Cameroon: Selected Issues
Author: International Monetary Fund. African Dept.
Publication Date:
17 Jul 2014
eISBN:
9781498396011
Language:
English
Keywords:
ISCR; CR; wage bill; public-private partnership; IMF staff estimate; Cameroon; base salary; government share; model PSC; baseline regime; valuation guideline; Brent crude; Oil prices; Oil production; Production sharing
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In recent years, the IMF has released a growing number of reports and other documents covering economic and financial developments and trends in member countries. Each report, prepared by a staff team after discussions with government officials, is published at the option of the member country.

Abstract

In recent years, the IMF has released a growing number of reports and other documents covering economic and financial developments and trends in member countries. Each report, prepared by a staff team after discussions with government officials, is published at the option of the member country.

Fiscal Regime of the Oil Sector

Assumed parameters for the upstream fiscal regime for the oil sector are stylistically modeled and the results show that the government’s take encompasses a large share of project net cash flows compared to other sub-Saharan African oil producers. Nonetheless, the regime could be made more attractive to investors and capture a higher share of rents by enhancing its progressivity.1

A. Introduction and Methodology

1. The purpose of this note is to provide a preliminary account of the upstream oil sector fiscal regime in Cameroon and draw lessons from international good practices in extractive industries. This is done through (i) analyzing the regulatory regime of the oil industry including the oil law, income tax law, model production sharing agreement (PSA), and other relevant regulations; and (ii) providing potential policy reforms to enhance transparency in the oil sector and help the authorities adopt relevant international good practices. The note does not cover Concession Agreements or actual PSAs in Cameroon.

2. The analysis is focused on the upstream section of the oil industry, which generates the highest level of revenues for the government and investors. The upstream section includes exploration, operating oil wells, and extracting oil from the ground. The midstream section deals with transportation and storage. The downstream section covers processing, marketing, and wholesale of the final oil products.

3. The authorities have requested International Monetary Fund’s (IMF) Fiscal Affairs Department (FAD) technical assistance in support of their review of extractive industries’ fiscal regime in Cameroon. That technical assistance will take up many of the issues raised in this SIP and, in the light of new data and analysis (especially those specific to Cameroon), may revise the approaches and issues for consideration raised here.

4. Modeling of the oil sector’s fiscal regime is based on FAD’s Fiscal Analysis of Resource Industries (FARI) model. The model allows a comparative analysis of fiscal regime design and effectiveness. The model requires information on country resources, including oil fields, and concession agreements and production sharing contracts (PSCs) over the lifetime of concerned oil fields. Most of this information is not publicly available in Cameroon and has not been made available for this note. In the absence of access to Cameroon’s PSCs and detailed oil data, assumed fiscal terms and a stylized oil project template, based on actual projects in other sub-Saharan African (SSA) countries, are used. The rest of the inputs for the model were either collected from publicly available information on Cameroon’s fiscal regime or based on IMF staff assumptions. Accordingly, the findings and characterizations in this note should be interpreted with more than usual caution and do not pre-empt the findings of any detailed technical assistance review.

B. Overview of Cameroon’s Oil Sector

Cameroon is SSA’s tenth largest crude oil producer (Figure 1). Exploration efforts have mostly taken place offshore, but in recent years some exploration activities expanded onshore. Most of Cameroon’s oil reserves are located offshore in the Rio del Rey basin, with the rest located in the Douala Basin. Rio del Rey is a mature field covering 7,000 km2 in the Niger Delta that generates close to 90 percent of the national crude oil production. The Douala/Kribi-Campo field covers 19,000 km2 off Cameroon’s western coast, including 7,000 km2 onshore.

Figure 1.
Figure 1.

Production of Crude Oil, 2011-2012

Citation: IMF Staff Country Reports 2014, 213; 10.5089/9781498396011.002.A003

Source: US Energy Information Administration.

5. Cameroon is a mature oil producer. The oil sector is more than 65 years old and the peak of production dates back almost three decades (Figure 2). Exploration began in 1947 and the first commercial discoveries were made in 1972 in the Rio del Rey basin. Annual oil production peaked in 1986 at 63 million barrels (Mbls). In 2013, production totaled about 24 Mbls. Proven reserves declined from a peak of 555 Mbls in 1986 to an estimated 200 Mbls in 2013, primarily because of the exhaustion of mature fields. Some sector analysts’2 forecast proven oil reserves to fall to 160 Mbls by 2021. However, the authorities believe there are good prospects to discover new oil fields both off- and onshore. In addition, technological progress in drilling and extraction techniques has reduced exploration and production costs making it possible for previously unprofitable discoveries to become commercially viable. Against this backdrop, oil production is projected to rise to around 40 Mbls a year by 2019.3

Figure 2.
Figure 2.

