The impact of the Covid-19 pandemic on production sharing contracts in Nigeria

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Inifome Usenu

Nigerian Petroleum Development Company, Benin City


There have been significant concerns regarding the current and long-term effects of the novel coronavirus (‘Covid-19’) on international trade and the global economy, following the declaration of Covid-19 as a global pandemic in March 2020. Of particular importance to Nigeria is the adverse effect that this global pandemic has had on the price of crude oil in the international market (which has been in freefall in the past few months), considering how crucial revenues from the sale of crude oil is to the sustenance of the Nigerian economy.[1]

The upstream oil and gas activities, which is contractually governed by the PSC is greatly affected by the Covid-19 pandemic. Following the recent amendment of the PSC Law (Deep Offshore and Inland Basin Production Sharing Contract Cap D3 LFN 2004 (Amendment) Law),the gains which were expected under the amended law seem to have been eroded by the Covid-19 pandemic due to the low price of crude oil in the global market.

Across the world, the activities of exploration, development, production and marketing of oil and gas and their associated products are conducted within the framework of host government laws and commercial contracts. In most countries, the state claims the title to the hydrocarbons within its territory. In other cases, the landowner may own the title. Generally, the state establishes the commercial, legal and fiscal framework within which the exploitation of the hydrocarbons takes place. The state and the oil companies are normally party to these agreements.

In Nigeria, the contracts could be in the form of Joint Operating Agreement (JOA), Production Sharing Contract (PSC) orService Contract (SC). JOA is defined as a contract between co-tenants or separate owners of oil and gas properties that are jointly operated. It is an agreement between two owners or among several concurrent owners for the operation of a leasehold for oil, gas or other minerals. The agreement calls for the development of the lease or the premises by one of the parties to the agreement, who designated as operator or unit operator for the joint account. All parties share in the expenses of the operations and in the proceeds resulting from the development.[2]

Service contract (SC) is an agreement between NNPC and the MNOC (the Contractor) by which the latter undertakes to carry out exploration activities and development, and at the option of the Government, production operations within the agreed contract period. The Contractor has no title to crude oil, but has the right to be repaid his investments plus an agreed mark-up usually in cash or crude oil if and when oil is discovered in commercial quantities and produced.

PSC is a contract where the state, as the owner of mineral resources, engages a multinational oil company (MNOC) as a contractor to provide technical and financial services for exploration and development operations. The state is traditionally represented by the government or one of its agencies such as the National Oil Company [Nigerian National Petroleum Corporation (NNPC)]. The MNOC acquires an entitlement to a stipulated share of the oil produced as a reward for the risk taken and services rendered. The state, however, remains the owner of the petroleum-produced subject, with only to the contractor's entitlement to its share of production. The government (NNPC) usually has the option to participate in different aspects of the exploration and development process. In addition, PSCs frequently provide for the establishment of a joint committee where both parties are represented and which monitors the operations.[3]

Production sharing contracts (PSC)

The nature and advantages of the PSC

Prior to 1993, the predominant contract model for the purpose of exploration, development and production of Nigerian oil resources was the JOA (joint venture arrangement), under which the Government of Nigeria, acting through the National Oil Company (NNPC), had to contribute substantial counterpart funding (cash calls) to meet equity participation in the joint ventures (JV), in which the government invariably had majority shares.

Consistent inability of the Nigerian government to adequately meet its obligations under the JV arrangements led it to explore other modes of developing the nation's vast oil resources (current reserves estimated at 25 billion bbl).[4]

The PSC arrangement provided a ready solution for both government and the operators. While government no longer needs to meet its periodic cash call obligations to Joint Venture programmes, the operators on the other hand readily embraced the varying degree of fiscal incentives and convenient work programs offered by the PSC law.

Prior to 1999, there was no specific legislation/enactment, which dealt with the Nigerian PSC arrangement. All that existed were agreements between NNPC and under listed contracting companies’ regulations, pronouncements and official statements, which went to reinforce the applicability of the PSC arrangement.

