A GUIDE TO THE TAXATION OF OIL OPERATIONS

January 2007

Content 1. The Nigerian Oil Industry

1.1 Overview of the Nigerian Oil Industry 1.2 Regulatory Agencies 1.3 Forms of Petroleum Contracts

2. Petroleum Act and subsidiary legislation made thereunder

2.1 Mineral Oils (Safety) Regulations 2.2 Petroleum Regulations 2.3 Petroleum (Drilling and Production) Regulations 2.4 Petroleum Refining Regulations 2.5 Crude Oil (Transportation and Shipment) Regulations 2.6 Petroleum Profits Tax Act (PPTA) 2.7 Deep Offshore and Inland Basin Production Sharing

Contracts Act 2.8 Oil and Gas Export Free Zone Act 2.9 Niger Delta Development Commission (NDDC) Act

3. Petroleum Profit Tax (PPT) Act 2004

3.1 Introduction 3.2 Administration of PPT 3.3 Imposition of PPT and Chargeable Persons 3.4 Computation of PPT 3.5 Compliance Procedures 3.6 Assessments 3.7 Objections/Appeal Procedures 3.8 Offences and Penalties 3.9 Deep Offshore Inland Basin Production Sharing Contract

4. Royalties

4.1 Royalty Rates 4.2 Computation of Royalty Payable

5. Taxation of Oil Operations 5.1 Changes in Licence and Petroleum Interests

5.1.1 Abandonment and Restoration 5.1.2 Participation 5.1.3 Unitisation 5.1.4 Carry Agreements 5.1.5 Underliftings and Overliftings 5.1.6 Assignment 5.1.7 Farmout Agreements 5.1.8 Production Payments

5.2 Transfer Pricing / Intercompany Transactions 5.3 Taxation of Marginal Fields

6. Review of proposed amendments to the PPT Act

7. Local Content

7.1 Local Content Policy 7.2 Measurement of Local Content under the Report 7.3 Categorisation of Service Companies 7.4 Value Matrix 7.5 Core Compensation and Job Categorisation 7.6 Policy Thrust 7.7 Regulatory Initiatives 7.8 Potential Impact on Foreign Oil Service Companies

8. Memorandum of Understanding (MOU)

8.1 Computation MOU Credit under the 2000 MOU 8.2 Computation Tax Reference Price (TRP) 8.3 Computation of Applicable Guaranteed Notional Margin

(GNM) 8.4 Summary of 2000 MOU

9 The Nigerian Natural Gas Industry

9.1 Upstream Gas Operations 9.2 Downstream Gas Operations

2

10 Review of the proposed Gas Fiscal Reform Bill 10.1 Upstream Gas Operation 10.2 Downstream Gas Operation

11 Oil and Gas Free Zones 11.1 Review of Oil & Gas Export Free Zone Act No. 8, 2004 11.2 Procedural Incentives to Companies Resident in the Zone 11.3 List of free trade zones

12 Niger-Delta Development Commission (NDDC)

12.1 Major Functions of the NDDC 12.2 Evaluation of the provision vis-à-vis E&P Company’s activities

13. Organization of Petroleum Exporting Countries (OPEC) 13.1 Overview of OPEC 13.2 Member States 13.3 Operations of OPEC 13.4 Implications of Quota Restriction 13.5 OPEC Price Band Glossary

3

1. THE NIGERIAN OIL INDUSTRY

1.1 Overview of the Nigerian Oil Industry Oil was first discovered in Nigeria in commercial quantities by Shell-BP at Oloibiri (Yenagoa Province, now Bayelsa State) in 1956. At that time, the ownership of mineral resources in Nigeria resided with the British (the Nigerian colonial masters) and was regulated by the Mineral Oil Ordinances of 1914. However, following from Nigeria’s independence in 1960, the government began to exercise greater control of this industry which was fast becoming the mainstay of the country’s economy. The Mineral Oil Ordinances of 1914 was therefore repealed and the Petroleum Act 1959 (the Act) was enacted. The Act introduced major changes, especially in matters such as duration, rent and royalties, technology transfer, etc. Also, by virtue of the Act and the 1979 Constitution of the Federal Republic of Nigeria, the Federal Government (FG) acquired exclusive ownership of petroleum and mineral resources, and the right to exploit and participate in joint exploration and production (E&P) activities with multinational oil companies operating in the country. In 1971, Nigeria joined the Oil Producing and Exporting Countries (OPEC) as its 11th member. In the same year, Nigerian National Oil Corporation (NNOC) was established as an instrument for accomplishing government’s policy objectives with respect to oil. The NNOC (which operated concurrently with the Ministry of Petroleum Resources) was empowered to enter into new beneficial oil arrangements with interested companies in Nigeria, on behalf of the FG. However, in 1977, the FG thought that a higher standard of goals and policies set for the oil industry was best achieved by a single entity. The NNOC and the Ministry of Petroleum Resources were therefore merged to form what is known today as the Nigeria National Petroleum Corporation (NNPC).

1.1.1 Upstream Sector of the Oil and Gas Industry

This involves all the activities carried out in the exploration, development and production of crude oil from its natural state. It is essentially referred to as “petroleum operation”, and the companies engaged in these activities are called Exploration and Production (E & P) companies. The income of these companies

is subject to tax under the Petroleum Profits Tax Act (PPTA), 2004, as amended.

The distinguishing features of this sector include: capital intensive operations; high business risks; unconventional accounting methods; and complex tax reporting/ returns system.

a. Oilfield Formation

Most geologists today agree that crude oil was formed over millions of years ago from the remains of tiny aquatic plants and animals that have been exposed to the combined effects of time and temperature. Oil is therefore a product of the degradation of organic matter remains of plants and animals. Sulphur rich fossil organic matter is known to form oil sooner than other organic matter because of the weaker atomic carbon-sulphur bonds compared with the stronger carbon-oxygen bonds present in other organic matter. In Nigeria, crude oil exists onshore below the ground at a depth of not more than 200 meters, while offshore at a depth of about 200 meters water depth.

1.1.2 Activities in the Upstream Sector

The activities in the upstream sector can be grouped into the following:

- Mineral Right Acquisition - Exploration - Drilling and Development - Production

4

Mineral Right Acquisition With the abrogation of the Mineral Oil Ordinances of 1914 and the enactment of the Petroleum Act, 1969, (now Petroleum Act, 2004 edition Laws of the Federation of Nigeria), all mineral rights were vested in the Federal Government. The Federal Government therefore acquired exclusive ownership of petroleum and mineral resources and the right to exploit and participate in joint exploration and production (E&P) activities with multi-national oil companies operating in the country. Concessions are issued to E&P companies in form of oil licences and leases. The Petroleum Act provides for the grant of three forms of licences:

(i) Oil Exploration Licence (OEL)

This is a licence granted to a company to explore for Petroleum. OEL is not exclusive to the licencee. Thus, another oil exploration grant may be made to another licencee to cover the same area.

(ii) Oil Prospecting Licence (OPL)

The Act defines OPL as a “licence granted to a company, under the Petroleum Act, for the purpose of winning petroleum or any assignment of such licence”. The area covered by the OPL must be compact, not being an area in excess of 2,590 square kilometers (1000 square miles)1. The duration is as determined by the grantor, but in no case shall it be in excess of 5 years for JV companies and 10 years for Production Sharing Contract (PSC) companies. The OPL gives the licencee the exclusive right to explore and prospect for petroleum within the area of grant. The licencee is also entitled to carry away and

1 The 2005 Licensing Bid Round guidelines reduced the size of an OPL to 1,250 square kilometers

dispose of the petroleum won and saved during its prospecting operations. (iii) Oil Mining Lease (OML) This is a lease granted to a company under the Petroleum Act for the purpose of winning petroleum or any assignment of such lease. The area covered by an OML must be compact and must not exceed 1,295 square kilometers. The life of an OML is usually for a maximum of 20 years but renewable upon the approval of the grantor.

Exploration and Drilling

Exploration activities involve identifying areas that may warrant evaluation and evaluating those areas considered to have petroleum prospects. This could be achieved through seismic surveys and interpreting data, as well as drilling exploratory wells. The process is capital intensive and the chances that oil will be found at the end of the exercise may be low and somewhat uncertain. However, with the advent of state of the art exploration techniques, the average exploration success rate has moved from a cumulative of 11% to currently over 60%.2

The principal costs incurred at this stage include:

(i) Cost of geological and geophysical studies, rights of

access to properties to conduct those studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies.

(ii) Costs of carrying and retaining undeveloped properties,

such as rentals, legal costs for title deeds, stamp duties and the maintenance of lease records.

2 Discover a new Nigeria- Publication of the Shell Petroleum Development Company

5

(iii) Dryhole contributions and bottomhole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Other associated costs such as resettlement of local

communities, compensation for economic crops, surface rights and road building.

Development

This involves the development of oil wells after hydrocarbons have been found in commercial quantities. Banks are usually able to assist with funds at the development stage. The funds are used to drill development wells and develop the oil field including construction of flow stations and pipelines. If evaluation during drilling strongly indicates the presence of oil, tests may be carried out to determine the productibility of the well. Further wells known as “appraisal wells” may be necessary to determine the extent of the reservoir and the flow rate of oil and gas.

Production

This involves the lifting of oil and gas to the surface, gathering, treating, field processing and storage. It also involves the maintenance of facilities and monitoring of the production of hydrocarbons. Examples of production cost include: (i) costs of personnel engaged in the operation of wells and

related equipment and facilities; (ii) repairs and maintenance of floating, production, storage

and offloading (FPSO) platform; (iii) materials, supplies, fuel consumed and services utilised

in such operations and royalties.

1.1.3 Crude Oil Grades

Crude oil is one of the main end products of petroleum exploration. It is a mixture of thousands of different hydrocarbons. They are classified according to their molecular weight. Therefore, there are as many different grades of crude oil, as there are oil reservoirs. Nigeria’s crude types have been known to be light and low in sulphur therefore have very high yield of gasoline. Due to these desirable characteristics, Nigeria’s crude oil grades are rated one of the best in the world. Crude oil is categorized by its American Petroleum Institute’s (API) gravity, which measures the specific gravity, of the crude oil relative to the density of water. Nigeria’s main export blends3 are: Bonny Light and Forcados among others and their characteristics are as follows (together with a comparison with other countries’ export blend): Crude Oil Grades

Crude Type Specify-API Gravity Sulphur Bonny Light 0.8398 – 370 API 0.14 Qua Iboe 0.8398 – 370 API 0.14 Escravos 0.8448 – 360 API 0.14 Brass River 0.8063 – 440 API 0.07 Bonny Medium 0.8984 – 260 API 0.28 Forcados 0.8708 – 310 API 0.2 Algeria Saharan Blend 440 API

0.1

Angola Soyo 340 API 0.2 Tukula 320 API 0.2 Egypt Suez Blend 320 API 1.5 Gabon Mandji 300 API 1.1

3 Source: Understanding the Nigerian Oil Industry NNPC publication 1986

6

1.1.4 Major operators

Until recently, multinational companies (MC) dominated the upstream economy. These companies operate under joint venture arrangements and production sharing contracts with the Federal Government. The MCs, which constitute the major player include: Shell Petroleum Development Company, Exxon Mobil, Chevron, TotalfinaElf and Nigerian Agip Oil Company However, in recent times, some indigenous E&P companies have sprung up. Under the indigenous arrangement, the Federal Government is usually not involved but reserves the right to participate when it deems necessary. Most indigenous companies operate in conjunction with foreign technical partners, who in most cases are responsible for providing the funds and expertise required. Some of these indigenous operators include Consolidated Oil, Moni Pulo Limited, Solgas Nigeria Limited and Express Petroleum and Gas Company, amongst others.

1.1.5 Downstream Sector of the Industry

All operations involved in the conversion of crude oil produced into usable forms e.g. Premium Motor Spirit (PMS), kerosene, etc are generally referred to as downstream operations. It also includes activities such as pipelines and storage, petrochemical sales and services, marketing and refinery activities. Companies engaged in these activities are assessed to tax under the Companies Income Tax Act (CITA), 2004, at the rate of 30% of assessable profits.

The principal regulators in the downstream sector include the Petroleum Inspectorate of the NNPC, the Department of Petroleum Resources and the Pipeline and Product Marketing Company Limited (PPMC). The key activities in the downstream sector are discussed below:

(i) Transmission and Conveyance

This involves the transportation of oil and gas to the refinery and gas stations. The pipelines usually run from the wellhead to the refinery or plant. Tankers and purpose built vessels are also used for this purpose.

(ii) Refining

Refining is simply the breaking down of the hydrocarbon mixture of crude oil into useful petroleum products. This is done through distillation, cracking, reforming and extraction process. The products of the refining process include: PMS, Household Kerosene (HHK), Aviation Turbine Kerosene (ATK), Automotive Gas Oil (AGO), known as diesel etc. Nigeria has four refineries, two situated in Port Harcourt and one each in Warri and Kaduna. The refineries are all wholly owned by the NNPC, however the Government intends to privatize the refineries and has called for investors to acquire the refineries. The number of refineries is however expected to increase soon, with the government’s effort at liberalizing the sector and encouraging private refineries. Though licences have been granted to a number of petroleum refinery companies, and State Governments, none has yet become operational. The capacity utilisation of the existing refineries is however, low, necessitating the importation of refined products from outside Nigeria to meet growing demand for petroleum products.

(iii) Distribution and Marketing

Distribution and Marketing of refined petroleum products are complementary activities. Distribution involves the transpiration of refined petroleum products from the refineries through pipelines, coastal vessels, road trucks, rail wagon etc to the storage/sale depots.

7

Petroleum products are supplied in Nigeria principally through PPMC’s pipelines system, which links the refineries to the 21 regional storage/sale depots. The five pipelines currently in use by the PPMC are referred to as 2A, 2B, 2C, 2D, and 2E4 systems. Oil marketing on the other hand, involves the procurement of refined petroleum products by marketers and the selling of products through a network of stations, peddling trucks and vessels (for sales on land and water). Marketers lift products from PPMC depots and deliver to their various retail outlets. They also import refined products from outside of Nigeria to meet the demands of their customers. There are however, guidelines issued by the Department of Petroleum Resources on the importation of products to prevent importation of substandard products. The Federal Government currently regulates the prices of refined products. The Petroleum Product Pricing Regulatory Committee (PPRC) is responsible for fixing the prices of petroleum products.

1.1.6 Major Operators

There are two groups of operators (marketers in the down stream sector namely: the “Majors” and the “independent” marketers.

(a) The Majors The Major marketers dominate the marketing of petroleum products in Nigeria. They account for about 64%5 of the total petroleum products sold. These companies include: Agip Nigeria Plc, Mobil Oil Nigeria Plc, Chevron Oil Nigeria Plc, and TotalFina Elf Nigeria Plc. The Majors operate under a trade association called the Major Oil Marketer Association of Nigeria (MOMAN). They have an edge over the independent marketers in the areas of capital base,

4 Source: ADCG Report 1996 5 Source: Agusto Report, 2002

management, range of products, technical assistance from foreign partners and experience.

(b) Independent Marketers (IM)

This group of marketers consists of indigenous petroleum companies. They operate under the trade name Independent Marketers Association of Nigeria (IPMAN). The first sets of licences were issued in 1980 and today we have over 2000 companies in this group. Though companies in this group are no threat to the Majors in terms of size, the group is gradually gaining market share in the industry. Some of the well known IMs include: Zenon, Oando, Honeywell Oil, Fowobi etc.

1.1.7 Oil Service

E&P companies worldwide depend greatly on oil service companies for carrying out almost all aspects of field operations. This is because, in most cases, these E&P companies do not have the technical and engineering know-how required for oil and gas prospecting. Infact, most of the engineering and technical systems required are patented. Also, E&P companies have discovered, over time that it is more economical to engage the services of specialists instead of hiring men, equipment and material on a permanent basis.

Scope of Services

Services in the oil industry include, but are not limited to, the following:

Logging Fishing Cementing Seismic survey

8

(a) Logging

This is the process of acquiring information about properties in the well and/or some property in the formation surrounding the well. These properties are the primary physical parameters such as permeability, porosity, water and oil saturation, which are used in the evaluation of petroleum reserves in a field. The document usually generated from logging operations is a well-log, which is a grid scaled in algorithmic divisions. The logarithmic grid serves to enhance resolution or magnify resistivity readings in the low resistivity range and eliminates the need for back-up galvanometers and associated curves in the high resistivity range.

(b) Fishing

A fish is a foreign object (such as a tool or pipe) lost in the borehole, which obstructs routine functions performed in the well and must be removed or by-passed. Fishing, is therefore, the process of retrieving the object lost in the well bore. The fish retrieved is usually placed in a shallow hole dug into the ground and filled with mud.

(c) Cementing Cement is a powder consisting of alumina, silica, lime and other substances, which hardens when mixed with water. It is extensively used in the oil industry to bond casing to the walls of the well. Cementing is the process of fixing the casing firmly in the hole with cement, which is pumped through the drill pipe to the bottom of the casing and up into the annular space between the casing and the walls of the borehole. After the cement sets (hardens) in the annular space between the well bore and casing, drilling operations continues. The casing can be perforated through the cement to allow reservoir fluids to enter the well after well completion.

(d) Seismic Survey

This is an enhanced survey method that gives the explorationist the precise details on the structure and stratigraphy beneath the surface. It is best described as taking the photograph of the subsurface. The picture obtained is the picture of the ground showing how various earth minerals are arranged sequentially down several kilometers into the earth. It is useful in decision making in field appraisal and development for the evaluation of production acreage.

