Introduction

Nigeria produces about two million barrels of crude oil per day and is ranked as the eleventh1 largest producer in the world. The oil and gas sector accounts for about 60% of government's total revenue and more than 90% of its foreign exchange receipts upon which all tiers of government depend. Nigerian oil reserves are now estimated at 25 billion barrels2. Crude oil production in Nigeria averages about 2million barrels per day ('bpd'), which is about 60% of the total African production – with Angola coming second at about 1.7m bpd. Based on an estimation of Nigeria's oil reserves it is believed that Nigeria will conservatively remain a producer of petroleum for another forty to fifty years.

In addition to its crude oil reserves, Nigeria is endowed with abundant reserves of natural gas. The preponderance of gas encountered in the search for oil has led many experts to describe the Nigerian petroleum fields as "a gas province with some oil in it"3 as, the proportion of natural gas in conjunction with crude oil is relatively high4. Today Nigeria's natural gas reserves have been estimated at about 166 trillion standard cubic feet, giving Nigeria the potential to produce gas for about 200 years or more and making it a fertile ground for investment in gas. By the end of 2005 Nigeria was ranked as the world's third biggest producer of liquefied natural gas (LNG)5.

Within the last decade some of the existing operators in the petroleum sector in joint venture with the Nigerian National Petroleum Corporation6 (NNPC) have embarked on a number of gas utilization projects. Most of these projects however, are in relation to associated gas discovered in the search for oil, whilst unassociated gas deposits are being reserved for future investment. Continuous emphasis is being laid on utilization of associated gas in pursuance of the Nigerian government's policy to eradicate the flaring of gas by the year 2008 and to broaden its revenue base through active support of gas projects. The 2008 flare-out date has not proved feasible and discussions are ongoing between producers and government on a more realistic date.

Between 1998 and 1999 the Nigerian government offered various investment and tax incentives to discourage the flaring of gas and to stimulate investment in the gas sub-sector. This article discusses those incentives and considers the effect, if any, that the recent tax reform has had on the tax regime of gas utilization projects under Nigerian law.

Overview of the Nigerian Gas Industry

The Nigerian gas industry, unlike its petroleum counterpart, is still relatively underdeveloped. In pursuit of its national objectives to achieve a reserve base of 30 billion barrels of oil by the year 2003 the Nigerian government laid much emphasis on the exploration and production of crude oil, and gas was merely considered as a by-product to be disposed of either by way of venting or flaring. Activities to increase its oil reserves rose to a peak in the mid seventies when about two hundred and fifty wells were drilled. Whilst investment in the Nigerian petroleum industry thrived gas was basically neglected.

In 1969 the Nigerian government began to seek ways of minimizing incidences of gas flaring by compelling operators to either find gainful uses for the gas produced with the oil or re-inject the gas back into the reservoirs. Companies engaged in petroleum operations in Nigeria were required, by virtue of the Petroleum (Drilling and Production) Regulations7, to submit detailed plans for the utilization of associated gas. In 1979 the Associated Gas Re-Injection Act was promulgated to control atmospheric pollution by stopping gas flaring through gas conservation and utilization. The Act provides that in addition to the plan to be submitted under the Petroleum Regulations, every company producing oil and gas in Nigeria must submit a preliminary program of schemes for the viable utilization of all associated gas produced from a field or groups of fields, and a project or projects to re-inject all gas produced in association with oil but not utilized in an industrial project8. The Act further provided that no company engaged in the production of oil and gas shall, after the 1st of January 1984 flare gas produced in association with oil without the written permission of the Minister for Petroleum9. Under the Act the Minister has the power to issue a certificate of exemption from the provision of Section 3 to any company upon such terms as he may impose if he is satisfied that utilization or re-injection of the gas produced in a particular field/s is not appropriate. Furthermore, the Act imposes stiff penalties for non-compliance with the provisions of Section 3.

As the time limit approached it was evident that the time limit set by the Act was impracticable by any of the operators in the industry. There was also the increasing possibility that if the Act were enforced without any modification, many oil and gas producing companies would rather severely curtail crude oil production or shut in their oil wells. Since this would have hampered Government's objective of increasing its reserves through the production of oil and gas, the Act was amended in 1985 to permit a company engaged in the production of oil and gas to continue to flare gas in any field in relation to which the Minister issues a certificate of exemption. Government subsequently announced that its final time limit for the total eradication of gas flaring is 31st of December 2008.

