Introduction
Taxation in the petroleum industry has always been a bone of contention and a factor that investors seriously consider when deciding to invest in countries. As a result, states have paid serious attention to the design of their taxation regimes to maximize economic gain. This article looks into the design of the taxation regimes of three African states at three key stages of their petroleum industry development: Frontier, Growing Industry, and Mature Industry. For this purpose, Namibia, Ghana, and Nigeria will serve as case studies.
This article will briefly establish the mechanism within a petroleum taxation regime and then identify and interpret their design within the systems of the three countries mentioned above.
The aim is to highlight how a nation, at a particular stage in its petroleum industry development, can design its tax system. Then this article will close by addressing non-legal factors that must be considered in future tax regime designs, and addressing the link between taxation regimes and the number of oil reserves in a territory.
Key Taxation Mechanisms
To effectively analyze taxation regimes, there must be common mechanisms within these regimes that can be identified and compared. A comparison of these mechanisms should be able to establish how harsh a regime is and what the objectives of the government are. The cornerstone mechanisms in a petroleum tax regime that will be used are corporate/petroleum income tax, royalties, additional profits tax, and incentives.(If you are already familiar with these mechanisms, you can skip to the "Country Analysis" section)
Corporate Income Tax (CIT)
In some countries, the Petroleum Income Tax is classified as a CIT, which is equal to the tax rate levied against all other companies in the country. It is, however, not uncommon for states to make an exception for the petroleum industry by use of a unique petroleum tax act or to negotiate an independent petroleum agreement. This petroleum tax act or petroleum agreement contains its PIT rate, which is typically higher than the CIT rate.
Royalties
Royalties in the petroleum industry are a method through which governments take revenue from petroleum operations based on the volume of hydrocarbon production and exports. Royalties are an attractive solution for governments they are paid before any other taxes or expenses–which makes them available even if the project eventually makes a loss. They are available from the start of production.
Additional Profits Tax
APT or AOE is always provided for in unique petroleum legislation. It is different from a regular petroleum tax because it is linked directly to the profitability of the project and applied after achieving specific financial milestones. When the milestone is achieved, a relatively high tax rate is applied. The main advantage of this mechanism is the neutrality of the tax. It will not be charged unless the profitability of the project is achieved.
Incentives
While the above mechanisms allow governments to take more petroleum revenues, they reduce the profitability of any given project and thus discourages investors. Incentives are a flexible mechanism that governments use to bargain with and attract investors. While various forms of incentives exist, this paper will focus on tax-deductible expenditures and the treatment of losses.
Exploration expenditure and development expenditure create immense financial risk for an investor. Some governments allow companies to deduct these expenditures from their tax base. This leaves less revenue for the government to tax, but it does enable the investors to recoup their investment faster.
When a project makes a loss, the government cannot claim taxes. In the instance, when a project makes a loss within one financial year, some governments allow companies to deduct that loss of one financial year from the tax base of the following(profitable) financial year. This has the effect of allowing investors to recoup more of their investment by dragging the balance sheet of the project into a "loss" that year, making it ineligible for taxes, to make up for the actual loss in the previous financial year.
Country Analysis
The Frontier Nation-Namibia
Although oil prospects and gas reserves exist in Namibia, it is still a frontier country because no proven oil reserves have been discovered at the time of writing this paper. There is no production, but there are over 35 exploration licenses in effect and growing interest. Namibia's petroleum tax system is designed as follows:
The PIT on petroleum operations is 35%,and royalties are payable at a fixed rate of5% of gross revenues. Additional Profits Taxis payable in three tranches, only if operations in a license area earn an after-tax rate of return of at least 15% is the first tranche payable. If operations in the license area earn an after-tax rate of return of 20% or 25%, then the second and third tranches of APT become payable. The specific amount payable is based on a formula that is outlined in the legislation.
Accumulated exploration expenditures are deductible in full in the first year of production. Exploration expenditures incurred after the year when production commences are immediately deductible. Accumulated development expenditures are deductible in three equal installments commencing in the first year of production.
Losses resulting from allowable deductions may be deducted as an allowable loss against the gross income from the license area in the next year. Losses may be carried forward without limitation.
It is clear that this taxation system is designed to attract investment, which is unsurprising given that Namibia is a frontier nation. A fixed instead of a flexible royalty provides certainty for investors over the long term.
The deductibility of exploration and developmental expenditures is geared towards the start of production, allowing investors to write off their expenditures as soon as possible–which reduces the taxable income that the state can access. The ability to indefinitely carry losses on the balance sheet for tax purposes further allows investors to fully recoup investments before the state has access to its funds via tax.
The Growing Industry Player -Ghana
The first major oil field in Ghana was discovered by Signal Amoco in 1970. Ghana joined the league of oil-and gas-producing nations with the discovery of the Jubilee field in 2007, today Ghana can boast of three offshore oil and gas projects in the Western Basin, providing an output 214,000 barrels of oil per day with plans to more than double that number by the year 2024. Ghana's petroleum tax system is designed as follows:
The applicable PIT rate is 35%,and the royalty rate is not fixed in legislation, as it is determined by the Minister. In the Petroleum Agreements signed so far, the rate ranges from 4% to 12.5%. The Government of Ghana also charges an additional oil entitlement, which is computed monthly, quarterly, or yearly, depending on the provisions of the contractor's Petroleum Agreement.
Broadly, expenditures of a capital nature are not deductible. However, Ghana has created incentives regarding capital allowance. Exploration costs incurred prior to or after to commencement of drilling operations are capitalized, and a capital allowance is claimed equally over a five year period of commercial operations.
