The oil and gas sector remains the mainstay of Nigeria’s economy, accounting for 75% of the country’s revenue and 90% of its total export earnings.[1] However, despite boasting a large oil and gas reserves base, there remains several undeveloped oil and gas assets.[2]

A key policy of government in tackling this underdevelopment, has been the indigenisation policy of the Federal Government of Nigeria (FGN) under which participatory rights to oil acreages were allocated by the President to indigenous companies on a sole risk basis, thereby entitling them to carry out sole risk petroleum operations under Oil Mining Leases (OMLs) held by the NNPC and the marginal fields policy passed into law pursuant to the Petroleum (Amendment) Decree of 1996[3].  

The FGN’s oil and gas indigenisation policy was essentially aimed at ensuring that the ownership and control of concessions and/or acreages are provided to Nigerians, in a bid to encourage growth in local participation in the exploration and development of oil and gas resources.  Thus, the aim of the marginal field program was to open up the upstream oil and gas sector to more indigenous participation, in a manner that positively impacts and contributes to the expansion of Nigeria’s oil reserves’ production,  encourage economic development through revenue generation, promotion of indigenous participation in oil and gas sector and discouragement of the abandonment of depleting oil fields in Nigeria.

In this regard, Paragraph 17 of the First Schedule of the Petroleum Act (as amended) [4] provides that:

“(1)      The holder of an oil mining lease may, with the consent of and on such terms and conditions as may be approved by the President, farm out any marginal field which lies within the leased area.

(2)        The President may cause the farm-out of a marginal field if the marginal field has been left unattended for a period of not less than ten years from the date of the first discovery of the marginal field.

(3)        The President shall not give his consent to a farm-out or cause the farm-out of a marginal field unless he is satisfied- 

  • that it is in the public interest so to do, and, in addition, in the case of a non- producing marginal field, that the marginal field has been left unattended for an unreasonable time, not being less than ten years; and  
  • that the parties to the farm-out are in all respects acceptable to the Federal Government. 

(4)        For the purposes of this paragraph-

“farm-out” means an agreement between the holder of an oil mining lease and a third  party which permits the third party to explore, prospect, win, work and carry away any petroleum encountered in a specified area during the validity of the lease.

In pursuance of the government’s objectives and as part of its efforts to reach its three million barrel per day output target by 2023, the FGN, on 1 June 2020, through the Department of Petroleum Resources (DPR), announced the launch of a new marginal field bid round[5] for fifty-seven available marginal fields[6]. The DPR also released the Guidelines for Farm-out and Operation of Marginal Fields 2020 (the “Guidelines”) covering the bid process, the award and farm-out of the marginal fields.

As in all previous guidelines before it, Paragraph 5.4.6 and 5.4.8 of the Guidelines provides for only indigenous ownership of marginal fields, while paragraph 12.8 of the Guidelines requires that awardees operate the asset at their “sole risk”, independent of the government, but with the understanding that the government reserves the right to a participating interest at any time.

With the enactment of the Nigerian Oil and Gas Industry Content Development Act 2010 (NOGICD Act), it has become easier to ascertain what makes a company an “indigenous company”. Section 106 of the NOGICD Act defines a ‘Nigerian Company” as “a company formed and registered in Nigeria in accordance with the provision of Companies and Allied Matters Act with not less than 51 % equity shares by Nigerians”.

Thus, only a ‘Nigerian company’ within the context of the NOGICD Act is eligible to participate in the 2020 Bid Round.

This Article seeks to give its reader an overview of the legal framework for the operation of marginal fields in Nigeria and the requirements awardees must take note of.

What is a Marginal Field?

A marginal field is such fields as the President may from time to time identify as marginal fields”.[7] The President is thus vested with the powers to designate marginal fields. As already mentioned above, an oil field must have been left unattended for a period of not less than ten years from the date of its first discovery to qualify for designation as a marginal field.[8]

In addition to the above, the Guidelines provides that the field in question must also have one or more of the following characteristics to be considered “marginal” [9]:

  • field not considered by its license holders for development because of assumed marginal economics under prevailing fiscal and market terms;
  • field with at least one exploration well drilled and have been reported as oil and or gas discovery for more than 10 years with no follow up appraisal or development effort;
  • field with crude oil characteristics different from current streams (such as crude with very high viscosity and low API gravity), which cannot be produced through conventional methods or current technology;
  • field with high gas and low oil reserves;
  • field that has been abandoned by the leaseholders for upwards of three years for economic or operational reasons; or
  • field that the present leaseholders may consider for farmout as part of portfolio rationalization programmes.

