production lease or license represent E&P assets owned by the leaseholder or licensee. When multiple corporations or parties enter into a JV/JOA arrangement in relation to such a lease, their ownership and corresponding liabilities of the E&P assets become joint and several based on their respective participating interests as defined under the JV/JOA. A party seeking to divest or assign or sell its participating interests to a third party who is not part of the JV/JOA arrangement must therefore adhere to the terms of the JOA regarding assignments of interests and any other applicable laws and regulations regarding the underlying license or lease. Before delving further into the requirements for successful assignments, divestments, and acquisition of E&P assets, it is worth highlighting the legal nature and implications of the Nigerian upstream licenses and leases, especially under the recently enacted PIA.

Petroleum Exploration Licence (PEL)

This is a non-exclusive right granted to the holder to carry out petroleum operations within the area provided for in the licence. This licence is for a period of three years and renewable for another three years. The exploration under this licence also covers areas that include Petroleum

⁴³ Under sections 29, 32 and 318 of the PIA transporting and exporting of petroleum from the measurement point of the petroleum mining lease fall under midstream and downstream operations which are regulated by the Nigeria Midstream and Downstream Petroleum Authority. Note that under Section 318, upstream measuring points are regarded as the point where the produced petroleum is measured and value determined for royalty purposes or the point beyond the flow station upstream. Activities beyond this point are categorized as part of midstream and downstream operations. The Act removes certain midstream and downstream activities from the scope of licenses granted under the Petroleum Act and creates new licenses such as a gas processing license and a transportation license, to be issued by the Nigeria Midstream and Downstream Petroleum Authority.

44 Sections 70, 71 and 73 Petroleum Industry Act 2021.

45 See Practical Law Glossary defining Profit à prendre as A right to take something from another’s land (the servient land) that is both: (i) capable of ownership; and a product of nature. Typical profits à prendre include The removal of part of the land itself, for example, soil or minerals. https://uk.practicallaw.thomsonreuters.com/6-386- 5195?transitionType=Default&contextData=(sc.Default)&firstPage=true (accessed 23 June 2024).

Prospecting Licence (PPL) and Petroleum Mining Lease (PML), provided that the holders of the PPL and PML have no obligation to pay for the survey conducted under the PEL.⁴⁶

Petroleum Prospecting Licence (PPL)

A holder has an exclusive right to drill exploration and appraisal wells and a non-exclusive right to carry out petroleum exploration operations within the area provided for in the license. The Minister is responsible for granting this licence, upon recommendation of the Commission.⁴⁷

A PPL licence for onshore and shallow water acreages shall be for not more than six years which comprises an initial period of three years and an option to extend for three years. A licence for deep offshore frontier acreages shall be for not more than 10 years comprising an initial exploration period of five years and an optional extension period of five years. The area provided for a PPL shall not exceed 350 square kilometres for any onshore or shallow water acreages, 1,000 square kilometres for any deep offshore acreages, and 1,500 square kilometres for any frontier acreages.⁴⁸ This licence is not to be extended except in accordance with the PIA.⁴⁹

Petroleum Mining Lease (PML)

This shall be granted for each commercial discovery of crude oil or natural gas or both to the holder of a Petroleum Prospecting Licence where it has satisfied the conditions imposed on it.⁵⁰ It is granted to qualified applicants to win, work, carry away, and dispose of crude oil, condensates, and natural gas on an exclusive basis, it also allows the applicants to drill exploration and appraisal wells, carry out the related test production on an exclusive basis and carry out petroleum exploration operations on a non-exclusive basis.⁵¹ The reference to the term ‘dispose’ under the terms of the PML is used in a classic ‘oil and gas industry context’ regarding rights to produce oil and gas and does not include rights to dispose via downstream sales or downstream operations. Generally, the produced oil and gas will need to be conveyed to the designated ‘measurement point’ as defined under Section 318. Natural gas production for instance will typically require gathering lines before measurement or midstream processing. Thus, reference to ‘disposal’ or rights to dispose of petroleum under the PML relates to the upstream operations aspect and excludes activities beyond the measuring point or activities classified as part of midstream and downstream operations.⁵² The NMDPRA is empowered to issue licenses for midstream and downstream operations, including the sale of petroleum.

A holder of an existing oil prospecting licence, or oil mining lease, as it was under the Petroleum Act, may enter into a voluntary conversion contract under the Petroleum Industry Act.⁵³ However such conversion must comply with the provisions of the Act for instance, the

46 Section 71 Petroleum Industry Act 2021.

⁴⁷ Section 72(5) of the Petroleum Industry Act 2021.

