Recent fiscal changes in Nigeria’s oil and gas sector

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Crystal Okwurionu
AELEX Partners, Lagos
cokwurionu@aelex.com

Introduction

There have been some recent changes to fiscal incentives which apply to Nigeria’s oil and gas sector. These changes were introduced by the Deep Offshore and Inland Basin Production Sharing Contracts (Amendment) Act and the Finance Act, which became law in October 2019 and January 2020 respectively.

The Deep Offshore and Inland Basin Production Sharing Contracts (Amendment) Act (the 'Amendment Act') amends the fiscal provisions for upstream companies operating in the deep offshore and inland basin area. The Finance Act amends primary tax legislation in namely the Companies Income Tax Act, The Petroleum Profits Tax Act, Personal Income Tax Act, Value Added Tax Act, Capital Gains Tax Act, Stamp Duties Act, and Customs and Excise Tariff Etc (Consolidation) Act.

Prior to the coming into force of the Amendment Act and Finance Act, oil and gas companies operating in Nigeria enjoyed certain incentives. For instance, those who operated in water depths of more than 1,000 metres were not required to pay royalties. Dividends due to shareholders from the profits of petroleum operations were also exempt from the application of withholding tax.

In this article, we examine the fiscal changes affecting the oil and gas sector and analyse the implication of the changes to investment.

Changes to royalty rates

Prior to the Amendment Act, royalty rates applicable to oil and gas companies operating in the deep offshore^[1] were graduated as follows:

• areas from 201 to 500 metres water depth – 12 per cent royalty rate;

• areas from 501 to 800 metres water depth – eight per cent royalty rate;

• areas from 801 to 1000 metres water depth – four per cent royalty rate; and

• areas greater than 1,001 metres water depth – no royalty rate.

For companies operating in the inland basin area,^[2] there was a flat ten per cent royalty rate.

The exemption of upstream companies operating in deep offshore water depths of more than 1,000 metres from royalty payments, was a concession given by the Federal Government of Nigeria (FGN), in recognition of the risks and high investment in offshore drilling at such depths. It was aimed at attracting foreign investment with the technical and financial expertise necessary for deep offshore drilling.

Under the Amendment Act, the deep offshore royalty has now been changed to a flat rate of ten per cent for all deep offshore operations, irrespective of depth. The rate is now based on the chargeable volume of crude oil and condensates produced from the deep offshore area for that period. The royalty rates applicable to the inland basin areas has been reduced from ten to 7.5 per cent. The new rates will ensure increased revenue for the FGN.

To understand how this new royalty rate will apply across the sector, it is necessary to explain the various petroleum contracts currently in use for the grant of interests in deep offshore assets. In Nigeria there are currently three contract structures for deep offshore assets: the Production Sharing Contract (PSC), the Production Sharing Agreement (PSA), and the Back-in Rights Production Sharing Contract.

The PSC is an agreement between the Nigerian National Petroleum Corporation (NNPC)^[3] as the concessionaire and an upstream company or companies as the contractor, and governs the exploration and production of oil in the deep offshore asset. The PSA is a contract between a local upstream company who was awarded the deep offshore asset on a discretionary basis, and another oil company, usually an international oil company (IOC) which has farmed-in to the asset.^[4]

Discretionary awards refer to sole risk award of deep offshore assets by the FGN via an indigenous exploration programme policy between the 1980s and 1990s. Although it was never codified in a document, the underlying principle of the grant was to encourage indigenous participation in the upstream petroleum sector. Awardees were permitted to farm out not more than 40 per cent of their interest in the asset to foreign investors. Although the indigenous upstream companies were left with 60 per cent interest in the asset, the FGN can (and has in one instance) compulsorily acquire 50 per cent interest in the asset, via the Deep Water Block Allocation to Companies (Back-In-Rights) Regulations, 2003.

A PSC also governs the portion of the asset which the FGN acquires. The PSC is an agreement between NNPC as the interest holder and an upstream company as the contractor. It is, therefore, possible for a deep offshore asset to be governed by both a PSC for the portion of the block which has been compulsorily acquired by the FGN and a PSA for the other part of the block awarded on a discretionary basis.

PSCs contain stabilisation clauses which provide for a review of the contract in the event of a material change to the fiscal legislation. However, only the PSCs with NNPC as concessionaire has stabilisation clause provisions. The PSAs which govern assets awarded on a discretionary basis do not provide for a stabilisation clause. For assets which are governed by both a PSA and PSC as discussed above, only the portion governed by a PSC with NNPC will be able to benefit from any stabilisation from the federal Government of Nigeria.

