Nigeria’s Petroleum Industry Bill PIB

No Comments » January 19th, 2014 posted by // Categories: Energy Development Project





PIB Summary

The PETROLEUM INDUSTRY BILL 2012 is a 223 page document with 362 sections and 5 schedules. The Bill is divided into 9 parts, which propose to cover the entire spectrum of the oil and gas industry. This part of the blog seeks to summarise the Bill along its 9 parts.

Part I – Objectives

Part II – Institutions

Part III – Upstream Petroleum

Part IV – Downstream Licensing

Part V – Downstream Petroleum

Part VI – Indigenous Petroleum Companies

Part VII – Health, Safety & Environment

Part VIII – Provisions on Taxation in the Petroleum Industry

Part IX – Repeals, Transitional & Savings Provisions



Part I – Objectives

Part I comprises of 4 sections, which provide the general principles governing the Bill. Section 1 lays out a number of objectives, which include:

Creation of a conducive business environment for petroleum opeations;
Establishment of a progressive fiscal framework that encourages further investment in the petroleum industry while optimising revenues accruing to the Government;
Creation of efficient and effective regulatory agencies; and
Promotion of transparency and openness in the administration of the petroleum resources of Nigeria.
Section 2 emphasises the principles laid out in section 44(3) of the Nigerian Constitution, which vests property and control of all petroleum in Nigeria including the Continental Shelf and Exclusive Economic Zone, in the Federal Government. Part I is rounded out by binding all agencies and companies created under the Bill to the provisions of the Nigerian Extractive Industries Transparency Initiative Act in carrying out their responsibilities.


Part II – Institutions

Institutional reform was a key platform of the oil and gas reforms leading to the draft of the Bill. Part II provides for the institutions to be created, their functions, funding as well as the mode of appointment of senior officials. The post-PIB reform structure will look like this:


PTB – Petroleum Technical Bureau

MPR – Ministry of Petroleum Resources

UPI – Upstream Petroleum Inspectorate

DPRA – Downstream Petroleum Regulatory Agency

PTDF – Petroleum Technology Development Fund

PEF – Petroleum Equalisation Fund

PHCF – Petroleum Host Communities Fund

NAPAMCorp – National Petroleum Assets Management Corporation

NAPAMCO – Nigerian Petroleum Assets Management Company Limited

NOC – National Oil Company

NGC – National Gas Company

The Minister is “responsible for the co-ordination of the activities of the petroleum industry and shall exercise general supervision over all operations and all institutions in the industry”. This all encompassing role of the Minister is backed up by significant powers, which include the power to formulate, determine and monitor government policy in the oil and gas industry; the power to issue licences and leases in the upstream and downstream sectors of the oil and gas industry and the power to advise the President on the appointments of the Chief Executive Officers of the institutions established under the Bill. The Minister is also to act as Chairman of NAPAMCorp.

Unlike previous drafts of the PIB, the Bill does not seek to replace the Ministry of Petroleum Resources. Indeed it does not propose any change to the structure of the Ministry. It does however propose the establishment of a Petroleum Technical Bureau (“PTB”) in the office of the Minister. The PTB is to be staffed with professionals in the petroleum industry as the Minister may from time to time deem fit. Its functions shall include providing professional support to the Minister; assisting the Minister in the formulation and monitoring the implementation of policy as well as carrying out the functions of the Frontier Exploration Service of NNPC. The Minister may also assign other functions to the PTB.

The Upstream Petroleum Inspectorate (“UPI”) has been proposed to carry out the upstream functions of the current DPR. Its functions are to include the regulation of the technical aspects of the upstream petroleum industry; regulation of commercial activities within the upstream petroleum sector as may be designated by the Minister; and execute policies assigned to it by the Minister. The UPI is to be headed by a Director-General (“DG”) appointed by the President on the advice of the Minister of Petroleum. It will have a board made up of the DG and such other number of executive Directors as approved by the Minister as well as non-executive directors representing specified industry stakeholders. The Inspectorate is required to maintain a fund which shall consist of budgetary allocations, monies derived from fees, gifts, loans and grants etcetera.

The Downstream Petroleum Regulatory Agency (“DPRA”) is to be established to regulate the downstream sector of the petroleum industry. This includes responsibility for regulating natural gas markets and infrastructure. Its functions include regulating the technical aspects of the downstream sector; regulating the commercial aspects of the industry as may be designated by the Minister; the issuance of downstream licences to industry operators; and the facilitation of an enabling environment for for investments in the downstream petroleum sector. The DPRA is to be overseen by a board including the Director-General, executive and non-executive directors all appointed by the President on the advice of the Minister. The Agency is required to maintain a fund which shall consist of budgetary allocations, monies derived from fees, gifts, loans and grants etcetera.