48 Section 77 Petroleum Industry Act 2021.

49 Section 72(2) Petroleum Industry Act 2021.

50 Section 80(1) Petroleum Industry Act 2021.

51 Section 70(1)(c) Petroleum Industry Act 2021.

⁵² See the definition of ‘Measurement Point’ and ‘Disposal’ in section 318 of the Petroleum Industry Act 2021.

53 Section 92 Petroleum Industry Act 2021.

conversion contract shall contain a termination clause for all outstanding arbitration and court cases related to the respective oil prospecting licences or oil mining lease.⁵⁴

Grounds for revocation of a licence or lease under the PIA⁵⁵

Failure to conduct petroleum operations in accordance with good international petroleum industry practices, the provisions of the PIA, and other relevant legislations;
Interruption of production for over 180 consecutive days without justification or as provided for in the applicable licence or lease;
Failure to fulfill the terms and conditions of the applicable licence or lease or the approved field development plan and to furnish reports or data on operations as required by law;
Failure to pay government, rents, royalties, taxes, or other payments and any transfer of interest otherwise than under the provisions of the Act.

2. Divestments and Acquisition of Upstream Assets

The privatization of NNPC and the uptick in the rate of divestments by IOCs from onshore JVs have been a key feature in the scheme of things over the past 10 years. By entering into a JV/JOA, the federal government through NNPC directly becomes a participant in the E&P operations and shares with the IOC the attendant risks and benefits based on agreed participating interests and JOA terms. The JVA often comprises the participation agreement, which defines the relationship and participating interests of the parties, and the JOA, which defines the legal and operational relationship of the joint venturers by providing for issues such as the operator of the lease or concession, the operating committee, work program, and budget, disposition of production, relinquishment, decommissioning, allocation of costs and profit hydrocarbon, transfer of participating interests and rights, etc.⁵⁶ Two key requirements for obtaining an OML or interest in an upstream asset are (i) the technical, and (ii) financial capacity to carry out the obligations and operations envisaged under the JV/JOA. Likewise, to acquire such participating interests or upstream assets, the regulatory institutions will ideally require some minimum levels of technical and financial capacities to develop the assets.

As discussed above, the NUPRC recently announced the approval for Exxon Mobil Corp.’s sale of its equity interests in MPNU and corresponding E&P assets to Seplat Energy Plc. There are also similar transactions such as SPDC’s proposed asset sale to Renaissance.⁵⁷ Shell, a major IOC, announced in January that it had reached an agreement to sell its Nigerian onshore subsidiary, Shell Petroleum Development Company of Nigeria Limited, to Renaissance for

54 Section 92(3) of the Petroleum Industry Act 2021.

55 Section 96 of the Petroleum Industry Act 2021.

56 Omorogbe (n37).

57 The Africa Oil+Gas Report, Nigerian Government “Very Close” to Granting Ministerial Consent for Shell- Renaissance Deal (17 December 2024) at https://africaoilgasreport.com/2024/12/farm-in-farm-out/nigerian- government-very-close-to-granting-ministerial-consent-for-shell-renaissance- deal/?mc_cid=368a8e66a3&mc_eid=fa5461c505 (accessed 17 December 2024); Petlong Dakhling, Nigeria to Approve Exxon-Seplat Deal in 120 Days, (African Energy Council, August 29, 2024) at https://africanenergycouncil.org/nigeria-to-approve-exxon-seplat-deal-in-120-days/ (accessed 29 August 2024). The Renaissance consortium in the process of acquiring the Shell onshore assets offered for sale comprises- Aradel, First E&P, ND Western, and Waltersmith. The fifth member of the consortium, Petrolin, is headquartered in Switzerland.

$2.4 billion after about a century of operations in the Niger Delta. The Federal Government initiated a due diligence meeting for Shell’s proposed sale to Renaissance Africa Energy.⁵⁸ It was reported that the Federal Government initially declined to consent to the transaction.⁵⁹ Although the main reason(s) that the NUPRC gave as grounds for withholding the approval was “financial and technical capabilities”, it is worth noting that the Renaissance consortium comprises companies with longstanding experience of successfully operating in the Nigerian Niger Delta where the assets are located.