This state of affairs provided the operators with problems, which were legal enforceability and difficulty in securing financing on the basis of mere agreements that were not backed by law. The Deep Offshore and Inland Basin Production Sharing Contracts Decree No. 9 of 1999 as amended, referred to as the PSC law, finally came about after persistent pressure by affected operators, demanding a formal law to give legislative backing to fiscal incentives, as guaranteed by the government under the PSC arrangement.[5]

PSCs are distinguished from other types of contracts in two ways. First, the MNOC carries the entire exploration risk. If no oil is found the company receives no compensation. Second, the government owns both the resource and the installations. In its most basic form, a PSC has four main properties. The MNOC pays a royalty on gross production to the government. After the royalty is deducted, the MNOC is entitled to a pre-specified share (eg 80 per cent) of production for cost recovery. The remainder of the production, so called profit oil, is then shared between the government and MNOC at a stipulated share (eg 65 per cent for the government and 35 per cent for the MNOC). The contractor then has to pay income tax on its share of profit oil.[6]

In view of the foregoing, the essence of PSC is that NNPC engages a competent contractor to carry out petroleum operations on NNPC’s wholly held acreage. The contractor undertakes the initial exploration and production risks and recovers his costs if and when oil is discovered and extracted.

Under the Nigerian PSC, the contractor has a right to only that fraction of the crude oil allocated to him under the cost oil (oil to recoup production cost) and equity oil (oil to guarantee return on investment). He can also dispose of the tax oil (oil to defray tax and royalty obligations) subject to NNPC’s approval. The balance of the oil, if any (after cost, equity and tax), is shared between the parties (profit oil).Accordingly, the PSC ultimately divides the oil production between the host government and the oil company (contractor), after allowing the contractor to recover some or all of its past costs. The PSC has flexibility, through the cost recovery, production share and tax elements.

The legal status and scope of the PSC    

The legal status of the PSC is that it is a risk contract where the contractor carries out petroleum operations and recovers its cost from discovered crude oil.

The development of PSC in Nigeria is highlighted below:

  • The first PSC was executed in 1972 between the National Oil Company and Ashland Oil Company.

  • Ashland Oil Company PSC was terminated in 1998 and replaced with the Addax PSC in 1999.

  • After the Addax PSC, there are three model PSCs in Nigeria: 1993, 2000 and 2005.[7]The fourth model PSC was that of 2007.

The scope of the PSC covers the following areas:

  • Contractor is required to obtain NNPC prior approval on financial and technical issues.

  • Contractor is appointed as exclusive company to conduct petroleum operations.

  • Contractor economic interest is guaranteed in crude oil deposit, if crude oil is discovered.

  • Contractor is required to employ and train Nigerians to acquire technology.

  • Contractor is engaged in Petroleum operations pursuant to the Petroleum Profit Tax Act Cap 354 LFN, Companies Income Tax Act Cap 60 LFN and other relevant laws.[8]

Comparative analysis of PSCs in selected jurisdictions

The comparative analysis is based on each country’s production sharing ratios. This is the percentage of government take home of oil and gas produced. The production sharing ratio can be viewed as the equivalent of the ‘purchase price’. It is the price at which a host government is willing to sell its sovereign hydrocarbon rights.[9]

Therefore, the underlying issue is the profit margin of the production sharing contractor compared to that of other operators. A comparison of production sharing contract summarised below shows that different arrangements of royalty oil, cost oil, tax oil and profit oil and in some contracts the absence of cost oil or tax oil can be made to the satisfaction of both parties to the PSC.[10]

Summary of relevant arrangements


It is a constitutional requirement that no more than 49 per cent of oil production can be received by an IOC. The sharing ratio reduces on a sliding scale based on oil production (a stepped reduction of the contractor’s share from 40 per cent to 12 per cent). Natural gas is subject to different rules and uses an investment rate of return (a stepped reduction from 100 per cent contractor share to 10 per cent IRR). The statutory requirement relating to oil is a cumulative, not periodical, limit and an IOC has been able to improve the economics of a project by negotiating a 65 per cent share in the early years of production.[11]

In Algeria for instance, the industry is governed by two main laws. Depending on the date on which the petroleum contract was signed, the Algerian fiscal regime applicable to the oil and gas upstream industry is governed either by Law No. 86-14 dated 19 August 1986 or Law No. 05-07 dated 28 April 2005 (as amended by Ordinance No. 06-10 dated 19 July 2006). The normal rate of royalty under Law No. 86-14 is 20 per cent and can be reduced to 16.25 per cent and 12.5 per cent corresponding to different zones of the Algerian territory. The royalty rate can be reduced beyond these by order of the Ministry of Finance, to a limit of ten per cent. The barest reduction is still higher than the seven per cent pre-PIB Royalty in Nigeria. Other taxes applicable to the IOCs are income tax at 38 per cent, TEP (Tax on Extraordinary Profits) or windfall tax at rates ranging from five per cent to 50 per cent.