1.1.8 Major Operators

The Nigerian Oilfield service industry is composed of small6 but very active players. These companies operate under the Petroleum Technology Association of Nigeria (PETAN). Some of the prominent companies and their respective areas of operation are listed below7:

Frank’s International Oilfield Services Construction Halliburton Energy Services Construction BJ Services Company Nigeria Limited Construction Baker Hughes Nigeria Limited Construction Anadrill Nigeria Limited Drilling MI Drilling Fluids Limited Drilling Baroid of Nigeria Limited Drilling (rigs & materials) Ciscon Limited Drilling (rigs & materials) Dowell (Nigeria) Limited Oil filed services Dresser-Rand Nigeria Limited Oil filed services Vigeo Limited Supplies Negris Limited Supplies

6 This is in comparison to the E&P companies 7 ADCG report, 1996

9

1.1.9 Natural Gas

Natural gas is a fossil fuel. Like oil and coal, it is formed from the remains of plants, animals and microorganism that lived millions of years ago. It is a combustible mixture of hydrocarbons gases containing primarily methane but could include ethane, propane, butane and pentane. The composition of natural gas can vary widely, but below is a chart8 outlining the typical makeup of natural gas before it is refined:

Component Formula % Composition

Methane CH4 70 – 90 Ethane C2H6 0 – 20 Propane C3H8 0 – 20 Butane C4H10 0 – 20 Carbon Dioxide CO2 0 – 8 Nitrogen N2 0 – 5 Oxygen O2 0 – 0.2 Hydrogen Sulphide H2S 0 – 5 Rare Gases A, He, Ne, Xe Trace

Natural gas is considered “dry” when it is almost pure methane, having most of its associated hydrocarbon removed. The gas is colourless, shapeless and odourless in the form.

Natural gas is known to be one of the cleanest, fastest and most useful energy sources in the world. Unlike other fossil fuels, natural gas is clean burning and emits lower levels of potentially harmful by-products into the air. It is used residentially, commercially and industrially.

In most cases, natural gas exists in association with oil. It is found in reservoirs underneath the earth. To successfully release natural gas, which is found closer to the earth’s surface than oil, a hole

8 Source:www.naturalgas.org

must be drilled through the impermeable rock. Since the gas in these reservoirs is typically under pressure, they escape freely on their own from the reservoirs.

(a) Trends in the gas industry

In Nigeria, natural gas has largely produced in association with crude oil. This has been the case as little or no prospecting has been made exclusively for gas.

Nigeria’s proven gas reserve is currently estimated at 159 trillion cubic feet making it the tenth largest in the world. The level of natural gas is about 22 billion barrels of its crude oil equivalent9.

However, despite the availability of gas in substantial quantities, it has not been commercially exploited as most of it is currently flared. It is estimated that about I billion cubit feet of gas is flared in Nigerian10 annually representing 40% of gas produced. This has resulted in environmental degradation resulting and there has been increasing pressure from environmentalists on the need to protect the environment. Consequently, Government has committed itself to increasing the utilisation of gas and ending all gas flaring by 2008. To enforce compliance, Government increased the royalty for gas flaring from N0.50 for 1,000 cubic to N10 for 1,000 cubic feet in 1998.

In order to exploit the country’s vast gas reserves, the Federal Government in 1985 set up the Nigeria Liquefied Natural Gas Ltd (NLNG) as joint venture with 4 shareholders – NNPC (49%), Shell (25.6%), Elf (15%), and Agip (10.4%). Shell is the technical manager to the LNG project. The project, which is exported-based, is aimed at converting natural gas into its liquid form for purpose of transporting it over long distances to areas where the market exists. The company’s first shipment to Europe was in 1999. The company has already negotiated a number of long-term (22.5 years) purchase agreements negotiated with some European national companies. These companies are ENEL (Italy) ENAGAS (Spain), BOTAS (Turkey), GAZ DE (France) and TRANSGAS

9 Source: www.nlng.com 10 Source: www.nlng.com

10

(Portugal). Trains 1 to 5 of the NLNG Plant have been completed and are on stream. Train 6 is estimated to come on stream in late 2007.

There is also the Escravos gas to liquid project, which is being developed by Chevron. The objective is to recover associated gas from the company’s offshore fields. Other major gas projects currently under way are the OSO NGL (Natural Gas Liquids) by Mobil/NNPC joint venture which produces about 110,000bbls/day of condensate, and the Olokola LNG project, which is a joint venture between Shell, Chevron, British Gas and the NNPC. . In addition to the above projects, the Trans West African gas pipeline has been completed. The pipeline will supply natural gas to Benin Republic, Togo and Ghana.

(b) Obstacles to Gas Exploration

Some of the factors that have accounted for the underutilisation of Nigeria’s gas resources through the years are as follows:

(i) The absence of a ready market for gas, both internally and

externally. (ii) The non-deregulation of the gas sub-sector, especially in

relation to appropriate pricing of gas to public utilities. (iii) The relative expensiveness of gathering associated gas in

Nigeria, given the difficult (swampy) terrain in most of the oil fields, the small size of the fields and the fact that gas supplies from such fields cannot be guaranteed, since this is dependent on the continued production of oil from the fields. Gas flaring therefore appears to be a better option.

(iv) Government’s preoccupation with political rather than

economic issues in its allocation of resources, and general approach to the industrial sector.

(v) Unattractive fiscal terms.

However, changing circumstances have compelled government to take a fresh look at the natural gas sub-sector and address some of the factors, which contribute to its sub-optimal performance. This has taken the form of fiscal incentives and policy measures, both general and specific, articulated in recent legislation and ministerial pronouncements to encourage the exploitation of gas. The key fiscal measures are covered in the next sub-section.

(c) Fiscal Incentives for Gas Exploration11

(i) Nigeria LNG (Fiscal Incentives, Guarantees and

Assurances) Act,(as amended), 2004 edition, Laws of the Federation of Nigeria

The most extensive and most publicised set of special incentives to a specific gas initiative is that given by the Act. This legislation grants the Nigeria LNG Limited, the Joint venture vehicle for the Nigeria Liquefied Natural gas project, a 10-year tax relief period as a pioneer company. In addition, the legislation completely exempts the company, its contractors and subcontractors, from all customs duties, taxes, levies and imposts of a similar nature in respect of imports pertaining to the projects. Under the Guarantees and Assurance in the second schedule to the Act, the company and its shareholders (NNPC, Shell Gas BV, CLEAG Limited (Elf), and Agip international (BV) are exempted from several regulatory approvals.

(ii) Condensate Project Act

Another set of special incentives aimed at a specific export-oriented gas initiative is that contained in the Condensate Project Act (No. 15 of 1990). The Act is aimed at facilitating the operations of the joint venture partners (Mobil and NNPC) in relation to the Condensate Project, which is for the recovery of natural gas liquids from an

11 Fiscal regime of natural gas in Nigeria - Paper prepared by George Nnona, an ex-Andersen Nigerian manager

11

offshore field for processing and export. The Act permits the NNPC to borrow money in any currency desired for the purposes of the project, and to pledge its fund and assets for the project. It also empowered NNPC to create escrow accounts in other countries for the purpose of paying capital and interests on money received from the project.

This Act particularly aims at facilitating the external financing of the project, by ensuring that payments due to external project creditors are not impeded by the constraints of the Nigerian regulatory environment. This Act was indeed a substantial boost to the project.

(iii) The Finance and Miscellaneous Taxation Act (Decrees

No. 18 of 1998 and No. 30 of 1999)

The Acts grant the following fiscal incentives to companies engaged in gas utilisation (i.e. marketing and distribution of gas for industrial and domestic purposes) as well as all gas development projects (including industrial projects that use gas, namely: power plants, gas-to-liquid plants, fertilizer plants, gas distribution and transmission pipelines):

(a) Taxation under the more favourable provisions of the

Companies Income Tax (CITA) with a current corporate tax rate of 30%, as against the provisions of the petroleum profits tax Act (PPTA) with a rate of 85%;

(b) An initial tax holiday period of 312 years, with a

possible renewal for another 2 years.

As an alternative to the initial tax-free period, an additional investment allowance of 35% (which will not reduce the value of the asset) is allowable. Where the Company opts for this alternative, it would forfeit the additional 15% investment allowance as stated in (d) below;

12 Though the initial tax holiday period of 3 years was extended in the 1998 budget, this has not been gazetted into law.

(c) Exemption from tax of all dividends distributed during

the tax holiday where

(i) the investment for the business was in foreign currency, or

(ii) the imported plan and machinery in the period was not less than 30% of the Company’s equity share capital

(d) Accelerated capital allowances after the tax holiday as

follows:

- 90% annual allowance with 10% retention for investments in plant and machinery; and

- 15% additional investment allowance which will not reduce the value of the asset.

(e) Deductibility of interest on loans for gas projects

provided the approval of the Federal Ministry of Finance is obtained before the loan is taken.

For upstream gas activities, the following fiscal incentives are made available:

(a) All investment necessary to separate gas from the

reservoir into usable products are now to be treated as part of the oil field development.

(b) Capital investment facilities to deliver associated gas in

usable form at utilisation or designated custody transfer points is to be treated as part of the oil field development.

(c) Transfer of gas at 0% Petroleum profits tax (PPT) and

0% royalty.

Also worthy of note are the incentives available under the Oil and Gas Export Free Zone Act No. 8 of 1996. These are discussed extensively under section 2.

12

(d) The Nigerian Gas Company

13The Nigerian Gas Company Limited (NGC) was established in 1988, as subsidiary of the NNPC. The company was charged with the supply of natural gas to the domestic economy and initially performed the task of sole transmitter and distributor of gas in Nigeria. However, the distribution phase has recently been ceded to two distribution companies; Shell Nigeria (SNG) Limited and Gaslink Nigeria Limited. NGC currently operates 8 gas supply systems in Nigeria, namely: Sapele – supplying gas to the National

Electric Power Authority (NEPA power station at Ogorode, Sapele

Aladja – supplying the Ajaokuta Steel plant

Northern Pipeline System Imo River-Aba Industrial System Obigbo North-Afam – supplying another NEPA station

at Afam Alakiri-Onne – supplying gas to the National

Fertiliser Company (NAFCON) Alakiri-Ikot Abasi – supplying gas to the Aluminium

Smelter plant (ALSCON) at Ikot Abasi

Escravos-Lagos Pipeline – supplying gas to NEPA power plant at Egbin.

NGC operates a total of 1,100 kilometres of pipelines, ranging from “4 to 36”, with a capacity of 2 billion cubic feet of gas per day. The Company also has 14 compressor stations and 13 metering stations.

13 Source: NGC website

The NGC is also actively developing a number of initiatives including the West Africa Gas Pipeline, being managed by Chevron, The Trans Nigeria Pipeline Project, which will provide gas supply to a series of Independent Power Projects being planned throughout the country, and the development of compressed natural gas as an automotive fuel.

(e) Shell Nigerian Gas Limited

Shell Nigeria Gas Limited (SNGL) is a wholly owned subsidiary of Shell Petroleum Development Company. The Company’s objective is to promote the development of a domestic gas market. SNGL intends to construct gas delivery lines to the factory gate, from where prospective users will provide required infrastructure within their premises. The target clients of the gas supply are: factories which have a high energy consumption companies which already use natural gas as feedstock companies looking for a clean and reliable source of fuel

1.2 Regulatory Agencies

1.2.1 Nigeria National Petroleum Corporation (NNPC) In 1971, Nigeria joined the Organisation of Oil Producing and Exporting Countries (OPEC), as its 11th member. In the same year, Nigerian National Oil Corporation (NNOC) was established as instruments for accomplishing government’s policy objectives with respect to oil. The NNPC (which operated concurrently with the Ministry of Petroleum Resources) was empowered to enter into new beneficial oil arrangements with interested companies in Nigeria on behalf of government. However, in 1977, the government thought that a higher standard of goals and policies set for the oil industry was best achieved by a single entity. NNOC and the Ministry of Petroleum Resources were therefore merged to form what is known today as Nigeria National Petroleum Corporation (NNPC).

13

The NNPC was established by the NNPC Act 1977. The Act sets out certain duties for the NNPC: (a) Duties The NNPC at its inception, was charged both with the responsibility of engaging in oil and gas operations on behalf of the FG and regulating the operations of the industry. Its specific duties were: exploring and prospecting for, working, winning or otherwise acquiring,

possessing and disposing of petroleum; refining, treating, processing and generally engaging in the handling of

petroleum for the manufacture and production of petroleum products and its derivatives;

purchasing and marketing petroleum, its products and by-products; providing and operating pipelines, tanker ships or other facilities for the

carriage or conveyance of crude oil, natural gas and other products and derivatives, water and any other liquids or other commodities related to the Corporation’s operations;

constructing, equipping and maintaining tank farms and other facilities for

the handling and treatment of petroleum and its products and derivatives; carrying out research in connection with petroleum or anything derived

from it and promoting activities for the purpose of utilising results of such research;

doing anything required for the purpose of giving effect to agreements

entered into by the Federal Government with a view to securing participation by the Government or Corporation in activities connected with petroleum;

generally engaging in activities that would enhance the petroleum

industry in the overall interest of Nigeria; and

undertaking such activities as are necessary or expedient for giving full effect to the provisions of this Act.

(b) Structure NNPC was initially made up of two broad divisions; the Commercial Division and Petroleum Inspectorate Division. In March 1998, the NNPC underwent structural reorganization and became a fully commercialized entity14, by virtue of the Commercialization and Privatisation Act The new NNPC group comprises the Group Managing Director’s office and 4 Directorates namely: (i) Refineries and Petrochemicals; (ii) Exploration and Production; (iii) Finance and Accounts; and (iv) Corporate Services. The NNPC has 10 wholly owned subsidiaries, 2 partly owned subsidiaries and 16 associated companies with financial autonomy to manage their businesses within the ambit of the enabling laws. The subsidiaries operate as strategic business units.15

14 NNPC was to operate as a profit making commercial enterprise without subventions from the FG. 15 The subsidiaries operate as strategic business units e.g. Pipelines and Products Marketing (PPMC), Nigerian Petroleum Development Company (NPDC) and the Nigeria Liquefied Natural Gas Company Limited (NLNG) amongst others.

14

NNPC subsidiaries and their activities16 17

Name Activities Duke Oil Limited International sale of crude oil and

petroleum products in the spot market

Eleme Petrochemicals Company Limited

Manufacture and sale of petrochemical products both locally and internationally

Integrated Data Services Limited Provision of services in seismic data acquisition, processing and interpretation as well as petroleum/reservoir engineering, data evaluation, computer and other ancillary service in Nigeria and the Africa sub-region

Kaduna Refining and Petrochemicals Company Limited

Processing of crude oil into refined petroleum products and manufacture of Linear Alkyl Benzene, tins and drums for domestic consumption and export

National Engineering and Technical Company Limited

Acquisition of engineering technology through direct involvement in all aspects of engineering in the oil and gas and non-oil sectors of the economy

Nigerian Gas Company Limited Gathering, transmitting and marketing of Nigeria’s natural gas and its by-products to major industrial and utility gas distribution companies both locally and in neighbouring countries

Nigerian Petroleum Development Company Limited

Exploration and production of crude oil and gases

Pipelines and Products Marketing Company Limited

Transportation of crude oil to the refineries and moving of white petroleum products to existing domestic and West African markets

16 Source: Nigeria Gas Association Journal, 2002 17 The partly owned subsidiaries are Hyson Nigeria Limited and Calson (Bermuda) Limited

Name Activities Port Harcourt Refining and Petrochemical Company Limited

Processing of crude oil into refined petroleum products at minimum cost locally but at competitive prices internationally

Warri Refining and Petrochemicals Company Limited

Processing of crude oil into refined petroleum products and manufacture and marketing of petrochemical products

In addition to the above, the National Petroleum Investment Management Services (NAPIMS)18), a division of NNPC monitors government investment in the upstream sector. The detailed description of its activities is given in the next paragraph. 1.2.2 National petroleum Management Services (NAPIMS) The National Petroleum Investment Management Services is the upstream arm of the NNPC, which oversees the government’s investments in the Joint Venture producing Companies (JVC’s), the Production Sharing Companies (PSC’s) and the Service Contract Companies (SC’s). NAPIMS also engages in exploration services in basins where the multinationals have been reluctant to venture (e.g. Chad Basin). The stated roles of NAPIMS are:

Maximize Petroleum Profit Tax (PPT) and guarantee a high rate of return

through efficient cost reduction mechanism Ensure that a reserve base is maintained and that reserve targets are met.

Current target is 40 billion barrels by 2010 Ensure that production targets are also met – current target is 4 million

bpd by 2010. Encourage gas utilization and commercialization.

18 The body charged with optimizing the benefits accruing to the FG from its investment in E & P activities.

15

Promote local content input in engineering and construction, supplies, and materials utilization through in-country technological capability.

Promote transfer of managerial skills and technology. Diversify the country’s revenue base in the hydrocarbon sector through

development of gas initiatives. Ensure gas flare out by 2008 as agreed with major producers. Negotiate and manage all third party operating agreements. 1.2.3 Ministry of Petroleum Resources The Ministry of Petroleum Resources started as a hydrocarbon section in the Ministry of Lagos Affairs in the 1950s and was later upgraded to a Petroleum Division within the Ministry of Mines and Power. In 1970 the division became known as the Department of Petroleum Resources (DPR). In 1971, a new body known as the Nigeria National Oil Company was established to engage in Commercial activities in the Petroleum industry. In 1975 the DPR was upgraded in status to a full fledged ministry known as the Ministry of Petroleum Resources (MPR) in 1975. However, in 1977, the Ministry was fused with the NNOC to form the Nigerian National Petroleum Corporation (NNPC) by the NNPC Act no. 33 of 1977 The Act provided for a Petroleum Inspectorate Division in NNPC to regulate the activities of the petroleum industry. This Inspectorate Division was however, barred from engaging in commercial transactions. From 1977 there was no Ministry of Petroleum Resources until 1985 when the Ministry was recreated. In 1988, following the commercialization of NNPC, the Petroleum Inspectorate Arm of NNPC was excised and merged with the Ministry of Petroleum Resources. The Inspectorate Division formed the nucleus of the present DPR, which is the technical arm of the Ministry 1.2.4 The Department of Petroleum Resources (DPR) DPR effectively took over the activities of the former Petroleum Inspectorate Division of the NNPC. The DPR is charged with the supervision of all operations carried out under licences and leases in the petroleum industry. The DPR is generally known as the agency that registers all companies

seeking to carry out business in the oil and gas industry. A DPR registration certificate is a pre-requisite for all bid submissions in Nigeria. Its functions include; but are not limited to the following: enforcing safety and environmental regulations; processing all applications for licences to ensure compliance with laid-

down guidelines; keeping and updating records on petroleum industry operations,

particularly on matters relating to petroleum reserves, production and exports, licences and leases as well as rendering regular reports on them to the FG;

advising the FG and relevant agencies on technical matters and public

policies which may have impact on the administration and control of petroleum; and

ensuring timely and adequate payment of all rents and royalties as and

when due. 1.3 Forms of Petroleum Contracts

The early forms of contract in Nigeria were the concession agreements where multinational companies were granted the rights to exploit and market mineral resources recovered within the concession area19. In return, such E & P companies were expected to pay royalty/rent to the FG. However, with the enactment of the Petroleum Act, and Nigeria becoming a member of OPEC, the need to share in the ownership and control of operations in the oil industry became paramount to the FG. This motive gave rise to the following forms of agreement with multinational oil companies: 1. Joint Venture Agreement 2. Production Sharing Contract20 3. Risk Service Contract 19 The concession area were usually very large and duration of the agreement very long. For instance, the concession granted Shell-BP was for 40 years and covered 357,000 sq. ml 20 Introduced in early 1990s due to the FG’s inability to meet its cash call obligations to E & P companies under the JV

structure.