The Petroleum Technology Development Fund (“PTDF”) established under the Petroleum Technology Development Fund Act is to continue. The sources of the fund includes monies granted by the Government, multilateral agencies or bilateral institutions. The purpose of the fund is to facilitate the training of Nigerians for jobs in the petroleum industry. The Board of the PTDF is to include an Executive Secretary as well as other board members representing specified organisations.

To facilitate uniformity in petroleum pricing nationwide, the Bill proposes to retain the Petroleum Equalization Fund. The Equalization Fund shall be funded by payments from petroleum products marketing companies as well as the Federal Government. The Bill allows for the abolition of the Fund by the Minister where full deregulation has taken place.

Under the Bill all petroleum producing companies are required to remit on a monthly basis, ten per cent of their net profits into the Petroleum Host Community Fund. Unlike previous iterations of this concept, the PHCF under the Bill is a centralised establishment similar in many respects to the existing Niger Delta development Commission. The PHCF is to be utilised for the development of the economic and social infrastructure of the communities within the petroleum producing area. Where an act of sabotage which causes damage to any petroleum facility within a host community occurs, the cost of repair is to be derived from the PHCF unless it is established that no member of the community is responsible.

To carry out the government’s commercial functions in the oil and gas industry, the Bill proposes the establishment of four entities. The National Petroleum Assets Management Corporation (“NAPAMCorp”) is to be a “holding company operating fully on commercial principles”, whose principal function shall be to acquire and manage investments of the Federal Government in the Nigerian upstream industry. NAPAMCorp is to be provided funds by the government to fund the activities of its subsidiaries, one of which shall be the Nigerian Petroleum Assets Management Company Limited (“NAPAMCO”). The assets and liabilities of NNPC comprising of the interests in all the unincorporated joint ventures are to be transferred to NAPAMCO. The Corporation’s ability to borrow may be capped by the President, whose approval is also required for borrowing in currencies other than Naira and where such borrowing is not to be temporary. The board of the Corporation is to be chaired by the Minister and its board of directors shall include the Permanent Secretary of the Ministry of Finance and two other persons appointed by the President.

A new National Oil Company is to be incorporated by the Minister within three months of the passage of the Bill. All assets and liabilities of NNPC save for its interest in the unincorporated joint ventures and the Nigerian Gas Company Limited shall be vested in the NOC. Up to thirty percent of the shares in the NOC may be divested on the Nigerian stock exchange any time within six years of the date of incorporation. The assets of the subsidiaries of NNPC listed under the Public Enterprises (Privatisation and Commercialisation) Act shall be de-listed. The NOC is to be subject to the governance rules of the Securities and Exchange Commission.

The National Gas Company Plc is also to be incorporated as a limited liability company. NGC is to take over certain assets and liabilities of NNPC, although as is currently worded, the nature of the assets and liabilities are unclear. Up to forty nine percent of the shares in the NOC may be divested on the Nigerian stock exchange any time within six years of the date of incorporation.The company is to be subject to the governance rules of the Securities and Exchange Commission.


Part III – Upstream Petroleum

Part III deals with upstream petroleum matters save for the fiscal aspects and comprises thirty six sections. Section 170 vests the Inspectorate with the power to administer all acreage in Nigeria. The Inspectorate is required to administer acreage under a new national grid system under which a basic unit is a parcel of two kilometres by two kilometres. The national grid system will be utilised in the definition of licence and lease areas, relinquishments, bid procedures, identification of well systems amongst other things. Existing licences and leases which do not conform to the proposed grid system will not be affected and shall remain unaltered.

