Chapter 4: Comparative Study of Tax Regimes in Selected West African Countries

Case study of Benin, Niger, Ghana, Côte d’Ivoire, Nigeria and Senegal

4.1- Design principles of the flow diagram associated with the oil contract

Before the start of oil negotiations, the State, which owns the resources, must draw up a simplified financial or economic flow chart showing the distribution of revenues between the contractor and the State. This diagram constitutes a summary economic model that allows the State to know the oil rent that will accrue to it after exploitation. This flow chart is a decision-making tool that allows the States that own the resources to better assess their tax regime and the negotiable parameters on which they must act during contract negotiations to get the most out of their resources.

The legal and regulatory instruments on which States must base their design of this decision-making tool are the Petroleum Code and especially the tax regime.

Petroleum Code

It is the legal instrument that governs the exercise of oil operations. It provides, among other things, provisions that are likely to encourage companies or consortiums of oil companies to carry out oil operations, given the particularly high costs of research work, but also provides provisions that regulate the distribution of revenues between the State and the partners.

Tax regime

The tax regime is generally enshrined in the oil laws of the states. In Benin, for example, Law No. 2019-06 of 15 November 2019 on the Petroleum Code only enshrines the production sharing contract as the applicable tax regime for the carrying out of oil exploration and exploitation work by the CPIs. To this end, a model production sharing contract was adopted by decree in 2020. Other countries have in their legislation in addition to the Production Sharing Contract (PPC), other tax systems, namely the concession contract and service contracts. In Nigeria and Côte d’Ivoire, for example, their legislation authorises the signing of a CPP or a concession contract.

The cardinal elements of the tax regimes that make it possible to produce this simplified diagram which allocates the revenues of the State and the contractor are the ad valorem royalty, the cost oil, the profit oil, the corporation tax. In addition, the State participates in oil operations.

Tax elements such as bonuses and ad valorem royalties (royalties) that induce upstream payments to the State are not based on the profit of the project. They are set up to reduce the risks of states. On the other hand, these upstream payments to the State make the tax regime regressive when they are too high, and therefore unattractive to investors. The regressive system does not encourage the CPIs who prefer a progressive tax regime where the state rent is much more based on income taxes, additional taxes etc. resulting from the benefits of the project.

1. Key tax elements applied in selected West African countries

4.2.1- Redevance ad valorem (royalty)

When the first drop of oil or gas comes out, a share is directly allocated to the state that owns the resources before any deduction of costs or any sharing of production. This share is called royalty. It is mainly applied in concession contracts. This royalty is introduced in the PSAs in anticipation of unforeseeable reservoir risks at certain hydrocarbon deposits. This fee, when it is too high in PSAs, can be the cause of early or premature cessation or abandonment of fields by the CPIs. It can be received in kind or in cash.

The balance obtained from the monetary value of oil extracted from the deposit (gross revenue) after deduction of royalty is the net royalty income. Gross income depends on the quantity of crude oil extracted from the deposit, the quality of the crude oil and the variation in the price of crude oil on the international market. Thus, we have:

Post Royalty Revenue = Gross Revenue – Royalty

Table 5 below shows the proportions of royalties adopted in the oil regulations of selected West African countries.

The analysis of this table shows that the royalty does not exceed 15% in most West African countries and varies according to:

1. The nature of the fluid: the royalty rate of oil is much higher than that of gas. The maximum in the countries studied is 15% for oil and 6% for gas. This difference may be linked to the recovery rate of gas, which is higher than that of oil;

2. The geological area of discovery: depending on whether it is onshore or offshore, shallow, deep or very deep. Royalties are lower in offshore geological areas that require more investment for hydrocarbon exploitation than in onshore;

3. the variation in the price of the barrel and on the volume of oil produced: in addition to the two groups of parameters mentioned below, other countries such as Nigeria for example, have introduced an additional royalty which is based on the variation in the price of the barrel and on the volume of oil produced. This royalty could be interpreted as an additional oil right allowing the capture by States of capital gains when the price of a barrel on the international market rises and reaches a given threshold, in order to increase their oil rent.