Award of Marginal Fields

Marginal fields are essentially fields that are “farmed out” of an oil mining lease. According to Paragraph 17(4) of the Petroleum Act,  “farm-out” means an agreement between the holder of an oil mining lease and a third party which permits the third party to explore, prospect, win, work and carry away any petroleum encountered in a specified area during the validity of the lease.” Effectively, the nature of a marginal field award is similar to that of a sub-lease whereby a lessee (in this case, the OML holder) creates a sub-lease between itself (as farmor) and the marginal field awardee (as farmee), with the consent of the head lessor (the federal government). Like the typical sub-lease, such sublease must devolve from, and be in accordance with the interest conveyed in the head lease.[10]

The terms of the sub-lease will be recorded in a farm-out agreement to be negotiated with the original OML holder, which will allocate responsibilities and liabilities as between the area holders, as well as the royalty payable and terms for accessing infrastructure.

In essence, the conclusion of the 2020 Bid Round will lead to the negotiation of a farm-out agreement, whereby the OML holder, as farmor, and under the supervision of the FGN, farms out a field under its lease to the marginal field awardee.

The Legal Framework for Marginal Fields in Nigeria

Several laws govern oil and gas exploration and production in Nigeria, including the operation of marginal fields, including:

  • Petroleum Act[11];
  • Nigerian Oil and Gas Industry Content Development Act 2010
  • Oil Pipelines Act[12];
  • Petroleum Profits Tax Act[13];
  • Mineral Oils (Safety) Regulations, 1997;
  • Petroleum (Drilling and Production) Regulations[14];
  • Nigerian National Petroleum Corporation Act[15];
  • Associated Gas Re-injection Act[16];
  • Flare Gas (Prevention of Waste and Pollution) Regulations 2018;
  • Deep Offshore and Inland Basin Production Sharing Contract Act[17];
  • Marginal Fields Operations (Fiscal Regime) Regulations, 2005; and
  • Oil Block Allocation to Companies (Back – in-Rights) Regulation 2019

The Petroleum Act[18]

The Petroleum Act is the principal legislation for petroleum activities in Nigeria. It was created for the purpose of regulating the exploration of petroleum from the territorial waters and the continental shelf of Nigeria, and contains provisions which vests the ownership and control of all petroleum derivable from all lands whether in Nigeria, under its territorial waters, forms part of its continental shelf or its exclusive economic zone, in the Federal Government, and for all other matters incidental thereto. As mentioned previously, the power to designate and farm out marginal fields is vested in the President of Nigeria under the Petroleum Act.

Nigerian Oil and Gas Industry Content Development Act 2010

In furtherance of the indigenisation framework provided by the Petroleum Act, the Nigerian Oil and Gas Industry Content Development Act 2010 was passed to further the FGN’s policy objectives for the development of local content by Nigerian companies in the petroleum industry.

Based on the definition of a ‘Nigerian Company” under the NOGICD Act, a Nigerian company that enters into a joint venture with a foreign company for the purpose of winning a marginal field award, shall retain a minimum of 51% ownership interest in the JV.[19]

This allows marginal field owners to partner with foreign companies with the requisite technology, technical expertise and buoyant balance sheet to farm into their operations to develop their respective assets. They also have the liberty to enter a Joint Venture (JV) with local or foreign companies.

Furthermore, marginal field awardees are expected to adhere to the local content requirement in terms of involvement of competent Nigerians in their management as well as commitment to training and growth of indigenous capability, manpower and local input in the provision of materials and services to the industry.[20]

Oil Pipelines Act[21]

As mentioned above, a “farm-out” grants the rightsto “explore, prospect, win, work and carry away any petroleum”. Transportation of such petroleum won is relevant to holders of a marginal field. In this regard, the Oil Pipelines Act provides as follows:

“The Minister may, subject to the provisions of this Act grant- (a) permits to survey routes for oil pipelines; and (b) licences to construct, maintain and operate oil pipelines. Provided that each licence shall be issued in respect of and authorise this construction, maintenance and operation of one pipeline only”.[22]

Section 11 goes further to provide that:

For the purpose of this Act, an oil pipeline means a pipeline for the conveyance of mineral oils, natural gas and any of their derivatives or components, and also any substance (including steam and water) used or intended to be used in the production or refining or conveying of mineral oils, natural gas, and any of their derivatives or components.”