Under Law No. 05-07: Royalties rate varies from 5.5 per cent for production of 20,000BOE/day to 23 per cent for production of 100,000BOE/day or over (where BOE is barrels of oil equivalent). Instructively, all the Majors in Nigeria have daily production in excess of 100,000 BOE but have consistently paid royalty rate of seven per cent. There is surface fee or tax which ranges from $50 to $100 per square kilometre, Petroleum Income Tax (PIT) ranging from 30 per cent to 70 per cent, Additional Profits Tax (APT) of 15 per cent for profits reinvested and 30 per cent for other profits. There are ancillary taxes like gas flaring tax. Nigeria has nowhere near this regime of taxes.[12]


Angolan legislation requires Sonangol to take a minimum of 51 per cent in all contracts unless in water depths greater than 150 meters when the 51 per cent is reduced. Sonangol is awarded, by Concession Decree, 100 per cent of a contract and Sonangol takes a percentage in a group acquiring the PSC, working as a full partner, paying its share of E&P costs. Sonangol’s production share varies from 0 per cent to 25 per cent. This will fluctuate depending on total production.[13]

Angola has an even more onerous tax regime. There are three types of contracts: PSA, Partnerships and Risk Service Contracts, RSCs. Taxes applicable to all oil regimes are Petroleum Income Tax (PIT) 50 per cent for PSA and 65.75 per cent for Partnerships and RSCs. Surface fee is $300/sq km and Training Tax Contribution, TTC, $0.15 per barrel for production companies, as well as companies engaged in refinery and processing of petroleum; $100,000 a year for companies owning a prospection license and $300,000 a year for companies engaged in exploration. For Partnerships, Petroleum Production tax, PPT (equivalent to royalty) is 20 per cent while Petroleum Transaction Tax is 70 per cent. A separate regime of taxes, equally strict, is applicable to the Angolan LNG Project.[14]


Clause 7 of Egypt’s Model Concession Agreement of 2000 leaves the production sharing ratio to be negotiated. It provides for a sliding scale ratio based on production levels. Historically, the NOC has received between 60 per cent and 90 per cent of production. An Apache Corp PSC signed in 1997 gave the Contractor 30 per cent (on 0–20,000 bopd) to 17 per cent (over 100,000 bopd). Offshore ratios may be more favourable to the contractor (depending on water depth). Egypt is a rare example of a country that does not take a participation interest in the contractor.[15]

Egypt charges a royalty rate of 20 per cent, which may be reduced according to the double tax treaties with other countries. Oil exploration and production tax is 40.55 per cent, among so many other taxes including production bonuses.[16]


The production ratio is negotiated in each PSC. Under old laws, production was split 70:30 in favour of Societe Nationale des Hydrocarbures (Cameroon’s NOC) over 60,000 bopd. In 1995 offshore licensing around this was increased to 60:40.

Democratic Republic of Congo (DRC)

The production ratio is negotiable and is a function of increased production.[17]

Equatorial Guinea

After royalties and cost recovery, profit oil is shared between the contractor and the NOC in ratios varying from 90:10 to 40:60 based on a pre-tax rate of return.


After royalties and cost recovery oil has been recovered, profit is shared between the contractor and the host government at negotiable rates linked to a sliding scale of daily production. The host government’s ratio rises to 45 per cent on over 45,000 bopd.


After royalties, cost recovery oil and tax oil has been recovered, profit is shared between the contractor and the host government on sliding scale of daily production.[18]

Essential provisions of the contract


The term of the contract is for 30 years inclusive of 10 years exploration and 20 years Oil Mining Lease (OML) period. However, the contract may be terminated if at the end of the sixth year (from the effective date of the contract) the agreed Work Programme has not been substantially executed, or either party gives a notice of not less than 90 days for termination of the contract (on grounds permitted by the contract terms). However, the 2005 PSC reduced the exploration phase for acreages located onshore and in shallow waters to five years.[19]

Work programme

The Contractor shall prepare a work programme and budget for the approval of the Management Committee. The Contractor also provides the required funds for the execution of the work programme. The work programme shall also be secured by a performance bond covering the entire budget of the work programme.

The minimum work programme during the exploration period shall be as follows:


Contract years

Amount to be expended


1 – 3



4 – 6



7 – 10



If during any period of the contract years, the contractor spends less than the required expenditure, an amount equal to such under-expenditure shall be carried forward and added to the amount to be expended in the following period of contract years.