From a transactional perspective, the following are some of the initial preliminary inquiries that can be raised by an advisor carrying out a due diligence exercise:

Is the transaction a sale of shares or assets?
If an asset sale, will the sale involve several assets or petroleum permits, or a specific, identified asset or petroleum permit? Obtain a description of the assets that form part of the sale, together with details (and, where relevant, copies) of any contractual rights, mortgages, charges, options, rights to acquire (or other pre- emptive type rights), assignments, liens, security interests, claims, rights, leases, royalty arrangements, retentions of title or other encumbrances over the whole or any part of the undertaking, properties or assets.
Where are the assets located? Do any assets or mining permit areas span multiple state, territory, or Commonwealth jurisdictions? Are inspections of the assets, mining permit areas, or project operations necessary? If so, consider whether physical inspection, digital surveying, or other methods of inspection are suitable.
Are there other property interests surrounding the assets or mining permits, for example, real property land rights, native title interests, pipelines, water authorities, electricity lines, roads, or railway lines?
At what stage are the operations? For example, are they at a brownfield, greenfield, production, or decommissioning stage?
Have project timelines and milestones been met? Request copies of all reports and studies completed in relation to the assets and project areas.
What is the structure of the operations to be acquired? Will the buyer be engaging in upstream, midstream, or downstream operations or a combination of these?
Will other transactions or acquisitions be necessary or desirable in future operations? This includes, for example, entering into a joint venture with neighbouring title holders to develop petroleum deposits that span multiple title areas, acquiring a company that holds strategic assets (for example, pipelines, railway lines, processing facilities, and high petroleum resource potential areas) in proximity to the project or entering into transportation and refinement or processing arrangements once the petroleum field begins production.⁶⁰

58 Petlong Dakhling, Shell to Finalize $2.4bn Nigeria Asset Sale by June, (African Energy Council, April 30, 2024) https://africanenergycouncil.org/shell-to-finalize-2-4bn-nigeria-asset-sale-by-june/ (accessed 29 August

2024).

59 See Reuters report, Nigeria rejects Shell’s $1.3 billion oil asset sale (16 October 2024) at https://www.reuters.com/markets/deals/nigeria-rejects-shells-13-billion-oil-asset-sale-thisday-reports-2024-10- 16/#:~:text=ABUJA%2C%20Oct%2016%20(Reuters),ThisDay%20newspaper%20reported%20on%20Wednes day. (accessed on 27 October 2024).

60 Brady and Yap (n9), Legal due diligence: oil and gas, ibid. For more information on jurisdictional

considerations, see Michael Brady, Legal due diligence: oil and gas, (Practical Law ANZ Practice Note) at https://us.practicallaw.thomsonreuters.com/w-024-5412 (accessed 12 October 2024).

What Constitutes an Assignment Under the Ministerial Guidelines

Before the enactment of the PIA, Paragraph 3.1 of the Department of Petroleum Resources (DPR)⁶¹ Guidelines and Procedures for Obtaining the Minister’s Consent to the Assignment of Interests 2021 (the “Assignment Guidelines”) provide as follows:

3.1. In these Guidelines an Assignment involves the transfer of an OPL, OML, MF, or OGPL or an interest, power, or right therein by any company or person with equity, participating, contractual, or working interest in the said OPL, OML, MF⁶² Or OGPL, through merger, acquisition, take-over, divestment or any such transaction that may alter the ownership, equity, rights or interest of the assigning company in question, not minding the nature of upstream arrangement that the assigning company may be involved in, including but not limited to Joint Venture (JV), Production Sharing Contract (PSC), Production Sharing Agreement (PSA), Service Contract (SC), Sole Risk (SR) or Marginal Fields operation. Instances of an assignment shall include, but not limited to, the following:
- 3.1.1. Assignment by way of exchange or transfer of shares: This shall entail the acquisition of part or all of the shares of a company that holds an OPL, OML, MF or OGPL in Nigeria.
- 3.1.2. Assignment by way of private placement or public listing, in any Stock Exchange, of a part or of the whole of the shares of a company that holds an OPL, OML, MF or OGPL.
- 3.1.3. Assignment by way of merger, wherein a company which holds an OPL, OML, MF or OGPL, combines with one or more companies to form another company by way of payment, exchange of shares or by any other means whatsoever.
- 3.1.4. Assignment by way of acquisition, wherein the acquiring company directly or indirectly takes over or acquires the entire rights or interest in an OPL, OML, MF or OGPL, and associated assets of the assigning company, including acquisition of interest by an entity in a parent company whose affiliate has interest in an OPL, OML. MF or OGPL, or associated assets in Nigeria.
- 3.1.5. Assignment to a company in a group of which the Assignor is a member and is to be made for the purpose of re-organization to achieve greater efficiency and to acquire resources for more effective petroleum operations.
- 3.1.6. Assignment brought about by reason of devolution of ownership of shares or interest in ownership of shares by way of operation of law or testamentary device. Operation of law may refer to a judgment of a competent court of law, an award from an Arbitration Panel, the appointment of a Receiver, Receiver/Manager or Administrator under the Companies and Allied Matters Act Cap C20 LFN 2004 or any comparable legislation in a foreign jurisdiction.