Licence Regime: PEL & PPL

Section 172 introduces the Petroleum Exploration Licence (“PEL”), the Petroleum Prospecting Licence (“PPL”) and the Petroleum Mining Lease (“PML”) to replace the existing Oil Exploration Licence (“OEL”), Oil Prospecting Licence (“OPL”) and Oil Mining Lease (“OML”) respectively. The PEL is a non-exclusive licence to explore an area, which shall be valid for not more than three years. The PPL grants an exclusive right to prospect for oil, including a right to carry away and dispose of oil, natural gas or bitumen found during prospecting operations. The term of the PPL is divided into three – the initial period, the renewal period and the appraisal period. The duration of each period is dependent on the terrain. The table below indicates the appropriate duration:


Terrain Initial Period Renewal Period Appraisal Period
Onshore and Shallow Waters 3 years 2 years 2 years
Deep water areas and frontier acreage 5 years 3 years 2 years


Under the Petroleum Industry Bill, the holder of a PPL is required to commit to drilling of at least one exploration well to a specified minimum depth during the initial period as well as during the renewal period. Where a PPL covers an area of more than ten parcels at least 50% of the original licence area must be relinquished after the initial period. Where a discovery of petroleum merits appraisal, the licensee is required to submit an appraisal programme for the Inspectorate’s approval. Section 178 also introduces the concept of the significant gas discovery retention area. This concept applies to an area over which the licensee has declared a significant gas discovery. The licensee is entitled to a retention period of not more than ten years over such an area. The retention period shall subsist even where the PPL has expired. Under section 179, where a licensee declares a commercial discovery, it is required to submit a field development plan for the approval of the Inspectorate. The Inspectorate is required to give such approval within sixty days of submission of the development plan.

Licence Regime: PML

The PML shall be granted to the holder of a PPL, where it has fulfilled all the terms and conditions of its licence and approval has been granted for its field development plan. A PML may also be granted under a bidding process, where an area contains commercial discovery of oil, natural gas or bitumen, or producing acreage with revoked or expired leases. The PML grants the lessee the exclusive right to conduct petroleum operations over the lease area. Lessees are subject to the domestic gas supply obligation as may be determined by the Inspectorate, where they are producing natural gas.

The duration of a PML shall be not more than twenty years and renewable for not more than 10 years, where the lease continues to be in commercial production. Provided that where a PML is derived from a PPL, the holder shall be allowed to utilise its entire PPL duration. This means that the overall period in onshore and shallow waters shall be twenty seven years from the date of the grant of the PPL and thirty years with respect to deep water and frontier areas. The Bill introduces development periods with respect to PMLs. The development period for onshore and shallow waters is five years and seven years for frontier and deep water leases. A PML not in commercial production within the relevant development periods may be revoked. Section 186 (5) provides for the relinquishment of all parcels that are not in commercial production or over which firm commitments have not been made after ten years of the grant of the lease.

Award Process

The Bill provides for the process by which PPLs and PMLs not derived from PPLs may be awarded. Section 190(1) requires that the grant shall be by open, transparent and competitive bidding process. The winning bidder is to be determined by a single bid parameter or a combination of bid parameters as laid out in section 190(2). The Bill does however grant the President the unfettered discretionary power to grant a licence or a lease.

Relinquishment from current licences

Prior to the relinquishment or expiration dates of existing OPLs or OMLs, the relevant holders are required to select portions of their licences or leases which they intend to continue to explore, develop and produce or wish to propose commercial discoveries, as appraisal areas or significant gas discovery retention areas. The provisions of the Bill shall apply with respect to any declaration made under section 193. In addition to the areas over which declarations have been made, the licensee/lessee may also select all or part of the remaining acreage as a PPL subject to commitment to drilling of a well of at least 3000 meters depth below the ground surface or the sea bed during the renewal period. All areas not selected must be relinquished on or prior to the relinquishment or expiry date of the OPL or OML.

Section 193 also entitles Marginal field operators to apply for PMLs over fields being operated as marginal fields at the date the Bill comes into force.

Assignment, mergers and acquisitions

Section 194 requires the written consent of the Minister for the assignment of a licence, lease or contract rights held by a contractor under a production sharing contract or a service contract. For the purposes of the bill an assignment includes mergers between a licensee/lessee and another company, acquisition of a licensee/lessee by another company including a change of control of a foreign parent company. The Bill specifies conditions which must be met by the proposed assignee, which are a good reputation; sufficient technical knowledge, experience or financial resources to enable it effectively carry out its responsibilities; and where the assignee is to serve as operator, proven operating experience or support by a competent operator under a technical service agreement. It should be noted that unlike previous drafts of the Bill, the Minister is not mandated to grant consent where these conditions are met.