Cameroon: Oil Production, Exports, and Proved Reserves, 1980-2012

(Million of barrels)

Citation: IMF Staff Country Reports 2014, 213; 10.5089/9781498396011.002.A003

Sources: International Energy Agency; IMF Staff Estimates.

6. Investment in the oil sector led to changes in production. Figure 3 plots the ratio of investment to production in the oil sector and the change in production. The investment rate peaked at 18.4 percent of production in 1994. Since then, it has monotonously declined. Production broadly followed the same trend with a five-year lag. The growth rate of oil production has been somewhat erratic. However, negative growth rates have dominated since the 1980’s. Once series are stabilized using five-year moving averages, investment is a fairly robust lead indicator of production. Lack of investment in the oil sector in the last decade may have contributed to the sharp decline in oil production and known reserves. Cameroon is estimated to have attracted a negligible proportion of oil sector investments in the Gulf of Guinea over the past decade (less than 2 percent; KPMG 2013).

Figure 3.
Figure 3.

Cameroon: Investment and Production in the Oil Sector, 1984-2012

(Percent)

Citation: IMF Staff Country Reports 2014, 213; 10.5089/9781498396011.002.A003

Source: IMF Staff Estimates.

7. Although oil is a relatively small share of overall economic activity, it plays an important role for exports and government revenues (Figure 4). In 2013, the oil sector represented 3.5 percent of GDP and 52 percent of exports. However, oil revenues decreased to 26 percent of government revenues in 2013 because of rising production costs. Going forward, the significant drop in the contribution of the oil sector to government revenues raises important fiscal concerns.

Figure 4.
Figure 4.

Sub-Saharan Oil Exporting Countries: Oil Real GDP as Share of Total Real GDP

(Percent)

Citation: IMF Staff Country Reports 2014, 213; 10.5089/9781498396011.002.A003

Source: IMF Staff Estimates.

8. The oil sector is dominated by a single public entity. The National Hydrocarbons Corporation (Société Nationale des Hydrocarbons; SNH), a government owned entity founded in 1980, oversees all companies operating in the oil sector and takes an active part in oil production and refined fuel distribution. The state controls 65 percent of oil production. In comparison, in the other SSA oil producers, governments control 53 percent of oil production on average. Only in Nigeria, the prominent SSA oil producer, does the state have a higher level of control (70 percent; Cossé, 2006).

C. Legal and Tax Framework for the Oil Sector

9. The indicators explained below are used to measure success in government fiscal efficiency in the oil sector.

  • Average effective tax rate (AETR), commonly known as the “government’s take” or the share of government oil rents, is the average tax rate that the firm pays on its investment; it is calculated as the ratio of the net present value (NPV) of tax payments to the NPV of the pre-tax net cash flow of the project.

  • Marginal effective tax rate (METR) is a measure of the tax wedge between pre-tax and after tax rates of return at the margin, where the return on the last dollar invested just covers its cost of capital. This indicator shows the deviation between an optimum level of investment in the extraction of oil, and the forthcoming investment given the fiscal regime in place. The size of this tax wedge depends on a series of factors, such as the rate of profit tax, tax treatment of the financing of the firm, and depreciation provisions.

  • Hurdle or breakeven price is the price for which the investment would be viable from the investor’s perspective, or a breakeven price given a required rate of return and the tax regime. This indicator is an alternative to the METR.

  • Time profile of revenues shows the distribution of revenues over the project’s lifetime. Different fiscal regimes will result in different time profiles of government revenues. For example, royalties ensure some government revenues from the start of production, whereas a resource rent tax, based on the rate of return, will generate tax revenues after the project reaches a threshold rate of return.

  • Variance of the NPV shows how the NPV of the project changes under different circumstances and it is an indicator of government revenues from a given project.

  • Expected monetary value (EMV) is the NPV of the expected revenues from a project, taking into account the probability of successful resource discovery and the sunk costs in the case of failure. Variations in EMV levels can be used as an indicator of the risk preference of the investor.