Côte d’Ivoire does not provide for a royalty in its PSA. This is likely to attract investors. In doing so, its PSA may seem more attractive than those of other countries in the West African sub-region in this area.

As for Benin, the royalty bracket in the offshore zone is less attractive than those of Ghana, Senegal, Côte d’Ivoire and Nigeria for oil but practically the same for natural gas.

4.2.2 - Recoverable Petroleum Costs

They concern exploratory costs, development costs and operating costs invested or set up by contractors for the conduct of oil operations, including depreciation/depreciation. Before the oil is profited, a portion of the production is allocated to recover the costs invested by the contractors. In oil contracts, a ceiling is set in the regulations of the tax regime. This cost recovery cap is called the Cost Stop. International oil companies want a quick recovery of their investments to minimize unexpected political risks that could cause a production blockade in some countries and unpredictable technical and reservoir risks that could lead to lower production yields sooner than expected. A cost stop and a high daily production rate allows the CPI to achieve the shortest possible payback period. This duration is defined by the time it takes for the initial investment related to exploration and development costs (CAPEX) to be recouped.

The graph below (Figure 24) shows the cost stop in the West African countries covered by our study.

Figure 24: Graph showing the cost stops applied in some West African countries

The analysis of this graph reveals that the setting of the cost stop varies from one country to another. The overall rate applied in these countries is between 55% and 80% and depends on the situation of the contractual area (onshore, shallow offshore, very deep or ultra-deep). The relatively higher cost stops are applied in areas of high bathymetry, i.e. deep to ultra-deep offshore, which present enormous challenges in terms of exploration technology and investment, in order to encourage companies to undertake operations in these areas of high financial and technical risk. On the other hand, for onshore and shallow offshore areas, states opt for a lower cost stop.

The comparative study of the Cost Stop shows that Benin and Côte d’Ivoire have a relatively more attractive cost stop. For Benin, it is capped as in the case of most countries and varies from 70% onshore to 80% very deep offshore. Côte d’Ivoire, for its part, has adopted in its regulations a cost oil of 60% in shallow offshore and 80% in very deep seas. Ghana, for its part, has opted in its legislation for a depreciation of capital expenditure (exploration and development costs) of 20% each year from the date of commercial production for a period of 5 years, i.e. a linear recovery of investment costs for 5 years. Ghana’s option allows the contractor and the State to operate an effective and efficient mode of production, in the sense that the annual amount to be reimbursed is not a function of production, so that the resources can be exploited responsibly and sustainably until the repayment of the capital expenditures recognized in the legislation.

4.2.3- Oil Profit

Oil profit is the share of oil that remains after the deduction of oil costs and the Royalty (ad valorem royalty) and is shared between the Government and the Contractor. Profit oil is analogous to taxable income in a concessional system. Oil profit is usually, but not always, taxed.

It is calculated by the following formula:

Oil Profit = Revenue Post Royalty – Recoverable Costs or

Oil Profit = Gross Revenue – Royalty – Recoverable Costs

In the Production Sharing Contracts of Benin and Niger, the share of the oil profit accruing to the contractor is no longer taxed.

The modalities of distribution of oil profit vary from one country to another. Some countries adopt a sharing mechanism based on daily or cumulative production on a progressive scale, while other countries opt for a sharing mechanism based on profitability (R-factor or rate of return), which is a function of oil revenues and costs. That is, maximum and minimum profit oil refers to contracts where there is a dynamic scale dependent on a trigger which can be the volume of production, economic factors like the internal rate of return or other criteria. If the sharing of profits is high in favor of the oil company, the States must secure their share by other measures, most often by taxation.