Environment, Abandonment & Gas Flaring

All licensees or lessees carrying out upstream petroleum operations are required to submit an environmental management plan (“EMP”) for the approval of the Inspectorate. The EMP is to be submitted within one year of the commencement of the Act and three months of the grant of new licences or leases. The EMP shall contain:

Environmental policy, objectives and targets; and
Commitment to comply with the relevant environmental laws, regulations, guidelines and standards.
Amongst other things, the EMP is required to consider the impact of the licensee/lessee’s operations on the environment and socio-economic conditions of persons directly affected by the operations. In addition the Bill requires the development of an environmental awareness plan for employees and a remediation plan for plan for pollution or environmental degradation caused by the activities of the licensee/lessee.

Section 204 requires the licensee/lessee to provide a decommissioning plan/programme for the approval of the Inspectorate. The plan shall set out an estimate of the costs, details of the measures proposed; and steps to be taken to safeguard health and safety and the environment where any installations, structures or pipelines are to remain disused and in position or are to be partly removed.

Section 201 provides that lessees shall pay such gas flaring penalties as the Minister may from time to time determine. Lessees are also required to install all measurement equipment to properly measure the amount of gas being flared as may be ordered by the Inspectorate.


Part IV – Downstream Licensing

Part IV provides for the licensing of downstream activities, which for the purpose of the Bill includes downstream petroleum products as well as natural gas.

Licence Grant

Unlike the Petroleum Act which vests such powers in the Minister, the downstream licensing authority under the PIB is the Downstream Petroleum Regulatory Agency, and it has the power to grant amongst others, the following categories of downstream licences based on standard conditions as specified in the licences:

Constructing and operating a process plant including those for gas liquefaction;
Constructing and operating a petroleum transportation pipeline for crude oil or gas or condensate or petroleum products;
Constructing and operating a petroleum transportation network;
Constructing and operating a petroleum distribution network;
Undertaking the supply of downstream products or natural gas;
Owning and running a downstream products or natural gas processing or retail facility.
The Agency shall also grant licences for the utilization of all chemicals used for downstream petroleum operations including chemicals used in the processing, distribution and storage of petroleum products in the Nigeria. The Agency also has the power to modify, renew or extend licences issued by it. It should however be noted that the Minister is vested with the power to make regulations governing issuance of licences and other downstream operations on the advice of the Agency. Breach of any of the conditions of a licence, regulation or provisions of the Bill or any of the other grounds for revocation as stipulated in the Bill also gives the Agency a right to suspend or revoke such licence.

Assignment & Surrender

Similar to previous PIB drafts, assignments and transfer of rights or obligations in a licence shall not be made without prior written consent of the Agency. A licensee may surrender its licence upon application to the Agency for any of the permissible reasons enumerated in the Bill. However, where such licensee has commenced activities and has ongoing operations, it would be required to give the Agency at least twelve (12) months’ written notice of its intention to surrender its licence.

Contravention and Enforcement of Licence Conditions

Where the Agency notices a breach or intending breach of any licence condition, it may issue a notice to the licensee and interested parties for further representations after which it may, based on its findings issue an enforcement order and appropriate penalties.


Part V – Downstream Petroleum

Part V is further divided into 3 sub parts. The first division covers operations, the second deals with specific provisions for gas whilst the last addresses the issue of Domestic Gas Supply Obligation.

A. Operations

Downstream Deregulation – A major addition to the PIB is the deregulation of the pricing of petroleum products in the downstream sector.

Open Access – The bill maintains the provision for open access as in previous drafts in relation to “regulated open access facilities” which include jetties, loading facilities and storage depots or pipelines currently owned by downstream operators. This does not however preclude the construction and operation of independent pipelines, depots and jetties by any licensed oil marketing companies, bulk consumer of petroleum products or independent refineries for their exclusive use subject to regulation by the Agency.

Tariff Methodology and Price Monitoring – The Agency shall oversee tariffs for transportation pipelines, bulk storage of petroleum products in regulated open access facilities and any regulated open access facility in a manner which allows efficient operators to recover the full cost of its business plus a reasonable return on investment, provides incentives for service improvement, prevents undue discrimination amongst consumers and gradually reduces cross-subsidies. Notice of the establishment or change of a tariff methodology shall be publicized and representations made by stakeholders shall be considered by the Agency in arriving at a methodology. The Agency is also empowered to monitor the pricing of petroleum products in the domestic market to prevent pricing collusion or manipulation. Engaging in any activity likely to adversely affect the price of petroleum products is an offence which upon conviction would result in the payment of a fine as determined by regulation.

National Strategic Stock – The bill also makes provision for the maintenance and distribution of the national strategic stock in accordance with regulations made by the Minister on the advice of the Agency.

Dispute resolution – The Agency is also empowered to mediate in all disputes between downstream operators and consumers in the downstream sector.