16

1.3.1 Joint Venture (JV) Arrangement There are two variants of this type of arrangement, the equity share participation and the non-equity share participation. (a) Equity Share Participation Agreement

Under this arrangement, a separate legal entity in the form of a limited liability company (LLC) is formed by a multinational company (ies) and the FG, through its agency (NNPC or NAPIMS). The new company draws, as may be agreed, from the financial and human resources of the shareholders. The Management Board representation of the company is usually based on the parties’ equity interest. The parties are entitled to dividends to the extent of their equity interest in the company. Most of the companies which fell into this classification are oil service companies21, in which the NNPC acquired 36 percent equity or more by virtue of the Nigerian Enterprises Promotion Decree of 1977. It is of note that NNPC also has equity joint venture agreement with Shell/Agip/Elf for the purpose of gas liquefaction, which led to the formation of the Nigerian Liquefied Natural Gas Company (NLNG).22

(b) Non-Equity Share Participation Agreement Under this form of JV, the FG, through the NNPC, enters into a Joint Operating Agreement with a multinational company or companies. Although, a new LLC is not formed, the JV partners agree to hold jointly all rights and interest under the JV, and to meet expenses in the proportion of their participating interest. One of the partners (usually the foreign technical partner) is designated the ‘Operator’. The Operator’s duties amongst others, includes the implementation of work program and budgets, and the provision of technical and advisory services. The Operator is subject to the overall supervision of the Operating Management Committee (OMC), comprising duly appointed members of

21 NNPC shareholding as at 1989, Schlumberger (40%), Bariod (36%), Hyson (51%) 22 NLNG was incorporated in February, 1990 as one of the subsidiaries of the commercialized NNPC with the respective

shareholding being NNPC (60%), shell (20%), Agip (10%) and Elf (10/%).

the JV partners. Contributions towards exploration, development and production costs are made through cash calls, based on work programs and budgets presented by the Operator, and approved by the OMC. Each partner under the arrangement can lift and dispose separately its share of crude, subject to the payment of Petroleum Profits Tax and royalty. The commercial aspect of JV arrangements is covered in the Memorandum of Understanding with the NNPC.

A schedule of the major JVs and the respective interest of the partner is shown below:

Operator Other Partners Daily Production (bbls)

Shell – 30% NNPC - 55% TotalFinaElf – 10% Agip – 5%

900,000

Mobil (Exxon Mobil) – 40% NNPC – 60% 520,000 Chevron – 40% NNPC - 60% 420,000 Elf (TotalFinaElf) – 40% NNPC - 60% 125,000 Nigeria Agip Oil Company – 20%

Phillips – 20% NNPC – 60%

145,000

1.3.2 Production Sharing Contract (PSC) Under this arrangement, the NNPC enters into a contract with a foreign company designated “the Contractor.” The Contractor would engage in E & P activities, but it has no title to the crude oil produced therefrom. The continuation of the contract and the recovery of its costs incurred would depend on the discovery of oil in commercial quantities from the allocated block. The Contractor therefore, bears all risks. If oil is found in commercial quantities, the Contractor recoups its investment and cost of operation after royalty payment to the Federal Government, but before payment of petroleum profits tax (PPT). The profits are shared between the NNPC and the contractor on a predetermined ratio.

17

The Contractor is allowed to market the portion of the production allocated to cost oil23 and its share of profit oil24, but at the price fixed by the NNPC. The concession under this arrangement is located in the deep offshore or inland basins. Examples of this arrangement include those signed between the government (represented by NNPC) and Esso, SNEPCO and Star Deep. Under a PSC, all qualifying capital expenditure (QCE) imported for E & P activities by the Contractor automatically becomes the property of the FG on arrival into the country. They may not also be disposed except with the prior consent of the FG, through the appropriate agencies. However, the Contractor could claim all available capital allowances on them for the purpose of PPT returns. 1.3.3 Risk Service Contract This form of petroleum contract is also called ‘operation or work contract’. The duration covered by the contract does not exceed five years and the contract area relates only to a single block. The Contractor, as in the PSC, has no title to oil produced. The concession ownership remains entirely with the NNPC. The Contractor undertakes exploration, development and production activities for, and on behalf of, the NNPC or the concession holder, at its own risk. It therefore provides risk capital and technical expertise for the petroleum operations. In return, the Contractor is reimbursed only from funds derived from the sale of available oil produced, and is paid periodical remuneration in accordance with the formulae stipulated in the contract. The NNPC has the right to market the oil produced and may pay any related cost in cash or in kind. However, the Contractor has the first option to buy back the crude oil produced from the concession. The option can be exercised even after the life of the contract. This kind of agreement exists between NNPC and Agip Energy and Natural Resources, and between SOGW/Atlas and Nexen Oilfield Services Nigeria Limited.

23 Cost oil: This is made up of the contractors operating costs recovered and capital investments. 24 The balance after deduction of cost oil and tax oil (actual tax plus royalty).

In a RSC, the Contractor does not derive its income from petroleum operations, as it’s carrying out that operation for and on behalf of another party. Consequently, the Contractor is subject to tax under the Companies Income Tax Act (CITA), at 30% of its assessable profit. The tale below summarises the major differences between the various forms of agreement. Major differences between JVs, PSCs and RSCs

JV PSC RSC

1. Origin

Existing 100 per cent concessionaire (foreign partner) had to accommodate the new partner (NNPC) in the venture as a participant.

NNPC and foreign partner started as co-ventures upon the execution of the PSC. No prior interest by the foreign partner in the title to the concession.

The primary period of the agreement varies between 2-3 years and is renewable for additional two years.

2. NNPC’s Interest in the Venture

This is limited to the

working interest and does not affect the foreign partner’s equity ownership. It is understood by the parties that NNPC has undivided interest in the concessions and in the assets and liabilities of the venture to the extent of 60 per cent effective 1st July, 1979.

The concession ownership remains entirely with NNPC. However, on production its interest and title attach to roughly 65 per cent of the Participant’s Oil or the Profit Oil. This increases to 70 per cent on the joint venture’s attainment of 50,000 barrels daily production.

The concession ownership remains entirely with NNPC. The agreement covers only a single concession or block.

18

JV PSC RSC

3. Cash Call obligations

Partners to the joint venture contribute to capital and operating costs in the ratio of their respective participating interests – current ratio is NNPC – 60 per cent and foreign partner – 40 per cent.

Contractor initially bears all the joint venture expenses. NNPC only pays its share through the allocation to Contractor of cost oil. The reimbursement of such costs (in kind) only occurs on the discovery and production of commercial oil reserve. No reimbursement at all when there is no production i.e. the investor bears all the investment risks.

The contractor provides all the funds and technical expertise. He is reimbursed only from funds derived from the sale of available oil production. NNPC has the right to market the oil produced and may pay the cost in cash or kind. The Contractor does not have title to the oil produced.

4. Tax Rates

(a) 85% (b) 65.75% (1st five

years)

50%

Technically speaking, the Contractor does not operate within PPTA 1990. In practice, however, the tax rate is 85%.

5. Marketing Rights Each party markets its

equity or participating interest share of the available crude oil production from the concession.

Contractor is allowed to market the portion of the production allocated to cost oil and Contractor’s share of Participant’s Interest Oil, but at the price fixed by NNPC.

Marketing rights lie with NNPC. However, the Contractor has the first option to buy back the crude oil produced form the concession. The option can be exercised even after the life of the contract.

JV PSC RSC

6. Examples

Shell Mobil

Addax Petroleum ConocoPhillips

Agip Energy Resources Nigeria

19

2. PETROLEUM ACT AND SUBSIDIARY

LEGISLATION The Petroleum Act The Petroleum Act (and its pursuant Regulations) is the main legislation governing matters related to petroleum exploration and production in Nigeria. The Act amongst others: (i) Vests entire ownership and control of all petroleum in, under or upon

any lands (including water) in the State.

(ii) It also governs the issue of oil exploration licenses, oil prospecting licenses and oil mining leases

(iii) The DPR permit is granted on the basis of service lines applied for and is renewable annually.

(iv) The Ministry of Petroleum Resources is the supervisory ministry.

(v) DPR oversees industry regulation.

(vi) A DPR permit is required by all service providers to operate in the Nigeria Oil and Gas industry.

(vii) The DPR permit is granted on the basis of service lines applied for and is renewable annually.

2.1 Mineral Oils (Safety) Regulations This regulation covers from the safety perspective, the duties of licensees and lessees; managers and employees for operations in the Nigeria Oil and Gas industry. It also details the safety requirements/ procedures for drilling, production, storage, transmission and loading operations; precautions against fire outbreaks and requirements for reporting accidents, amongst others.

2.2 Petroleum Regulations This regulation covers the: Importation, Shipping, Unshipping and Landing of Petroleum. It provides for regulations governing the following: Storage of Petroleum: Licence for storage, Issue of licences, Storage sheds etc

Transport of Petroleum: Licence for transport, Issue of licence, Permit to operate kerosene peddling truck etc

Liquefied Petroleum Gas (LPG): Licences for importation of LPG, Storage of LPG, Fire precautions etc

Fuelling of Aircraft: Precautions while fuelling, Operation of fuelling vehicles Offences and penalties etc

2.3 Petroleum (Drilling and Production) Regulations This regulation deals with the requirements for application for oil exploration licence, oil prospecting licence and oil mining lease. The regulations provides in detail for the requirement for obtaining licences and the obligations of the lessees and licensees, including:

20

Requirements Application forms, Registration of licences and lease, Approval of applications etc

Obligations of Lessees and Licensees Recruitment and Training of Nigerians, Exploration and drilling, Field Development, Reports , Accounts and records, Fees, Rents and Royalties etc

2.4 Petroleum Refining Regulations These regulations cover the following areas: Licence to construct / operate a refinery Enlargement / modification of refineries Appointment of competent persons to manage and supervise refineries Observance of good refining practices Observance of fire and safety regulations Medical facilities and first aid services Reporting requirements Offences Fees etc

2.5 Crude Oil (Transportation and Shipment)

Regulations This regulation covers the requirements for transportation and shipment of crude. It provides for: The specification of ships utilised in crude transportation;

Requirements to be observed by ships to be used in transportation of crude oil;

Declaration of capacity of receptacle (ship, tanker or vehicle) holding

the crude; Documentation requirements of receptacle; and Penalty for non-compliance. 2.6 Petroleum Profits Tax Act The PPTA provides the legal basis for the imposition of taxes on the income of companies engaged in petroleum operations. The Act defines itself as: “An Act to impose a tax upon profits from the winning of Petroleum in Nigeria, to provide for the assessment and collection thereof and for purposes connected therewith.” The PPTA covers items like: Imposition of tax and ascertainment of chargeable profits Ascertainment of assessable tax and of chargeable tax Chargeable persons Accounts and assessments Appeals Collections, recovery and repayment of tax Offences and penalties 2.7 The Deep Offshore and Inland Basin Production

Sharing Contracts Act

The Act specifies the royalty rates applicable on production from PSC fields. It is described as: “An Act , among other things, to give effect to certain fiscal incentives given to the oil and gas companies operating in the Deep Offshore and Inland Basin areas under production sharing contracts between the Nigerian

21

National Petroleum Corporation or other companies holding oil prospecting licenses or oil mining leases and various petroleum exploration and production companies”. Deep Offshore”, according to the Act, means “any water depth beyond 200 metres”. The rates are graduated as follows:

Area Rate (%)

In areas from 201 to 500 metres water depth 12 In areas from 501 to 800 metres water depth 8 In areas from 801 to 1,000 metres water depth 4 In areas in excess of 1,000 metres water depth 0

2.8 Oil and Gas Export Free Zone Act

The OGEFZA was enacted pursuant to the Free Trade Zones (FTZ) scheme, conceived by the Federal Government (FG) in 1992 to facilitate a friendly climate for local and foreign investments25. The OGEFZA provides the regulatory frame work for the designation of FTZs. The Act also established the Oil and Gas Export Free Zone Authority. Several incentives are granted to enterprises within the EFZ. These incentives include: (i) exemption from all Federal, State and Local Government taxes, levies

and rates and import duties on any capital and consumer goods, raw materials components or articles to be used in respect of any approved activity within the EFZ;

(ii) repatriation of foreign capital investment (profits and dividends) in the

EFZ at any time; (iii) exemption from application for import and export licences;

25 The Nigeria Export Processing Zones Act, (NEPZA) 1992 is the equivalent legislation for the non-oil sector.

(iv) up to 25% maximum production may be sold in the Customs territory of the EFZ against a valid permit and on payment of appropriate duties;26

(v) rent free land at construction stage, thereafter rent shall be as

determined by the Authority; and

(vi) foreign managers and qualified personnel may be employed by companies operating in the EFZ without expatriate quota requirements.

2.9 Niger Delta Development Commission Act The Act set up the Niger Delta Development Commission Act (NDDC). The Act establishes the Governing Board of the NDDC. It provides amongst others for the following items NDDCs source of funds NDDC’s expenditure Establishment of monitoring committee Evaluation of the provision of the Act vis-à-vis E&P Company’s activities Tax treatment of the contribution from oil and gas companies . Contribution to host communities. Applicability to companies in exploratory stage.

26 Please note that the FG has recently announced a policy change allowing up to 100% exportation into the Customs territory, although this is yet to be enacted into law.

22

3. THE PETROLEUM PROFITS TAX ACT, 2004

3.1 Introduction The Petroleum Profits Tax Act, 2004 (PPTA) governs the taxation of companies engaged in petroleum operations. The Act defines petroleum operations as, “the winning or obtaining and transportation of petroleum or chargeable oil in Nigeria by or on behalf of a company for its own account by any drilling, mining, extracting or other like operations or process, not including refining at a refinery, in the course of a business carried by the company engaged in such operations, and all operations incidental thereto and sale of or any disposal of chargeable oil by or on behalf of the company”. Any other activity not covered by the above definition is liable to tax under the Companies Income Tax Act (CITA), 2004. Such activities include: Refining Marketing Petrochemical Sale and Marketing Liquefied Natural Gas Oil Field Services 3.2 Administration of Petroleum Profits Tax (PPT) The tax is administered by the Federal Board of Inland Revenue (“The Board”), through its administrative arm, the Federal Inland Revenue Service (FIRS). The Board has the following powers, amongst others: 1. To carry out such acts as may be deemed necessary and expedient for

the assessment and collection of tax 2. To sue and be sued in its official name

3. To acquire, hold and dispose any property taken as security for, or in satisfaction of any penalty, tax or judgment debt due from a company27.

4. It may authorize any person within or outside Nigeria to perform or

exercise any of its powers or duties or receive any notice or other document to be served upon or delivered or given to the Board.

5. The Board shall be subject to the authority, direction and control of the

Minister and any written direction, order or instruction given by him. 3.3 Imposition of PPT and Chargeable Persons

The tax is levied on the profits of a company engaged in petroleum

perations during an accounting period. o Chargeable persons under PPTA are corporate bodies engaged in petroleum operations. Individuals on their own or jointly as partners are not allowed to engage in petroleum operations. However, two or more companies can, as partners or in joint venture, engage in petroleum operations. The tax liability arising from the joint operation shall be apportioned among the comp nies as the minister may deem fit. a

Non-resident companies engaged in petroleum operations in Nigeria are assessable to tax either directly or in the name of their manager. For a company being wound up, the receiver or liquidator is liable to the tax.

3.4 Computation of PPT

In order to ascertain the tax payable by an E&P company, the following computations are necessary:

Revenue Adjusted Profit Assessable Profit

s Capital Allowanceit Chargeable Prof

Assessable Tax 27 The Board must account for any such property to the Minister of Finance.

23

3. 4.1 Revenue

The revenue28 of a company engaged in petroleum operations is taken to be the aggregate of:

(a) the proceeds of all c

that period; hargeable oil sold by the company in

b) hargeable oil disposed29 by the company in ( the value of all c that period; and

c) ( all income of the company that period incidental to and

arising from any one or more of its petroleum operations.

3 4.2 Adjusted Profit .

To obtain the adjusted profits for an accounting period, all out goings and expenses incurred by the company wholly, exclusively and necessarily, in its petroleum operations for that period, whether within or outside Nigeria, are deducted from the revenue. The following allowable expenses are specifically listed by the Act: a) in respect ( rents incurred by the company during the period

of land or buildings occupied for its operations.

(b) all royalties incurred in respect of casinghead petroleum spirit.

crude oil or

( compensation incurred for disturbance u prospecting licence or oil mining lease. c) nder an oil

(d) interest payable on monies borrowed and employed as

capital by the company on its operations (either from third parties or related entities)

28 This originally included the value of all chargeable natural gas. This was expunged by virtue of the Finance and Miscellaneous Tax Provision Decree No 18 of 1998.

29 This is the value of oil determined for the purpose of royalty, after making adjustment for cost of extraction of the oil and

any cost incurred in transporting and storage of the oil between field of production and place of disposal.

(e) any expense incurred for repairs of premises, plant, machinery or fixtures employed for the purpose

(f) all expenses previously classified as tax offsets attributable

to royalties on locally disposed oil, non-productive rents, customs and excise duties on essentials.