The 1993, 2000 and 2005 rounds of PSCs however differ on the specifics of the work programme and the effect of the Contractor’s failure to fully execute the same. Whereas the 1993 PSC only specifies the minimum amount of money required to be spent by the Contractor at different stages of the 10 year exploration period, the 2000 PSC clearly specifies the exploratory works to be done, such as the drilling of certain number of exploratory and appraisal wells. If during any period of the contract years the Contractor spends less than the budgeted operating expenditure, the 1993 PSC provides that an amount equal to such expenditure be carried forward and added to the amount to be expended in the following period of contract years. The 2000 and 2005 PSC on the other hand, provides for the forfeiture of the equivalent amount left outstanding under the Performance Bond. Again the 1993 PSC permits the Contractor to finance the operations with loans from external sources subject to the approval of the NNPC and add the interest to the operating expenses, while under the 2000 and 2005 PSC, the Contractor can only borrow at its own cost as it is not be allowed to add the interest to the operating expenses.[20]

Management Committee

A Management Committee (MACOM) is to be established within 30 days from the effective date of the contract. MACOM and its various subcommittees provide orderly direction on all matters pertaining to petroleum operations. The Committee is composed of ten members, five each representing the NNPC and Contractor. NNPC appoints the Chairman, while the Contractor appoints the Secretary who is not a member. The committee meets periodically and takes decisions by unanimity. The NNPC monitors and controls the operations of the PSC companies through MACOM, its technical subcommittee (TECOM), and other subcommittees established by MACOM.

The monitoring and control powers of MACOM and its subcommittees include:

  • the revision, and approval of all proposed work programmes and budgets;

  • the consideration and decision on matters relating to the relinquishment of areas in the contract area pursuant to the provisions of the contract and the petroleum laws;

  • ensuring that the Contractor implements the provisions of the accounting procedure (Annex B), lifting procedure (Annex D), and the procurement and project implementation procedures (Annex E) and all amendments and revisions thereto as agreed by the parties; and

  • ensuring that the Contractor provides an annual budget for capacity building of the NNPC’s personnel in all facets of petroleum operations.[21]

The day to day monitoring of the implementation of these obligations is overseen by National Petroleum Investment Management Services (NAPIMS) on behalf of NNPC.

Title to equipment

All equipment purchased by the Contractor for the petroleum operations shall become the property of NNPC upon arrival in Nigeria.

Exclusion of areas

At the end of the ten year OPL period, the Contractor is required to relinquish 50  per cent of the contract area and the 50 per cent of the contract area to be excluded is to be agreed by both parties, but shall not include any part of the contract area corresponding to surface areas of any field in which petroleum has been discovered in commercial quantity.[22]

The discovery and utilisation of natural gas

In the event of a discovery of a commercially viable quantity of natural gas, the Contractor is required to submit proposals on commercial development of the gas for NNPC’s approval. The 1993 PSC recognizes the Contractor’s right to participate in its development under a ‘separate agreement’, whereas the 2000 and 2005 PSC requires the parties to enter in to a ‘supplemental agreement’, which shall give the Contractor the right to recover the costs and share in the profits.[23]

Employment and training of Nigerian personnel, and local content

The Contractor is required to employ Nigerians only, in all non-specialised positions and employ qualified Nigerians in all specialised positions such as those in exploration, drilling, engineering, production, environmental safety and finance. Qualified non-Nigerians may be employed by the Contractor in such specialised positions, provided that that Contractor shall recruit and train Nigerians for such specialised positions, such that the number of non-Nigerians staff shall be kept to a minimum. The Contractor is also required to submit an annual programme for the training of its Nigerian personnel in accordance with the Petroleum Act. Under the 2000 and 2005 PSCs the Contractor is required to meet a target of 75 per cent overall Nigerian staffing in the first ten years of the contract, and 85 per cent in twenty years. The contracts also require the Contractor to give preference to locally manufactured goods that meet industry standards.


Both contracts require the contractor to set aside an abandonment cost. The 2000, 2005, 2006 and 2007 PSC for example requires the Contractor to provide an abandonment cost either in the form of (i) a standby letter of credit or corporate or bank guarantee or (ii) an abandonment fund in US dollars to be held in an interest bearing escrow account jointly established by the parties at a first class bank.

