The first commercial discovery of oil in Nigeria was in 1956 in Oloibiri, Niger Delta. The discovery attracted other multinational oil companies to explore the onshore areas of Nigeria in 1961. As more players entered the upstream oil industry, the Federal Government of Nigeria created policies for the exploration and production of petroleum. Actual oil production and export from the Oloibiri field in 1958 with an initial production rate of 5,100 barrels of crude oil per day. The output rose to 2.0 million barrels per day in 1972 and a peak of 2.4 million barrels per day in 1979. Nigeria was a top oil producer, ranking 7th in the world in 1972, and has become the sixth-largest oil-producing country globally. (Source: NNPC)
Nigeria has about 159 trillion cubic feet of proven natural gas reserves. The country is among places with the top ten natural gas endowments in the world. However, Nigeria flares an estimated 40% of the natural gas produced and re-injects 12% to boost oil recovery. According to the World Bank, Nigeria contributes 12.5% of the world’s total gas flaring. (Source: NNPC)
The Federal Government set up policies to reduce gas flaring and improve the petroleum sector but faced slow growth. There were still gaps in the governance, infrastructure, and accountability. It became necessary to reform the entire petroleum sector in Nigeria. Better regulations, better returns on investment. The national move led to the birth of the Petroleum Industry Bill in 2000. Several attempts to pass the bill into law were unsuccessful for two decades. As a result, Nigeria lost about $50 billion in investment over the last ten years. (Source: Press release)
Finally, the Nigerian President signed the Petroleum Industry Act (PIA) 2021 into law on August 16, 2021. PIA 2021 is coming at a time when major oil producers are converting to clean energy. Mixed reactions from stakeholders, as usual, on the new law. Nevertheless, the much-awaited reform in the oil and gas industry will be attainable with accountability and transparency.
The Petroleum Industry Act 2021 seeks to encourage investment in the Nigerian petroleum industry. By balancing rewards with risk, the new law can increase revenue to the Federal Government of Nigeria. It also seeks to provide a forward-looking fiscal framework. However, a fiscal framework that excludes renewable energy may be relevant for a short period. The additional sources of funds such as levies, statutory contributions will expand the revenue of the Federal Government. Nevertheless, an equitable and transparent administration is necessary to attain the objectives.
The petroleum industry in Nigeria has upstream, midstream, and downstream operators.
3. REGULATORY BODIES
There are two regulators of the Nigerian petroleum industry. They are the Nigerian Upstream Petroleum Regulatory Commission and Midstream and Downstream Petroleum Regulatory Authority. Each year, the regulators will prepare and submit audited financial statements. The statement of estimated income and expenditure is due on September 30 every year.
3.1. Nigerian Upstream Petroleum Regulatory Commission (Commission)
Nigerian Upstream Petroleum Regulatory Commission is responsible for upstream petroleum operations. The Commission promotes the exploration of the frontier basin. Also, the Commission determines and collects royalties, signature bonuses, and related payments or production shares where the model contract includes production sharing or risk service provisions and gas flare penalty arising from midstream operations. Gas flaring is, however, permissible for facility start-up and strategic reasons. Furthermore, the Commission can enforce any regulation, provisions, guidelines of the Department of Petroleum Resources or Petroleum Inspectorate.
Source of Fund for the Commission
The funds to carry out its functions will be available from
- money appropriated by the National Assembly
- fees for licensees, lessees permit holders, and other authorizations
- cost of collection
- publications income and related activities
- fees paid to the Commission for using facilities owned or managed by the Commission
- grants, aids, gifts, testamentary dispositions, endowments, and contributions
3.2. MIDSTREAM AND DOWNSTREAM PETROLEUM REGULATORY AUTHORITY (MDPRA or Authority)
The Midstream and Downstream Petroleum Regulatory Authority is responsible for the midstream and downstream petroleum operations. The Authority ensures the accuracy of metering pumps. MDPRA also regulates the domestic base price of wholesale petroleum products.
Sources of Fund for MDPRA
- federal allocation;
- licensees, lessees permit and related fee;
- 0.5% of the statutory levy on the wholesale price of petroleum products sold in Nigeria;
- publications income and similar activities,
- fees for using facilities of the Authority; and
- grants, aids, gifts, testamentary dispositions, endowments, and contributions.