The R-factor can be used as a trigger for both royalty and profit sharing. It is determined in different ways:

1. R-Factor=Cumulative Revenue/Cumulative Cost

2. R-Factor = (Cumulative Revenue - Cumulative Opex) / Cumulative Capex

3. R-Factor = (Cumulative Revenues - Cumulative Profits) / (Cumulative Investments + Cumulative Opex)

4. R-Factor=Cumulative Net Revenue/Cumulative Costs

When the – R factor becomes larger and larger, it means that the profitability of the project becomes higher with a drastic decrease in recoverable costs. It is up to the States to define in their regulations the easiest method of calculation that allows them to capture the best shares of the oil profit more quickly. Thus, when all capital expenditure (CAPEX) is recovered by the contractor, the sharing key must be reversed so that the State’s share becomes higher and higher.

In addition, in order to avoid any manipulation and inflation of recoverable oil costs, it is essential that States rigorously monitor the costs invested, carry out annual audits and train their staff in cost control, since the calculation of the R-Factor is closely linked to the costs invested and consequently the mechanism for rewarding profits depends on it.

The mechanism linked to the volume of production seems simpler and easier for States but seems to be less objective and equitable than the model based on profitability. However, in both cases, the monitoring and control of production and cost declarations is very important to minimize false declarations and product trafficking in order to optimize the oil revenues of the States.

Table 6 below shows the mechanism used in some countries.

4.2.4- Profit/corporate tax

Normally, oil companies are subject to the payment of income tax. However, in the tax laws of the countries we study, the policy for paying corporate taxes varies, depending on their strategy to attract investors. In Benin and Niger, for example, the company does not pay tax directly on its profits. The profit tax is paid in the state’s share of the oil profit. In contrast, in Nigeria, Ghana and Senegal, they are subject to the payment of income tax. For the latter batch of countries, some pay it in accordance with the provisions of the General Tax Code of their country (Senegal for example) and others apply specific rates such as Ghana for example.

The table above shows the summary of income taxes in the countries covered by this work.

Looking at this data, Nigeria has the highest rate in West African countries, followed by Ghana. It can therefore be deduced that countries with enormous proven oil resources apply a more comfortable rate in their tax system in order to maximize their profit in the exploitation of their resources. For countries such as Benin and Niger and even Côte d’Ivoire (in some of its contracts), profit oil and profit tax are therefore not separate and constitute a single tax for the benefit of the contractor, i.e. the international oil company. It is desirable to separate these two concepts.

4.2.5-State participation

The State that owns the oil resources has the right to participate in oil operations in accordance with the procedures defined by the Oil Law. This participation consists of the taking of a share of the share which may be carried by the contracting party or directly for consideration. This state participation is generally managed through the intermediary of the national hydrocarbon companies. The acquisition of shares in oil operations allows States to:

• maximize the revenues from the exploitation of their resources through the dividends that its participation will generate as a shareholder and stakeholder or co-contractor;

• better control of the operations and interests of the State

• acquire and develop national expertise in the conduct of petroleum operations.

The table below summarises the level of participation of States in the countries covered by this study.

Table 8: State participation rate in selected West African countries

An analysis of this table shows that only Nigeria has a high initial participation rate, which is above average, i.e. higher than that of the international oil company. As a result, it will increase its oil revenues very considerably. This risk-taking by Nigeria could be explained by the fact that the geological risk is lower in Nigeria, which has a proven enormous potential in oil resources. The other countries have an initial participation (between 10 and 20%) that is still very low in order to have real control over their resources and substantially increase their oil rent.

However, the paradox in analyzing this table is that these countries with relatively low potential are still hesitant to increase their participation after a discovery. Thus, the additional participation is between 5 and 20% in these countries.

The State’s participation is an essential and decisive element of the tax system allowing the State to increase its oil rent through dividends proportionally generated to the States according to their level of participation.

For this reason, it is desirable that these countries dare to improve their legislation on additional participation, which can enable them to hold a total participation of at least 50% in the exploitation phase.

On the other hand, the efforts of the States to participate constitute an act of sharing geological, technical, economic and political risk that reassures foreign investors for the implementation of projects.

Table 9 below summarizes the key elements of the tax systems of the six countries covered by this study. These elements make it possible to determine the share of the oil rent accruing to the State and the contractor.