Once granted, a permit to survey shall entitle a marginal field awardee to use the necessary equipment and vehicles, to enter the awarded field, in order to survey and take levels of the land, dig and bore into the soil and to cut or remove such trees and other vegetation as may impede the transportation process[23]. Upon successful conclusion of a survey, an application may be made to the Minister for the grant of an oil pipeline licence to construct and operate oil pipelines.[24] It is however the industry practice for a marginal field awardee to negotiate with for the use of an OML holder’s existing infrastructure.

Nonetheless, such actions carry with them legal, social and environmental implications, and the marginal field awardee must take all reasonable steps to avoid unnecessary damage to any land entered upon and any buildings, crops or profitable trees thereon,  and to make compensation to the owners or occupiers for any damage done under such authority and not made good.[25] This obligation extends to land not covered in the lease or “sub-lease”, albeit, such claim must be for compensation and not damages or any other relief.[26]

Where an offence under the Act is proved to have been committed with the consent or connivance of or to be attributable to any neglect on the part of, any director, manager, secretary, or other similar officer of the body corporate, or any person purporting to act in any such capacity, he, as well as the body corporate, shall be deemed to be guilty of that offence and shall be liable to be proceeded against and punished accordingly.[27]

Petroleum Profits Tax Act[28]

The Petroleum Profits Tax Act (as amended) (PPT Act) makes provisions for the determination of the tax payable on the chargeable profits of companies involved in the upstream activities of exploration, drilling, extraction and transportation of crude oil. The PPT Act provides that:[29]

“1)     The assessable tax for any accounting period of a company shall be an amount equal to 85% of its chargeable profits of that period.

 (2)    Where a company has not qualified for treatment under paragraph 6 (4) of the Second Schedule to this Act, that is to say, where a company has not yet commenced to make a sale or bulk disposal of chargeable oil under a programme of continuous production and sales as at 1 April 1977, its assessable tax for any accounting period during which it has not fully amortised all pre-production capitalised expenditure due to it less the amount to be retained in the book as provided for in paragraph 6 of the Second Schedule to this Act shall be 65.75% of the chargeable profits for that period”.

Thus, the PPT Act imposes tax upon profits from petroleum proceeds in Nigeria to the tune of 85% of its chargeable profits for that period[30], with a reduced rate of 65.75% payable within the first five years, therefore allowing all pre-production capital expenses to be fully paid off.

It is the profits generated by companies that engage in the winning of, obtaining and transportation of petroleum or chargeable oil in Nigeria by or on behalf of a company for its own account by any drilling, extracting or other like operations or process, not including refining at a refinery, in the course of a business carried on by the company engaged in such operations and all operations incidental thereto and any sale or any disposal of chargeable oil by or on behalf of the company that is chargeable.[31]

Section 60 of the PPT Act previously provided that:[32]

“No tax shall be charged under the provisions of the Personal Income Tax Act or any other Act in respect of any income or dividends paid out of any profits which are taken into account, under the provisions of this Act, in the calculation of the amount of any chargeable profits upon which tax is charged, assessed and paid under the provisions of this Act.”

Thus exempting dividends received from after-tax profits of upstream petroleum operations from taxes.

However, by reason of deletion of this provision under section 24 of the Finance Act 2019, marginal field awardees will now be required to withhold tax from dividends paid to their shareholders. Also, Personal Income Tax Act and other tax laws can now be levied on the income or dividends paid out of any profits to which the PPT Act applies. This is likely to impact the amount available as returns to investors/shareholders of marginal field awardees.

Mineral Oils (Safety) Regulations, 1997[33]

The Mineral Oils (Safety)Regulations (Oils Safety Regulations) provide for precautions to be taken by all Licensees and Lessees in their oil fields for the safe drilling, production, storage and handling of mineral oils.[34]

All operations of marginal field awardees are therefore required to be in accordance with the Oils Safety Regulations by ensuring that any field development plan proposed for the production of a marginal field provides for the safe conduct of all operations and the safety and health of employees. 