  • Payback period of a project is the time required for the investor to recoup all the invested capital. The investor uses it to decide whether to undertake a project or not. It is used as a proxy to estimate investor’s risk preference.

  • Government share of total benefits is the ratio between overall government revenues from the project and net project revenues excluding initial capital investments. This indicator, when used in conjunction with the rate of return of the project, reflects the progressivity of an oil fiscal regime, i.e., the regime’s ability to capture increases in project profitability.

A discussion on the principles and design of oil fiscal regimes is presented in Box 1.

Principles and Design of Oil Fiscal Regimes

The key objectives of an oil fiscal regime include: neutrality, revenue raising capacity, government risk, investor risk, adaptability, and progressivity (Daniel et al., 2010, IMF 2012).

Neutrality: a neutral regulatory framework is one that does not generate, or at least minimizes, distortions in economic decisions that operators would make in the absence of regulation.

Revenue raising capacity: in an oil-rich country, a large share of government revenues comes from the taxation of the oil industry. One of the key goals of oil regulation is therefore to contribute toward maximizing government revenues on a sustainable basis.

Government risk preference: the ability and willingness of the government to take on fiscal risk in the context of an oil project typically is a function of the country’s income level, the ability of the government to access capital markets, the size and the diversity of the portfolio of current and future oil projects, and the relative size of individual projects

Investor risk preference: the perception of risk by oil operators is typically a function of the political risk associated with the host-country and of the neutrality and revenue raising capacity of the regulatory framework. A framework that has fiscal stability clauses is more attractive to investors and also ensures more sustainable government revenues, all else being equal.

Adaptability and progressivity: a fiscal regime is adaptable if it is able to respond to changes in industry standards and the economics of individual projects, such as production levels, cost structure, prices, and internal rate of return. Although it is better to incorporate the backbone of the regulatory framework in the legislation, typically an oil code, some elements may be left to negotiation to increase competition within the industry and to allow the government to maximize its share of economic rents. Biddable fiscal elements could include bonuses, tiers in the case of production sharing contracts, or profit tax rates in the case of concession agreements. A fiscal regime is progressive if the government captures a higher portion of profits when projects become more profitable, including when the sale price of oil increases or extraction costs decrease.

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D. Cameroon’s Oil Fiscal Regime

10. The legal and fiscal framework for the upstream oil sector is governed by a comprehensive set of legislation. These include the General Tax Code; the Oil Law of 1999; the Oil Law Application Decree 2000/465; concession agreements (CAs); and PSCs. A CA gives the oil company the exclusive right to the resource and to explore, develop, produce, and market oil at its own risk and expense. In exchange for the concession, the contractor is obligated to pay the appropriate royalties and taxes (Figure 5). Under a PSC, the government retains the ownership right to oil resources in the ground. The agreement between the government and the oil company stipulates that the latter bears all costs of exploration and development in exchange for a share of production, but gives the oil company the right to explore, develop, and produce oil, which is equivalent to owning a share of the reserves (Figure 6). Therefore, PSC rights can be viewed as similar to concession rights. With the right fiscal tools, both CAs and PSCs can yield similar streams of government revenues.

Figure 5.
Figure 5.

Concession Agreement Example

Citation: IMF Staff Country Reports 2014, 213; 10.5089/9781498396011.002.A003

Source: IMF Staff Estimates.
Figure 6.
Figure 6.

Production Sharing Contract Example

Citation: IMF Staff Country Reports 2014, 213; 10.5089/9781498396011.002.A003

Source: IMF Staff Estimates.

11. The authorities have negotiated advantageous oil contracts over the years (Omgba, 2011). The main fiscal instruments applicable to the Cameroonian oil industry include: royalty; corporate income tax; cost recovery provisions; economic rent capture mechanisms; and duties.

12. The following fiscal elements play an important role in the production sharing fiscal regime as represented by the Model PSA.4

  • Bonuses. The model PSC requires oil companies to pay signature and production bonuses. The signature bonus is payable at the signing of the PSC, whereas production bonuses are determined on the basis of total production levels. Bonuses are not considered recoverable costs. They are common practice in PSCs and thus they need no revision.