The promulgation of the Associated Re-Injection Act was not enough to eradicate gas flaring in Nigeria. Most operators continued flaring gas with or without the Minister's permission and would simply pay the penalty for flaring, which was 20 cents/mscf of flared gas. The cost of penalty payments, to the operators was lower than that of installing gas re-injection systems and whatever amounts are paid as penalty formed part of their operating expenses, which were tax deductible10. A few uncoordinated gas utilization projects were undertaken, involving direct supply of natural gas to some industries and power generating plants contiguous to the oil fields. However, the volume of gas involved in these supply systems were a very small fraction of the total associated gas produced and insignificant as far as the reduction of gas flaring was concerned. As the demand for natural gas increased on a global scale due to its environmental advantage, the Nigerian government began to encourage more investment in its gas industry whilst intensifying its effort at eradicating the flaring of gas. One of such intensified efforts is the recent increase in the penalty for flaring from 20cents/mscf to $3.50 per mscf of flared gas11.

Statutory and Regulatory Regime of Gas Production and Utilization

As developments progressed in the gas sector a national gas policy was proposed by the Nigerian government. Apart from its stated objective of eradicating gas flaring by the year 2008 by encouraging investment in gas utilization and the provision of incentives for that purpose, the proposed policy government did not address other ancillary issues relating to gas exploitation in Nigeria. Of the nearly thirty enactments governing operations relating to crude oil production only four relate to gas operations.

After much speculation about what issues the proposed gas policy should address, the Nigerian government finally adopted a gas policy earlier this year12. The policy provides a gas pricing framework for the determination of the floor price for gas. Its main thrust is to promote domestic gas utilization especially for power generation and industry. It however does not address issues relating to exploration and production which are areas of concern for most potential investors particularly as it relates to cost allocation for tax purposes. There has been much anticipation that the policy would also address issues relating to the transmission, storage, marketing and utilization of gas and would form the framework for comprehensive gas legislation.

Taxation of Gas Utilization Projects

Under the current tax regime upstream gas utilization projects are taxed either under the Petroleum Profits Tax Act ('PPTA'), whilst downstream gas operations are taxed under the Companies Income Tax Act ('CITA'). In addition to the tax levied on their profits under these Acts, several categories of tax are levied on companies engaged in gas utilization13. Upstream Gas Utilization14 refers to activities designed to separate crude oil and gas from the reservoir into usable products or form, or to deliver such gas to designated points for use by, or transmission to, downstream users, and includes gas production.

Currently, there are three different tax regimes applicable under the PPTA, depending on the type of contractual arrangement that governs a company's operations. Petroleum Profits Tax ('PPT') is imposed at the rate of 85% of the company's chargeable profits and at the rate of 65.75% on companies that have not yet commenced sales or bulk disposal of chargeable oil. For companies operating under a joint venture arrangement with NNPC the effective tax rate applicable based on the terms of a memorandum of understanding15 between the operators and the Nigerian government is about 65%, whilst companies engaged in deep offshore operations under Production Sharing Contracts are taxed at the rate of 50%. Apart from PPT royalty is also charged at a graduated rate of 0% in areas beyond 1000 metres water depth to 20% in onshore areas of operations. Royalty payments in respect of natural gas disposed under a gas sales agreement however is tax deductible. Whereas the value of natural gas disposed under a gas sales contract would attract PPT, gas produced and transferred to gas-to-liquid facilities is at a 0% tax and 0% royalty rate16. In addition, the company will be entitled to the fairly extensive incentives set out in Section 10A of the PPTA as amended.

In 1999 the incentives applicable to associated gas utilization were extended to non associated gas. The implication as construed by the majority was that where a company produces gas solely for the purpose of utilising such gas for a downstream project, the expenses incurred in connection with the production of that gas would be allowable against the income derived from the project for which such gas is utilised. This is because in such situation there would be no "gas production income" accruing to the company against which allowable gas production expenses could be offset.

Incentives For Upstream Gas Operations

Incentives available for upstream gas utilisation operations, i.e. the separation of crude oil and gas from the reservoir into usable form for onward delivery to downstream projects, are stated in Section 10A of the PPTA as amended. Although the primary purpose of these incentives is to encourage companies already carrying on petroleum operations to utilise rather than flare the associated gas encountered in the course of oil production, these incentives are also applicable to non-associated gas utilization projects.