As such, only upstream companies operating in assets governed by PSCs can trigger stabilisation discussions with the FGN with respect to the new royalty rates. Upstream companies operating in assets governed by PSAs cannot rely on the comfort of a stabilisation clause. The reason is simply that, while blocks governed under a PSC arrangement with NNPC ensures periodic returns to NNPC in the form of profit oil, the NNPC, not being a party to the PSA, has no interest in blocks awarded on a discretionary basis.

Considering that several IOCs have interests in deep offshore blocks awarded on a discretionary basis, the effect of the royalty rate changes may cause the IOCs to re-evaluate the value of current projects and upcoming projects which are awaiting final investment decision.

Introduction of a price-based royalty

The Amendment Act has also introduced a second-tier royalty which is based on the price of crude oil. Royalty will accrue to the FGN, where the price of crude oil exceeds US$20 per barrel (/bbl). Where the crude oil price is above US$20/bbl and up to US$60/bbl, a royalty rate of two point five per cent applies. Where the price is above US$60/bbl and up to US$100/bbl, the applicable royalty rate is four per cent. In the event that crude oil prices rise above US$100/bbl and up to US$150/bbl, the royalty rate graduates to eight per cent and, finally, to ten per cent where the price of crude oil exceeds US$150/bbl.

Price-based royalty is applied in countries such as Mexico. In Mexico, where the price of crude oil is less than US$48/bbl, a 7.5 per cent royalty is to be paid. Where the price of crude oil is equal to or exceeds US$48 per barrel, the royalty rate will be equal to (0.125 x the contractual reference price) +1.5.

Although Mexico also applies the price-based royalty structure, it does not appear that the country also uses production-based royalty. This is in line with most oil producing countries which apply either a field- or production-based structure of royalty, or a royalty structure based on the price of crude oil.

With the introduction of this royalty, Nigeria will now operate a two structure royalty regime based on production as well as price of crude oil.

Introduction of periodic review of the PSCs

The Amendment Act also provides for a mandatory review of existing PSCs every eight years. Investors may need to consider the implication of the periodic reviews on their investments, project planning and project development as it creates some level of uncertainty on what the result of the review may yield.

Changes to tax-free dividends policy in respect of upstream operations

Before now, shareholder dividends from profits on the sale of crude oil were exempt from withholding tax. For this exemption to be applicable, however, the profits had to be obtained exclusively from upstream activities. This exemption was likely in contemplation of the relatively high taxes upstream companies are required to pay as corporate income tax. While other companies currently pay corporate income tax of up to 40 per cent, under the Companies Income Tax Act and the Finance Act, upstream companies pay 85 per cent in accordance with the provisions of the Petroleum Profits Tax Act. The only exception is upstream companies operating in the deep offshore and inland basin area, who are allowed to pay corporate income tax of 50 per cent.

By the provisions of the Finance Act, shareholder dividends derived from the sale of crude oil will now be liable to withholding tax of up to ten per cent.

By the introduction, Nigeria joins oil producing African countries such as Ghana in charging withholding tax on dividends paid to shareholders on the profits of upstream companies. We note, however, that while the withholding tax that applies to upstream companies in Ghana is eight per cent, for Nigeria it is ten per cent, except for foreign investors from countries who have double taxation treaties with Nigeria.

While the change will increase revenue to the FGN, the implication for investors/shareholders is a reduced investment return. It is, therefore, likely that the change will influence foreign portfolio investment decisions in oil and gas.

Change to the investment tax credit on obsolete plant and machinery

The Finance Act has removed the provision of Corporate Income Tax Act (CITA) which entitles downstream and mid-stream companies who replace obsolete plant and machinery to enjoy a tax credit of 15 per cent of the replacement cost. The implication is that affected companies will no longer enjoy the incentive when they replace obsolete plant and machinery.

Introduction of VAT on services rendered remotely by foreign companies

The Finance Act now provides for the payment of a Value Added Tax (VAT) of 7.5 per cent by persons and companies in Nigeria who receive services from non-resident companies. This means that oil and gas companies are now required to submit VAT to the tax authority where they receive services from foreign companies.

Conclusion

These changes are likely to have an impact on the inflow of foreign investment into the oil and gas sector, considering that it does increase the royalties and tax costs of oil and gas companies. This is in addition to the lack of certainty surrounding the fiscal outcomes of the Petroleum Industry Bill, which may gather momentum in the coming months.

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