Financial and fiscal provisions for cost recovery

The allocation of available crude oil for cost recovery is regulated by the provisions of the Petroleum Act as amended, the Petroleum Profits Tax Act[24] (PPTA) (as amended), the Deep Offshore and Inland Basin Production Sharing Contract Act[25] (as amended) and the provisions of the Contract with respect to profit split. The allocation procedure is stated as follows:

a) Royalty oil to be allocated to NNPC in such quantum as will generate an amount equal to the actual royalty payable during each month and the concession rental payable annually.

b) Tax oil to be allocated to NNPC in such quantum as will generate an amount of proceeds equal to the Petroleum Profits Tax (PPT) liability payable during each month. The payment is to be made by NNPC on behalf of both parties.

c) Cost oil to be allocated to the Contractor in such quantum as will generate an amount of proceeds sufficient for the recovery of operating cost.

d) Profit oil, being the balance of available crude after deducting royalty oil, tax oil, and cost oil, to be allocated to each party based on the agreed sharing formula.[26]

Ring-fencing of operating expenses

Operating expenses (OPEX) incurred on different OPLs are ring fenced by statute.[27]However, the 1993 PSC appears to allow the Contractor to consolidate OPEX incurred on different OPLs for Tax purposes only.The 2000, 2005, 2006 and 2007 PSCs expunged the concept of consolidation of OPLs.[28]

Miscellaneous provisions


The contract can be terminated in accordance with its terms. However provisions of the 1993 PSC on termination are fairly liberal to the Contractor, and contains such ambiguous grounds as the (i) ‘material breach’ of Contractor’s obligations and (ii) failure of the contractor to ‘substantially’ execute the agreed work programme after the sixth year from the effective date. The 2000 PSC on the other hand allows NNPC to terminate the contract if the Contractor, inter alia: (i) defaults in the performance of any of its obligations set out in specific provisions of the contract; (ii) fails to pay the agreed bonuses and or fully execute the agreed minimum work programme; and (iii) if the warranties given by the Contractor that it has, along with its affiliates, sufficient funds both in foreign and local currencies to carry out petroleum operations under the contract, are found to be false.

Governing law, stabilisation, and arbitration

The PSCs and any disputes arising there from are governed or determined by and construed in accordance with the Laws of the Federal Republic of Nigeria. The 1993, 2000, 2005, 2006 and 2007 PSCs provide for economic stabilisation of the contract where the interest of the Contractor is adversely affected.

The PSCs provide for a binding and enforceable arbitration in Nigeria, pursuant to the Arbitration and Conciliation Act.[29] The 2000 PSC goes a little further to provide for an independent expert opinion prior to arbitration.

Deep Offshore and Inland Basin Production Sharing Contract Act Cap D3 LFN 2004 (Amendment)Law

The Deep Offshore and Inland Basin Production Sharing Contract Act (PSC Law) was amended in 2019 particularly Section 16, which provides that the law could be amended where oil price is above $20. The price of crude oil when the Deep Offshore and Inland Basin Production Sharing Contract Bill was signed into law in 1993 was $13 and the law provides for the following incentives:

  • longer duration of oil prospecting licenses;

  • reduction in the petroleum profit tax rate; 

  • investment tax credit or investment tax allowance; and

  • lower royalty regime.[30]

The amendments to the 1993 PSC Law introduce the following:

a. Section 5 of the PSC Law was amended as follows:

a. Field based royalty rates of ten per cent for deep offshore (greater than 200m water depth) and 7.5 per cent for frontier/inland basin operation; and

b. Introduction of incremental royalty rate based on the price of oil as follows:

b.i. from US$0 and up to US$20 per barrel: 0 per cent

b.ii. above US$20 and up to US$60 per barrel: 2.5 per cent

b.iii. above US$60 and up to US$100 per barrel: four per cent

b.iv. above US$100 and up to US$150 per barrel: eight per cent

b.v. above US$150: ten per cent

b. Section 16 of the PSC Law (the Principal Act) which provides for review of the law where the price of crude oil exceeds US$20; and review of the law after 15 years was deleted;

c. Section 17 was inserted in the PSC Law and it provides for periodic review of the PSC arrangement every eight years;

d. Section 18 was inserted in the PSC Law and it provides for penalty of N500m or five years’ imprisonment or both for offences.


The effect of the Covid-19 pandemic on the upstream oil and gas sector has far-reaching consequences, particularly for those with PSC contractual arrangements in Nigeria.