  • Production royalties. CA holders are liable for production royalties, which are payable monthly either in nature or in kind. The specific rate and base for the production royalty are subject to negotiation and specified in the CA. (CAs are not further discussed in this note.)Royalties ensure an immediate stream of revenues for the government, once production starts. It is important to specify clear guidelines for the calculation of the royalty “tax base.” Data provided by the authorities show, in some instances, a royalty flow from the SNH to the oil company.5 It is unclear from the legislation what the underlining methodology for this flow is. Conversely, the model PSC does not include a royalty on oil production. In Cameroon, royalties are not necessary in PSCs because the cost recovery limit, coupled with a minimum production share, ensures an immediate stream of revenues for the government when production starts (see below).

  • Surface fees. All oil contractors are required to pay an annual surface fee specified in their CA or PSC. Surface fees are levied on the surface of the contract area. The model PSC specifies different rates for the first three years of the project and the later years. Revenues from surface fees contribute minimally to government revenues once oil production starts.

  • Cost recovery. This element is specific to PSCs. Oil companies holding a PSC bear all the financial and exploration risks, while the government holds the rights to the oil resource. Therefore, to compensate the oil company for the risks, part of the oil revenues may be used by the company to recover its operational and capital costs—this is often referred to as “cost oil.” The remainder of oil revenues, known as “profit oil,” is shared between the oil company and the government through terms defined in the PSC. The limit on cost recovery and the government’s minimum production share ensure some revenues for the government from production start. As per standard practice, PSC holders are entitled to cost recovery in any accounting period, expressed as a percentage of total production. The terms and limit for cost recovery are negotiated in the PSC and vary from contract to contract. Terms of reference for several licensing biddings, through which the government issues new oil exploration licenses (CAs or PSCs), specify a maximum cost recovery of 60 percent.6

  • Profit oil. According to the model PSA, profit oil is shared between the oil company and the government using either the daily rate of production (DROP) or the R-factor as benchmarks. The DROP system determines the government share of profit oil based on the average daily rate of production for the latest quarter. The R-factor is calculated as the ratio of net accumulated revenues over accumulated investment and it is used as a benchmark to determine government’s share of profit oil. The different tiers of the DROP rates or the R-factor benchmarks and the respective government share of profit oil are established in PSAs.

  • Corporate income tax. Oil contractors pay CIT based on a rate varying from 35 to 50 percent, as determined in the CA or PSC. Although CITs are standard practice, it is important that all legislation and technical rules on CITs be consistent across different legislations.

  • Ring-fencing. When a project is treated in isolation for tax purposes, it is considered “ring-fenced.” This imposes limitations on income consolidation and deductions for tax purposes across different projects undertaken by the same contractor. Ring-fencing prevents the erosion of the tax base. In Cameroon, there may be an inconsistency on multiple oil project taxation. The General Tax Code allows consolidation of businesses for the same tax payer, while the Oil Law explicitly foresees project ring-fencing.

  • Depreciation for income tax. The General Tax Code gives priority to the straight line method, and states rates for specific assets varying from 5 to 33 percent. However, there is flexibility for oil contracts to provide project-specific depreciation terms.

  • Carry forward of losses. In general, losses may be carried forward for up to four years following the year in which the loss is incurred. However, the PSC may provide different terms on the carry forward of losses.

  • Special tax on revenues. Payments from companies operating in Cameroon to nonresidents are subject to a 15 percent special tax, except when there is a treaty of no double-taxation between Cameroon and the company’s home country. The oil sector is exempted from this tax during the exploration and the development phases. This tax has the features of a services withholding tax, which is common practice in the industry. This implicitly assumes a 37.5 percent profit margin.7 Given the large amounts spent on drilling services, this withholding tax rate may be a disincentive to oil exploration in Cameroon.

  • Decommissioning. Virtually all oil fiscal regimes require contractors to decommission oil fields at the end of their production life and to restore the production site in a manner consistent with good environmental practice. Both the Oil Law and the model PSC give consideration to decommissioning. The model PSC requires the oil company to start a decommissioning fund, and depositing annual payments in an escrow account, within the first six months of the start of production. This is at par with international good practices.

  • Tax exemptions and incentives. The oil sector is exempted from value-added tax (VAT), import duties, and dividend withholding taxes. According to the Oil Law, two pieces of legislation, Law 91/018 of December 12, 1991 and Law 95/19 of August 8, 1995, have specific incentive measures and provisions for the promotion of oil exploration and production. These exemptions vary considerably from country to country.