( repairs and renewals of premises, pla fixtures employed in the operations. g) nt, machinery or

( bad debts incurred during the period as well as specific h) provisions for doubtful debts. The Board is to be satisfied

that such debts have become bad or doubtful of collection.

(i) n any expenditure incurred in connection with the exploratioo appraisal wells, whether or not and drilling of the first tw

the wells are productive.

(j) oved pension, provident or other any contribution to an appr retirement benefit scheme.

(k) liability incurred by the company during the period to the

federal, state or local government in Nigeria by way of stamp duty, tax or any rate, import fee or other like charge.

( intangible drilling costs directly inc drilling, appraisal or development. l) urred in connection with

(m) education tax

(n) scholarship expenses (as decided by the Supreme Court in

September 1996 in the case between Shell and FBIR).

( such other deduction made under the Act. o) s as may be prescribed by any rule

24

The following deductions are specifically disallowed by the Act:

(a) any capital withdrawn or any sum employed or intended to be employed as capital. (b) any capital employed in improvements as distinct from repairs

(c) any sum recoverable under an insurance or contract of indemnity

(d) any amount in respect of income tax, profits tax or other similar tax, whether charged in Nigeria or elsewhere. (e) fixed assets depreciation (f) any contribution to an unapproved pension, provident or other similar schemes. (g) any expenditure for the purchase of information relating to the existence and extent of petroleum deposits. (h) any disbursements or expenses not wholly and exclusively incurred for the purposes of the business

3.4.3 Assessable Profit

The Assessable Profit of an E&P company for any accounting year is obtained by deducting from the Adjusted Profit, any amount of loss30 incurred in a prior accounting period. The amount of loss recouped cannot, however, exceed the adjusted profit.

3.4.4 Capital Allowances

An E & P company is eligible to claim capital allowances (CA) in respect of any qualifying capital expenditure (QCE) only if it was

30 Under PPTA, losses can be carried forward and relieved against future profits indefinitely. There is no time limit for recouping losses as under CITA.

the owner of the QCE (asset) at the end of that accounting year, and the QCE was in use for the purposes of the petroleum operations carried on by it.

The PPTA recognizes four types of QCE on which capital allowances can be claimed. These are:

(a) Plant – capital expenditure on plants, machinery and fixtures.

(b) Pipeline and Storage – capital expenditure on pipelines and

storage tanks.

(c) Building – capital expenditure on the construction of buildings, structures or works of a permanent nature.

(d) Drilling – capital expenditure in respect of acquisition of rights in or over petroleum deposits, searching for, or discovering and testing deposits, and construction of any works or structure which are likely to be of little use when petroleum operation ceases.

3.4.4.1 Types of Capital Allowances

(a) Petroleum Investment Allowance (PIA)

This is an allowance granted to an E&P company in the first year a QCE was incurred for the purpose of its operation. The applicable rates depend on the fiscal regime (contract form) under which the E&P company operates.

The following rates are applicable to companies in JV operations.

25

QCE in respect of Rate (%) Onshore operations 5 Offshore operations: Up to and including 100m of water depth 10

Between 100m and 200m water depth 15 Beyond 200m water dept 20

Companies that operate PSCs are either entitled to a PIA or an

Investment Tax Credit (ITC)31 depending on when the PSC was signed. For PSCs signed after 1993, PIA at the rate of 50% of qualifying capital expenditure would apply. For PSCs signed by 1993, ITC at the same rate would apply. (b) Annual Allowance

Annual allowance is granted to a company which has acquired QCE,

in lieu of depreciation. The current rates are 20% in the 1st four years and 19% in the fifth year. The balance of 1% of the cost is retained in the books until the QCE is sold.

(c) Balancing Allowance/Charge

Balancing allowance is granted to a company where, on disposal of a QCE owned by it and exclusively used for its business, the tax-written-down-value (TWDV) on disposal exceeds the sale proceeds. On the other hand, where the sale proceeds exceed the TWDV of the QCE, the excess, known as the balancing charge, is treated as income to the company in that accounting period. The balancing charge should, however, not exceed the total CA claimed to date on that QCE.

31 Treated as a credit against tax payable and not a charge against income.

3.4.4.2 Restriction on Capital Allowance

CA claimable by an E&P company is restricted to the lower of: (a) Actual computation and

(b) 85% of assessable profit less 170%32 of Petroleum Investment

Allowance (PIA).

In practice however, the 170% PIA adjustment is usually disregarded, as it seeks to discourage further capital investment in the sector by E&P companies. Therefore, the CA is simply restricted to the lower of actual CA and 85% of assessable profits.

3.4.5 Chargeable Profit

This is obtained by deducting allowable capital allowances from the assessable profit.

3.4.6 Assessable Tax 3.4.6.1 PPT Rates

The applicable tax rate is 85% for an E&P company in JV with the NNPC. However, where the company is in its first five years of petroleum operation, the applicable rate is 65.75%. The PPT rate for companies operating PSCs with the NNPC is 50% flat for the contract area, irrespective of the duration of the contract as provided under Section 3 of the DOIBPSC Act.

32 This is actually a disincentive to incur capital expenditure as the more the capital expenditure incurred by the company in any year the less the capital allowances it can claim. There is a need for the Board to revisit provision and make amends.

26

3.4.6.2 Format for the Computation of Assessable Tax

For JV Companies

$ $ Sales Proceeds + Incidental Income x Less: Royalties x Operating Cost x Intangible Drilling Cost x Tangible Drilling Cost x Education Tax x (x) Adjusted Profits x Less Unrelieved Losses (x) Assessable Profits x Less: Capital Allowances as restricted x

Petroleum Investment Allowance x (x) Chargeable Profits x Assessable Tax/Chargeable Tax x

For Companies Operating PSCs $

Sales Proceeds + Incidental Income x Less: Royalty Oil (x)

Income net of Royalty Oil x Less Cost Oil (Opex, Educ. Tax, IDC, CA, ITA) (x) Chargeable Profits x Assessable Tax @ 50% x Less ITCs (PSCs signed in 1993) (x) Tax Oil x Profit Oil (Chargeable Profits less Tax Oil & ITC) x

3.4.7 Tax Treatment of Pre-production Expenses

Section 21 (2) of the PPTA states: “…where a company has not yet commenced to make a sale or a bulk disposal of chargeable oil under a program of continuous production as at 1 April 1977, its assessable tax for any accounting period during which it has not fully amortised all pre-production capitalized expenditure due to it less an 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 profit for this period” The underlined portion of the section suggests that: (1) Pre-production expenditure would be capitalised on

commencement of petroleum production; (2) The capitalised pre-production expenditure would be

amortised by way of capital allowance as provided for in paragraph 6 of the second schedule to the PPTA

Paragraph 1 (Interpretation) to the second schedule of the PPTA defines “qualifying expenditure” for the purpose of capital allowances (and PIA) as: (a) capital expenditure (qualifying plant expenditure) incurred

on plant, machinery and fixtures; (b) capital expenditure (qualifying pipeline and storage

expenditure) incurred on pipelines and storage tanks; (c) capital expenditure (qualifying building expenditure)

incurred on the construction of buildings, structures or works of a permanent nature; or

(d) capital expenditure (drilling expenditure) …incurred in

connection with, or with petroleum operations in view of … while; Paragraph 5 states that: “where a company has incurred any qualifying capital expenditure wholly, exclusively, and necessarily for the purpose of petroleum operations, carried out by it, there shall be due to that company, … an allowance (in this schedule called “Petroleum Investment Allowance” ) at the appropriate rate …”:

27

If Paragraph 5 is read in conjunction with Section 21 (2) and Paragraph 1, it can be concluded that since pre-production expenses are now to be treated like capital expenditure under the Second Schedule, all allowances applicable to capital expenditure would apply to them, i.e. PIA and capital allowances would be applicable.

3.4.8 Signature Bonuses

A signature is paid for acquisition of rights or interest in an oil concession. For the purpose of cost oil recover under PSC signature bonus is not included. However, based on the provisions of paragraph 1(d) of the second schedule of PPTA, which defines qualifying drilling expenditure for capital allowance purposes, to include, “the acquisition of, or of rights in or over, petroleum deposits”, signature bonuses are considered as part of qualifying drilling expenditure. Thus for PPT purpose, it can be recovered by way of capital allowance.

3.5 Compliance Procedures 3.5.1 Returns The PPTA provides that every company engaged in petroleum operations should file two sets of returns: 3.5.1.1 Estimated Tax Return

This return is to be filed not later than two months after the commencement of each accounting period, i.e. February of every year. The return contains an estimate of the PPT liability for the accounting year. In preparing this return, an E&P company bases its calculations on the approved budget for the year.

The projected price per barrel used by the FG in its annual

budget usually constitutes the reference price of crude oil for the purpose of the PPT returns.

Revised estimated return may be submitted if at any time during such an accounting period, the company becomes aware that the initial estimate submitted requires revision, failing which the initial return may result in overpayment of tax at the end of the year.

3.5.1.2 Final Tax Returns

An E&P company is expected to file, within five months from the end of an accounting period, its actual returns in the prescribed format33.

Accounting period in relation to a company engaged in

petroleum operations is defined as:

(a) a period of one year commencing on 1 January and ending on 31 December of the same year, or

(b) any shorter period commencing on the day the

company first makes a sale or bulk disposal of chargeable oil under a program of continuous production and sales, domestic, export or both and ending on 31 December of the same year; or

(c) any period of less than a year being a period

commencing on 1 January of any year and ending on the date in the same year when the company ceases to be engaged in petroleum operations.

3.5.2 Tax Payment The estimated PPT liability for an accounting year is payable in 12 equal monthly installments, plus a final installment. The first installment is due and payable not later than the third month of the accounting period (i.e., March). Subsequent installments will be due and payable not later than the last day of each month.

33 The Returns would contain the signed audited account, final tax computations and a declaration signed by a duly authorised

officer of the company that the information contained therein is true and complete.

28

The audited accounts of an E&P company is expected to be finalized and the actual (final) tax returns filed by May of the subsequent year. Therefore, the actual PPT liability, based on the audited accounts is computed, and compared with the estimated PPT. Where the actual PPT is higher than the estimated PPT, an additional assessment is raised for the difference. The assessment is due and payable within 21 days from the date of the service of the assessment notice for such accounting period. Where the actual PPT is lower than the estimated PPT, the overpayment (tax credit) is carried forward to offset the PPT liability of the subsequent tax years.

3.6 Assessments There are 4 types under the PPTA, namely

1. Original Assessments

This is issued where the E & P Company files its annual returns, and it is acceptable by the Board

2. Best of Judgment Assessment

This is issued where:

a company fails to submit its returns within the statutory time limit.

in the opinion of the Board, the returns submitted does not reflect the true tax liability of the company

3. Additional Assessments

This is issued where after carrying out an audit; the Board discovers that tax has not been charged on a company liable to tax or that the tax assessed is less than the amount, which it ought to have been assessed.

4. Revised Assessments

This is issued where a tax payer objects to an assessment or it has been a subject of appeal and an agreement is subsequently reached on the tax payable and the original assessment is amended in accordance with the grounds of objection or amendment.

3.7 Objection/Appeal Procedure

A chargeable person (E&P company) may object to an assessment if he is of the opinion that the assessment is excessive. The following conditions must hold for an objection to be valid:

It must be in writing

It must be made within twenty-one days from the date of service of the notice of assessment

It must contain the amount of chargeable profits of the company for the accounting period in respect of which the assessment is made, the amount of the assessable tax and the tax which such person claims should be stated on the notice of assessment.

If the person so assessed and the Board reach an agreement on the amount

of tax liable to be assessed, the assessment shall be amended accordingly, and the notice of the agreed tax payable shall be served upon such person.

If the person to be assessed fails to agree with the Board on the amount of

the tax, the Board shall give such a person notice of refusal to amend the assessment. The Board may revise the assessment to such an amount as it may determine, and serve a notice of the revised assessment upon the person. If the person is still not satisfied, he may appeal to the appropriate Body of Appeal Commissioner.

The procedure to be followed for the appeal to be valid includes:

1. It must be made within 30 days of notice of refusal to amend assessment

29

2. It must be in writing and addressed to the Board and the Secretary of the Body of Appeal Commissioners

3. It should specify the following particulars The official number of the assessment and the accounting period

for which it was made. The amount of tax charged by the assessment The date upon which the appellant was served with notice of

refusal of the Board to amend the assessment as desired. The precise grounds of appeal against the assessment. An address for service of any notices, etc.

All appeals shall be heard ‘in camera’.

If the applicant is still aggrieved by the decision of the Appeal Commissioners, he may appeal to the Federal High Court. Again, he is required to first give notice in writing to the Board within thirty days after the date upon which such decision was given of his intention to appeal against the decision. Further appeal against the decision of the Federal High Court shall liable to the Federal Court of Appeal. However, further appeal is possible only if the tax assessed is up to N1,000. 3.8 Offences & Penalties The offences under the PPTA and the associated penalties are as follows:

Section of Act Offences Penalties

Section 46 Instalment of tax due not paid at the appropriate time

A sum equal to 5% of the amount due and payable

Section 51 Late submission of tax returns Fine of N10,000 and a further sum of N2,000 for each day the offence continues, and in default of payment to imprisonment for 6 months

Section of Act Offences Penalties

Section 51 Failure to deliver accounts or information or to keep the required record.

Same as Section 51 above

Section 51 (c) Failure to attend to a notice or summon served or to answer any question lawfully asked.

Same as Section 51 above

Section 51 (d) Failure to submit any return required

Same as Section 51 above

Other offences under the PPTA include: - Failure to furnish additional information required by the Board - Falsification of accounts - False statements and returns - Impersonation

3.9 Deep Offshore and Inland Basin Production Sharing Contracts Act (DOIBPSC) The DOIBPSC is the enactment which gives effect to the fiscal incentives granted to oil and gas companies operating in the Deep Offshore and Inland Basin areas under PSCs with the NNPC. These PSCs stipulate a different fiscal regime than that contained in the PPTA. “Deep Offshore” has been defined as any water depth beyond 200 metres.

The DOIBPSC imposes tax at the rate of 50% of chargeable profits34 of exploration and production companies for the duration of the PSC. The fiscal regime applicable to any PSCs is specific to the oil and gas licensing round during which the relevant OPL was awarded. The incentives applicable under the Act include: Tax rate of 50% of chargeable profits35 for the duration of the PSC.

34Same as taxable profit 35 Same as taxable profit

30

Claim of Petroleum Investment Allowance (PIA) or an Investment Tax Credit (ITC)36 of 50% of qualifying capital expenditure depending on when the PSC was signed. For PSCs signed in 1993, ITC is applicable, while PIA is applicable to PSCs signed after 1993.

Royalty rate of 10% for companies operating in the Inland Basin and graduated royalty rates for companies in Deep Offshore operations.

36 Treated as a credit against tax payable and not a charge against income.

31

4. ROYALTIES The Petroleum Act (1969) requires the holder of an OPL or an OML, to pay to royalties to the FG as soon as production starts. This is usually in form of monthly cash payments37 at an agreed percentage of the quantity of oil produced, after making adjustments for treatment, handling and related expenses.

4.1 Royalty Rates 4.1.1 JV Operations

The royalty rates currently applicable are as follows:

(i) on-shore production 20%

(ii) offshore production up to 100 metres water depth 18½%

(iii) offshore production beyond 100 metres water depth 16⅔%

4.1.2 PSCs

The Deep Offshore and Inland Basin Production Sharing Contracts

Act No 9 of 2004, specifies the royalty rates applicable on production from PSC fields. “Deep Offshore”, according to the Act, means “any water depth beyond 200 metres”. The rates are graduated as follows:

Area Rate (%) In areas from 201 to 500 metres water depth 12 In areas from 501 to 800 metres water depth 8 In areas from 801 to 1,000 metres water depth 4 In areas in excess of 1,000 metres water depth 0

37 In most production sharing contracts, ‘royalty oil’ is allocated to NNPC. Payment is therefore in kind rather than in cash

4.2 Computation of Royalty Payable

The Petroleum (Drilling & Production) Regulations Act of 1969 provides that handling, treatment, storage and transportation expenses incurred on crude oil disposed are deductible in determining the royalty due on production. Therefore, the actual amount of royalty payable is arrived at as follows:

(a) Determine the volume of chargeable oil (CGOIL) for royalty purpose

as follows:

CGOIL = Q- (q1 + q2 + q3) Where:

Q = quantity of crude oil produced by the company q1 = internal storage/usage by the company

q2 = losses via evaporation, etc q3 = returns to formation/closing stock (b) Determine production revenue by applying the appropriate posted

price to the chargeable oil. (c) Obtain the value of chargeable oil by deducting handling, treatment,

storage and transportation costs from the production revenue. (d) Apply the appropriate royalty rate on the value of chargeable oil to

obtain the royalty due (e) Deduct from the royalty due, any production rentals payable by the

company, to arrive at actual royalty to be paid. In practice, most oil companies do not deduct handling, treatment, storage and transportation costs from production revenue to obtain chargeable value of oil. This may be because of the delay in obtaining approval of the claim from the Department of Petroleum Resources.

32

5. TAXATION OF OIL OPERATIONS

5.1 Changes in Licence and Petroleum Interests 5.1.1 Abandonment and Restoration Costs Abandonment relates to activities involved in giving up further exploration

activities in a well or field in which oil or gas has not been found in commercial quantity. The cost incurred in the dismantling of production facilities on abandoning the oil well, as well as those incurred in restoring the well to its original ecological state, are called restoration & abandonment costs.

Abandonment can also occur where the operators are of the view that oil or gas is exhausted and can no longer be profitably produced. On the other hand, restoration involves bringing the exploration site to its original ecological state.

Due to the size and complex nature of oil wells, the costs could run into

several millions of dollars. The ability to cover such costs by insurance is severely restricted. Therefore, the tax treatment is imperative for any E&P company.

Usually abandonment cost will exceed taxable profit for the relevant

chargeable period. Consequently the risk exists that the tax payer may not be able to claim a tax relief on the cost.

For accounting purpose, abandonment costs are estimated at the beginning of the period and amortized as part of operating costs. However, since “provisions” are generally disallowed for tax purpose, on the principle that they have not yet been incurred, it implies that any provision for the above amount would be disallowed.