3.2.1. Midstream and Downstream Gas Infrastructure Fund (MDGIF)
There is an additional fund created for the midstream and downstream gas operations. It is the Midstream and Downstream Gas Infrastructure Fund (MDGIF). The MDGIF seeks to ensure equity investments of Government-owned participating or shareholder interests in the infrastructure of midstream and downstream gas operations.
Sources of fund for MDGIF
- 0.5% of the wholesale price of petroleum products and natural gas sold locally. The income is an addition to the 0.5% payable to the MDPRA Fund.
- Funds and grants accruing from multilateral agencies, bilateral institutions, and related sources
- Income from gas flaring penalties
The due date for the MDGIF levy is 21 days of sale.
3.3. Nigerian National Petroleum Corporation (NNPC) Limited
A new company, NNPC Limited, will be formed within six months of the commencement of PIA. The old company, Nigerian National Petroleum Corporation, will cease operations. Government shares in NNPC Limited are non-transferable unless approved by the Government and endorsed by the National Economic Council. The Minister of Finance will determine the assets, interests, and liabilities of NNPC that are transferable to NNPC Limited. Furthermore, NNPC Limited will act as an agent of NNPC during the winding-down process. NNPC employees will transfer to the new company with similar conditions of employment. NNPC Limited can form an agreement with partners on upstream petroleum operations as an IJVC (Incorporated Joint Venture Company).
4. PETROLEUM OPERATIONS AND LICENSES
4.1. UPSTREAM OPERATIONS
There are three types of upstream operations. They are petroleum exploration, petroleum prospecting, and petroleum mining. An operator needs a license/lease to commence any activity. The licenses/lease are;
- Petroleum exploration license
- Petroleum prospecting license
- Petroleum mining lease
4.1.1. Petroleum exploration license
Petroleum exploration license may cover petroleum prospecting and mining licenses. The approval is valid for three years and renewable by three years.
4.1.2. Petroleum prospecting license
The duration of the license depends on the acreage. For onshore and shallow water acreages, the approval is valid for three years and renewable by three years. It is five years and an additional five years for deep offshore and frontier acreages.
The area in a petroleum prospecting license has a maximum of;
(a) 350 square kilometers for onshore or shallow water acreages
(b) 1,000 square kilometers for deep offshore acreages
(c) 1,500 square kilometers for frontier acreages
4.1.3. Petroleum mining lease (PML)
PML has a maximum period of twenty years, including the development period. An onshore lease will use five years where the development period is not available. A lease in shallow water, deep offshore, or frontier acreage runs for seven years.
It is optional to convert an oil prospecting license to PPL or oil mining lease (OML) to PML. However, the incentives under the Petroleum Profits Tax Act are not transferrable. Under a model contract, NNPC Limited can participate up to 60% in a concession agreement or as a bid parameter. Transfer of rights in a license or permit is disallowed except the relevant parties have prior approval.
A marginal field before January 1 2021 that is not producing will convert to a petroleum prospecting license. In contrast, a marginal field that is not producing will continue under the old royalty rates and farm-out arrangements but change into a PPL within 18 months from the effective date.
- Field development plan: Where a marginal field is yet to be transferred to the Government within three years from the effective date, the holder of an OML must submit a field development plan and approval from the Commission.
- Environmental management plan (EMP): Operators in upstream and midstream operations will submit an environmental management plan for impact assessment. EMP is due within one year from the effective date or six months after the grant of the license.
- Also, a natural gas flare elimination and monetization plan are due within 12 months from the effective date.
National Grid System
The Commission will use acreage management after consultation with the Surveyor-General.
4.2. MIDSTREAM AND DOWNSTREAM OPERATIONS
4.2.1. Midstream and Downstream gas operations
The operations cover;
- Storage facility
- Processing of natural gas
- Construction of fertilizer plants
- Wholesale gas supply
4.2.2. Downstream gas operations
The activities are retail supply as well as gas distribution network.
Midstream and downstream petroleum sectors in Nigeria carry out gas and petroleum liquids operations.
4.2.3. License for Midstream and Downstream gas operations
The license for Midstream and Downstream gas operations in Nigeria are;
- Gas processing license
- Bulk gas storage license
- Gas transportation pipeline license
- Wholesale gas supply license
- Retail gas supply license
- Gas distribution license
- Domestic gas aggregation license
Public service levy: There will be a tariff on customers for complying with public service obligations on licenses. The Authority may issue regulations on the modalities.