Additionally, it is required that every drilling, production and other operation carried out by a marginal field awardee shall conform with good oil field practice which, for the purpose of the Oils Safety Regulations, shall be considered to be adequate if it conforms with the appropriate current Institute of Petroleum Safety Codes; or the American Petroleum Institute Codes; or the American Society of Mechanical Engineers Codes; or any other internationally recognized and accepted systems.[35]

Petroleum (Drilling and Production) Regulations, 2006[36]

The Petroleum (Drilling and Production) Regulations (as amended)[37] provides that:

“The holder of an oil exploration licence, oil prospecting licence or oil mining lease may not export samples or specimens abroad except with the written permission of the Director of Petroleum Resources and subject to such conditions as he may prescribe.[38]

Accordingly, since a marginal field devolves from an OML, a marginal field awardee is bound by the above law and is not permitted to export any sample or specimen of petroleum abroad without the prior written consent of the DPR.[39]  

Additionally, there is the requirement to comply with all existing safety regulations and all such instructions as may, from time to time, be given in writing by the DPR for securing the health and safety of persons engaged on or in connection with operations under his license or lease.[40]

It is also noted that a marginal field awardee is obligated to submit a report of the progress of its operations containing particulars of the contents of the record required to be kept under the Drilling and Production Regulations within 21 days after the end of each month to the Director of Petroleum Resources and Director of Geological Survey, in a form from time to time approved by the DPR,   and in addition a statement of the areas in which the licensee or lessee has carried out any geological or geophysical work and an account of the work in question.[41]

Nigerian National Petroleum Corporation Act[42]

The Nigerian National Petroleum Corporation Act established the Nigerian National Petroleum Corporation (NNPC)  to engage in all commercial activities relating to the Petroleum industry and to enforce all regulatory measures relating to the general control of the Petroleum sector through its Petroleum Inspectorate department.[43]

Under Section 10 of this Act, the Petroleum Inspectorate (now the DPR) was created as an integral part of the NNPC and entrusted with the regulation of the petroleum industry.

Also, the Minister is responsible for issuing permits and licenses for all activities connected with petroleum exploration, exploitation, refining, storage, marketing, transportation and distribution[44].

Associated Gas Re-injection Act[45] and the Flare Gas (Prevention of Waste Pollution) Regulations, 2018

The Associated Gas Re-Injection Act places a duty on companies producing oil and gas in Nigeria to submit detailed plans for implementation of gas re-injection and to prohibit gas flaring.[46]

Amongst others, it provides that no company engaged in the production of oil or gas shall after 1 January 1984 flare gas produced in association with oil without the permission in writing of the Minister.[47] Thus, awardees may only flare gas in particular fields upon application for same and receipt of a certificate issued by the Minister to that effect.

Such certificates are issued upon payment of the required sum as the Minister may from time to time prescribe for every 28.317 standard cubic metre (SCM) of gas flared.[48] The payment shall be made in the same manner and be subject to the same procedure as for the payment of royalties to the Federal Government by companies engaged in the production of oil.[49]

It should be noted that failure to comply with the provisions of the Act makes the concessions in question liable to forfeiture[50].

The Minister may also order the withholding of all or part of any entitlements of any person towards the cost of completion or implementation of a desirable re-injection scheme or the repair or restoration of any reservoir in the field in accordance with good oil-field practice.[51]

The Flare Gas (Prevention of Waste Pollution) Regulations, 2018 (Flare Gas Regulation) was made pursuant to section 9 of the Petroleum Act and Section 5 of the Associated Gas Reinjection Act and aims to reduce the environmental and social impact caused by the flaring of gas, protect the environment, prevent waste of natural resources and create social and economic benefits form flare gas capture by creating a regime that allows the FGN grant permit to access glare gas to permit holders on an exclusive basis form one or more flare sites. Thus, no Producer shall flare gas from any facility operated except pursuant to a certificate issued by the Minister.[52] The Flare Gas Regulation also closed the gap in the Associated Reinjection Gas Act by providing flare payment to be $2 (two United States Dollar) per 28.317 standard cubit feet of gas flared where 10,000 barrels or more of oil  is produced per day in any OML or marginal field, $0.50 (fifty United States Cent) per 28.317 standard cubit feet of gas flared where less than 10,000 barrels of oil  is produced per day in any OML or marginal field.