E&P companies may, however, be able to obtain a tax-deduction for this item, if they execute a plan for restoration and abandonment. Such plan should provide for a fund, to which any provision for this cost can actually be paid into, and managed by an external fund manager. On commencing an abandonment and restoration programme, the company can draw down on the fund (together with any accrued interest income) to finance the cost.

It is believed that if this approach is adopted, the yearly expenditure, involving actual physical cash payment, should be deductible for the E&P company’s PPT purpose.

5.1.2 Participation In 2003, the Federal Government announced its intention to achieve majority state participation in commercial deep offshore acreages, in which the Government does not already have 100% interest. Under the Back-in-Rights Regulations 2003, the Federal Government can acquire Five – Sixth of the Nigerian ownership interest in the concession. The policy is usually implemented through negotiation of participation agreements with the oil companies. The terms of agreements of a participation agreement may vary according to particular circumstances. (Famfa and SAPETRO). However, the conclusion of a participating agreement is tax neutral, based on the compulsory nature of government participation. 5.1.3 Unitisation

This is an agreement between two or more E&P companies to jointly fund

the working of two or more oil concessions, where hydrocarbon accumulations straddle the boundary between the concessions held by the different parties. Usually, the E&P companies would form a single structure for the concessions, and appoint among themselves, an operator that would work the concession. The concessions will be operated as one “unit”. In the event that the oil companies cannot readily undertake to operate on this basis, NNPC can compel them to do so. Unitisation usually occurs after the appraisal stage and involves a re-allocation of participating interest, as shown on the next page.

33

Example: Participants OPL1 OPL2 A 60% - B 40% - C - 70% D - 30% Est. Production 160 40 Revised interest Production Percentage A 96/200 48% B 64/200 32% C 28/200 14% D 12/200 6% The unit operating agreement will usually provide for a redetermination of the participating factors since the initial participating ratio would have been based on limited data about the reservoirs. The revision of the participation factors may result in an adjustment of the participant’s share of production and cost, and payments among the participators. Unitisation is “tax free “in the sense that no taxable capital gain will be imputed to the parties receiving a cash settlement. However, difficulties can occur when unitization takes place after production has started and expenditure claims have already been allowed by the tax authorities; especially where individual returns are filed. In this situation, adjustments may need to be made to capital allowances already claimed.

5.1.4 Carry Agreements

Carry agreements refer to an arrangement involving two or more parties, in which a carrying party or the assignee finances the exploration and development activities in consideration for a reward out of future production (if any) and if necessary from the carried party’s or the assignor’s share of such future production. The assignor is usually the

carried party while the assignee is the carrying party. A production Sharing Contract (PSC) is a form of carried interest. The basic rule is that the taxpayer incurring the expenditure will receive the relevant tax relief and the tax payer receiving the production will be taxed on it. The Carrying party should be able to recover the cost of carrying the Carried Party from the proceeds of crude oil sale, after payment of royalty, but before payment of PPT. Consequently, the carried party would only have a share of the profit oil only after the “carry costs” have been recovered by the Carrying party. 5.1.5 Underliftings and Overliftings This usually occurs in connection with tanker loadings, particularly in relation to a participator with a small license share. SAS 14 provides that the company that underlifts must treat the underlift as receivable or stock valued at the lower of cost and market value. The corresponding credit will be to revenue. The party overlifting will account for it as payable and exclude from income. For PPT purpose, the participants are taxed on the basis of actual liftings. 5.1.6 Assignment

This occurs when a Participator assigns his license interest to another company (as opposed to a farm out), subject to DPR approval. The consideration for such an assignment may be: (i) Cash (ii) A retained source of production (net production interest) (iii) Overriding royalty interest (share in gross production) Section 6(1) of the Capital Gains Tax Act provides for the taxation of capital sum received from an assignment. Consequently, such amount will be taxed at 10%.

34

5.1.7 Farm out Agreement A farm out agreement usually arises when license holder is unable to finance exploration and/or development alone. It is mainly a financing arrangement Farm out arrangements may include: (i) partial or total reimbursement of past costs (ii) a carried interest (iii) a front-end loan recoverable out of future production A Licensee who surrenders part of his license is only entitled to producti n related to retained interest after payout.

o

There are mainly capital gains tax implications, which may however be mitigated by rollover relief. 5.1.8 Production Payments This is mainly a method of financing oil developments.. The steps involved are as follows: The lending banks would establish a shell company “A”; Company A forward purchases oil from the field at an agreed price.

The oil company uses the advance payment to finance field development;

Company A sells the oil to the oil company at pre-arranged prices under

a long term sales agreement and applies proceeds to service its bank borrowings.

Under this type of arrangement, Company A is only liable to tax under CITA.

5.2 Transfer Pricing/Inter-company Transaction

The World Bank has described transfer pricing as “process for goods, services and intangibles and royalties for intangibles as well as cost sharing agreements for research and development activities e.t.c, in transactions between related connected parties”. Simply put, a transfer price is the price at which goods and services are transferred between connected parties.

5.2.1 Pricing Policies

There is no universal pricing policy appropriate to all transactions among entities. The concept of arm’s length pricing seems, however, to be the overall guideline among tax authorities and international organisations. The concept is, however, not easily applied in practice.

Multinational companies determine their pricing policy based on a variety

of factors. The factors may include tax savings, competition or circumventing foreign exchange controls. It should be noted that tax is not the most important factor in setting a transfer price. Policies will depend on the type of transaction, countries in which entities operate and the multinational’s accounting policy.

Inter-company transactions of a multinational group generally fall into one

of the following categories: i. Sales and purchase of goods With respect to sale and purchase of goods, transfer pricing/arms length

transactions can only be straight-forward where a company sells its product to both related parties and unrelated parties. However, in circumstances where the company only sells its products to related parties, the issue of arm’s length transaction becomes more complicated. The search for a company with similar finished/semi-finished goods would most probably be cumbersome.

35

ii. Technology Transfers Transfer pricing under technology transfer is perhaps the most

complicated. This is especially so where the technology transferred is unique. In this scenario, the determination of the value of such technology is peculiar only to the related companies.

iii Provision of services Management and administrative services are quite peculiar to specific

companies. In order to attach a representative price, a full understanding of the functions of each entity would be required. Consideration would be required for the identification of the type of services rendered; determination of benefit effectively derived; and evaluation of appropriate charge.

iv Financial Transactions Inter-company lending becomes important and difficult to generalize to

arrive at arm’s length rate given considerations for cost of capital. A company can raise finance using internal sourcing or external funding depending on the cost of each source. However, where the sourcing is from one related party to another, this gives rise to transfer pricing concerns for the relevant authorities especially where the companies are in different countries.

5.2.2 Methods of Transfer Pricing

Some of the methods often adopted for transfer pricing include:

(i) Cost Based Transfer Pricing method

The cost plus starts with the supplier’s cost to which is added an appropriate margin. Cost, for the purpose of this definition, could be full cost, variable cost, standard cost or cost plus mark-up. The cost based method is commonly used to set prices charged by a manufacturing company and in particular, a contract manufacturer.

Advantages It offers the only available option when there is no market. Prices can easily be obtained from the costing system. A transfer price could be fixed especially when standard costing

approach is used, hence little or no externalities. Disadvantages

Unpredictable fluctuations associated with standard costing A pre-specified mark up makes profit highly predictable leading to inefficie It treats each division as cost rather than profit centers.

(ii) Market Based Transfer Pricing

The price would be that which both the selling and buying divisions are prepared to transact.

Advantages

Autonomy of division Basis for performance evaluation Objective and verifiable

Disadvantages

Accurate information about market price may not be readily available

Problem of unrealized profit in stock valuation when group account is being prepared.

(iii) Negotiated Transfer Pricing Method

Under this method, the buying and selling divisions will agree in advance to use mutually acceptable transfer price. It is a good motivational method for managers but great time is wasted during negotiation.

36

(iv) Arbitrary Method

Top management for all divisions determines transfer price. Though it promotes uniformity, it however erodes independence normally desirable for autonomous divisions.

5.2.3 Tax Impact of Transfer Pricing

Sometimes, related parties involved in a transfer pricing

situation may exist across country borders thus giving rise to issues relating to the taxation o f the companies global profits. Where countries tackle the taxation of such multinational companies in isolation, a huge double taxation burden would arise on these companies thus making foreign investments unattractive.

Member countries of the Organisation for Economic

Cooperation and Development (OECD) recognised this potential for double taxation, thus leading to the publication of the OECD transfer pricing guidelines. However, despite attempts by many countries to formulate acceptable and workable transfer pricing methodologies, international transfer pricing is still fraught with uncertainty and inconsistency thus creating challenges for multinational companies with local tax authorities of countries in which they operate.

5.2.4 Relevant Tax Provision in Nigeria

There is no specific legal provision on transfer pricing in

Nigeria. There are, however, some general provisions and guidelines, which may apply to transfer pricing. These include:

Joint Operating Agreement (JOA)

The charge to joint accounts in respect of general services should:

a. represent a fair allocation of actual costs relative to actual services provided and benefits enjoyed by the Joint Venture.

b. not exceed the amount which would normally be charged

by an affiliate to any other company within the group.

c. not duplicate any other amount charged to operator.

Maximum amount for home office charges contained in the

JOA/PSC

Companies Income Tax Act (CITA), as amended Section 22 of CITA discusses artificial transactions. It provides that where the Federal Board of Internal Revenue (Revenue) is of the opinion that a transaction, which reduces tax payable, is artificial, it may disregard such transaction and determine tax payable, as it considers appropriate.

Generally, a transaction may be deemed to be artificial or fictitious if made between persons, one of who has control over the other and the Revenue is of the opinion that the transaction has not been made on terms expected to have been made by persons engaged in the same or similar activities, dealing with one another at arm’s length. This provision of CITA is in line with the recommendations of the OECD with regards to transfer pricing.

Petroleum Profit Tax Act (PPTA), as amended

Section 15(1) of the PPTA also discusses artificial transaction with similar provisions to the one under CITA discussed above.

In addition, an amendment to Section 10 of PPTA by Decree no 30 of 1999, allows interest on inter-company loans as tax-deductible, for companies engaged in crude oil production. The interest must however reflect terms prevailing in arm’s length transactions.

37

Hence, interest on loans from parent companies to subsidiaries or associates, for example, will be allowed for tax purposes, if the interest amount is comparable to what obtains in the open market.

Capital Gains Tax Act (CGTA), as amended Artificial transaction is also provided for under CGTA. The provisions are similar to the provision of CITA discussed above.

Statement of Accounting Standard (SAS) 17 – Accounting in the petroleum industry: downstream activities SAS 17 briefly discusses transfer pricing within the context of accounting in the petroleum industry. The SAS recognizes the following methods used for transfer pricing decisions:

(i) market based pricing (ii) cost-based pricing; and (iii) negotiated pricing

The standard requires companies to disclose in the financial statement, the policy adopted with regards to transfer pricing.

5.3 Taxation of Marginal Fields

In recent times, the FG has come under great pressure to increase indigenous participation in the oil and gas industry by relocating marginal fields, belonging to multinational companies, to indigenous concession holders. In response to this call for increased participation, the government, in 1996, promulgated the Petroleum (Amendment) Act No. 23 on the development of marginal fields. 5.3.1 What is Marginal Field?

The Act does not define marginal fields. It however provides the criteria for determining which fields are marginal. Section 16A (2) of the first schedule provides that:

‘the Head of State, Commander-in Chief of the Armed forces may cause the farm-out of marginal field, if the marginal field has been left unattended for

a period of not less than 10 years from the date of the first discovery of the marginal field’. The above suggests that where non-producing fields have been left unattended for not less than 10 years, they qualify as marginal fields, and therefore can be compulsorily assigned by the Government without the consent of the concession holder.

The DPR’s “Draft Guidelines for Farm-out of Marginal Fields”38 also mandates all oil companies to update their portfolio of underdeveloped fields and report to the DPR on periodic basis.

A Marginal Field is thus, any field that has reserves booked and reported annually to the DPR and has remained unproduced for a period of over 10 years. 5.3.2 Features of Marginal Fields The DPR’s “Draft Guidelines for Farm-out of Marginal Fields”13 further expatiates the provisions of the Decree. It identifies marginal fields as follows: a. fields not considered for development by leaseholders because of economics.

b. fields that have had an exploratory well drilled on strata and have been reported as oil and/or gas discovery for more than 10 years.

c. fields with high gas and low oil reserves.

d. fields with crude oil characteristics different from current streams, which cannot be produced through current technology.

e. fields abandoned by leaseholders for upwards of 3 years for

economic reasons. f. fields that the present leaseholders may consider for farm-out due to

portfolio rationalization.

38 Source: Marginal filed development in Nigeria Ike Oguine

38

5.3.3 Objectives of the Marginal Field

(i) Expand the scope of participation in Nigeria’s oil industry. (ii) Increase the oil and gas reserves base. (iii) Promote indigenous participation in the oil industry.

(iv) Provide opportunity for portfolio rationalization.

(v) Enhance employment opportunity.

5.3.4 Enabling Legislation a. Petroleum Act; b. Petroleum (Amendment); c. Petroleum (Drilling and Production) Regulations; d. Associated Gas Re-injection Act; and e. Petroleum Profit Tax Act.

5.3.5 Classifications of Marginal Fields a. Oil companies are to carry out field studies and update their

portfolio of underdeveloped fields. b. Status of fields to be reported to DPR on a periodic basis.

5.3.6 Criteria for Evaluation of Application for Marginal Fields

The application for assignment must be made to the Minister of Petroleum Resources and approved by the Head of State, and must show the following: Company’s details. Evidence of the company’s technical and managerial capability.

Premium – signature bonus of $150,000. Environmental consideration. Local content. Commitment to social projects. Specific fields being bidded for. Financial capability.

5.3.7 Structure of Consideration to Leaseholders Overriding royalty payment for Farmor (percentage of income). Tariff payment ($/bbl).

5.3.8 Fiscal Regime There is no specific tax legislation for Marginal Fields, however, the PPT Act modified by the MOUs, will apply. The tax rates are as set out in the Deep Offshore and Inland Basin Production Sharing Contracts Act, as follows: Year 1-5 65.75% Year 6-11 85% Application field by field

Investment Tax Allowance is also applicable as follows: Onshore 10% 0-100m 15% 100-200m 20%

39

Royalty Rates for marginal fields are as follows:

Terrain Onshore Land/SWP

Offshore WD<100m

Offshore100<200m

Prod<2000 bopd 6.50% 2.50% 1.50% 2000<Prod<5000

bopd 15% 7.50% 3%

5000<Prod<10000 bopd

20% 12.50% 5%

10000<Prod<15000 bopd

20% 18.50% 10%

15000<Prod<25000 bopd

20% 18.50% 162/3%

Prod>25000 bopd

20% 18.50% 162/3%

5.3.9 Review of Production Sharing Contracts

The Deep Offshore and Inland Basin Production Sharing Contracts Act, governs PSCs. Below is a summary of the key provisions of the Act. (i) The Act provides that an OPL relating to PSCs in the deep offshore

and inland basin shall be determined by the Minister of Petroleum Resources, and will be for a minimum period of 5 years and an aggregate period of 10 years (Section 2)

(ii) The PPT rate applicable to the contract area in the PSC is 50% flat

rate of chargeable profits for the period of the PSC (S.3) (iii) PSC contractors are entitled to investment tax credit of 50% of the

Qualifying Capital Expenditure (QCE), where the PSC was signed prior to 1993, and the investment tax allowance ate same rate for PSCs signed after that date.

(iv) the applicable royalty rate are graduated as follows:

Area Rate (%) In areas from 201 to 500 metres water depth 12% In areas from 501 to 800 metres water depth 8% In areas from 801 to 1,000 metres water depth 4% In areas in excess of 1,000 metres water depth 0% Inland Basin 10% (v) Royalty Oil will be allocated to NNPC or concession holder in such

quantum to generate an amount of proceeds equal to actual royalty and concession rental payable (S.7)

(vi) The PSC contractors will be reimbursed its cost incurred to date of

production through cost oil. (vii) Tax Oil will be allocated to NNPC or the holder to generate an

amount equal to actual PT liability payable (S.9). (viii) The balance of crude oil after deducting royalty oil and cost oil,

known as profit oil, will be allocated to each party to the PSC in line with the provisions of the PSC (S.10)

(ix) NNPC or the holder has responsibility to pay all royalty, concession

rentals and PPT on behalf of itself and the Contractor out of the allocated royalty oil and tax oil. However, the FIRS will issue separate tax receipts for the respective amounts of PPT paid on behalf of the parties.

(x) NNPC and the Holder will split the chargeable PPT in the ratio as the

split of profit oil as defined in the PSC (S.12)

40

6 REVIEW OF PROPOSED AMENDMENT TO PPT ACT

6.1 Computing assessable profit

The major amendments are as follows:

Deletion of royalties on natural gas sold and actually delivered to the NNPC or any other customer as a deductible tax expense;

Ministerial approval required for loans whose interest rate exceeds the London Inter Bank Offer Rate (LIBOR);

Inclusion of any expenditure (whether tangible or intangible), directly incurred in connection with the drilling of an exploratory well and the first four appraisal wells in the same field, whether the wells are productive or not; and

Inclusion of provision for abandonment and restoration made in accordance with any rules approved by the Ministers charged with the responsibility for matters relating to petroleum and finance.

The deletion of royalties (first item) and the expansion of the number of appraisal wells to four from two for tax deduction purposes are welcome developments. Since gas income is now taxable under CITA, the deletion will ensure consistency and avoid contradiction in our laws. The oil and gas industry has long awaited the tax deductibility of the provision for abandonment and restoration cost.

The requirement for the approval of the Minister of the “maximum spread on LIBOR” is a setback for the freedom to obtain foreign loans without ministerial approval under the Foreign Exchange Act, 1995. It is hoped that the responsible ministry will put in place an efficient process for granting the required approval in order to ensure

that applications are not unduly delayed. Since most foreign loans are above LIBOR, it would be better if the law provides for a band above LIBOR beyond, which the ministry’s approval would be required. Better still, the requirement of ministerial approval should be dispensed with, as the oil companies can do without another bottleneck on their way.