3. In-depth analysis of tax regimes by country

4.3.1- Nigeria

Nigeria’s tax system is one of the most complex in the region, the result of decades of incremental change. The 2021 Petroleum Industry Law (PIA) consolidated many of these elements, establishing a dual tax structure: a hydrocarbon tax and a corporate tax, and revising the royalty framework.

Royalties now vary depending on the land and production levels. Deepwater projects benefit from relatively low rates, while onshore and shallow water operations are subject to higher rates, including price-related components that accentuate escalation. Historically, Production Sharing Agreements (PSCs) allowed for cost recovery caps of up to 80%, which encouraged investment but delayed early tax revenues for the government. The Public Investment Act (PIA) corrected this imbalance by capping it at 70%, although implementation challenges remain, particularly in terms of cost verification and regulatory coordination.

Nigeria offers strong resource potential and high growth potential, but this is offset by fiscal complexity and operational risks.

4.3.2- Ghana

Ghana is often considered one of the most balanced and transparent regimes in the region. Its system combines elements of Production Sharing Agreements (PSAs) with corporate taxation, creating a structure that is both progressive and relatively simple. Royalties are typically between 5% and 12.5%, with cost recovery caps of 20%. The share of oil profits increases with profitability, and corporate tax is around 35%.

The strength of the Ghanaian system lies in its institutions. The Oil Revenue Management Act provides a clear framework for their distribution, while participation in the Extractive Industries Transparency Initiative strengthens accountability. The main challenge is to maintain competitiveness in the face of increasingly selective global investment demand.

4.3.3- Senegal

Senegal’s tax framework reflects its status as an emerging producer. Production Sharing Agreements (PSAs) offer relatively low royalties and high cost recovery caps, recognizing the importance of the investments required in offshore oil and gas development. The distribution of oil profits is progressive and the state’s participation is managed by Petrosen, usually with interests carried over during exploration.

The framework also includes provisions on the domestic use of gas, in line with the broader energy policy objectives. As Senegal enters the production phase, maintaining transparency and institutional discipline will be essential.

4.3.4- Côte d’Ivoire

Côte d’Ivoire has developed a competitive system based on production sharing contracts (PSCs) with moderate royalties and cost recovery limits between 60 and 80%. The terms for sharing oil profits are flexible and often tailored to the specific risks of each project, which has helped attract investment, especially in deepwater exploration.

Recent discoveries at sea demonstrate the effectiveness of this approach. However, as production increases, the government will need to balance competitiveness and revenue optimization, while continuing to strengthen institutions and maintain transparency.

4.3.5 - Benin and Niger

Both countries have relatively simple tax systems, based on moderate royalties and with corporate taxation not segregated from the share of their oil profits. Their regulatory frameworks are functional but need to be strengthened, which reflects the small size of their oil sectors, particularly in Benin. The distribution of profits in these two countries is progressive and the State’s participation is managed, as in Senegal, by their National Hydrocarbons Company (SNH-Benin and SONIDEP).

Like Côte d’Ivoire, Benin has adopted a highly incentivizing oil cost recovery limit of up to 80% to take into account the difficulties and risks of huge investments in the deep and very deep seas.

4.3.6- Other West African countries

• Mauritania

Mauritania’s tax regime reflects its growing role as a gas producer. Production Sharing Agreements (PSAs) provide for moderate royalties and cost-recovery provisions tailored to large offshore gas projects. Coordination with Senegal on the Grand Tortue Ahmeyim project complicates the system, but also makes it possible to achieve efficiency gains through the pooling of infrastructure.

Institutional capacity remains a constraint, and the effective management of future gas revenues will be critical to long-term economic development.

• Sierra Leone and Liberia

Both countries offer relatively advantageous tax conditions – low royalties and high cost recovery caps – to compensate for significant geological and political risks. Despite this, the success of exploration remains limited, highlighting the inadequacy of tax incentives. Weak institutions and lack of infrastructure continue to hold back investment.

• Guinea and Guinea-Bissau

These border territories also rely on advantageous tax conditions to attract exploration activities. However, political instability and governance challenges remain significant obstacles. Without broader institutional improvements, tax incentives are unlikely to generate sustainable investment.