Transportation pipeline owner licence – The PIB grants the Agency powers to issue a licence to a transportation pipeline owner to operate and maintain a transportation pipeline within a route as defined in the licence subject to conditions as stipulated in the bill and as may be imposed by the Agency.

Transportation network operator licence – The Agency is also empowered to grant licences to transportation network operators for the conduct of activities specified in the licence and such licensees amongst other obligations, are required to ensure transparent access to the network, establish and publish terms and conditions for access to the network and enter into relevant agreements for connection to and operation of the network. The licence may also include an obligation to develop mutually agreeable market rules among stakeholders.

Gas supply licence – A gas supply licence, granted by the Agency, allows the licensee “supplier” to supply gas into the downstream petroleum sector nationwide subject to conditions as specified in the bill. Such supply licence may also come with the rights, as determined and regulated by the Agency, to terminate gas supply to a customer in the event of nonpayment following a notice period and regulated disconnection procedure, recover all associated costs reasonably incurred in the supply of gas, and licence fees, enter into premises to remove, read and test meters. The supply licence is to be issued to gas producers seeking to provide gas into Nigeria’s downstream sector.

Gas distribution licence – The Agency is empowered to grant a gas distribution licence conferring exclusive right to own and operate a gas distribution system to distribute gas within a local distribution zone to non-wholesale customers. Conditions imposed upon such licence include amongst others, the duty to cooperate with the Agency in the development of the Network Code and to offer and publish terms and conditions of access to its distribution network. Similar rights as conferred on gas suppliers are also applicable to the gas distributor.

Network Code/ Wholesale Gas Market – The Agency is empowered to establish the Network Code in consultation with licensees and stakeholders covering all aspects of the downstream gas network and copies of the guidelines for the code shall be made available to interest parties. Following consultations with stakeholders, the Agency may also request the Minister to issue regulations determining classes of customers to be categorized as wholesale customers and the criteria for such classification. Such wholesale customers shall be entitled to secure gas from any gas supply licensee.

Third Party Access – The bill also allows a non-discriminatory right of third party access to transportation pipelines/networks or a distribution networks for the purpose of having gas transported to points of consumption subject to specified terms and conditions.

Gas pricing – The Agency, upon consultation with licensees and industry participants and in accordance with gas pricing principles as set out in the bill may regulate the prices of gas charged by licensees, where the Minister on the advice of the Agency determines that a monopoly situation exists. Tariff structures to be applied by licensees shall be approved by the Agency.

Wholesale gas prices – This is to be negotiated directly between parties on an arm’s length basis such that the gas transfer price between an upstream gas producer and a downstream gas purchaser shall reflect the costs of transfer between the parties subject to the powers of the Agency to monitor wholesale gas supply transactions. The supplier is also required to provide the Agency with all relevant information regarding any wholesale gas transaction with fourteen (14) days of the transaction and such information shall be classified as confidential information by the Agency not to be disclosed to any person or institution except the Federal Inland Revenue Service (the “Service”) for a period of five (5) years. An intentional failure by the supplier to provide the requite information to the Agency within the stipulated timeframe or the provision of false or misleading information shall result in a penalty not exceeding NGN1,000,000 per day until the provision of the information.

Transitional pricing arrangements – This allows the Agency in consultation with the Ministers of Petroleum Resources, Finance, Industries, Power and Steel, gas producers, electricity producers, the National Electricity Regulatory Commission (“NERC”) and other key stakeholders, to introduce and implement a transitional pricing plan which allows a gradual transition into the pricing arrangements specified in the bill.

Anti-competitive behaviour/ Consumer protection – The Agency may investigate and impose penalties for anti-competitive behaviours by licensees and may advise the Minister to issue regulations requiring licensees to conduct their operations in a specific manner formulated to protect their customers. Licensees and related persons with ability to influence the terms and conditions on which licensed activities are performed and the price at which petroleum products are supplied are also prohibited from exercising their powers in a manner liable to manipulate market prices or the price of any product or service or cause the direct or indirect exclusion of other licensees.


In addition to the provisions of the bill and government policies as determined from time to time, the Inspectorate and Agency are required to regulate the gas sector in accordance with the National Gas Master Plan.

Upon the yearly determination by the Agency of the Domestic Gas Demand Requirement (“DGDR”), the Inspectorate shall allocate the DGDR to every petroleum mining lessee by means of a Domestic Gas Supply Obligation (“DGSO”) determined as a function of the gas production and proven gas reserves of the lessee.