61 Now NUPRC.

62 Under section 94 of the PIA no field shall be declared a marginal field. Previously, under the Petroleum Act, a Marginal Field was any field declared as such by the President. Now under the PIA, existing marginal field must be converted to a PPL. Furthermore, discoveries classified as marginal fields must be transferred to the government. The Nigerian Upstream Petroleum Regulatory Commission (NUPRC) may then offer these fields through a bid round. If the transfer does not occur within three years of the PIA’s enactment, the holder must submit a Field Development Plan (FDP) for the field, farm out the discovery with the Commission’s consent, or relinquish the field entirely. Testamentary device shall refer to the transfer of shares through a Will or Letters of Administration.

Although the above provisions of the Assignment Guidelines were issued pursuant to the 1969 Petroleum Act and legal framework, the savings provisions of the PIA stipulates that any subsidiary legislation or guidelines (among other things) made under previous laws amended or repealed by the PIA shall remain in force so long as it is not inconsistent with the PIA.⁶³ Thus, any acts, directives, guidelines, or subsidiary rules such as the Assignment Guidelines highlighted above remain valid as if issued by the NUPRC under the PIA until replaced or revoked accordingly.

Issues in Contemporary Divestments and Acquisitions

Following the enactment of the PIA, it is now the case that until (i) the voluntary conversion of an OML or (ii) the termination, expiration, or renewal of an OML, such existing OML will generally be subject to the regulatory regime applicable before the enactment of the PIA (i.e., the Petroleum Act).⁶⁴ Therefore, companies acquiring assets from IOCs who are divesting are required to do due diligence to determine what regime their licence falls under, when the renewal date is due, and whether they want to convert to a PML. Concerning OMLs governed by a PSC, where negotiations of the relevant PSC are continuing on the effective date of the PIA and such contracts are signed within 1 (one) year of the effective date, the relevant PSC shall continue to be subject to the Petroleum Act. Where the parties fail to complete the negotiations within 1 (one) year of the effective date, such PSCs will be subject to the PIA regime, at the expiration of the underlying OML.⁶⁵

The Process for Transfer of an Interest

The prior written consent of the Minister is required in respect of the direct or indirect assignment of an interest in an OPL or OML under the provisions of the previously applicable Petroleum Act,⁶⁶ the new PIA,⁶⁷ the Petroleum (Drilling and Production) Regulations, 1969 (as amended) (the “PDPR”)⁶⁸ and the Assignment Guidelines. Paragraph 3.1 of the Assignment Guidelines provides that an assignment involves the transfer of an OML (which is now interpreted to include a PML), or an interest, power, or right therein by any company or person with equity, participating, contractual, or working interest in the said OML through merger, acquisition, take-over, divestment or any such transaction that may alter the ownership, equity, rights or interest of the assigning company in question. Further, such an assignment is expected to be consistent with the provisions and peculiarities of the upstream arrangement that the assigning company may be involved in such as the JV/JOAs discussed earlier or a PSC. According to the Assignment Guidelines, the notion of an “Interest in a licence or lease” means any arrangement such as a PSC, Production Sharing Agreement, Farm-in or Farm-out agreement, sale, purchase, mortgage, charge, lien or other business arrangements by which a

⁶³ Section 311, Petroleum Industry Act 2021.

⁶⁴ See Section 92 and 303, Petroleum Industry Act 2021.

65 Section 311(2)(a)(i) of the Petroleum Industry Act 2021.

66 Paragraph 14 of the First Schedule to the Petroleum Act.

67 Section 95 of the Petroleum Industry Act 2021.

68 Regulation 4 of the PDPR.

right, privilege, power, benefit, gain or advantage in a licence or lease is transferred to or conferred either directly or indirectly on a third party.⁶⁹

Pre-authorization by the NUPRC

As part of the process of obtaining the consent of the Minister, a pre-authorization is required from the NURPC. Paragraph 4.2 of the Assignment Guidelines requires an assignor to notify the DPR (now NURPC) before the commencement of a transaction. The assignor must not proceed with any process incidental to the assignment transaction until it is authorized to do so by the NURPC. The NUPRC⁷⁰ is obligated to conduct due diligence on the assignee. The Assignment Guidelines extend the objectives of the due diligence exercise to include the determination of the legal status of the assignee, the history of the assignor’s relationships with previous assignees, the history of compliance with the provisions of the Act, and the assignor’s track record on the operation of the asset. Further, in line with the general theme of the New Guidelines for the provision of timelines for the different activities of the DPR, the due diligence exercise must be conducted within sixty (60) calendar days from the date of receipt of the complete application.⁷¹

In addition, the Assignment Guidelines impose notification requirements on the assignor. The assignor is required to submit the list of qualified prospective assignees to the NURPC after the technical evaluation. The NURPC will utilize the list to determine companies that are acceptable to the Federal Government of Nigeria (“FGN”) and any company found unacceptable will not be permitted to proceed to the commercial stage of the transaction. According to the Assignment Guidelines, where the assignor fails to submit the list of qualified candidates and proceeds to the commercial stage, the transaction shall not be eligible for the Minister’s consent.