• The Gambia

The Gambia is still in its infancy in terms of sectoral development. Its tax framework aims to reduce barriers to entry, through low royalties and flexible production sharing contract (PSC) terms. As exploration progresses, the system will have to evolve in order to reconcile competitiveness and fair exploitation of exploitation.

3. State/Contractor income associated with the tax system in selected West African countries

The calculation of the parties’ cash flow on the basis of the tax terms negotiated and agreed in the contracts of the countries subject to this study between the State and the contractor is carried out in a flow chart of cash flows.

The flow chart will illustrate how in each country subject to our study, 100 barrels of crude oil are distributed between the contractor and the State.

Thus, considering the data recorded in Table 9 above, the distribution of the cash flow of the different parties to the contract from the respective tax regimes of Benin, Ghana, Côte d’Ivoire, Nigeria, Senegal and Niger, is as follows (Figure 25 to 30):

STATE

10

Post-royalty income: 90

Taxable

0

14,85

Net cash flow

-2,23

+ 2,23

State participation

15%

2,23 (SNH-BENIN)

12,62

Partner net cash flow

75,62

Total gross cash flow of the contractor

Figure 25: Simplified organizational chart showing the share of the State and the Contractor in the taxation associated with the CPP of Benin

Corporate tax:

35%

+20,82

-20,82

Total gross cash flow of the contractor

52,88

Figure 26: Simplified organizational chart showing the share of the State and the Contractor in the taxation used in the Ghana model contract

Taxable: 0

86,5

13,5

Gross cash flow

Total gross cash flow of the contractor

85,35

Figure 27: Simplified organizational chart showing the share of the State and the contractor resulting from the taxation associated with the CPP of Côte d’Ivoire

12,5

Post-royalty income: 87.5

+14,55

-14,55

Profit tax: 50%

14,55 (29,1-14,55)

Net cash flow (CPI+NNPC)

-8,73

State participation: 60%

+8.73 (NNPC)

Total gross cash flow of the contractor

62,69

Figure 28: Simplified organizational chart showing the share of the State and the Contractor in the taxation associated with the CPP of Nigeria

9

Post-royalty income: 91

+5,46

-5,46

Profit tax: 25%

16,38

Net cash flow (CPI+PETROSEN)

-1,64

State participation: 10%

+1,64

69,34

Total gross cash flow of the contractor

Figure 29: Simplified organizational chart showing the share of the State and the Contractor resulting from the taxation associated with the Senegalese CPP

15

Post-royalty income:85

Imposable/taxable :0

15,3

Net cash flow (CPI+SONIDEP)

+1,53

-1,53

State participation: 10%

Total gross cash flow of the contractor

73,27

Figure 30: Simplified diagram showing the share of the State and the Contractor resulting from the taxation associated with the CPP of Niger

Figure 30 :

On the basis of the tax parameters summarized above on the basis of the legislative and regulatory texts of the six countries that were the subject of this study, the proportions of the States’ oil revenues in relation to the earnings of the CPIs (contractors) are presented in Tables 9 and 10 and the graphs below (Figures 31 and 32).

Table 10 shows the percentage of oil rent accruing to the State and the contractor after deduction of the expenditure incurred on oil extraction. This distribution is therefore made on the basis of the real economic value of oil, i.e. the net value of the expenses for its extraction.

Table 11 shows the overall cash flow distribution scheme between the parties based on 100 barrels of oil extracted. The oil share for the repayment of investments is added to the contractor’s income.

Figure 31: Graph showing the share of net profit accruing to the CPI and the States according to the tax regime applicable in these States

Figure 32: Graph showing the distribution of the cash flow between the State and the contractor considering 100 barrels of oil extracted

4. Analysis and interpretations

   1. On the net income of States/contractors and attractiveness to foreign investment

It appears from the analysis of the graph in Figure 31 and Table 10 that Nigeria’s tax system offers a better oil rent (net cash flow) for the State (more than 86%) due to the State’s participation of 60% through its National Company NNPC and the tax on profits (tax oil) which is 50%. Despite this apparently very high profit margin for the state, Nigeria remains attractive to foreign investors because of the very high prospectivity of its sedimentary basins. Nigeria’s option to participate financially in oil operations is supported by its very high prospectivity and its policy of capturing more dividends in the profits accruing to the various partners in the contract through its national company.