The Agency shall require the Domestic Gas Aggregator to establish an aggregate price for gas (“Aggregate Gas Price”) for only the volume of the Domestic Gas Demand Requirement, which shall be based on the weighted average of the purchase prices and supplied volumes of the purchased gas, and shall be used by the Domestic Gas Aggregator as a basis for gas supply to the domestic market. Failure to comply with the DGSO by a lessee shall result in the payment of penalty, embargo from supplying to any export project and revocation of gas licence where the non-compliance continues for a period exceeding three months.

Gas Licensing – The Bill requires companies intending to export gas are required to apply for a gas export licence (“GEL”) issued by the Agency pursuant to guidelines to be determined by the Agency. The Agency is empowered to refuse the grant of a licence where in its opinion such gas export is not in the national interest due to insufficient available proved gas reserves to supply to long term domestic market. However, such discretion shall not hamper the supply of contracted gas export capacity being undertaken under an export licence. For volumes of gas in excess of the DGSO, parties are free to contract in accordance with terms and conditions as agreed between them.

Prohibition of gas flaring – The Bill provides for the prohibition of gas flaring after “the flare out date” to be prescribed by the Minister in subsequent regulation. Any flaring after that date may only take place with the permission of the Minister. The circumstances under which such permission may be given are:

Equipment failure;
Shut down;
Safety flaring; or
Inability of gas customer to offtake.
Ministerial permission may only be granted for 100 days or such additional time as approved by the Minister.

Gas flaring undertaken without ministerial permission would be subject to a fine not less than the value of gas flared and the oil and gas facility may be shutdown.

Oil and gas operators are also required to submit gas utilisation plans for the approval of the Inspectorate within 6 months of the passage of the Bill. Operators are to categorize all of their flared gas resources (daily flare quantity, reserve, location, composition) and submit this data along with the gas utilisation plans for approval by the Inspectorate.


Part VI – Indigenous Petroleum Companies

The Bill defines Indigenous Petroleum Companies (“IPCs”) as those petroleum companies in which:

51% or more of its shares are beneficially owned directly or indirectly by Nigerians (this aligns with the percentage shareholding required under the Nigerian Content Act and is a shift from previous PIB drafts some of which adopted 55% or 60% shareholding);
Meets the requirements of any guidelines or regulations issued by the Inspectorate or Agency; and
Is accredited as such by the Agency.
The wording suggests that these three conditions are cumulative. It should be noted however that a company listed on any stock exchange in Nigeria with a majority of Nigerian directors is deemed to qualify as an IPC.

Part VI applies specifically to OPLs/OMLs currently held by IPCs and provides for certain benefits for those IPCs as follows:

Exclusion of state participation in IPCs with less than twenty five thousand barrels of oil per day aggregate production;
IPCs with the above stated production level will be allowed to produce up to the technical allowable limit and are therefore not subject any OPEC quota related restrictions;
Minister to issue regulations/guidelines to increase IPC participation and set targets for:
indigenous petroleum reserves;
Production personnel content and measurable parameters for determining level of indigenous participation which shall be subject to periodic review for continuous increase in indigenous participation.
Unlike previous drafts of the Bill, there are no preferential fiscal terms or access to acreage by IPCs.

Part VII – Health, Safety & Environment

Unlike the Petroleum Act which vests powers to make regulations regarding the environment on the Minister, the Bill vests such powers on the Agency or the Inspectorate (in consultation with the Ministry of Environment) depending on whether the matter relates to the upstream or downstream sector of the industry. However, the Bill further provides that licensees are required to comply with all environmental health and safety laws, regulations, guidelines or directives as may be issued by the Ministry of Environment, the Minister, the Inspectorate or the Agency.

It should also be noted that that fines to be paid for violation of these provisions are to be prescribed by the Inspectorate and the Agency in consultation with the Minister.

Obligations of licensees under Part VII of the Bill include:

Adopting the principle of sustainable development in operations;
Utilisation of good oil field practices;
Rehabilitation of environment affected by operations provided that the licensee shall not be responsible for rehabilitation where the damage to the environment is as a result of acts of sabotage to petroleum facilities. Disputes regarding ascertainment of cause of damage shall be referred to the Agency which shall be the final arbiter of such dispute.
The Agency is also responsible for issuing guidelines on rates of compensation (referred to as fair and adequate compensation) to be paid by upstream petroleum licensees to land owners or legitimate occupiers of the licensed or leased lands.