Obtaining Ministerial Consent

It shall be the responsibility of the Assignor to secure the consent of the Minister concerning any Assignment of interest in an Asset.⁷²

The first step requires the assignor to notify the NUPRC in writing of its intention to carry out an assignment. Although, the NUPRC does not provide any guidance on what constitutes an ”assignor’s intention”, it is not unreasonable to argue that this obligation will be triggered once the assignor comes to a decision through a board resolution, shareholder resolution or management decision. In a bid to facilitate ease of business, the Assignment Guidelines impose an obligation on the NUPRC to respond to the notification within ten (10) working days from the date of receipt of the notification, failing which the assignor may proceed to the next stage of the assignment process based on a deemed approval.⁷³

69Paragraph 12 of the Guidelines and Procedures for obtaining Minister’s Consent to the Assignment of interest in Oil and Gas Assets 2021.

70 Now under the Petroleum Industry Act 2021, the Department of Petroleum Resources has been replaced by the

National Upstream Petroleum Regulatory Commission (NUPRC) and National Midstream and Downstream Petroleum Regulatory Authority (NMDPRA).

71 Paragraph 5.4 of the Assignment Guidelines.

72 Paragraph 4 of the Assignment Guidelines.

73 Paragraph 4.2 of the Assignment Guidelines.

Upon the completion by the assignor of the technical evaluation of companies shortlisted for the Assignment, the assignor is required to submit the shortlist to the NUPRC. The prospective assignor will not be eligible to apply for the Minister’s consent if it fails to fulfill this obligation. The DPR is required to respond to the notification within ten (10) working days following the receipt of the notification. However, the DPR’s approval will not be deemed in the absence of a response.⁷⁴

Upon the successful completion of the notification stages in paragraph 4 above, an Assignor shall submit a written application to the Director of the NUPRC requesting the Minister’s consent.⁷⁵

Under the PIA, a holder of a PPL or PML shall not assign, novate, or transfer his licence or lease or any right, power, or interest without the prior written consent of the Minister and the consent of the Minister shall be granted upon the recommendation of the Commission.⁷⁶

To reduce the administrative hurdle, under the PIA a PPL holder only requires the prior consent of the Commission, to create a security interest in a PPL whether by assignment, pledge, mortgage, charge, or hypothecation.⁷⁷ The PIA has also introduced a time limit for trading applications for consent and a concept of deemed approval for the consent of the minister. The Commission is required to complete its review of consent applications within 60 (sixty) days of receipt of an application, otherwise, consent may be deemed.⁷⁸

According to Paragraph 7 of the Assignment Guidelines, the Minister’s consent may only be granted where the Minister is satisfied that:

the proposed assignee is of good reputation, or is a member of a group of companies of good reputation, or is owned by a company or companies of good reputation;
the proposed assignee is in all other respects acceptable to the FGN; and
there is likely to be available to the proposed assignee sufficient technical knowledge, experience, and financial resources to work the acquired assets.

The PIA also provides conditions that the NUPRC may consider appropriate for the grant of the Minister’s consent, including that the proposed assignee – (a) is a company incorporated in Nigeria; (b) is of good reputation and standing; (c) has sufficient technical knowledge, experience and financial resources to enable it to carry out all responsibilities under the lease; and (d) shall comply with the Federal Competition and Consumer Protection Act, 2018.

Examples of recent D&As in Nigeria

As we mentioned in the introduction there have been what can accurately be described as a flurry of divestments in the upstream oil and gas space in the last couple of years. Examples of those divestments include:

74 Paragraph 4.3 of the Assignment Guideline.

75 Paragraph 5 of the Assignment Guidelines.

76 Section 95, Petroleum Industry Act 2021.

77 Section 95(4) Petroleum Industry Act 2021.

78 Section 95(6) Petroleum Industry Act 2021.

Equinor and Chappal Energies agreed to the sale of Equinor Nigeria Energy Company which holds a 53.85% ownership in OML 128, including a unitized 20.21% stake in the prolific Agbami deepwater oil field, operated by Chevron.
ExxonMobil has reached an agreement to sell its equity interest in Mobil Producing Nigeria Unlimited to Seplat Energy, a Nigerian independent oil and gas company, through its wholly owned subsidiary Seplat Energy Offshore Limited.
Shell has reached an agreement to sell its Nigerian onshore subsidiary, Shell Petroleum Development Company of Nigeria Limited (SPDC) to Renaissance, a consortium of five Nigerian companies (ND Western Limited, Aradel Holdings Plc, the Petrolin Group, First Exploration and Petroleum Development Company Limited and the Waltersmith Group) comprising four exploration and production companies based in Nigeria and an international energy group.⁷⁹
Eni also announced the signing of an agreement with Oando PLC for the sale of Nigerian Agip Oil Company Ltd (NAOC Ltd), the wholly Eni-owned subsidiary focusing on onshore oil & gas exploration and production in Nigeria, as well as power generation.