In 2019 PSC Law (Deep Offshore and Inland Basin Production Sharing Contract Cap D3 LFN 2004 (Amendment) Law),was amended in order for the Nigerian government to derive more revenue through incremental royalty from the PSCs as the price of crude oil rises in the global market.

Section 5 Deep Offshore and Inland Basin Production Sharing Contract[31]was amended as follows:

a. Field based royalty rates of ten per cent for deep offshore (greater than 200m water depth) and 7.5 per cent for frontier/inland basin operation; and

b. Introduction of incremental royalty rate based on the price of oil as follows:

b.i. from US$0 and up to US$20 per barrel: 0 per cent

b.ii. above US$20 and up to US$60 per barrel: 2.5 per cent

b.iii. above US$60 and up to US$100 per barrel: four per cent

b.iv. above US$100 and up to US$150 per barrel: eight per cent

b.v. above US$150: ten per cent

Given the low price of crude oil in the global market, the benefit that the Nigerian government seeks to derive under the PSCsthrough Deep Offshore and Inland Basin Production Sharing Contract Cap D3 LFN 2004 (Amendment) Law, seems to have been eroded by the Covid-19 pandemic.

However, it is hopeful that the effect of Covid-19 would be mitigated in the future as the crude oil price in the global market increases, thereby impacting positively on the Nigerian economy.



[1]Banwo and Ighodalo: ‘Assessing The Impact Of The Covid-19 Pandemic On The Operations Of Marine Vessels In The Nigerian Oil And Gas Industry’,, visited on 10/05/2020.

[2]Marvan. J, ‘The changing shape of a Joint Venture/Partnership Agreement and How you can effectively prepare for its evolving structure within your terms: A Case Study from Mexico’,visited 14/05/2013.

[3]Kirsten Bindemann, Production-Sharing Agreement: An Economic Analysis, (Oxford: Oxford Institute of Energy Studies 1999), p.1.

[4]Okonjo, P, ‘West Africa: Production Sharing Contract Solve Cash Call Problem’, 14/05/2013.

[5]Okonjo, P, ‘West Africa: Production Sharing Contract Solve Cash Call Problem’, 14/05/2013.

[6]Bindemann, K. Op cit, p. 1

[7]Madichie, A. C., The Development of the Production Sharing Contract and the Differences Between the Various PSCs in Nigeria - NNPC/National Petroleum Investment Management Services Presentation (undated), p.3.

[8]Ibid, pp.3-4.

[9]Hammerson, M., Production Sharing Contract: An Analysis of Comparative Production Practice, visited 07/07/14 (United Nations Conference on Trade and Development held in Nairobi on 23rd to 25th May, 2007.

[10]Olisa, M. M., Op Cit, p. 145.

[11]Hammerson, M., Production Sharing Contract: An Analysis of Comparative Production Practice, visited 07/07/14 (United Nations Conference on Trade and Development held in Nairobi on 23 to 25 May, 2007.

[12]Thisday Newspaper, 27 March 2013, P.33.

[13]Marc Hammerson, Op Cit.

[14]Thisday Newspaper, 27 March, 2013, p. 33.

[15]Marc Hammerson, Op Cit.

[16]Thisday Newspaper, 27 March, 2013, p. 33.

[17]Marc Hammerson, Op Cit.

[18]Madichie, A. C., Op Cit, p.15.

[19]Section 2 of the DeepOff-Shore and Inland Basin Production Sharing Contracts Act (Cap D3) LFN 2004.

[20]Madichie, A. C, Op Cit, p.9.

[21]Umar, M. B. Legal Issues in the Management of Nigeria's Production Sharing Contracts from a Study of the Nigerian National Petroleum NNPC's (National Petroleum Management Services') Perspective, (OGEL Vol 3 – Issue 1, 2005) p. 35.

[22]Umar, M. B., op cit, p. 55.

[23]Madichie, A. C., op cit, p.19.

[24]Cap P13 LFN 2004.

[25]Cap D3 LFN 2004.

[26]Umar, M. B., op cit, p. 40.

[27]Section 8 of the Deep Offshore and Inland basin Production Sharing Contract Act Cap D3, LFN 2004.

[28]Madichie, A. C., Op Cit, p.21.

[29]Cap A20, L.F.N, 2004.

[30]PWC, ‘A Bill to amend the Production Sharing Contract Act in the Petroleum Industry has been signed into law’,, visited on 25/02/2020. 

[31]Cap D3 LFN 2004.

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