Part VIII – Provisions on Taxation in the Petroleum Industry

Part VIII deals with the taxation aspects of the Petroleum Industry Bill. It is focused on “upstream petroleum operations”, which is defined under the Bill as upstream gas operations and upstream crude oil operations. These terms are further defined as the winning and obtaining of crude oil or natural gas in Nigeria by or on behalf of a company on its own account for commercial purposes and shall include any activity or operation related to crude oil or natural gas that occurs up to fiscal sales point or transfer to the downstream sector. In the case of natural gas, this includes gas treatment.

FIRS & The Minister

The Bill provides for the imposition of the Nigerian Hydrocarbon Tax (“NHT”) on upstream petroleum operations. The NHT replaces the current Petroleum Profits Tax (“PPT’) regime and is to be administered by the Federal Inland Revenue Service (“FIRS”). In carrying out its responsibilities, the FIRS shall be subject to “the authority, direction and control of the Minister”, although the Minister may not give orders or instructions requiring the FIRS to raise an additional assessment on a company or increase or decrease any assessment. The Minister is also empowered to make rules generally for the carrying out of the provisions of this Part of the Bill.

Profits, Adjusted Profits , Assessable Profits & Chargeable Profits

Profits are determined by deducting the cost of extraction of oil, gas condensate or bitumen and the relevant cost of transportation between the field of production and the place of its disposal from the value of that oil, gas, condensate or bitumen as determined at the measurement point.

Adjusted Profits of any accounting period is the profits less allowable deductions under section 305 and adjustments under section 307.

Section 304(4) states that the Assessable Profits of an accounting period shall be the amount of the adjusted profits after any deduction allowed by section 312 of the Bill. This appears to be an error as Section 309 states that Assessable Profit shall be the amount of the adjusted profits less deduction of the amount of any loss incurred during any previous accounting period. The error in section 304(4) should be corrected.

Chargeable Profits are the amount of assessable profits less any deductions allowed under section 312 of the Bill. Section 312 provides for deductions with respect to capital allowances and production allowances.

Allowable Deductions

The Bill provides for the deductions which may be made from the profits of a company involved in upstream petroleum operations. Some notable deductions include:

(a) Rents and royalties;

(b) Sums paid to the government in respect of customs or excise duty on machinery, equipment and goods used in the company’s upstream petroleum operations;

(c) Interest on money borrowed where the Service is satisfied that the interest is payable on capital employed in carrying on upstream petroleum operations except in the case of production sharing contracts;

(d) Any expenditure incurred in connection with drilling of an exploration well and the next two appraisal wells;

(e) Contributions made to the Petroleum Host Communities Fund;

The Bill also specifies deductions that are not allowed, which include:

(a) Any disbursement or expenses not being wholly and exclusively expended for the purpose of upstream petroleum operations;

(b) Any expenditure for the purpose of paying penalties or fees relating to gas flaring or domestic gas supply obligation;

(c) General, administrative or overhead expenses incurred outside Nigeria in excess of one percent of the total annual capital expenditure;

(d) 20 per cent of any expenditure incurred outside Nigeria except where such expenditure relates to the procurement of goods and/or services not available in Nigeria.

Assessable Tax

The assessable tax is 50% for onshore and shallow water areas and 25% for bitumen, frontier acreages and deep water areas.

Capital & Production Allowances

Section 312 provides for the deduction of the aggregate sum of the capital allowances and the production allowances provided for in Schedules 4 and 5 respectively from the assessable tax. Under Schedule 4 a company that owns an asset over which it has incurred qualifying expenditure wholly, necessarily and exclusively for the purpose of petroleum operations shall be entitled to an annual allowance as follows:


Annual Allowance Rate per centum
1st year 20
2nd year 20
3rd year 20
4th year 20
5th year 19
6th year and after 19


The Schedule also provides for balancing allowances and balancing charges where the qualifying asset has been disposed of by the company at a lower or higher value than the initial expenditure.

The production allowances in schedule 5 are provided according to the type of petroleum produced and the area of production. Claims by contractors in production sharing contracts in the deepwater are ring fenced per petroleum mining lease and where a shareholder holds at least 10% directly or indirectly in several companies, those companies shall be treated as one company for the purpose of computing production allowances.

The production allowances are depicted in the tables below:

Table 2


The production allowance for crude oil production does not apply to companies that are in a joint venture contract arrangement with NNPC. Additionally, companies in a production sharing contract arrangement with NNPC that are not benefitting from the Investment Tax Credit or Investment Tax Allowance are entitled to a general production allowance of $5 per barrel or 10% of the official selling price.