Côte d’Ivoire and Ghana offer, according to their contract economic model, an attractive tax regime compared to that of Benin, Senegal and Niger. The results of the determination of the cash flows accruing to their respective countries (Côte d’Ivoire and Ghana) show that they make a net profit of about 59% of their oil resources while the foreign contractor earns a profit of about 41%.

For Côte d’Ivoire, the low proportion of its oil revenues (58.6%) can be explained by two fundamental reasons:

1. First, zero royalties adopted in its legislation and

2. second, the absence of direct deduction of tax on profits for CPIs (confers 2019 ENI contract on block CI-501), like the legislation of Benin and Niger which provides for the payment of tax on profits in the share of oil profit accruing to the State.

Thus, an examination of the tax regime applied to Côte d’Ivoire’s petroleum code shows that it derives less profit from its oil resources compared to the other five countries. The Ivorian strategy, through the adoption of such a fiscal policy in its production sharing contract, certainly aims to promote the competitiveness of its sedimentary basin in the West African sub-region, particularly in the face of Ghana, Benin, and Nigeria, which are countries located in the same geological environment of the Gulf of Guinea. This strategy has also borne fruit in view of the large number of oil contracts signed over the last ten years.

The same is true for Ghana’s tax system, described as hybrid, i.e. a combination of the concession system and the CPP by the “Ghana Petroleum Commission in 2016”, which offers almost the same competitiveness as that of Côte d’Ivoire with the signing of contracts with several oil companies in recent years.

Given that Côte d’Ivoire and Ghana have proven a significant prospectivity of their sedimentary basins through several discoveries that have followed one another in recent years, it is essential that they review their tax policies and regulations in order to maximize their oil revenues and create the conditions for more sustained development because the impact of oil and gas exploitation does not yet seem to be very noticeable in terms of the quality of services energy and industrial development. Energy needs are clearly increasing in these countries and in most countries of the subregion.

The determination of the cash flow on the basis of the tax elements of the 2019 petroleum code in Benin shows that the net income for the contractor (CPI) is 34.1%, practically in the same size as that of Niger (34%) and slightly higher than that of Senegal (32.47%). The income of the foreign partner (CPI) in these countries is much lower than that of Ghana and Côte d’Ivoire, which are around 41%. It is clear that Senegal, Benin and Niger are less attractive from a tax point of view for foreign investment than Ghana and Côte d’Ivoire in terms of their tax regimes. The attractiveness of Nigeria’s tax regime is mainly linked to its large proven oil potential, which considerably reduces the financial risk associated with the absence of discovery at the IPCs.

As a result, the absence of oil contracts over the past ten years in Benin, a country that is very close to Nigeria, Ghana and Côte d’Ivoire, could be explained by its unattractive tax policy adopted in 2019 added to its little-known oil potential (obvious geological and financial risk for the CPIs).

As Benin’s oil potential is still very little known, it would be much more desirable to act on the parameters that make Benin’s tax system regressive, namely the reduction of “incidental expenses” such as bonuses, legal and financial assistance fees and other fees paid upstream, i.e. not based on profitability. This improvement would make our code more attractive and competitive.

1. On the overall State/Contracting Party cash flows

The oil rent thus generated by these tax regimes for each country, as shown in Table 10, is an apparent value because it is conditioned by the control by the States of the costs invested by the contractor. These benefits for the parties are only real if the States control the oil costs invested by the contractor. This control or control of costs is not generally a reality in our African countries where there is a great weakness and inadequacy in the monitoring of the oil costs actually invested by the CPIs.