The Flare Gas Regulation reiterated the right of the FGN to take natural gas produced with crude oil free at the flare and without payment of royalty.[53] The Producer shall also maintain a daily log of all associated natural gas produced from the OML or marginal field[54] and the flaring and venting of associated natural gas produced and shall submit the logs to the DPR within 21 days following the end of each month[55].

Furthermore, an obligation is placed on Producers to keep a Flare Gas Data which the DPR may request the Producer to provide within 30 days of request.[56] It is an offence to supply inaccurate or incomplete flare gas data. [57]

In the event of a conflict or inconsistency between any of the provisions of the Flare Gas Regulations and the provisions of any preceding regulations issued by the Minister in relation to the flaring of natural gas, the provisions of the Flare Gas Regulations shall prevail to the extent of such conflict or inconsistency”[58]

The Producer under the Flare Gas Regulations is “a holder of on Oil Mining Lease or an allottee of a marginal field[59]

Deep Offshore and Inland Basin Production Sharing Contract Act[60].

The Deep Offshore and Inland Basin Production Sharing Contracts Act 2019 (DOIBPSCA) is the extant law for charging royalties in the deep offshore areas.

The  DOIBPSCA establishes the legal framework for deep offshore and inland oil activities, including the applicable royalties and key fiscal terms, with its key objective being to maximize government’s revenue from Production Sharing Contracts (PSCs) in the face of changing prices of oil and gas.

The DOIBPSCA defines the PSC as “any agreement or arrangements made between the Corporation or the holder and any other petroleum exploration and production company or companies for the purpose of exploration and production of oil in the Deep Offshore and Inland Basin”.

By virtue of its 2019 amendment, the DOIBPSCA now provides for the following:
1.       Flat offshore royalty rate: A 10% royalty will apply on production from fields with a water depth of greater than 200 metres.
2.       Reduced rate for frontier and inland basins: Frontier and inland basins will be subject to a 7.5% royalty.

3.       Oil price royalty: The amendment also imposes an additional royalty rate to account for increase in price of crude in excess of $20 per barrel. A new royalty is also payable on the basis of the oil price with an additional rate payable of 2.5% for an oil price of US$ 20 – 60 per barrel; 4% for an oil price of US$ 61 – 100 per barrel; 8% for an oil price of US$ 101 – 150 per barrel; and 10% above US$ 150.

It is important to note that section 18 of the amended DOIBPSCA provides for a penalty for non-compliance with the Act. It indicates a penalty for a term not less than five years or an option of a fine not less than five hundred million naira.

Furthermore, the DOIBPSCA provides that all PSCs shall be reviewed every 8 years by the NNPC.[61]

Marginal Fields Operations (Fiscal Regime) Regulations, 2005

We note that a different fiscal regime from that of the DOIBPSCA may apply to marginal fields pursuant to the provisions of the Marginal Fields Operations (Fiscal Regime) Regulations, 2005[62] (Marginal Field Regulations), which provide for the royalty rates applicable to all marginal field operations in Nigeria.

Paragraph 2 of the Marginal Field Regulations provides categories of royalties due to the government, based on the level of production undertaken in marginal fields, as follows:

Production (barrels of oil per day)Royalty rate (%)
Below 5,000 bopd2.5%
5,000 and 10,000 bopd7.5%
10,000 and 15,000 bopd12.5%
15,000 and 25,000 bopd18.5%

The fiscal provisions stated above supersede any other fiscal terms existing for marginal field operations in Nigeria.

In addition, Paragraph 3 of the Marginal Field Regulations permits the commingling of fluid production from two or more reservoirs, following the approval of the Department of Petroleum Resources, and based on the compatibility of the reservoir fluids and pressures.

Where a marginal filed is considered a deep offshore field (i.e. greater that 200 metres water depth), the question arises whether the provisions of the Marginal Field Regulations or DOIBPSCA will apply to that field as to royalties. We are of the view that the provisions of the Marginal Field Regulations will apply to any marginal field as of right no matter the terrain of the field. This is because the Marginal Field Regulations is the principal regulation enacted under enabling law to provide specifically for marginal fields and supersede any other fiscal terms existing for marginal field operations in Nigeria whether before or after the enactment of the Marginal Field Regulations unless such law or regulation was made pursuant to the same Petroleum Act and expressly overrides the provisions of the Marginal Field Regulations. This is based on the principle of hierarchy of statutes as espoused in the decision of Labiyi v Anreriola[63], that where a law has been made on a particular matter, another law cannot be made to override the provision of the previous law without expressly repealing the previous law as the latter law would be regarded as inconsistent with the former law. This is even more so where the previous law is the principal statute dealing with the subject matter.