  • Allowable Expenses for upstream operations
    Amounts invested in the separation of crude oil and gas from a reservoir into usable form are considered as part of the oil field development and therefore treated as an allowable expense. This is a deduction additional to the allowable deduction for expenditure (including tangible costs) directly incurred in connection with drilling and appraisal of development wells. Although section 11(c) of the PPTA provides that capital employed in improvement, as distinct from repairs, is not an allowable deduction, capital investment on facilities and equipment used to deliver associated gas in usable form at utilisation or designated custody transfer points is treated, for tax purposes, as part of the capital investment for oil development and is therefore deductible.
  • Capital Allowances
     Capital allowances, operating expenses and basis of tax assessment is subject to the provisions of the PPTA and the terms of the revised MOU between the Federal Government and its joint ventures. In effect, these allowances may be used to offset the company's crude oil income. Operating expenses for contractors under Production Sharing Contracts are treated as reimbursable expenses.

The incentives listed above are only granted to petroleum companies that are engaged in projects, which utilise associated gas. To prevent these companies from lumping expenses together in an attempt to reduce their taxable profits under the PPTA the law has set out strict conditions to which they must adhere. These may be summarised as follows:

  1. Condensates extracted and re-injected into the crude oil stream will be treated as oil (and therefore taxable as oil income) but condensate not re-injected will be "treated under existing tax arrangements" so that the PPTA incentives apply.
  2. The company must pay the minimum penalty charged by the Minister of Petroleum Resources for any gas flared by the company.
  3. The company must, where practicable, keep the expenses incurred in the utilisation of associated gas separate from those incurred on crude oil operations. Only expenses that cannot be separated will be allowed as a deduction against the company's crude oil income.
  4. Expenses identified as incurred exclusively in the utilisation of associated gas will be regarded as gas expenses and will only be allowable against the gas income and profit to be taxed under the CITA.
  5. Companies that invest in natural gas liquid extraction facilities to supply gas in usable form to downstream projects and other associated gas utilisation projects will benefit from the incentives.
  6. All capital investments relating to gas-to-liquids facilities will be treated as a chargeable capital allowance recoverable against crude oil income.
  7. Gas transferred from the natural gas liquid facility to the gas-to-liquids facilities shall be at 0% tax and 0% royalty.

Tax Regime of Downstream Gas Utilization Operations

Downstream gas utilisation is defined by Section 28G(3) of the CITA (as amended by section 4 of the Finance (Miscellaneous Tax Provisions) Act of 1998) to mean the marketing and distribution of natural gas for commercial purposes, including the establishment of power plants, liquefied natural gas plants, gas to liquid plants, fertiliser plants, and gas transmission and distribution pipelines. Companies' income tax is charged at a rate of 30% on the assessable profits of a company engaged in downstream utilisation, subject to the application of the incentives specified in Section 28G of CITA.

Incentives for Downstream Gas Operations

The incentives for downstream gas utilization are provided under Section 28G of the CITA as amended and are as follows:

  • Tax Holiday
    A three-year tax holiday, which may be renewed for a further two years subject to determination of satisfactory performance by the Minister of Petroleum. In the alternative, a company may claim a 35% investment allowance ("IA") on qualifying capital expenditure incurred in respect of the project which allowance shall not reduce the value of the asset for purposes of computing capital allowances.
  • Tax Deductible Interest on loans
    Interest payable on any loan obtained for a gas project, with the prior approval of the Minister of Petroleum, is tax deductible.
  • Tax-free dividends
    Tax free dividends during the tax holiday, provided that the downstream investment was made in foreign currency or provided that plant and machinery imported during the tax-free period, for purposes of the project, account for not less than 30% of the company's equity. Although not expressly stated in the CITA, the Petroleum and Pioneer Department of the FBIR have confirmed that where a company takes advantage of the 35% Investment Allowance in lieu of a tax holiday, dividends paid to investors during this period will not be tax free. The confirmation we received is consistent with our understanding of Section 28G(1)(c) which links the receipt of tax-free dividends, to the tax-free period.
  • Accelerated capital allowances
    After the tax holiday, an IA of 90% of capital expenditure on plant and machinery and an additional IA of 15% which shall not have the effect of reducing the value of the asset. A company which has opted for the 35% IA is not entitled to claim the additional 15% IA. Paragraph 16(2) of the Second Schedule to CITA gives the taxpayer the option of claiming such capital allowances before the asset is put to use, subject only to the taxpayer being able to establish to the satisfaction of the Board that the first use to which the asset will be put by the company incurring the expenditure will be for the purposes of the taxpayers trade or business. The taxpayer may, in the alternative, elect to claim the capital allowances with effect from the date on which such asset was first put to use.
  • VAT Exemption on Plant and Machinery
    As a further incentive, VAT exemption is granted in respect of plant and equipment purchased in connection with the utilisation of gas in downstream petroleum operations, from the imposition of VAT. Machinery, equipment or spare parts imported into Nigeria in connection with the processing of gas, or the conversion of such gas into electric power, is also exempted from customs duties.