6.2 Removal of incentives for gas utilisation

The proposed amendments suggest the deletion of Sections 11 and 12 which provide for incentives for utilisation of associated gas and non-associated gas. Interestingly, the proposed Gas Fiscal Reform Bill still contains reference to those sections proposed for deletion.

The reality is that after the provisions are deleted, there would be no legal basis for the continued enjoyment of the incentives by the existing beneficiaries. In view of the fact that we have not reached the stage of optimal gas utilisation yet in Nigeria, it would be better for the Government to allow a few more years before withdrawing the incentives, if at all.

6.3 Separation of petroleum business from other lines of

business – amendment to Section 14

The proposed amendment seeks to match expenses with related income. Consequently, expenses not related to petroleum operation cannot qualify for tax deduction under the PPT.

6.4 Chargeable profits of any company for any

accounting period – Amendment to section 20

The proposed amendment removes the existing restriction on the amount of capital allowances claimable. Based on the proposed amendment, exploration and production (E&P) companies will not

41

be in a tax payable position where the available capital allowances exceed the assessable profits.

6.5 Computation of assessable profit for petroleum

operations – Amendment to Section 21

The proposed amendments introduce three new subsections as follows: i. Subsection 21(3) – confirms the assessable tax rate of E & P

companies (under PSC terms) at 50% of chargeable profits from the contract area. The rate may, however, be varied by the Minister of Finance on the advice of the FIRS;

ii. Subsection 21(4) – which assesses to tax at zero percent,

transfer/sale/disposal of gas to a gas utilization project where the transfer is done at cost of production. However, where the transfer is done at a price higher than cost, the profits shall be subject to tax at the CIT rate; and

iii. Subsection 21(5) – export of gas to be taxed at the CITA rate.

6.6 Investment tax credit for production sharing contract

(PSC) – Amendment to Section 22

The amendments to subsections (1) and (2) of section 22 seek to clarify:

i the confusion that trailed the provisions of earlier Acts with respect to whether PSCs signed between 1993 and 1 July 1998 are entitled to claim Investment Tax Credit (ITC); and

ii The basis for calculating ITC.

Based on the proposed amendment, ITC will be applicable to all PSCs signed on or before 1 July 1998 and shall be calculated as 50% of the qualifying capital expenditure.

6.7 Information to be provided on Joint Venture

arrangement – Amendment to Section 24

The proposed subsection 24(7) on reporting requirements provides that notwithstanding any other contrary provision, every E&P company in a Joint Venture or partnership shall be responsible for reporting its petroleum operations, profits, outgoings, expenses, qualifying expenditure and the tax chargeable on its petroleum operations.

6.8 Reporting requirements – Amendment to Section 30

The proposed insertion of section 30A, in general terms, seeks to encourage and promote more transparency and accountability through the provision of relevant information by the national oil company and regulator (NNPC and DPR). The entire gamut of reporting requirements is in the spirit of the Federal Government’s desire to support the Extractive Industry Transparency Initiative (EITI)’s drive for promoting transparency in the industry.

6.9 Power to distrain for tax – Amendment to Section 35A

The insertion of a new section 35A contains eight subsections essentially identical to equivalent proposals for distraining under the CITA Amendment Bill. The PPTA did not give the FIRS any distraining powers. These new provisions are intended to strengthen FIRS’ revenue collection efforts.

42

6.10 Appeal against the decision of a High Court Judge –

Amendment to Section 42

The amendment substitutes the amount of N1,000 with N100 million as the threshold for appealing the decision of the judge of a High Court (either by an E&P company or the FIRS), to a Court of Appeal. This proposal may be challenged as unconstitutionally limiting the right to appeal by citizens.

6.11 Interest/Penalty for underpayment or late payment

of tax – Amendment to Section 45 & 46

The proposed amendments to sections 45 and 47 seek to introduce interest charges on any delayed payment of PPT installment or underpayment of PPT by an E & P company and the increase in penalty rate from 5% to 10%.

6.12 Failure to deduct or remit tax – Amendment to

Section 54

The proposed amendment seeks to reduce the penalty for failure to withhold tax or remit deducted tax within 30 days from 200% of the amount of tax (on conviction), plus interest at commercial rate, to 10% and interest at the prevailing CBN minimum rediscount rate.

6.13 Deduction of tax at source – Section 56

The proposed amendment suggests that in determining the rate of tax that will apply to any payments made to a company, the FIRS may take into account:

(i) any assessable profits of that company arising from any other

source on which income tax is chargeable; and

(ii) any income tax or arrears of tax payable by the company for

any of the six (6) preceding years of assessment.

43

7. LOCAL CONTENT

7.1 Local Content Policy

7.1.1 Brief Overview

In October 2001, the Nigerian National Petroleum Corporation (NNPC) inaugurated the National Committee on Local Content Development (the Committee) to develop a policy document on increased utilization of local (Nigerian) manpower, goods and services in the Nigerian oil and gas industry.

The Committee’s report titled “the Report of the National Committee on Local Content Development in the Upstream Sector of the Nigerian Petroleum Industry” (the Report), was submitted in April 2002. An updated version of the report was submitted in 2003 titled “Synchronised Report on Enhancement of Local Content in the Upstream Sector of the Oil and Gas Industry in Nigeria”39

The Report defines “local content” or “Nigerian content” as: “the quantum of composite value added to, or created in, the Nigerian economy through the deliberate utilization of Nigerian human and material resources and services in the exploration, development, exploitation, transportation and sale of Nigerian crude oil and gas resources, without compromising quality, health, safety and environment”.

The policy requires the local/Nigerian content of a contract to be stated as a percentage of the total contract sum. The above developments demonstrate the Federal Government’s (FG) keen interest in increasing the use of Nigerian manpower, goods and services in the upstream sector of the Nigerian petroleum industry. The President reiterated, in November 2003, that his administration

aims to increase local content to 45% by 2007 and 70% by 2010.

39 This report is stated to be a collation of the “Report of the Committee on Local Content, 19 January, 2002” and “ Enhancement of Local Content in the Upstream Oil and Gas Industry in Nigeria – a Comprehensive and Viable Policy Approach, SNF Report No. 25/03, August, 2003”

40 Consequently, the NNPC and its investment arm, the National Petroleum Investment and Management Services (NAPIMS), usually insist that certain portions of contracts awarded by multinational oil exploration and production (E&P) companies operating in Nigeria must be exclusively reserved for indigenous companies.

This is especially the case in respect of services for which Nigerian expertise is available. NAPIMS also usually insists on requiring contractors and operators to demonstrate the percentage of their projects or contracts that provide opportunities for local content development.

7.1.2 Guidelines for the 2005 Licensing Bid Round released by

the DPR The 2005 Licensing Bid Round took place in August 2005, and the related guidelines which governed the bidding round substantially reflected the local content policy thrust of the Federal Government. While the guidelines relate to only exploration and production (E&P) companies; in practice, oil services companies are required to also comply with the general local content regulations.

Among the key provisions contained in the guidelines, are:

(i) the broad objectives of the local content policy include

promotion of indigenous participation in the oil and gas industry to foster technology transfer, local goods and services utilisation and skills and competencies acquisition by indigenous employees;

(ii) the FG reserves the right to recommend Local Content

Vehicles (LCVs) to partner with foreign companies which win concessions;

(iii) local content was made a biddable criterion in the guidelines,

and the bids submitted by foreign companies shall include the activities which the operator would be willing to mandate to

40 In this context, ‘local content’ means Nigerian value added/input - Nigerian manpower, goods and services as a component of the overall project.

44

its local content partner expressed in US Dollars (US$). 7.2 Measurement of local content under the

Report

The Report listed the following eleven (11) parameters for evaluating/ measuring local content, as follows:

(i) Percentage of Nigerian management and established managerial

control of company. This is determined by reference to the composition of the Board of Directors of companies and the number of (top) management positions occupied by Nigerians in the companies involved in the relevant contract;

(ii) Percentage element of Nigerian ownership of company. This is

determined by reference to the shareholding of the companies involved in the execution of the contract. This will be evidenced by the certified true copy (CTC) of Form CAC 2.41 Thus, a company wholly owned by Nigerians or in which Nigerians hold majority of the shares would be deemed to have satisfied this requirement;

(iii) Percentage element of direct Nigerian employment (skilled and

unskilled);

(iv) Percentage cost of services provided by Nigerians;

(v) Percentage cost of Nigerian raw materials utilized;

(vi) Percentage cost of Nigerian finished goods utilized;

(vii) Percentage cost of Nigerian participation in the procurement of imported goods;

(viii) Quality and quantity of committed infrastructure investment in

Nigeria;

41 ‘Return of Allotment of Shares’ filed by companies at the CAC to reflect the shareholding structure of the company or changes thereon arising from new allotments, etc.

(ix) Effective technology acquisition and adaptation, and capacity building through joint ventures, equipment upgrades, formal training and other business development programmes;

(x) New jobs/ employment opportunities created for Nigerians; and

(xi) Amount of taxes, fees, duties and payments to the Government.

Although the Report provides parameters for measuring local

content, it is silent on the weight to be attached to each parameter in respect of any contract and the stipulated minimum percentage of Nigerian labour (on professional cadres) for listed projects in such contracts. In practice, the operators/regulatory authorities use their judgment to determine the weighting on a case-by-case basis. They also consider the relevance or otherwise of the parameters, since all the parameters will not be relevant in some cases. 7.3 Categorization of Service companies

The Report classifies service companies into five (5) categories (A to

E), depending on their ownership and institutional structure, as shown in the table below:

Category Title Description

A Wholly indigenous company

An indigenous company or contractor is one, which is wholly owned by Nigerians; has a recognizable establishment and its own resources in Nigeria are appropriate to the type and level of work, which it claims to be able to perform. Other features of a wholly indigenous company include:

Equipment must be 100% owned by the company;

At least 80% of the Directors

45

Category Title Description

must be Nigerians; A minimum of 80% of the

top management must be Nigerians; and

A minimum of 90% of senior field personnel must be Nigerians.

B

Majority Nigerian Shareholding company

A company registered in Nigeria with majority Nigerian shareholding that has the establishment, enterprise, assets and financial capability appropriate to the type and level of work it claims to be able to perform.

C Alliance or Joint Venture

An alliance between a Nigerian company (Category A) and a foreign company (Category E).42

D

Majority foreign shareholding company

A company registered in Nigeria with minority Nigerian shareholding that has the establishment, enterprise, assets and financial capability appropriate to the type and level of work it claims to be able to perform.

E Foreign company

A foreign company, whether registered in Nigeria or not, with no Nigerian shareholding and whose assets belong to the offshore company.

Source: ADCG Industry Survey 2004: The Nigerian Oil Industry43

42 Category C would apparently be a 50:50 JV between Category A and Category B companies. The proposed JV with Nigerdock (if Nigerdock is 100% Nigerian owned), may fall under this classification. 43 The ADCG Industry Survey cited NNPC as the source for the Table.

The Report assumes that “alliance and joint venture” would only be

recognised for the purposes of local content if formed between a Category A and Category E companies only. In practice, this is too restrictive as joint venture and alliances other than the one recognised (as Category C) may be necessitated by circumstances of particular projects or contracts.

With respect to evaluation of company types for bidding and contract

awards, it is safe to state that, all other things being equal, a Category A Company would have preference over all other categories, Category B being next in line, with Category E coming last. Given the provisions of the OGEFZA exempting foreign companies from local incorporation (provided they are registered in the Zone with the Zone Authority), a Category C Company does not need to set up either a Category B or D company, if its services to be performed in Nigeria, are carried out in the Zone. 7.4 Value Matrix

The Report provides guidance for measuring local content in respect of procurement of goods and services, utilization of direct and indirect labour and payment of taxes/fees on the basis of the value matrix below:

Goods/Materials/Equipment procured

Where the product or its components are not of Nigerian origin, but imported, then the Nigerian content is simply the added value to the product by Nigerians (working in a registered company in Nigeria) in the course of product delivery.

Where the product is manufactured in Nigeria using Nigerian raw materials, then the Nigerian content is 100%.

With respect to the proposed business of fabrication and welding, the Report notes that fabrication is one of the activity areas with high

46

potential for local content growth and is probably the most developed manufacturing area in the Nigerian petroleum industry.44 Where equipment is leased, then the Nigerian content will depend on the category of the owner/lessor companies weighted as follows: A- 100%, B-75%, C-25% and E-50%. A wholly owned foreign company would ordinarily have lesser weighting than a JV in which there is Nigerian participation (the greater the quantum of local participation, the better). Furthermore, please note that the various criteria are not mutually exclusive.

Services procured (including Sub contacting)

All services rendered in Nigeria by Nigerians working in any categorized company shall be deemed 100% Nigerian Content. For competitiveness, it is envisaged that JVCo would employ a higher number of Nigerian vis-à-vis expatriate employees.

Direct and Indirect Labour (total payroll)

All gross payments (inclusive of salary, social security tax etc.) to all Nigerian citizens employed for direct performance and indirect support of the contract/project shall be deemed 100% Nigerian Content.

Taxes/Fees/Duties

Should include the total value of all taxes and fees paid on all materials and equipment to the Federal/local government or regulatory agencies by Contactor in connection with performance of work during the reporting period.

Labour Hours

Where cost breakdown is extremely difficult, then the ratio of estimated total Nigerian-man hours compared to estimate total man-hours shall be Nigeria content.

44 According to the report, there is a total capacity of 23,000 tons spread across yards located in Dubi, Dorman Long and Niger Dock in Lagos, Warri and Port-Harcourt that are not fully utilised.

7.5 Core Competencies and Job Categorisation

The Report listed eleven (11) core competencies in the petroleum industry, and identified their various aspects that have high, medium and low technology impact, respectively. The expectation is for jobs/ services to be categorised on the basis of their technology and cost impact.

Although DPR and NAPIMS are expected to periodically publish a list of jobs and services, which can be awarded to only wholly indigenous companies, they are yet to publish a formal list. It is expected that DPR/NAPIMS would give first consideration to Category A (wholly indigenous companies) for relevant jobs or services with low or medium technology impact, where such companies have capacity which has not been fully utilised. In such instances, a price premium of up to 10% may be accepted for Category A company vis a vis other companies.

7.6 Policy Thrust

It is recommended that the policy thrust be put in place in achieving the targets on local content. These include, amongst others, that: NAPIMS to ensure that work scopes for mega-projects are broken down into smaller packages to facilitate participation of indigenous companies.

Industry stakeholders led by NAPIMS/DPR should establish a system for joint qualification of contractors through establishment of national databank of available capabilities.

DPR/NAPIMS should use preferential patronage as an instrument to mandate multinational service companies to invest in the local fabrication, infrastructure, and other facilities in Nigeria.

Any Category A company that wins a contract and fraudulently uses a foreign company to execute the contract shall be deemed to have committed an offence and risks having its DPR Permit withdrawn.

47

The policy objective of the Federal Government should be to strive towards achieving an increase in the market share of the wholly indigenous companies (Category A) in the petroleum industry.

7.7 Regulatory initiatives

The recommendations in the Report are yet to be enshrined in any approved policy statement by the Government but there are several draft bills before the National Assembly in this regard. The most prominent of these bills is the draft Local Content, Nigerian Content Development Bill, 2004 also contained a draft of the proposed law (Nigerian Local Content Implementation Bill), which the Committee recommended for passage into law by the Government to provide the legal backing for its recommendations.

The key recommendations of this Bill include:

(i) establishment of regulations by the DPR governing minimum price levels of Nigerian Content and the price premium that may be applied for Nigerian Content particularly for major contracts in the Nigerian Petroleum Industry;

(ii) contracts awarded in excess of a threshold value set by DPR in the procedure guide for the industry shall contain a “Labour Clause” mandating the use of a minimum percentage of Nigerian Labour (on professional cadres) for listed projects in such contracts.45

(iii) The DPR in consultation with NNPC shall establish for

companies involved in the oil and gas industry targets for Nigerian employees and for representation on the Board of Directors;

(iv) The DPR shall establish along with the companies, a Nigerian

Content performance monitoring procedure;

45 In practice, this has already commenced.

(v) Companies shall be required to produce annual local content plans for utilisation of contractors and labour from the host communities as well as plans for community development;

(vi) From when the A t is passed, no expatriate quota would be

granted to any company involved in the oil and gas industry without first obtaining the approval of the DPR.

The Oil and Gas Services Bill is another legislation that would be relevant on local content issues. The Bill makes it mandatory for companies doing business in the oil and gas sector to establish a physical presence in the State where they operate, and ensure that, as much as practicable, any contract they win is executed in Nigeria as well as fulfil other corporate social responsibilities.46 The affected companies are also required to comply with regulations and enactments relating to the welfare, safety, health and environment of its community of operation, and employment of a reasonable qualified number of peoples in the community, local government area, and state of operation.

Section 2(1) of the Bill includes a foreign company with an established Nigerian subsidiary, which:

(i) has its operational base in Nigeria;

(ii) employs citizens of Nigeria in its managerial, professional

and supervisory (MPS) grades, such that at least 30% of the subsidiary’s MPS positions are occupied by Nigerian citizens; and

(iii) after five (5) years of its operations in Nigeria, the number of

Nigerians employed in the subsidiary’s MPS grades shall not be less than 75% of total number of persons employed in such positions as eligible for the award of contracts in Nigeria’s oil and gas sector.47.

46 There are restrictions on executing parts of contracts outside of Nigeria: contractor must apply for permit to execute (not more than) 10% outside Nigeria from the NAPIMS, and permit would only be issued upon satisfaction of stated criteria. 47 Incidentally, such foreign company was not listed in section 4 amongst candidates for preferential consideration in award of contracts. Companies registered outside Nigeria can also get contracts in the oil and gas industry if Nigerians own 50% of their shares and if the shares are also listed and quoted on the Nigerian Stock Exchange

48

Notwithstanding the absence of enabling legislation on the matter, NNPC/NAPIMS have commenced the implementation of the local content policy enshrined in the Report in contract award process in the oil industry.