4.2.4. Midstream and Downstream petroleum liquids operations
The operations are;
- Exportation or importation
- Establish crude oil refinery
- Bulk transportation
- Bulk sale
4.2.5 License for Midstream and Downstream petroleum liquids operations
- Crude oil refining license
- Bulk petroleum liquids storage license
- Petroleum liquids transportation pipeline license
- Wholesale petroleum liquids supply license
4.3. UPSTREAM, MIDSTREAM AND DOWNSTREAM OPERATIONS
Every person engaged in petroleum operations must register with the Authority or Commission. Default approval (or rejection) is based on the guideline or within 90 days.
4.4. DECOMMISSIONING AND ABANDONMENT FUND
Decommissioning and abandonment of facilities, structures, and wells require written approval from the Authority or Commission. Each lessee and licensee shall open a decommissioning and abandonment fund with an independent financial institution. Fund will be kept in an escrow account accessible to the Authority or Commission.
The amount of royalties depends on production and price.
4.5.1. Royalties per production
- onshore areas – 15%
- shallow water – 12.5%
- frontier basins and deep offshore (above 200m water depth) – 7.5%
4.5.2. Royalties per price
- Below USD $50 per barrel – 0%
- At USD $100 per barrel – 5%
- Above USD $150 per barrel – 10%
- Between USD $50 and $100 or USD $100 and $150 per barrel – The price is on linear interpolation.
Condensates shall be treated as crude oil and natural gas liquids as natural gas to determine royalties.
5. HOST COMMUNITIES DEVELOPMENT (HCD)
HCD Trust is to finance and execute projects for the benefit and sustainable development of the host communities. A settlor will create a host community development trust fund for upstream petroleum operations. Payment is 3% of the actual operating expenditure in the preceding calendar year. The funds created under PIA are exempt from taxation. Payment made by the settlor is deductible for hydrocarbon tax and companies income tax purposes. A settlor will provide a host community needs assessment and a development plan.
6. FRONTIER EXPLORATION FUND
The Frontier Exploration Fund (FEF) seeks to promote the frontier basin in the country. FEF is 30% of the profit oil and profit gas of NNPC Limited.
The Federal Inland Revenue Service (FIRS) assesses and collects the income tax on petroleum operations. The applicable taxes are hydrocarbon tax, companies income tax, and tertiary education tax. Petroleum Profit Tax Act, the old tax law, will be canceled upon conversion to PIA. Upstream petroleum operations are subject to CIT and HT.
7.1. HYDROCARBON TAX (HT)
Hydrocarbon tax applies to companies engaged in upstream petroleum operations. HT also applies to crude oil, field condensates, natural gas liquids derived from associated gas, and produced in the field upstream of the measurement points.
The crude oil revenue is the value of chargeable oil adjusted to the measurement points on the sale of all chargeable oil and disposal proceeds. The disposal value of chargeable oil is the sum of the crude oil determined for royalties from all fields based on PIA 2021 or any applicable law.
HT will not apply to:
- associated natural gas, including gaseous natural gas liquids produced in the field and contained in the rich gas and non-associated natural gas
- condensates and natural gas liquids produced from non-associated gas and associated gas
- frontier acreage until reclassified under section 68 of PIA 2021 and deep offshore
- The cost of producing associated gas goes to crude oil for HT purposes. The rule holds when the taxable person claims capital and operating costs for the wells producing associated gas in the Companies Income Tax Act.
7.1.1. Allowable expenses (upstream operations)
Deductible expenses are wholly, reasonably, exclusively, and necessarily incurred for a period. It includes:
- Rents incurred under a petroleum mining lease or petroleum prospecting license
- Repair and maintenance expenses
- Drilling expenditure of the first exploration well and the first two appraisal wells in the same field
- Decommission and abandonment contributions to an approved fund by the Commission, provided the balance is subject to tax under PIA at the end of life of the field where the lessee receives the surplus.