Tax losses incurred in any year of assessment can be deducted from the subsequent year's profit. The loss can be carried forward for no longer than five years.
A difference between the frontier and the oil-producing nations is immediately visible. A flexible royalty that has gone as high as 12.5%, non-deductibility of capital expenditure, and placing a limit of five years on how long losses can be carried forward for tax purposes. This indicates that oil-producing countries begin drawing back benefits in order to strike a fairer deal.
The Mature Oil Nation -Nigeria
Oil was first discovered in Oloibiri in 1956. Since then, Nigeria has grown into the largest oil-producing country in Africa, with crude oil exports of 1,979,500 barrels per day and proven crude oil reserves of 36,972,000,000.Nigeria has, by far, one of the most detailed petroleum tax regimes. Nigeria's petroleum tax system is designed as follows:
The PIT rate rests at 65.75% for the first five years of production for new incoming JVsand then increases the rate to 85% for subsequent years.
Royalties are provided for by the Petroleum Act and the Petroleum (Drilling and Production) Regulations. The royalty payable is dependent on the concession agreement between the company and the government. Royalty rates for JV operations areas follows :
• Onshore production—20%
• Production in territorial waters and continental shelf up to 100 meters' water depth—18.5%
• Offshore production beyond 100 meters—16.67%
The Deep Offshore and Inland Basin Production Sharing Contracts Act specifies the royalty rates that apply to production from PSC fields beyond 200 meters. For inland basins, the royalty rate rests at 10%. For deep offshore drilling up to 200m water depth, the rate is 16.67%, and the rate gradually decreases, the deeper the drilling operation. For operations drilling in excess of 1,000m water depth, the royalty rate is 0%.
The Nigerian regime does not provide incentives for oil exploration in the region.
It is clear that this regime is designed to maximize the government's ability to obtain revenue from petroleum operations by virtue of its comparatively high tax rate. Nigeria's thorough royalty regime allows the state to charge comparatively high royalty fees on most operations and allows leeway on the projects that have more risks, like deep offshore projects drilling in excess of 1,000 meters. Furthermore, no revenues are lost through a broader range of tax-deductible expenditures because no investor incentives are provided.
Despite such a harsh regime, sector performance is healthy. Drilling activity in Nigeria is ramping up and is expected to continue. The new production is likely to only offset declining volume from older fields, keeping the oil supply stable. The most recent drilling activities include the flagship development of the ultra-deep water Egina oil field by Total. There is a clear trend for harsher fiscal regimes to be put into place, the more mature the petroleum industry is.
Up until now, investors have continued to do business in these regions. The question becomes; how harsh would tax systems need to be to begin seriously discouraging investments? The draft Petroleum Industry Bill (PIB) would be the next evolution in Nigeria's petroleum taxation regime. Naturally, it is harsher than the current system. This Bill has suffered over a decade of legislative delays and has gone through several literation's. Economic projections on the 2017 version of the PIB highlighted a 59%reduction in investment, among other negative impacts. Newer versions of the draft PIB have been tempered in light of such projections. It is yet to be implemented but news reports state it is set to be implemented mid-2020.
External Factors
It is crucial to understand the non-legislative factors that must be considered when contemplating the design of future petroleum taxation regimes. We must acknowledge the Paris agreement as a strong driving force of change in the petroleum industry. A wave of global transformation to mitigate climate change has taken place since its signing, and its enforcement in 2016. The result is that the energy mix worldwide has slowly shifted against fossil fuels, and similarly, investment in fossil fuels has also shifted away. The agreement provides for a range of obligations, inclusive of a 'global stock take' meant to measure the efforts of states to transition their energy systems away from fossil fuels.
Supplementary to this, a preliminary text agreed by EU member states calls on the European Investment Bank to stop multi-billion Euro funding of fossil fuel projects in a bid to reduce carbon emissions.
Additionally, the oil squabbles between Russia and OPEC, the rise of shale oil producers in the US, and most recently, the Corona Virus (causing the shut/slow down of major cities and industries) are all contributing to the already declining oil price.
All these factors put the petroleum industry in a delicate place. This must be noted by policy makers in shaping future taxation regimes. With that said, the oil industry is still a robust one with a strong market in Africa where the effects of the Paris Agreement are on a much slower road to implementation.
Conclusion
The design of a petroleum taxation regime is a unique tool that is tailor-made to its user.
The evolution of the petroleum sector within a country will impact its tax system. With more abundant resources, the taxation regime will grow harsher. With fewer resources, one will see designs as investor-friendly as the one existent in Morocco, that doesn't require petroleum companies to pay tax for their first ten years of operation.
For frontier countries attempting to adopt systems that resemble growing industry player regimes or for growing industry players attempting to adopt systems that resemble mature oil nation regimes, there is still room for reform. However, the number of oil reserves required to economically justify that change may
be a lot more substantial than that required in previous years. Lest the taxation reform leads to a sharp decline in investment.
For mature oil nations attempting to adopt a harsher regime, there doesn't appear to be as much room. Nigeria, as the state with the harshest petroleum taxation regime in Africa, is the nation to watch. Their ability or inability to implement the PIB will dictate the limit of what African petroleum taxation regimes can look like.
About the Author Kauraisa obtained his LLB from the University of Namibia and is currently a2019/2020 Candidate for an LLM in International Oil and Gas Law and Policy at the Centre for Energy, Petroleum, Mineral Law and Policy. For inquiries, email:kauraisaz@gmail.com