Proposed Reforms

In 2004 the Federal Government of Nigeria announced its intention to embark on a major tax reform. The thrust of the reform was to address the long standing challenge of tax evasion and non-compliance, both of which have been largely attributed to poor administration on the part of the tax authorities. Specific reforms proposed in relation to gas were as follows:

  • Withdrawal of the tax incentives for upstream gas utilization;
  • Royalty on natural gas sold and delivered to a third party will no longer be allowed as a deductible expense;
  • Export proceeds from gas will be taxed at 30%;
  • Introduction of the R-Factor basis of taxation for companies engaged in downstream gas utilization operations;
  • Profits attributable to downstream gas operations are to be separated from the total profits of the company;
  • Incentives available to companies engaged in LNG operations will be limited to a specific project and will not extend to additional trains upon the expansion of such projects.

These proposals were not passed into law but efforts continue to revise the tax regime for oil and gas operations.

Conclusion

Nigeria's gas reserves are still very much untapped and the opportunities for investment are immense. Domestic daily demand for gas exceeds 300million standard cubic feet per day and foreign demand for LNG exports exceeds 700 million standard cubic feet per day. A proposed trans-west African pipeline is expected to deliver over 120 million standard cubic feet per day to two of Nigeria's neighbors on the West African coast. These gas utilization projects create diverse opportunities for investment both locally and internationally. Government also recognizes the revenue potential of such investment opportunities and is working through the Oil and Gas Implementation Committee ('OGIC')17 to create the legal framework for the taxation of gas projects. Recently the OGIC sponsored a Petroleum Industry Bill. Although the entire bill has not been released, excerpts which have been seen remove the ability to consider amounts spent in separating associated gas as part of the oil field development18 and propose new tax rates for gas development. The Bill, if and when passed into law would form the tax regime for the gas industry.

Footnotes

1. Energy Information Administration of the US Department of Energy (www.eia.doe.gov)

2. National Petroleum Investments Management Services (www.napims.com)

3. Grant, G., Investment Opportunities In Nigeria's Gas Sector, Johannesburg, South Africa at the 1995 Sub-Saharan Oil & Minerals Conference.

4. The natural gas to crude oil ratio, in terms of gas quantity measured in cubic feet and crude oil measured in barrels, oscillated by 1966 at around 800cu.ft. per barrel.(L.H. Schatzl, Petroleum In Nigeria, The Nigerian Institute of Social and Economic Research, 1969)

5. Ford, Neil: African Business, Monday, August 1, 2005 [source: www.allbusiness.com/africa]

6. The NNPC is the entity through which the Nigerian government executes its policy of direct national involvement and participation in petroleum activities in Nigeria. The corporation was established under the NNPC Act of 1977. (Cap. N123 Laws of the Federation of Nigeria)

7. Regulation 42

8. Section 1, Associated Gas Re-Injection Act, Cap A25, Laws of the Federation of Nigeria 1990

9. Section 3

10. All outgoings and expenses wholly, exclusively, and necessarily incurred by a company for the purpose of its operations are tax deductible.( Petroleum Profits Tax Act Cap P.13 LFN S.10(1))

11. Discussions are ongoing between government and producers who argue that the penalty is prohibitive and should be reviewed downwards.

12. The National Domestic Gas Supply and Pricing Policy

13. Capital Gains Tax, levied on gains from the disposal of assets; Value Added Tax, Education Tax, Stamp Duty, and local government rates and levies.

14. This definition is essentially a paraphrase of Section 10A(1)(a) and (b) of the PPTA,

15. The MOU is an incentive scheme introduced in the 80's to ensure that foreign oil companies participating in joint venture with the government made a reasonable return on their investments. The first MOU was signed in 1986 and was later reviewed in 1991 and subsequently in the year 2000.

16. Section 10A(g) of the PPTA (as amended further by Decree No. 30 of 1999)

17. the Oil and Gas Implementation Committee ('OGIC') set up by President Yar'adua in 2007

18. ibid., at P. 4

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.