- Statutory levies, stamp duties, and fees
- Costs of gas re-injection wells subject to ratification by the Commission
- Contribution to host communities development trusts and related sums
- Recoverable expense
7.1.2. Disallowable expenses (upstream operations)
- Purchase of information on the petroleum deposits other than for the acquisition of petrophysical, geological, and geochemical data and information
- Penalties, natural gas flare fees
- Financial charges, arbitration and litigation costs, bad debts, and interest on borrowing
- Expenses relating to head office or affiliate, shared services, research, and development
- Production bonuses, signature bonuses for petroleum deposits, bonuses or renewal fees for petroleum mining lease
- Tax inserted in a contract on a net tax basis and paid by a company on behalf of the vendor
- Capital employed
- Sum recoverable under an insurance or contract
- Rent or repairs cost not incurred for operations
- Income tax on profits tax or similar taxes
- Payment to provident, savings, widows and orphans or other society
- Any contribution to a pension, provident or other society scheme or fund for production staff
- Customs duties
- Costs under paragraph 2 (2) (c) of the Sixth Schedule to PIA
7.1.3. Assessable profits
It is adjusted profit after the deduction of the loss incurred. The assessable profit is determined separately in chargeable tax identified in Section 267 (a) and (b). A taxable person can carry forward unutilized losses until the balance is zero.
Within five months after the end of the accounting period of a company or as the Service may permit in writing, the company may elect a formal deduction under this section shall be deferred to and be made in the next accounting period.
7.1.4. Chargeable profits and allowances
Allowable deductions are capital and production allowances. For acquisition costs of petroleum rights, the value of the rights and assets acquired is reposed separately to FIRS. It is subject to the value of the rights eligible at an annual allowance of 20%. The assets are also depreciated at the applicable rates with a remainder of 1% till the year of disposal.
In calculating the chargeable profits, the total cost will not be more than the cost-price ratio. The chargeable profits and allowances will be determined separately for the two classes of assessable profits under Section 267 (a) and (b) of PIA 2021.
7.1.5. Chargeable tax
Under Section 267 (a) and (b) of PIA 2021, the chargeable tax is the percentage of the chargeable profit from crude oil for onshore and shallow water as 30% and 15% of the profit for PML and PPL, respectively. The additional points to note in determining the chargeable tax are;
(1) Where the chargeable tax calculated under this Act other than this section is less than the amount in subsection (2) the company will pay an additional tax equal to the differential.
(2) The amount in subsection (1) is the chargeable tax for crude oil. For exports, sales proceed is the number of barrels of crude oil determined at the measurement point multiplied by the fiscal oil price per barrel.
Additional tax payable in certain circumstances
Additional tax for crude oil and associated gas is payable with the final installment of the chargeable tax due for a period.
Chargeable profits and consolidation for tax purposes
The Service may disregard artificial or fictitious transactions that reduce tax payable or make appropriate adjustments. The provisions of the Income Tax (Transfer Pricing) Regulations 2018 will apply. Artificial transactions are activities between related parties which were not at arm’s length. A company has a right of appeal.
Subject to WREN and allowable deductions, a pre-operational expense incurred upon commencement will be deemed as qualifying pre-production capital expenditure and amortized.
FIRS will review a sale or transfer arrangement.
7.1.6. Costs consolidation
Consolidation of costs for companies’ income tax is allowed. On the other hand, consolidation of the costs and taxes for HT is allowed only across assets in which the company holds licenses and leases.
7.1.7. Persons chargeable
It is an offense for an individual or a group of persons other than a company to engage in upstream petroleum operations.
7.1.8. Applicable accounts and particulars
Particulars and documents required for determining hydrocarbon tax are:
- statement of accounts
- computation of actual adjusted profit/loss and actual assessable profits
- schedule showing the residues at the end of that period, all qualifying petroleum expenditure, assets disposed, and the allowances due
- schedule showing total production allowance from upstream petroleum operations related to crude oil
- computation of the actual chargeable profits for the two classes of chargeable profits
- statement of amounts repaid, refunded, waived, or released
- chargeable tax computation and the methodology; where associated gas is sold or delivered through the measurement point
- duly completed self-assessment form
- evidence of payment of the final installment
7.1.9. Due date
The deadline is the later of five months after the end of that period or the effective date of PIA. The taxable person will submit a copy of its audited accounts and the particulars of an actual and complete declaration and an estimate duly signed by an authorized person.
A company yet to commence bulk sales or disposal of chargeable will file with its audited accounts and returns within 18 months from the date of its incorporation for a new company and 5 months after any period ending on December 31.