7.8 Potential impact on foreign oil service

companies

The implementation of the recommendations contained in the Report is likely to have the following impact on oil service companies with foreign majority shareholding operating in Nigeria:

(i) Increase in the compliance requirements for foreign companies

operating in the Nigerian oil and gas industry. For instance, it is envisaged that such companies would render quarterly and annual returns to the Department of Petroleum Resources (DPR) and NAPIMS on their local content achievement during contract execution. These returns will be in addition to their existing compliance requirements.

(ii) Foreign companies may be obliged to either increase their

Nigeria local content through Nigerian shareholding/directorship, management staff recruitment, local raw material utilisation joint venture and alliances with Nigerians, etc.

(iii) The practice of engaging expatriates for services for which there

are qualified Nigerians will be minimized. The foreign companies may not be able to obtain expatriate quota approvals or renewals for such positions. One of the policy thrusts in the Report is the collaboration of DPR/NAPIMS with FMIA to achieve controlled reduction of expatriate workforce and progressive build up of indigenous manpower.

(iv) Foreign companies will be obliged (or encouraged) to invest in

local fabrication, infrastructure and other facilities in Nigeria.

(v) Foreign companies with over ten (10) years presence in Nigeria may be obliged to achieve 95% of Nigerian presence in its management, professional and supervisory cadres as well as at

least 60% Nigerian presence on their Boards of Directors. Thus, there is the potential risk of Nigerianisation of the Boards of subsidiaries/ affiliates of multinational companies in Nigeria unless this element of the policy is reversed in the light of Federal Government’s foreign investment promotion policy.

49

8. THE MEMORANDUM OF UNDERSTANDING

(MOU)

The MOU is an understanding reached between the FG and oil producing companies in JV operations with the NNPC. The main objective of the MOU is to guarantee the E&P companies a profit margin, irrespective of market conditions. This was necessary to inject life into the oil industry, which was experiencing a slump in the mid 1980’s. The margin was determined by a combination of formulae used to arrive at the incentive, defined as the “MOU tax credit”. The MOU, first signed in 1986, was revised in 1991 and again in 2000.

8.1 Computation of MOU Tax Credit under the 2000

MOU.

The MOU Tax Credit is used as a tax offset against PPT liability. Its effect is to reduce the tax payable by an E&P company in JV with NNPC. MOU Tax Credit under the fiscal incentives of the 2000 MOU is computed as the difference between:

1. Initial Government Take (IGT) computed as Royalty plus

PPT using posted price, and 2. Revised Government Take (RGT) computed as Royalty plus

PPT, using the Tax Reference Price (TRP) 8.1.1. Computation of IGT

IGT is the sum of PPT and Royalty computed using “posted price.

8.1.2. Revised Government Take

The Formula for computing the (RGT) is given as:

RGT = ROYTRP + PPTTRP + TIP where:

ROYTRP = Revised Royalty PPTTRP = Revised PPT TIP = Tax Inversion Penalty

8.1.2.1 Computation of Revised Royalty (ROYTRP)

This is computed using the formula

ROYTRP = RR x TRP x V where: RR = Applicable royalty rate TRP = Tax Reference Price

V = Company’s crude oil production volume

8.1.2.2 Computation of Revised PPT(PPTTRP)

This is computed using the following formula

PPTTRP = [(TRP x Vs) - ROYTRP – TC] x TR where:

TRP = Tax Reference Price Vs = Company’s crude oil sales volume ROYTRP = Revised Royalty, computed under 4.1.2.1 above TC = Technical Cost, defined as allowable deductions

and capital allowances under PPTA excluding Royalty)

TR = Applicable Tax Rate

50

8.1.2.3 Computation of Tax Inversion Penalty (TIP)

TIP is aimed at reducing operating cost inefficiencies of E&P companies in JV with NNPC. Where in any year the technical cost (TC) of operation is greater than $1.70/bbl or greater than $2.30/bbl for companies producing above an average of 175,000 bbls/day, or $3.00/bbl for companies producing below an average of 175,000 bbls/day, a penalty is imposed. If however the reverse is the case, a credit is given. It should however be noted that at the limits (i.e. $1.70/bbl, $2.30/bbl or $3.00/bbl as the case may be), no penalty or credit is charged / accrued.

The formula for computing TIP is twofold;

1. Where TC is greater than $1.70/bbl

2. Where TC is greater than $2.30/bbl in any

year for companies producing above an average of 175,000 bbls/day or $3.00/bbl for companies producing below 175,000 bbls/day

For (1) above

TIP = (TR – TIR) x (T1 – LTIT) x V

For 2 above

TIP = (TR – TIR) x (T1 – UTIT) x V where:

LTIT = Lower Tax Inversion Threshold = $1.70/bbl

UTIT = Upper Trigger Point for Tax Inversion for T1 = $2.30/bbl for companies producing above an average of 175,000 bbl/day in the

same calendar year or $3.00/bbl for companies producing below an average of 175,000bbl/day in the same calendar year. To the extent that V, as defined below, is adversely impacted by circumstances outside the control of the company, UTIT shall be adjusted to negate such adverse impact the procedure of which is set out in Appendix C of the MOU.

TR = Applicable Tax Rate TIR = Tax inversion rate (35%)

8.2 Computation of Tax Reference Price (TRP)

TRP = RP – (M + 0.15 x FC)

0.88 where:

RP = Realisable Price

M = Applicable Guaranteed Notional Margin which varies

with RP

FC = Notional Fiscal Technical Cost of $4/bbl

8.3 Computation of Applicable Guaranteed Notional Margin (GNM)

(a) For Realisable Price less than $13.48/bbl

M = (1 – FC) x (RP1a1 + RP2a2 + RP3a3)

RP where:

51

RP = Realisable Price

FC = Notional Fiscal Technical Cost of $4.00/bbl

A = Company’s Percentage share of field profit

For:

Realisable Price in the Range

Company Share Applicable to Price Range

T2 < 2.00 T2 > 2.00 0 < RP1 < $5/bbl

a1 = 0.300 0.365

$5/bbl < RP2

< $10/bbl a2 = 0.285 0.28833

$10/bbl < RP3 < $13.48/bbl

a3 = 0.10744 0.08286

(b) For Realisable Prices between $13.48 and $15/bbl:

M = M15 + (RP – 15) x a Where:

M15 = $2.50/bbl when actual capital investment costs

(T2) is $2/bbl or less

= $2.70/bbl when actual capital Investment costs (T2) is greater than

$2/bbl a = Company’s Percentage share of field profit For:

Realisable Price in the Range

Company Share Applicable to Price Range

T2 < 2.00 T2 > 2.00

$13.48 < RP< $15/bbl

a = 0.1160 0.1315

(c) For Realisable Prices greater than $19/bbl and less

than or equal to $30/bbl:

M = M19 + (RP – 19) x a Where:

M19 = $2.50/bbl when actual capital

Investment costs (T2)is $2/bbl or less = $2.70/bbl when actual capital Investment

costs (T2) is greater than $2/bbl

RP = Realisable Price a = Company’s Percentage share of field profit For:

Realisable Price in the Range

Company Share Applicable to Price Range

T2 < 2.00 T2 > 2.00 $19 < RP< $30/bbl

a 0.1160 0.1315

(d) For Realisable Prices greater than $30/bbl:

The Minister of Petroleum Resources shall advise any

change in applicable margin when oil prices (RP) exceed $30/bbl, for at least 45 days continuously. If the

52

RP returns below $30/bbl, the margin will return automatically to the levels above as appropriate.

Format for computing PPT Under MOU Incentives

$ $

Sales Proceeds + Incidental Income x Less: Royalty x

Operating Cost x Intangible Drilling Cost x

Tangible Drilling Cost x Education Tax x (x)

Adjusted Profits x Less Unrelieved Losses (x) Assessable Profits x Less : Capital Allowances as restricted x Petroleum Investment Allowance x (x) Chargeable Profits x Assessable Tax @ 85% x Less MOU Tax Credits (x) Chargeable Tax x

8.4 Summary of the 2000 MOU

2000

A Incentives: I. GNM to the Company

GNM to NNPC Provided that TC

II. GNM to the Company GNM to NNPC where T2 (CIC/bbl) and TC

III. Reserves Additions Bonus

$2.50 $1.25 < $4.00 $2.70 $1.35 > $2.00 Not Applicable Not Applicable

IV. Education Tax (net of other taxes, levies, etc payable to the Federal, State and Local Governments)

Applicable

B Calculation of Revised Government Take (RGT)

Substitute Official Selling price with

Tax Inversion Penalty Currency of Calculation

Tax Reference Price Applicable US Dollars

53

9 THE NIGERIAN NATURAL GAS INDUSTRY

As discussed in Module 1 under Section 1.1.9 (Trends in the gas industry) natural gas in Nigeria is largely produced in association with crude oil, most of which is currently being flared. Nigeria’s proven gas reserve is currently estimated at 159 trillion cubic feet making it the tenth largest in the world. The level of natural gas is about 22 billion barrels of its crude oil equivalent48. One of the reasons put forward for the underutilization of gas is the absence of a ready market for gas internally and inappropriate pricing locally. To enhance the development of the gas industry especially for export, government has put in place specific export-oriented gas utilisation initiatives as well as other fiscal incentives that would act as stimuli for the development and utilization of Nigerian gas. The following are the incentives granted to companies involved in gas utilization projects.

(i) an initial tax holiday period of three (3) years, which may;

subject to the satisfactory performance of the business, be renewed for an additional period of 2 year;

(ii) as an alternative incentive to the initial tax –free period, gas

utilisation companies may claim an additional investment allowance (IVA) of 35%, which will not reduce the value of the asset. However, if the company claim the IVA, as opposed to the tax free holiday, it will not be able to claim the accelerated capital allowances which are provided in (iii) below;

(iii) accelerated capital allowances after the tax-free period as

follows:

an annual allowance of 90% with 10% retention for investment in plant and machinery; and

48 Source: www.nlng.com

an additional investment allowance of 15% which shall

not reduce the value of the asset;

(iv) tax-free dividends during the tax-free period, where the investment was in foreign currency, or the introduction of imported plant and machinery was not less than 30% of the company’s equity share capital; and

(v) interest payable on any loan obtained for gas project, with the

prior approval of the Minister of Finance shall be tax deductible.

Gas income is taxed at the rate of 30%.

Also worthy of note are the special incentives granted to Nigeria LNG

Limited under the Nigeria LNG (fiscal incentives, Guarantees and Assurances) Act. A few of these incentives include, a 10 year tax relief period for the company and the exemption of the company and its contractors and subcontractors from all custom duties, taxes, levies and imposts of a similar nature in respect of imports pertaining plant, machinery, goods and materials for use in the construction of, or incorporation to the project.

9.1 Upstream Gas Operations

Upstream gas operation involves all operations necessary to separate gas from the reservoir into usable form at utilisation or designated custody transfer points, either through pipelines or tankers.

The capital allowances, operating expenses and assessment of companies engaged in upstream gas operations are subject to the provisions of the PPT Act and fiscal incentives under the revised Memorandum of Understanding (MOU).

54

9.2 Downstream Gas Operations

Downstream gas operation” involves the marketing and distribution of gas and its industrial uses. This would include power generation, liquefied natural gas (LNG), and household factory consumption.

Companies engaged in downstream gas operations, are subject to the provisions of the Companies Income Tax Act (CITA).

55

10. REVIEW OF THE PROPOSED GAS FISCAL

REFORM BILL (GFRB)

The gas fiscal reforms, encapsulated in the Gas Fiscal Reform Bill, 2005 (GFRB)49, are still under discussion in the National Assembly. Hopefully, after public hearings are conducted (involving various stakeholders), the final version should be passed into law in no distant future.

The major changes that the GFR bill seeks to effect are as follows:

10.1 Upstream

(i) define “upstream gas operation” as operation which “shall

include any activity or operation that is upstream of the downstream gas sector (as defined in the Downstream Gas Act)”;

(ii) restrict the incentives granted to upstream gas projects to only those projects commenced before the GFRB comes into force. Ironically, the sections containing these incentives in CITA and PPTA are proposed for deletion;

(iii) provide a basis for calculating the applicable tax rate to

upstream gas operation;

(iv) specify the payment of gas income tax on an annual basis as against monthly basis for petroleum operation; and

(v) specify the capital allowance rate (only annual allowance)

of 25% per annum (for four years) from commencement of production as certified by the Minister.

49 You should please note that there is a Natural Gas Fiscal Reforms Bill (NAGFRB). The provisions of this bill are being harmonized with that of GFRB.

10.2 Downstream

(i) restrict the applicability of the incentives for downstream

operations to such operations that commenced before the GFR bill comes into effect;

(ii) provide varying tax rates of between 20% and 75% for assessing downstream gas income to tax;

(iii) remove the time restriction (4 years) for recouping losses

incurred in downstream gas projects;

(iv) remove the applicability of investment tax credit (ITC) at 15% to qualifying capital expenditure incurred on replacement of obsolete plant and machinery;

(v) stipulate that only annual allowance is claimable on a

straight line basis over four years; and

(vi) restrict total capital allowances claimable to 85% of assessable profit.

(vii) The changes are supposed to affect any gas project

commenced after the GFR bill is passed into law.

56

11. OIL AND GAS FREE ZONES

The Oil and Gas Export Free Zone Act (OGEFZA) established the Oil and Gas Export Free Zone. The Zone refers to the Onne/Ikpokiri area of Rivers State. The OGEFZ is managed, controlled and co-coordinated by the Oil and Gas Export Free Zone Authority.

11.1 Review of the Oil and Gas Export Free Zone

(OGEFZ) Act

The OGEFZ Act establishes an Oil and Gas Export Free Zone and also the Oil and Gas Export Free Zone Authority (“The Authority”), to manage and co-ordinate all activities within the zone. The Authority has power to take over and perform such functions performed hitherto by the Nigeria Export Processing Zones Authority, as they relate to the export of oil and gas from any of the Nigeria Export Processing Zones (NEPZ) established by the NEPZ Act.

Exemption from Taxes Approved enterprises operating within the export free

zone are exempted from all Federal, State and Local Government taxes, levies and rates

Approval of Enterprise to Undertake Approved Activity An enterprise is required to apply to the Authority if it

wishes to undertake an approved activity within the Export Free Zone. The Authority is not, however, compelled to grant such application

Power to Grant Licence The Authority may grant a licence for any approved

activity in the Export Free Zone to an individual or business concern whether or not the business is incorporated in the customs territory.

The grant of licence by the Authority constitutes

registration for the purposes of company registration within the Export Free Zone

A body corporate licensed to operate within the Export

Free Zone and undertaking an approved activity shall notify the Authority of any purchase, assignment or transfer of shares in the body corporate, except where such shares are quoted and are freely transferable on any international stock exchange.

Payment for Goods and Services Where an approved enterprise operating in the Export

Free Zone is entitled to receive payment for goods and services sold to customers within the customs territory in foreign currency. The rules and regulations applicable to importation of goods and services into Nigeria and repatriation of the proceeds of sales or services will apply

Where a person within the customs territory supplies

goods and services to an approved enterprise established within the Export Free Zone, that person shall be entitled to receive payment for such goods or services in foreign currency, and the rules and regulations applicable to export from Nigeria and the repatriation of proceeds from sales or services shall apply

Import of Goods into the Export Free Zone The Authority and any approved enterprise are entitled to

import into the Export Free Zone, free of customs duty, any capital goods, consumer goods, raw materials, components or articles intended to be used for the purposes of and in connection with an approved activity, including any article for construction, and maintenance of premises in the Export Free Zone or for equipping such premises

57

All articles for equipping premises include equipment for

offices and other ancillary facilities necessary for the proper administration of the premises and for health, safety, hygiene and welfare of the premises and of persons employed therein

All goods brought into the Export Free Zone shall be

consigned to the Authority or to an approved enterprise and the goods may, with the approval of the authority, be transferred from one approved enterprises to another or from the Authority to an approved enterprise or from the approved enterprise to the Authority.

The Authority may take such steps as it deems necessary

to preserve goods within the Export Free Zone, whether by moving the goods from one place to another or by storing the goods and where any expenses are incurred by the Authority in so doing, the owner or consignee of the goods shall reimburse the Authority for the expenses.

Where any goods which are dutiable on entry into the

customs territory are sent from the Export Free Zone into the customs territory , the goods will be subject to the provisions of the Custom, Excise Tariff, (consolidation) Act and its regulations, and if the goods are intended to be disposed of in the customs territory, will not be removed from the export Free Zone unless

(a) the consent of the Authority has been obtained; and (b) the relevant customs authorities are satisfied that all

relevant import restrictions have been complied with and all duties have been paid.

Where goods are brought from the customs territory into

the Export Free Zone for the purposes of an approved activity, the goods are deemed to be exported

11.2 Registration Procedure

Free Port Licence Obtain and complete an Application Form

Submit completed Application Form together with

certificate of incorporation and DPR Permit to the Free Zone Management

Free Zone Management checks and sends application to

Ministry of Commerce for final approval

On acceptance by Ministry, the free zone management issues a Free Port Licence to the applicant

Free Port with Manufacturing, Processing or assembly Operations There are two types of licences applicable here:

a. Special Licence: granted to companies that are not incorporated in Nigeria

b. General Licence: granted to Nigerian registered

companies

The application procedures here are the same as those under the Free Port Licence. The supporting documents for registration include: a. Original or notarised copy of the certificate of incorporation; b. A notarised copy of the MEMART; c. notarised Board resolution approving the establishment of a

branch in the free zone;

58

d. A statement on the amount of capital set aside for the free zone operation;

e. A certified copy of the DPR Registration Certificate; f. A specimen signature of the Branch Manager designate; and g. A photocopy of the Branch Manager designate passport

11.3 Incentives available to enterprises operating within the Zone

The incentives include: All approved enterprises shall be entitled to import into

the OGEFZ, free of customs duty, any capital goods, consumer goods, raw materials, components or articles to be used in carrying out an approved activity or for the construction, alteration, reconstruction, extension or repair of premises in the OGEFZ. (S12 {1})

Approved enterprises operating within the Export Free

Zone shall be exempt from all federal, state and local government taxes, levies and rates (S8)

Legislative provisions pertaining to taxes, levies, duties

and foreign exchange regulations do not apply within the OGEFZ (S18{1a)

Repatriation of foreign capital investment in the OGEFZ

at any time with capital appreciation of the investment (S18{1b})

Remittance of profits and dividends earned by foreign

investors in the OGEFZ (S18{1c}) No import and export licences are required (S18{1d})

Sales of a maximum of 25 percent of production in the Customs territory (i.e. Nigeria) against a valid permit and on payment of appropriate duties (S18{1e})

Rent free land during construction stage, thereafter rent

shall be as determined by the Authority (S18{1f}) Foreign managers and qualified personnel may be

employed by companies operating in the OGEFZ – No expatriate quota requirements (S18{1h})

11.4 List of free trade zones

S/N NAME LOCATION YEAR OF APPROVAL STATUS OWNERSHIP

1 Calabar Free Trade Zone (CFTZ)

CRS 1992 Operational Fed. Govt.

