On the 16th of August, 2021 the President signed the Petroleum Industry Bill into law after a wait that spanned for decades, this piece of legislation if fully adhered to promises to be a game-changer within the Nigerian economy. We reviewed some of the provisions in the Act, also highlighting key revenue-generating models deployed.
There is no doubt that Nigeria’s petroleum law is long overdue for reform and the Petroleum Industry Act (PIA) represents a long-overdue overhauling of the petroleum system in Nigeria. The most recent version of the Act was presented to the National Assembly by the President in September 2020 and was signed into law by the President on the 16th of August, 2021.
With the oil and gas industry is highly regulated by the government, the National Petroleum Commission (NNPC) acting as the sole regulator, the PIA represents a complete overhaul of the Nigerian oil and gas sector which seeks to, among others, ensure an increased level of transparency and accountability in the sector by strengthening the governing institutions to attract investment capital through changes to the governance, administrative, the regulatory and fiscal framework of the Nigerian oil and gas industry.
The PIA repeals about 10 laws including the Associated Gas Reinjection Act; Hydrocarbon Oil Refineries Act; Motor Spirit Act; NNPC (Projects) Act; NNPC Act (when NNPC ceases to exist); PPPRA Act; Petroleum Equalisation Fund Act; PPTA; and Deep Offshore and Inland Basin PSC Act. It amends the Pre-Shipment Inspection of Oil Exports Act while the provisions of certain laws are saved until termination or expiration of the relevant oil prospecting licenses and mining leases including the Petroleum Act, PPTA, Oil Pipelines Act, Deep Offshore and Inland Basin PSC Act.
The key changes in the Act include:
Organisational changes
The Act seeks to limit the power of the Minister of Petroleum Resources by revoking the Minister’s power to grant, amend, revoke or renew licenses, and removing the Minister’s seat on the board of NNPC Limited. In addition, two proposed regulators, the Nigerian Upstream Regulatory Commission (the ‘Commission’) and the Midstream and Downstream Petroleum Regulatory Authority (the ‘Authority’) would replace the multitude of regulating bodies (the DPR, Petroleum Inspectorate, the Petroleum Products Pricing Regulatory Agency, the Petroleum Equalisation Fund, among others) and must consult each other on new regulations or amendments. Such structural reforms create a clear separation between NNPC Limited’s operations as a commercial entity and the regulatory roles to be exercised by the regulatory authorities, allowing for more transparent oversight.
About two decades ago, Nigeria launched its goal of achieving gas-based industrialisation in the country. Whilst this goal was largely left unachieved, the need to actualise this goal became even more urgent in the years that followed. Over the past decade, Nigeria has continually buckled under several bouts of oil-induced economic recession, a near-stagnant industrial sector due to epileptic power supply, and the increasing unaffordability of Petroleum Motor Spirit (PMS) in the domestic market.
Requirement for Companies and Taxation of Income from Petroleum Operations
With the introduction of the PIA, a company shall not be involved in more than one stream of petroleum operation (i.e. Upstream, Midstream and Downstream sectors) and would have to register a separate company for each stream of petroleum operations.
While the applicable CIT rate will be in line with the provisions of the CIT Act (rate of 30%), the NHT rate will be graduated and dependent on the area of operation and the period the mining lease was granted.
Host Communities
The definition of host communities is contentious; as “host communities” are no more restricted to the oil-producing areas alone but includes communities where pipelines pass through. Under the Act, non-oil producing states that have pipelines passing through them will now be beneficiaries of the percentage allocation for that purpose. That automatically grants some northern states the status of oil producers.
Also, any company granted an oil prospecting licence or mining lease or an operating company on behalf of joint venture partners (the settlor) is required to contribute 3% - 5% (upstream Companies) and 2% (other companies) of its actual operating expenditure in the immediately preceding calendar year to the host communities development trust fund. This is in addition to the existing contribution of 3% to the NDDC. The Fund is tax-exempt and any contributions by a settlor is tax-deductible.