7.1.10. Estimated tax
Returns of the estimated hydrocarbon tax is due two months after the commencement of an accounting period. The currency for calculating and remitting hydrocarbon tax is US Dollars.
FIRS has the power to call for books and returns within 21 days.
HT is payable in equal monthly installments and a single float payment. The first payment is due on the third month of the accounting period. The remaining payments are due on the last day of the month. A final installment of tax is payable on or before the due date of filing the self-assessment.
Interest is at the prevailing LIBOR rate plus 10% points of the difference between the revised and estimated tax.
7.1.11. Offences and penalties
- Non-compliance – NGN10,000,000 and an additional fee of NGN2,000,000 or other statutory charges when the default continues.
- Where no specific penalty for an offense is present, the fine will be NGN10,000,000 and an additional fee of NGN2,000,000 when the default continues or imprisonment for six months.
- Making an incorrect return – NGN15,000,000 or 1% of the tax understated plus the actual principal sum.
- False or misleading information – NGN5,000,000 or 1% of the understated tax
- False statement and returns – NGN15,000,000 or 1% of the assessment or imprisonment for six months or both the fine and imprisonment
- Improper dealings by the tax officials – 200% of the sum or imprisonment for a maximum of three years or both fine and imprisonment
7.2. COMPANIES INCOME TAX
Companies in upstream, midstream, and downstream petroleum operations are subject to the Companies Income Tax Act. The revenue is the sales proceeds of chargeable oil or gas adjusted to the measurement points and disposed amount. CIT is payable on natural gas transferred or disposed from the upstream to the midstream or downstream. It also includes liquids and liquid petroleum gases derived from natural gas. Upstream petroleum operations will file returns on an actual year basis for its companies income tax.
Other points to note:
No stamp duties and capital gains tax when a company involved in more than one stream separates operations.
Consolidation of capital investment in midstream operations and upstream operations are possible at an arms-length price. However, the consolidated capital investment cannot be represented for capital allowances when fiscaling the income from midstream petroleum operations.
Transfer or disposal of natural gas is subject to CIT.
Acquisition costs of petroleum rights are eligible for annual allowance at 20% with a retention value of 1% in the last year until the asset is disposed.
7.2.1. Allowable deductions (added to the provisions in CITA)
- Rents and royalties for the sale of crude oil, condensate, and natural gas or delivered or disposed
- Contribution to approved fund for abandonment and decommissioning, petroleum host communities development trust, or environmental remediation
- Other deductions prescribed by the Minister of Finance
7.2.2. Disallowable deductions (added to the provisions in CITA)
- Cost of information for petroleum deposits, except the acquisition of geological, geophysical, and geochemical data
- Production bonuses, signature bonuses or fees
- Tax inputted into a contract or an agreement on a net tax basis
- Hydrocarbon tax is not deductible
1. Late filing of companies income tax returns for upstream – NGN10,000,000 on the first day and an additional NGN2,000,000 for each day of default or other sums as prescribed by the Minister of Finance
2. Late remittance –
- Naira: Interest at the prevailing NIBOR plus 10%
- Foreign currency: Interest at the prevailing LIBOR or any successor rate plus l0%
8. NO LONGER IN USE
Sequel to PIA, the following enactments and regulations are repealed –
- Associated Gas Reinjection Act, 1979 CAP A25 Laws of the Federation of Nigeria (LFN) 2004, and its amendments
- Hydrocarbon Oil Refineries Act No. 17 of 1965, CAP H5 LFN 2004
- Motor Spirits (Returns) Act, CAP M20 LFN 2004
- Nigerian National Petroleum Corporation (Projects) Act No. 94 of 1993, CAP N124 LFN 2004
- Nigerian National Petroleum Corporation Act (NNPC) 1977 No, 33 CAP N123 LFN, as amended
- Petroleum Products Pricing Regulatory Agency (Establishment) Act No. 8 2003
- Upon the successful conversion process, Petroleum Profit Tax Act, Cap. P13, LFN, 2004 and Deep Offshore and Inland Basin Production Sharing Contract Act 2019, as amended, will phase out.
Domestic midstream petroleum operations, downstream gas operations, and large-scale gas utilization industries can benefit from the incentives in Section 39 of the Companies Income Tax Act.
Updated: September 27 2022