IV. Considerations for New Upstream Asset Acquisitions

Despite the global trend toward decarbonization and net-zero economy targets, there is still a need for investment in upstream petroleum (especially natural gas) projects to support industrialization objectives and sustainable economic growth in developing economies such as Nigeria. The IEA reports that production from existing fields, globally, will decline at a rate of about 8% per year in the absence of any investment, larger than any plausible fall in global demand. Consequently, investment in existing and some new fields remains part of the picture. But as overall investment falls back and markets become increasingly competitive, only those with low-cost resources and tight control of costs and environmental performance would be able to benefit, because emerging clean energy technologies such as renewables, hydrogen, and gas produced using carbon capture and storage (CCS) systems, or carbon markets may have become more prevalent.

Although resources-rich developing economies like Nigeria contribute very little to global emissions when compared to advanced economies like the US and China, it is becoming increasingly difficult for operating local E&P companies to obtain needed international financing for investing in new projects without some form of corporate plan or commitment towards future net-zero targets or carbon neutrality. Consequently, some IOCs, NOCs, INOCs, and independents are becoming “energy” companies aiming to supply a diverse range of cleaner fuels, electricity, and other energy services to consumers. For instance, Norwegian Statoil changed its name to Equinor while Shell and Total are increasingly investing in energy systems such as offshore wind. Likewise, Nigerian independents that recently acquired E&P assets from IOCs such as Seplat Energy have announced plans to invest in more sustainable pathways such as gas-to-power to reduce gas flaring, promote the use of compressed natural gas as a cleaner alternative to diesel for transportation, and LPG as a better alternative to firewood and biomass for clean cooking. In Nigeria, the focus of policymakers, and agencies such as the National Council on Climate Change established under the Climate Change Act 2021 is to facilitate climate mitigation and adaptation policies that are in line with national

79 Shell Plc. Shell agrees to sell Nigerian onshore subsidiary, SPDC, (15 Jan 2024) at https://www.shell.com/news-and-insights/newsroom/news-and-media-releases/2024/shell-agrees-to-sell- nigerian-onshore-subsidiary-spdc.html (accessed 7 May, 2024)

development priorities such as ensuring reliable and affordable supplies of energy. As a result, interested E&P operators are considering the adoption of voluntary carbon markets and working with policymakers to facilitate investments in nature-based decarbonization tools like deforestation as a means of reaching long-term net zero or carbon neutrality targets, thereby driving investments in new production.

From a policymaking perspective, introducing market-based tools such as carbon taxes and emissions trading schemes in a developing economy such as Nigeria may be understandably unpopular due to potential socio-economic effects on the price of goods and services. Carbon Taxes are environmental taxes on units of carbon used to discourage carbon emissions through the utilization of fossil fuel-based energy sources which occur as a result of production or consumption of goods and services. Emissions Trading is an incentives-based technique whereby the Federal Government sets a limit on the highest level of emissions and grants or permits for each unit of emission that can be traded by individuals and legal entities. This signifies emission allowances and certificates earned for emitting less than the allowed threshold could be transacted like commodities. For such a system to work efficiently it will require factors such as a very well-organized and monitored system of accounting for emissions, a registry, and enough baseline emissions to justify the regulatory and transaction costs.

A more popular option that is being considered by industry and policymakers is to create a system for earning carbon credits and carbon allowances following investments in clean energy resources, and decarbonization technologies such as those eliminating gas flaring, nature-based solutions, or CCS. With carbon credit, carbon revenue flows vertically from companies to regulators, and companies who end up with excess credit can sell them to other companies.⁸⁰ As companies divest and others acquire upstream assets, it will be essential to understand how and to what extent the need to pursue net-zero or low-carbon goals affects the future commercial outlook for the new E&P operators.

1. Other Common Factors in Acquiring Upstream Assets

Financing

A mix of debt and equity financing is common to financing transactions in Nigeria. In structuring effective finance, attention needs to be given to some specific areas such as; the choice of a financing model; the life cycle of the oil and gas fields; the ease of exit from investment; a future change in control of the company; the viability of the company involved and the term of payback. Below are a few financing options for emerging operators.