The control of oil costs is therefore a fundamental element that characterizes the reliability of the oil rent that goes to the States. These costs are most of the time subject to manipulation aimed at inflating them excessively, since the higher the investment declared by the contractor, the lower the profit margin to be shared by the parties. Thus, the bulk of the oil produced is generally intended to repay oil costs during the first five years of production.

Table 11 and the graph in Figure 32 illustrate the reality of the oil rent of the States of the West African sub-region according to their tax regime. The results clearly show that out of 100 barrels of oil produced, more than 50% goes to the contracting international oil companies during the first years of production during which the CPIs have to recoup their investments.

Careful analysis of this table shows that Ghana’s tax system is more responsible and advantageous with 47.12 barrels out of 100 barrels produced for the state. This profit margin, which is better than in other States, is the consequence of the 20% straight-line depreciation rate adopted for the reimbursement of oil costs, unlike the other States which have opted for a cost stop of between 60 and 80% indexed to production. It is followed by Nigeria, which takes about 37.31% of production because of its high state shareholding, which maximizes its share of oil profit.

Côte d’Ivoire has the least advantageous tax regime in the sub-region, as it takes less than 15 barrels (14.65 barrels) for every 100 barrels produced, during the first years of production. It is followed in this “sell-off” of hydrocarbon resources to the benefit of foreign investors by Benin, Niger and Senegal with a share of 24.38, 26.73 and 30.66 barrels per 100 barrels produced, respectively.

4.6- Some suggestions for maximizing the oil revenues of the States

In view of the above analyses and comments, two parameters of tax regimes can serve as levers to maximize oil revenues in West African countries when they are well controlled and negotiated in oil contracts by government authorities or actors. These are oil costs and the State’s participation.

4.6.1 - Recoverable Petroleum Costs

The recovery scheme for the oil costs invested by the contractor, generally based on a cost stop, long considered as an incentive parameter for the CPI when it is high, is also an element whose lack of control favours the levelling of the oil rent of the States in the sense that it limits the possibility for the States to make better use of their resources during the first years of production. This parameter also influences the distribution key of the oil profit. This is why we suggest that States:

• Adopt an oil cost recovery scheme that does not take into account production but rather a cost amortisation model that can provide a considerable amount of profit to share in oil.

• review the model or margins of very high cost stop proposed in the tax systems of the States. The cost stop is a very difficult element for our States to control and a very high ceiling does not favour the State to have an appreciable oil rent.

• train specialists in oil cost control, auditing and management and rigorously monitor exploration and development and even operating costs.

4.6.2- State participation

The rate of state participation in oil development and production projects is a very important additional means of increasing the profit margin of states in oil contracts. It is also a responsible and sustained way to boost the confidence of foreign investors as well as political stability.

As a result, it is hoped that States will start by investing better in oil projects, particularly in its exploitation phase. The problem of financing by the Liberals through a substantial participation remains a subject of great concern. To this end, we suggest:

• a pooling of efforts between African states to raise funds as shareholders in oil projects

• the creation of the African or Regional Bank for the Financing of Oil Projects, the majority of whose shareholders will be African countries.

  7. Partial conclusion

Comparative analysis of tax regimes shows that in West Africa, there is a clear correlation between tax conditions, geological maturity and perceived risk. Established producing countries, such as Nigeria and Angola, tend to enjoy a larger share of government revenues, while emerging market economies offer more favourable conditions for attracting investment. Tax competitiveness is not static: it evolves with oil prices, technological advances, and global capital flows. Governments must constantly adapt their systems to remain attractive while protecting their national interests.

The global energy transition is beginning to influence the design of tax policies. There is an increasing focus on gas exploitation, emissions management and decommissioning obligations. At the same time, digital technologies are improving tax administration, allowing for better monitoring of production and costs, and reducing the risk of revenue losses.

Overall, tax regimes and contractual frameworks are at the heart of the governance of the oil sector. West African systems have evolved significantly, but challenges remain, including in terms of institutional capacity, transparency and long-term competitiveness. As the global energy landscape continues to evolve, countries will need to adapt their approaches to remain attractive to investors while ensuring sustainable incomes.