Table 3

It should be noted that this table applies to natural gas fields with liquid yield greater than 5 barrels of condensate per million cubic feet of gas

Table 4

It should be noted that this table applies to natural gas fields with liquid yield less than 5 barrels of condensate per million cubic feet of gas.

With respect to the gas fields under tables 2 and 3 above companies in a production sharing contract arrangement with NNPC that are not benefitting from the Investment Tax Credit or Investment Tax Allowance are instead entitled to a general production allowance of $0.5 per MMBTu or 30% of the value of the natural gas per PML regardless of the liquid yield for all production volumes. Additionally companies that are in a joint venture contract arrangement with NNPC are only entitled to a general production allowance of $0.3 per MMBTu or 30% of the value of the natural gas per PML regardless of the liquid yield for all production volumes.

Table 5


It should be noted that companies in a production sharing contract arrangement with NNPC that are not benefitting from the Investment Tax Credit or Investment Tax Allowance are entitled to a general production allowance of $5 per barrel or 10% of the official selling price for all production volumes.

Companies Income Tax (“CIT”)

The Bill also makes CIT chargeable on “all companies, concessionaires, licensees, lessees, contractors and subcontractors involved in upstream petroleum operations”. The current CIT rate is 30%.



Part IX – Repeals, Transitional & Savings Provisions

One of the major objectives of the PIB is the fusion of various fragmented legislations regulating the oil and gas industry into one single law. Part IX of the Bill deals with repeals, transitional and savings provisions and provides for the repeal of not just the Petroleum Act, but a number of key legislations dealing with issues which have been incorporated into the Petroleum Industry Bill. However, a number of subsidiary legislations which are not inconsistent with the Bill remain applicable pending their revocation or replacement by subsidiary legislation made under the Petroleum Industry Bill.

Repeals – The Bill repeals the following enactments:

(a) Associated Gas Re-injection Act, CAP A25 Laws of the Federation of Nigeria, 2004;

(b) Motor Spirits (Returns) Act, CAP M20 Laws of the Federation of Nigeria, 2004;

(c) Petroleum Act, CAP P 10, Laws of the Federation of Nigeria, 2004;

(d) Petroleum Products Pricing Regulatory Agency (Establishment) Act, 2003;

(e) Petroleum Equalisation Fund (Management Board, etc.) Act, CAP P11 Laws of the Federation of Nigeria, 2004;

(f) Petroleum (Special) Trust Fund Act, CAP P14 Laws of the Federation of Nigerian, 2004;

(g) Petroleum Technology Development Fund Act, CAP P15 Laws of the Federation of Nigeria, 2004

(h) Deep Offshore and Inland Basin Production Sharing Act, CAP D3 Laws of the Federation of Nigeria, 2004, (except for sections 16 subsection (1) and (2) which deals with periodic review of the Act to ensure that the FGN’s take in the PSC arrangements are economically beneficial);

(i) Petroleum Profits Tax Act, CAP P13 Laws of the Federation of Nigeria, 2004.

The NNPC Act, NNPC (Projects) Act and NNPC Amendment Act shall also be deemed repealed on the date that the Minister signifies by legal notice in the Gazette that the assets and liabilities of NNPC are fully vested in successor entities.

Savings Provisions – In addition to the below, the Bill empowers the Minister within three months from the effective date of the Bill being passed into law (“the Effective Date”), acting on advice from either the Inspectorate, the Agency, or NNPC to make any further transitional and savings provisions as are consistent with the transitional and savings provisions in the Bill.

(1) Licences or leases granted under the Oil Minerals Act, 1958 and the Petroleum Act 1969 remain effective and OPLs granted thereunder are not subject to the provisions of sections 172 and 178 of the Bill. For such licences, existing terms on licence duration, work program, commitments and relinquishments shall continue unaltered for a period of ten years from the granting of such licence;

(2) Existing downstream licensees are required within three months from the Effective Date, to apply to the Downstream Petroleum Regulatory Agency (“Agency”) for the issuance of the appropriate licence as specified in the Bill;

(3) All other valid licences, permits or other rights granted by DPR or the PPPRA, shall continue in force for the remainder of the term granted;

Tariffs, prices, levies, or surcharges currently payable to DPR or PPPRA remain applicable until the earlier of the expiration of their term or the making of alternative provisions in accordance with the Bill.


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