Introduction of a new tax regime and tax rate
The Act proposes to replace the existing Petroleum Profits Tax (PPT) with the National Hydrocarbon Tax (NHT). Companies engaged in upstream petroleum operations will now be subjected to a dual income tax regime, i.e. the Hydrocarbon Tax (HT) and the Companies Income Tax (CIT). While the applicable CIT rate will be in line with the provisions of the CIT Act (rate of 30%), the NHT rate will be graduated and dependent on the area of operation and the period the mining lease was granted. The rate is as stated below
|
Fiscal regime |
Onshore |
Shallow water |
Deep offshore |
|
New acreage |
42% |
37.5% |
5% |
|
Converted acreage |
22.5% |
20% |
10% |
The Act also provides that NHT shall not be payable on associated and non-associated natural gas, as well as condensates and natural gas liquids produced from non-associated gas in fields or gas processing plants, regardless of whether the condensates or natural gas liquids are subsequently comingled with crude oil. However, HT will apply to crude oil, condensates and natural gas liquids produced from associated gas. Further to this, the Act provides that a newly incorporated company that is yet to commence bulk or disposal of chargeable oil is now required to file its audited accounts and returns within 18 months from the date of its incorporation.
Ascertainment of Assessable and chargeable profits for HT and CIT Purposes
The PIA places restrictions on the deductibility of expenses and amends several of the provisions in the PPTA as it relates to ascertaining the assessable profits of companies with upstream petroleum operations. The proposed changes include the following:
I. Introduction of the reasonability test for deductibility of expenses incurred for HT purposes. This is in addition to the requirement under the PPT Act for allowable expenses to be wholly, exclusively and necessarily incurred, to be tax-deductible.
II. Royalty expense will only be deductible in ascertaining the HT payable after it has been incurred and paid. This is a deviation from the accrual basis for royalty deduction under the PPT Act.
Gas utilisation incentives will apply to midstream petroleum operations and large-scale gas utilisation industries.
III. Education tax, bad debt, bank charges, cost incurred by affiliates, arbitration/ litigation cost, penalties, natural gas flare fees and taxes paid on behalf of another person will not be deductible expenses for the purpose of determining the HT payable.
The PIA introduces new provisions to apply to such companies, in addition to the provisions of the CIT Act. For instance, rents and royalties incurred and paid, contributions to abandonment and host community funds, and other deductions that may be prescribed by the Ministry of Finance will be deductible expenses. However, signature bonuses paid for the acquisition of rights, penalties and gas flare fees will not be deductible expenses for CIT purposes.
Therefore, companies will have to pay particular attention to the computation of their HT and CIT payable, given that certain expenses such as bad debt and bank charges that are not deductible for HT purposes are tax-deductible when determining the CIT payable.
Royalties
All production of petroleum, including production tests, shall be subject to royalties. For royalty purposes, condensates shall be treated as crude oil and natural gas liquids shall be treated as natural gas. The rates are:
|
Production Terrain |
Royalty Rate |
|
Onshore |
18% |
|
Shallow Water (up to 200m) |
16% |
|
Deep Offshore (greater than 200m) |
10% |
|
Frontier Basins |
7.5% |
Last year, The royalty rate for natural gas in onshore area is 7.5%, while the rate for every other area and for gas produced and utilized in-country is 5%. For Deep offshore fields with production during a month of not more than 15,000 barrels per day, the royalty rate will be 7.5%. Production above 15,000 barrels per day will be at the rate specified in the table above. Royalties for onshore fields and shallow water fields during a month shall be calculated on a tranche basis as shown above.
Stringent Penalty Regime
The penalties for defaults or offences committed under the fiscal framework of the PIA increased significantly. These include:
I. An increase in penalties for not filing income tax returns from NGN10,000 on the first day of default and NGN2,000 for every other subsequent day to NGN10,000,000 and NGN2,000,000, respectively.