The above ultimately will be of no moment for marginal fields, as the Guidelines provide for renegotiation of terms of development of deeper pools discovers as a result of deep drilling. Thus, we are of the view that the royalty regime applicable to marginal fields will take into cognizance the terrain of the field to ensure a commensurate rate of return to investors.

Oil Block Allocation to Companies (Back – in-Rights) Regulation 2019

Paragraph 35 of the First Schedule to the Petroleum Act provides (among others) that:

“If he considers it to be in the public interest, the Minister may impose on a licence or lease to which this Schedule applies special terms and conditions not inconsistent with this Act including (without prejudice to the generality of the foregoing) terms and conditions as to participation by the Federal Government in the venture to which the licence or lease relates, on terms to be negotiated between the Minister and the applicant for the licence or lease;

The Guidelines make it clear that the government back-in-rights provided for in the Petroleum Act apply to marginal fields as marginal field awardees shall “operate on a sole risk basis. However, Government reserves the right to a participating interest at any time[64].

The manner of exercise of the government’s back-in-rights are provided for in the Oil Block Allocation to Companies (Back–in-Rights) Regulation 2019[65] (Back–in-Rights Regulations).

The Back–in-Rights Regulations apply to all oil prospecting licences and oil mining leases (including marginal fields carved out therefrom) as may be granted from time to time in respect of an application for an award, conversion or renewal of an oil prospecting license or oil mining lease.[66]

Paragraphs 2 and 3 of the Back–in-Rights Regulations provide that:

2.  The Federal Government:

“(а)      shall exercise its right to participate in any venture to which an oil prospecting license or oil mining lease relates by acquiring up to five-sixths of the interest of the applicant (rounded up to the nearest whole percentage point of total interest in such license or lease) in the relevant oil prospecting license or oil mining lease; and

(b)        may exercise its right to participate at the commencement of a license, or upon conversion of the license to a lease or at the renewal of a license or a lease.

3. (1) Prior to the acquisition referred to in regulation 2 of these Regulations, the Minister shall invite the applicant for the award, conversion or renewal of a license or a lease for negotiations in respect of the terms for the acquisition of the participating interest by the Federal Government in the license or lease, provided that the applicant for the license or lease shall be given at least 14 days’ notice of the date, time and venue of such negotiations with the Minister.

It is useful to note that while the Back–in-Rights Regulations provide that government may exercise its back-in-rights “at the commencement of a license, or upon conversion of the license to a lease or at the renewal of a license or a lease”, the Guidelines provide that this right may be exercised “at any time”.

It has been held by the Nigerian courts[67] that the Minister, while negotiating the terms of its participation must take into consideration the huge sums of money spent by the applicant, and ensure that it is recompensed by the government in respect of its participation in acceptable terms. In this regard, paragraph 2 of the Back–in-Rights Regulations provides that all unrecovered Proven Costs of the asset holder shall be recovered (without interest) from the government’s participating interest share of revenues from the lease. Proven Costs in the context of the regulations mean expenditures made and obligation incurred exclusively, wholly and necessarily for the purpose of carrying out petroleum operations in respect of the said license or lease or field.


In awarding marginal fields to indigenous operators, the government hopes to not only increase oil production, but also encourage indigenous capacity building in the upstream petroleum sector.

However, more still needs to be done, and many factors have constrained the activities of marginal field operators, especially in relation to the lack of funding, inadequate technical expertise, and government policies on royalties and petroleum taxes.

The 2020 marginal field bid round, however, remains a welcome development and it is hoped that the additional production from these fields will boost the nation’s daily crude production output and government revenue, for the benefit of all Nigerians and their joint venture partners.

Written by Olayemi Anyanechi, Joshua Olorunmaiye, and Elizabeth Ero

The information and opinions in this publication are provided for general information only. They are not intended to constitute legal or other professional advice. If you would like additional information, please contact the author at [email protected]

© All Rights Reserved. Sefton Fross is a leading full-service law firm in Nigeria internationally recognised for its expertise in corporate, commercial and mergers and acquisitions.

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