2 Kano Free Trade Zone (KFTZ) Kano State 1996 Operational Fed. Govt.

3 Onne oil & Gas Free Zone River State 1996 Operational Fed. Govt.

4 Lagos Free Zone Lagos State 2002 Under Cons. Private

5 Tinapa Free Zone & Tourism Resort

CRS 2004 Under Cons. Private

6 Olokola Free Zone Ondo & Ogun 2004 Under Cons. States/ Private

7 Snake Island Integrated Lagos 2005 Operational Private

8 Maigatari Border Free Zone

Jigawa State 2000 Operational State

9 Banki Border Free Zone Borno State 2000 Declaration State

59

S/N NAME LOCATION YEAR OF APPROVAL STATUS OWNERSHIP

10 Ladol Logistics Free Zone Lagos 2006 Operational Private

11 Ibom Science & Tech. Park Free Zone

Akwa Ibom 2006 Under Cons. State

12 Living Spring Free Zone Osun State 2006 Under Cons. State

13 Airline Services Export Proc. Zone

Lagos State 2006 Operational Private

14 Lekki Free Zone Lagos State 2004 Under Cons. State/ Private

15 Egbeda Free Zone Oyo State 2001 Declaration State

16 OILSS Logistics Free Zone Lagos 2004 Declaration Private

Source: www.nepza.org

60

12. NIGER DELTA DEVELOPMENT COMMISSION The Niger Delta Development Commission (NDDC) bill was passed into law in June 2000 by an Act of the National Assembly. The Act repealed the Oil Mineral Producing Areas Commission Decree No. 41 of 1998 and conferred on the NDDC the status of a body corporate distinct from its governing board. The NDDC is managed and supervised by a governing board, whose members are appointed by the National Assembly.

12.1 Establishment of the Governing Board

A Chairman

A representative from each member state of the commission, namely Abia, Akwa Ibom, Bayelsa, Cross River, Delta, Edo, Imo, Ondo and Rivers

Three persons representing the non-oil producing state, drawn

from geo-political zones outside the Niger Delta

A representative each of oil producing companies in the Niger Delta, the Federal Ministry of Finance, and the Federal Ministry of Environment

The Managing Director of the Commission

Two executive directors

12.2 Funding

The NDDC sources funds through:

Federal Government of Nigeria – 15% of the total monthly statutory allocation of member states of the Commission from the Federal Account

Oil producing companies operating (onshore and offshore) in Niger Delta – 3 % of their total annual budget

50% of the monies due to member states of the Commission

from the Ecological Funds Grants and loans from the Federal or State Government, any

other body or institution (local or foreign) Proceeds from any assets that may accrue to it; and Money from other sources – gifts, grants-in-aid, testamentary

disposition, etc

Authorised Expenditure

Administrative costs

Payment of salaries, fees, remuneration, allowances, pensions and gratuities to qualified members of the board and employees

Payment for contracts, including mobilisation, fluctuations,

variations, legal fees and cost on contract administration Other relevant activities

Monitoring & Supervision

Provision for the establishment of a Monitoring Committee by the President

Functions of Monitoring Committee monitor the management of the funds of the Commission and

implementation of its projects; have access to the account books and other records of the

Commission submit periodic reports to the President

61

12.3 The Major functions of the NDDC include:

formulating policies and guidelines for the development of the Niger Delta area;

attending to and solving ecological and environmental

problems that arise from exploration of oil minerals in the area;

assessing and reporting on any project being funded or

carried out in the Delta by oil and gas producing companies, any other company and non-governmental organisations;

utilising the funds contributed to the Commission in

executing projects, which are required for the sustainable development of the Niger Delta area.

The effective implementation of the Commission will boost exploratory and development activities in the Niger Delta. This is because the frequent shutdowns of production facilities caused by community disturbance will be greatly reduced. Consequently, the cost of carrying on petroleum operations in the area may actually reduce, notwithstanding the 3% statutory contribution by the oil producing companies.

12.4 Evaluation of the provisions of the Act vis-à-vis E&P Company’s activities

The impact of the Act on the activities of E&P companies will be evaluated below:

(i) Tax treatment of the contribution from oil and gas

companies

The annual contribution to the NDDC would qualify as an allowable deduction for tax purposes, since it is an expenditure that is wholly, exclusively and necessarily

incurred for petroleum and gas operations. This is further supported by the ruling in the case between Gulf Oil Co. Nig Ltd v FBIR I1997) 7 nigeria Weekly Law Report 700; where it was held that any statutory obligation on the part of the tax payer should be deductible in computing the tax liability of the tax payer.

(ii) Contribution to host communities

The contributions of oil companies to host communities have continued despite the inauguration of the Commission. E & P companies have argued that since they already meet certain obligations to the host communities on the same subject matter for which the NDDC was set up, it amounts to a duplication of efforts, and consequently, a waste of their resources. It is unclear whether these companies would reduce their commitments/annual budget to/on community development, given the mandatory contribution to NDDC.

(iii) Applicability to companies in exploratory stage50

It is not clear whether companies, which have not yet commenced production, are liable to contribute to the NDDC fund. This confusion has arisen because of the apparent distinction made between oil and gas ‘prospecting’ and ‘producing’ companies in section 7(1) of the Act. Since the provision of the section 14(b) on financial contribution says oil ‘producing’ companies, it seem that oil companies, which are yet to commence productions, may be exempted.

50 Source: Article by Adewale Ajayi – International Energy Law and Taxation Review

62

13. ORGANISATION OF PETROLEUM EXPORTING

COUNTRIES (OPEC) 13.1 Overview of OPEC The Organization of the Petroleum Exporting Countries (OPEC) is a permanent, intergovernmental Organization, created on September 10–14, 1960, by Iran, Iraq, Kuwait, Saudi Arabia and Venezuela. The five Founding Members were later joined by eight other Members: Qatar (1961); Indonesia (1962); Socialist Peoples Libyan Arab Jamahiriya (1962); United Arab Emirates (1967); Algeria (1969); Nigeria (1971); Ecuador (1973–1992)* and Gabon (1975–1994).* Angola recently joined the OPEC bringing the current number of members to 12.

OPEC had its headquarters in Geneva, Switzerland, in the first five years of its existence, but currently has its headquarters in Vienna, Austria.

OPEC's objective is to co-ordinate and unify petroleum policies among Member Countries, in order to secure fair and stable prices for petroleum producers; an efficient, economic and regular supply of petroleum to consuming nations; and a fair return on capital to those investing in the industry.

As stated above, Nigeria joined OPEC in 1971. The organization enjoined its members to acquire participating interests in the operations of the oil companies present in their respective countries. This led to the establishment of the Nigerian National Petroleum Corporation (NNPC) and the subsequent signing of Joint Venture Agreements between the Government of the Federal Republic of Nigeria and the various oil producing companies.

13.2 Member States

There are currently 12 OPEC Member Countries:

Country Date Joined Location

Algeria 1969 Africa Angola 2006 Africa Indonesia 1962 Asia IR Iran 1960* Middle East Iraq 1960* Middle East Kuwait 1960* Middle East SP Libyan AJ 1962 Africa Nigeria 1971 Africa Qatar 1961 Middle East Saudi Arabia 1960* Middle East United Arab Emirates 1967 Middle East

Venezuela 1960* South America

* Founder Members 13.3 Operations of OPEC The OPEC statute stipulates that: "any country with a substantial net export of crude petroleum, which has fundamentally similar interests to those of member countries, may become a Full Member of the Organization, if accepted by a majority of three-fourths of Full Members, including the concurring votes of all Founder Members".

The Statute further distinguishes between three categories of membership: Founder Member, Full Member and Associate Member.

Founder Members of the Organization are those countries,

63

which were represented at OPEC's first Conference, held in Baghdad, Iraq, in September 1960, and which signed the original agreement establishing OPEC.

Full Members are the Founder Members plus those countries

whose applications for membership have been accepted by the Conference.

An Associate Member is a country which does not qualify for full membership, but which is nevertheless admitted under such special conditions as may be prescribed by the Conference.

OPEC members meet four times a year to discuss and agree issues relating to `s and pricing of oil. Quotas of each member state are based on production capacities and represent maximum production output of crude oil imposed by the organisation on each member. 13.4 Implications of Quota Restrictions

Each member country is allocated a quota, which officially should not be exceeded. The quota allocated is dependent on a number of factors which include but are not limited to the following:

(1) a country’s current level of reserves and its ability to increase

the reserves;

(2) political stability;

(3) production capability; and

(4) global oil prices.

Although, the quota restrictions may seem to hamper a country’s ability to produce more crude and earn more revenue, it has served, over the years, the need to maintain some price stability. However, it is being argued in some quarters that the restriction in quota does not serve this purpose any longer given the consistently increasing prices over the last 12 months.

OPEC has been restricting members quota to stabilise global oil price and Nigeria’s current production quota is 2.3 million bpd. Restrictions in OPEC quota may result in cut back in production especially on the part of the majors. Consequently, most of the operators have to contend with the restriction vis-à-vis their ambitious exploration programmes aimed at raising reserves and production capacities. They are especially faced with additional cost of maintaining equipment, which had been shut of production as a result of the restriction 13.5 OPEC Price Band

The OPEC price band strategy is aimed at stabilizing oil prices while at the same time ensuring that there is minimal disruption of oil supply. In the late 1980’s OPEC sought to keep prices at around 18$/b. In the 1990’s, it raised its aspirations to a price of 21$/b. In 2000 it replaced the target price with a price band of $22-$28/b for its basket of crudes. This was abandoned officially in 2005, although it had become obsolete by 2003 with oil prices standing at about 50$/b for Brent (European standard for oil prices).

Under the price band strategy, if the OPEC price basket exceeds $28 for 20 days, OPEC will initiate a pro-rata increase in output of 500,000 b/d. If the OPEC basket falls below $22 for 20 days, OPEC will initiate a pro-rata decrease in output of 500,000 b/d.

Given the sustained increase in the price of crude products it would be safe to assume that a minimum price should be in the range of 40$/b.

The OPEC “basket” of crude oils includes: Algeria’s Sahara Blend Indonesia’s Minas Nigeria’s Bonny Light Saudi Arabia’s Arab Light Iran’s Heavy Iraq’s Basra Light

64

Kuwait’s Export UAE’s Murban Venezuela’s BCF17 Libya’s ES Sider Qatar’s Marine

65

GLOSSARY i. Abandonment-The process of giving up further exploration

activities in a well or field in which oil or gas has not been found in commercial quantity. This does not include capped (plugged) wells. It can also relate to the giving up of production wells or field at the end of their productive lives.

ii. Acquisition Costs are costs of acquiring concession rights in a

lease area. iii. Amortization is used generically to mean the depreciation of

tangible costs, depletion of mineral acquisition costs, and intangible costs.

iv. Appraisal Well is a well drilled to ascertain the commercial

potentials of a reservoir discovered from exploratory activities. v. Barrel is a standard of measurement in the oil industry. One

barrel equals 42 U.S. gallons (35 Imperial gallons) at standard conditions.

vi. Blow out refers to when gas, oil or salt water escapes in an

uncontrolled manner from a well. vii. Bottom Hole Agreement refers to an agreement in which cash

consideration or property is given to another party for his use in drilling a well or property in which the payer has no mineral rights, in exchange for technical information from the drilling of the well.

viii. Carried Interest is when one licensee meets part or all of a fellow

licensee’s costs during exploration or development. ix. Casinghead Petroleum Spirit means any liquid hydrocarbon

obtained in Nigeria from natural gas by separation or by any chemical or physical process before same has been refined or otherwise treated.

x. Casing Point is the point at which the drilling has reached its objective depth, in which case determination can be made as to its productivity or otherwise.

xi. Ceiling Test is a test to determine whether the recorded capitalised

exploration, appraisal and development costs are recoverable from proved reserves.

xii. Chargeable Natural Gas in relation to a company engaged in

petroleum operations means natural gas actually delivered by such company to NNPC under a Gas Sales Contract but does not include natural gas taken or on behalf of the Government of the Federation in pursuance of the Petroleum Act

xiii. Chargeable Oil in relation to a company engaged in petroleum

operations means casinghead petroleum spirit and crude oil won or obtained by the company from such operations

xiv. Christmas tree is an array of pipes and valves fitted to a

production well head to control oil or gas flows and to prevent blow outs.

xv. Commercial Quantity is the quantity of oil or gas in a reservoir

that can be produced economically at current prices using existing technology. The Petroleum Act however, defines commercial quantity as daily production of 10,000 barrels of crude oil or more.

xvi. Completion is the process of bringing an oil or gas well into

production. The process begins only after the well has reached the depth where oil or gas is thought to exist, and generally involves installation of casing pipes, perforation of the casing pipes, and acidizing and fracturing operations.

xvii. Concession is a right granted to a company by the federal

government on behalf of the federation to explore and produce oil and gas within a given area. In Nigeria this involves the granting of oil exploration licence, oil prospecting licence or oil mining lease.

66

xviii. Condensate refers to liquid hydrocarbons which are sometimes produced together with natural gas (SEE LPG).

xix. Conservation refers to the preservation or restoration of a drilling

site to its natural state after drilling. It may also be related to economy and avoidance of waste during drilling.

xx. Cost Pool is a cost centre comprising a defined geographical area

used under the full cost method of accounting as a basis for accumulating depreciable capitalised exploration, appraisal and development expenditure. Cost pools are usually not smaller in size than a country except where warranted by major differences in economic, fiscal or other factors in that country.

xxi. Crude Oil means any oil (other than oil extracted by destructive

distillation from coal, bituminous shale or other stratified deposits) won in Nigeria either in its natural state or after the extraction of water, sand or other foreign substance therefrom, but before any such oil has been refined or otherwise treated

xxii. Development Costs are additional capital costs incurred following

a decision to develop a reservoir. xxiii. Directional drilling is a technique used extensively in offshore

drilling where many development wells have to be drilled from a single platform, i.e. where the well is not drilled vertically.

xxiv. Discovery well is an exploratory (wildcat) well that finds a new

deposit of oil or gas. xxv. Discovery Value is the estimated value of oil and\or gas at the date

of discovery. xxvi. Dry Hole (also referred to as a duster or wet hole) is a well that

either finds no oil or gas, or finds too little to make it commercially viable.

xxvii. Dry Hole Agreement is similar to bottom hole agreement except

that money or property contributions are made to another party

only in the event that the well reaches an agreed depth and is found to be non-productive.

xxviii. Exploration and Appraisal Costs are costs incurred in the search

for oil and gas deposits after obtaining a licence but before a decision is taken to develop a reservoir.

xxix. Exploratory Project Area is an acreage usually larger than a field

where initial finding efforts such as geological and geophysical surveys are undertaken.

xxx. Exploratory Well is a well drilled to ascertain whether or not oil

or gas exists in a field. xxvii. Farm In refers to the transfer of all or part of an oil and gas

interest in consideration for an agreement by the transferee (farmee) to meet certain oil exploration and development costs which would otherwise have been undertaken by the owner (farmor). See Farm out.

xxviii. Farm Out is a sharing of oil exploration and development

activities and costs whereby a company with a concession, either because it has more potential oil acreage than it can handle or wishes to share risks, invites others to explore all or portions of the tract in return for a share of whatever oil it found. See Farm In.

xxix. Field is a given area or region, usually comprising a number of

individual reservoirs in which oil and gas reserves exist. xxx. Injection well is a well used for injecting gas or water into the

reservoir rock to maintain pressure for secondary recovery.

xxxi. Impairment is the possible diminution in the value of unproved properties of an exploration and production company arising from events or circumstances outside its control.

xxxii. Net profits interest refers to a share in production measured by a

certain percentage of the net profits. xxxiii. Plugging is the filling in with concrete of an abandoned well.

67

68

xxxi. Pre-Licence Costs are costs incurred in the period prior to the

acquisition of a legal right to explore for oil and gas in a particular location. Such costs include the acquisition of speculative seismic data and expenditure on the subsequent geological and geophysical analysis of these data.

xxxi. Production Costs (operating or lifting costs) are the recurrent

costs incurred in oil and gas production activities. xxxii. Production payment refers to a right to receive in cash or in kind,

a specified share of production from an oil or gas interest up to an agreed amount.

xxxiii. Property includes leases, reservations, royalty rights, and similar

rights. xxxiii. Proved Developed Reserves represent oil and gas reserves that

can be expected to be recovered from existing wells and facilities using existing technology.

xxxv. Proved Reserves represent estimated quantity of oil and gas that

can be recovered from known reservoirs using existing technology. xxxvi. Proved Undeveloped Reserves include all proved oil and gas

reserves that do not qualify to be described as proved developed reserves.

xxxvii. Reservoir is a natural formation of porous and permeable spaces

in the earth’s crust containing accumulation of oil and gas. Each distinct reservoir is confined by impermeable rocks or barriers, which help to trap oil and gas.

xxxviii. Seismic survey is the determination of rock structure below an

area by using acoustic shock waves and measuring reflected signals.

xxxix. Spud in refers to making a hole to commence drilling operations.

xxxvii. Stratigraphic Test Well is a well drilled to obtain information about the geological conditions of an exploration area.

xxxvii. Wildcat Well is any well drilled in an unproved territory. xxxviii. Workover is a remedial operation required to restore oil flow from

a well to its maximum production capacity or to enhance its production capacity following a decline in production.