Equity Investment

This is one of the traditional modes of raising finance and for an awardee, it involves finding the right equity partners to inject the necessary capital into the awardee entity or a Special Purpose Vehicle. Equity funding can be raised through private placements, rights issue, or fresh capital from the capital markets. Another avenue to source for equity is through private equity investment. Due to the extent of finance requirements for acquiring oil and gas assets, equity finance is unlikely to be the only means of acquisition financing for most investors. There is

⁸⁰ The ultimate guide to understanding carbon credits, < https://carboncredits.com/the-ultimate-guide-to- understanding-carbon-credits/ > (accessed September 9, 2024)

usually required to be a mix of equity and debt. This has certainly been the case in most of the recent divestments in Nigeria.

Debt Finance

Equity investment typically goes hand in hand with debt financing as most lenders would require some evidence that the promoters have committed or will commit some equity to the project (usually 30%) before providing the debt. In recent times, awardees have found it increasingly difficult to attract this form of financing as the usual Debt Finance Institutions (DFI) often express an aversion to financing traditional oil development projects due to environmental concerns. There are different types of debt packages available to oil and gas investors for acquisition finance.

Reserve Based Lending (RBL)

RBLs are loans secured against developed and producing assets. The loan to be secured is based on the determined reserves of the awarded marginal field, and the facility is repaid from crude oil proceeds from the field. For a bankable RBL transaction, the reserves of that field, the anticipated price of oil and gas, expected capital expenditures, and the operating costs of the awardee must be ascertainable.

Contractor Financing

This option involves Oil Field Service (OFS) contractors providing required services for the development of the field in exchange for either cash or the products (either oil and gas or both). The drawback with this mode of financing is that oil field service contractors are generally averse to production risks therefore it tends to be the larger OFS contractors that provide this form of financing given the strength of their balance sheets. With the COVID-19 pandemic and its effect on the oil and gas service industry, this form of financing may be limited.

Trading

This is a developing practice whereby the IOCs using their trading companies or oil trading companies execute offtake agreements with local independents which allows the local companies to source financing from financial institutions for the development of the fields or in some instances advance the finance for the acquisition or development of the fields. The IOCs often execute these agreements with the awardees that are awarded fields carved from blocks originally owned by the IOCs the reservoir characteristics of which are known to the IOC.

Decommissioning

One of the key issues to be considered by a company in an acquisition of an oil and gas asset from a divesting company is, what are the potential decommissioning obligations of the asset. Decommissioning is the process of disuse and uninstallation of oil and gas infrastructure in both onshore/shallow water areas and offshore fields after they are no longer in operation, to minimize their impact on the environment and other legitimate interests. Before enacting the PIA, decommissioning obligations under the previous law were inadequate and the license holder was only required to plug unused wellheads to prevent water ingress and egress. It was also unclear who was to bear decommissioning costs and disposal liability.

Under the PIA, sections 232 – 233 provide a procedure for decommissioning oil and gas installations. Among other things, it requires:

the approval from the Nigerian Upstream Petroleum Regulatory Commission or the Nigerian Midstream and Downstream Petroleum Regulatory Authority before decommissioning;
the licensee must submit a decommissioning program with cost estimates;
The licensee or lessee must establish and maintain a decommissioning fund with an independent financial institution in the form of an escrow account accessible by the Nigerian Upstream Petroleum Regulatory Commission or the Nigerian Midstream and Downstream Petroleum Regulatory Authority.
Contributions to the fund depend on approved plans for upstream and midstream operations. Yearly amounts are estimated and approved by the Nigerian Upstream Petroleum Regulatory Commission or the Nigerian Midstream and Downstream Petroleum Regulatory Authority.”The contributions to the decommissioning fund are eligible for cost recovery and tax deduction.

Post PIA, an acquiring company must consider decommissioning as part of the cost of owning oil and gas assets, and a provision for those costs has to be factored into the financial model utilized both by the acquiring company and any financier.