II. With regards to penalties on non/late payment of tax, the company will be subject to a penalty of 10% and interest at the prevailing LIBOR or any other successor rate plus 10% as against the previous rate of 5%.
III. A person who fails to comply with the provisions of any regulations therein for which no specific penalty has been provided shall be liable to an administrative penalty of NGN10,000,000. Where default continues, there would be a further administrative penalty of NGN2,000,000 or such sum as may be prescribed by the Minister of Finance.
Production incentives
In place of the current Investment Tax Credit (ITC) and Investment Tax Allowance (ITA) as applicable, there will be a production allowance for crude oil production by leases which are converted to oil mining leases based on a conversion contract and their renewals which is the lower of US$2.50 per barrel and 20% of the fiscal oil price. The production allowance for new acreages will be determined as follows:
I. For onshore areas, the lower of US$8 per barrel and 20% of the fiscal oil price up to a cumulative maximum production of 50 million barrels from the commencement of production and the lower of US$4 per barrel and 20% of the fiscal oil thereafter.
II. For shallow water areas, the lower of US$8 per barrel and 20% of the fiscal oil price up to a cumulative maximum production of 100 million barrels from the commencement of production and the lower of US$4 per barrel and 20% of the fiscal oil thereafter.
III. For deep offshore areas, the lower of US$8 per barrel and 20% of the fiscal oil price up to a cumulative maximum production of 500 million barrels from the commencement of production and the lower of US$4 per barrel and 20% of the fiscal oil thereafter.
Furthermore, the Gas utilisation incentives will apply to midstream petroleum operations and large-scale gas utilisation industries. An additional 5-years tax holiday will be granted to investors in gas pipelines.
Abandoned Wells or Pipelines
The PIA requires that necessary and adequate provisions be made for the decommissioning and abandonment of onshore and offshore petroleum wells, installations, structures, utilities, plants and pipelines for petroleum operations and shall be conducted in accordance with international best practice and guidelines by the Commission or the Authority. This exercise shall take place with the approval of the Commission or the Authority, as applicable.
The PIA requires that each lessee and licensee shall set up and maintain a decommissioning and abandonment fund, which shall be held by a financial institution that is not an affiliate of the lessee or licensee. The fund so set up, will be used for abandonment and decommissioning purposes. Where the licensee or the lessee fails to comply with the abandonment plan, the Commission or the Authority will access the fund for this purpose.
Shortcomings
- For existing companies, the new fiscal regime will only start to apply upon renewal of existing Oil Mining Leases (OMLs) and Oil Production Licenses (OPLs) or the execution of new ones. Therefore, it is important for companies engaged in petroleum operations to conduct a PIA impact assessment to decide whether to adopt the fiscal regime of the PIA, prior to the due date of mandatory adoption (i.e. expiration and renewal of existing OMLs and OPLs).
- Despite the positive aspects highlighted, the PIA ultimately fails to account for climate change, acknowledge the Paris Agreement, and address the need for diversification to adequately prepare Nigeria for the energy transition that is already underway.
- Considering the significant capital requirements for new projects in the oil and gas industry, restrictions on the deductibility of some valid operating expenses may discourage investment in this industry thereby stripping one of the major aims of attracting investment in the sector.
- Although the PPT was expunged and replaced with NHT & CIT for companies engaged in upstream petroleum operations, this might not be as incentivizing as it seems as it may lead to overall higher taxes for an organization engaged in both oil and gas operations.
- The Act failed to accede to the request of representatives of host communities that they are allocated 10 percent on the grounds that three percent is not enough to improve the standard of living of their people and correct the already significant damage done to their environment.
In conclusion, it is therefore essential that all stakeholders get acquainted with the changes in the Act in order to ensure that the law accomplishes its main objective of reforming the industry for the collective good and sustainable future of all Nigerians. By ensuring an enabling environment for investors backed by a transparent and strengthened regulatory framework, the PIA will present significant investment opportunities for both regional and international stakeholders.
Author
Olakanye Oluwatobi | Research Analyst, Revenue | o.o@borg.re
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