V. Conclusion

Several leases and licenses granting rights to explore and produce oil and gas from onshore and shallow water areas of the Nigerian Niger Delta have been held and operated by IOCs under a JV/JOA arrangement with NNPC since the 1960s and 1970s. Over the past decade, an uptick in divestments from onshore areas by some major producers reflects the move to focus more on deepwater prospects and possibly due to other international energy industry developments. There is also notable growth in the number of Nigerian-owned independents with the required capacity to acquire and operate the onshore E&P assets, thus, leading to new upstream consortiums and JV/JOA arrangements as discussed in this paper. More upstream divestments and acquisitions may be expected going forward if the current trend continues. Consequently, the above discussion highlights the legal framework that governs ownership of E&P assets and the assignment of interests in such assets, especially given the recent enactment of the PIA and the implications of the Assignment Guidelines. To efficiently advise parties engaged in the process either through the sale of equity leading to the change in control of an E&P asset owner or a direct assignment, it is essential to understand (i) the nature of these interests, and (ii) the conditions attributable to owning the interests following the divestments and acquisition process. Other essential issues to note include environmental concerns such as future decommissioning and carbon emissions management obligations for the acquiring party.

Following the enactment of the PIA, the nature of the upstream asset and interest that an acquiree obtains has changed. Also, the conditions and terms that attach to that interest have changed accordingly. For example, there are now substantial decommissioning costs and compliance obligations placed on a license holder and consequently a new acquirer of an upstream interest subject to the terms of engagement with other joint venturers under a JV/JOA arrangement. Also, the process for divestment and acquisition is now more detailed, and primarily overseen by the independent upstream regulator, coupled with compliance requirements commencing from the pre-bid stage and continuing until the grant of consent by the Minister of Petroleum Resources. The process and requirements appear to be aimed at increasing the involvement of PIA regulatory agencies in the process and creating greater transparency.

New entrants in the industry will also need to be aware of the new licensing authority of the NMDPRA and its involvement in the final sale of crude oil to offtakers by its issue of a license for sale. While this may be acceptable from a regulatory standpoint, it may increase compliance costs and bureaucratic bottlenecks from a commercial and operator standpoint.⁸¹ These are essential issues to be noted and hopefully addressed by the policymakers considering the potential implications in increasing or decreasing much-needed investment into the Nigerian oil and gas industry. It will be a useful exercise for the regulatory authorities in Nigeria to evaluate the impact of new laws and regulations, for instance through a thorough regulatory impact assessment on the industry, and work with the legislature to achieve a more efficient balance that encourages investment while at the same time fostering better regulatory oversight by the relevant institutions.

81 See Oyewunmi (n14), pp. 249 – 257, on developing ‘Regulatory and Institutional Effectiveness’ in the energy industry context.

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International Oil and Gas Transactions and the Emerging Trend of Upstream Divestments and Acquisitions in Nigeria.

Table of Contents

Abstract

I. Introduction

II. International Oil Companies and Nigerian Upstream Concessions

1. Transfer of Interests in Concessions and E&P Assets

III. Nigerian Upstream Petroleum Operations and Commercial Ventures

1. Regulating Assignments, Divestments, and Acquisitions of E&P Assets

Petroleum Exploration Licence (PEL)

Petroleum Prospecting Licence (PPL)

Petroleum Mining Lease (PML)

Grounds for revocation of a licence or lease under the PIA⁵⁵

2. Divestments and Acquisition of Upstream Assets

What Constitutes an Assignment Under the Ministerial Guidelines

Issues in Contemporary Divestments and Acquisitions

The Process for Transfer of an Interest

Pre-authorization by the NUPRC

Obtaining Ministerial Consent

Examples of recent D&As in Nigeria

IV. Considerations for New Upstream Asset Acquisitions

1. Other Common Factors in Acquiring Upstream Assets

Financing

Equity Investment

Debt Finance

Reserve Based Lending (RBL)

Contractor Financing

Trading

Decommissioning

V. Conclusion

International Oil and Gas Transactions and the Emerging Trend of Upstream Divestments and Acquisitions in Nigeria.

Table of Contents

Abstract

I. Introduction

II. International Oil Companies and Nigerian Upstream Concessions

1. Transfer of Interests in Concessions and E&P Assets

III. Nigerian Upstream Petroleum Operations and Commercial Ventures

1. Regulating Assignments, Divestments, and Acquisitions of E&P Assets

Petroleum Exploration Licence (PEL)

Petroleum Prospecting Licence (PPL)

Petroleum Mining Lease (PML)

Grounds for revocation of a licence or lease under the PIA55

2. Divestments and Acquisition of Upstream Assets

What Constitutes an Assignment Under the Ministerial Guidelines

Issues in Contemporary Divestments and Acquisitions

The Process for Transfer of an Interest

Pre-authorization by the NUPRC

Obtaining Ministerial Consent

Examples of recent D&As in Nigeria

IV. Considerations for New Upstream Asset Acquisitions

1. Other Common Factors in Acquiring Upstream Assets

Financing

Equity Investment

Debt Finance

Reserve Based Lending (RBL)

Contractor Financing

Trading

Decommissioning

V. Conclusion

Grounds for revocation of a licence or lease under the PIA⁵⁵