  • State participation. According to the model PSC, the government participates in oil joint ventures through the SNH. It is unclear from the available legislation and regulations whether the state participates in a joint venture in the case of a CA. Although the model PSC specifies a minimum 5 percent government participation, several licensing biddings have established this share at 25 percent. State participation takes the form of paid equity and it starts from the development phase of the project. All costs associated with SNH’s share are paid to the partners in the joint venture when SNH decides to exercise its rights of participation. An equity participation of about 10–15 percent by the government should not deter investors. However, there are potential financing implications for the government, as SNH will be responsible for funding its share of development costs, which may be sizable and required to be met before any revenue is received from a project.

E. Fiscal Regime Modeling

13. Cameroon’s upstream oil fiscal regime is modeled using a stylized project that reflects production and cost profiles similar to other fields in the region. A stylized 450 million barrels (Mbl) oil project and several oil production scenarios were evaluated using the FARI model. The project examples were initially generated from the IHS Que$tor8 tool, which enables detailed production, capital, development, and operating cost estimations for new oil and gas projects in most oil basins worldwide. The Que$tor estimates are then compared and modified in line with other data sources, providing estimates of expected oil development costs in peer SSA countries.

14. The modeling includes a number of important assumptions: no international tax issues, such as tax evasion by multinational contractors; perfect tax collection mechanism and full and timely tax payments; and all foreign-sourced debt. To simplify the calculations of withholding taxes, the model assumes that oil companies procure their debt financing in the international financial markets rather than in the domestic banking market. Owing to lack of information, Cameroon’s baseline regime includes assumptions on production sharing tiers; DROPT tiers; “R-factor” (the ratio of project revenues and project costs) tiers; and royalty rates. Fiscal parameters used in the model are presented in Appendix 1.

15. The FARI model shows that Cameroon’s take, under the assumed parameters described in Appendix 1, represents a large share of project net cash flows compared to other SSA oil producers. The AETR is used to compare the baseline oil fiscal regimes to other international oil regimes. In calculating the AETR, government revenues and pre-tax net cash flows are discounted at 10 percent. Two PSC examples are evaluated. The first example defines the production sharing tiers based on the R-factor. The second example defines the production sharing tier, based on the average daily rate of production (DROP). The model yields an AETR of 82 percent for the R-factor approach and 80 percent for the DROP approach, capturing a share at the top of the range of peers (Figure 7; the figure also shows results for a 0 percent discount rate) Figure 8 illustrates the breakdown of government revenues in a stylized PSC.

Figure 7.
Figure 7.

AETR far Selected Regimes AETR Discount Rate 10%

Citation: IMF Staff Country Reports 2014, 213; 10.5089/9781498396011.002.A003

Source: IMF Staff Estimates.
Figure 8.
Figure 8.

Breakdown of Government Revenu es in Example PSC

Citation: IMF Staff Country Reports 2014, 213; 10.5089/9781498396011.002.A003

Source: IMF Staff Estimates.

16. A fiscal regime that uses the R-factor responds better to fluctuations in oil prices and project costs than a regime using the DROP. Scenario analysis of government revenues shows that the R-factor regime captures a higher share of revenues as oil prices increase and as project costs decrease (Figure 9). The share of project benefits is used as a proxy for government revenues. The higher the slope of the government share, the higher the increase in government revenues. Sensitivity of government revenues to oil prices is measured by evaluating the government share of project total benefits to oil prices ranging from US$50/bl to US$220/bl. The cost sensitivity is carried out for project costs varying from US$2/bl to US$24/bl. Using the R-factor to determine production sharing makes the regime more progressive, i.e., it captures a higher share of net cash flows when oil prices increase.

Figure 9.
Figure 9.

Cameroon: Comparative Analysis - Price and Cost Sensitivity

Citation: IMF Staff Country Reports 2014, 213; 10.5089/9781498396011.002.A003

Source: IMF Staff estimates

F. Issues for Consideration

17. The assumed Cameroonian oil fiscal regime could be improved through the following:

Fiscal Regime

  • The corporate income tax rate for the oil sector should not be negotiable.

  • Consider with planned technical assistance including a separate section in the General Tax Code on all tax features of the oil industry and ensure consistency of the Oil Law with them.

  • Set depreciation rules in legislation.

The Role of the State

  • The role of SNH. SNH has a double mandate, serving as both an industry regulator on behalf of the state and as the national oil company (NOC). Although the motivations for this double role are understandable, international experience suggests that too often, NOCs fail to meet expectations. In the case of Nigeria, for instance, the government’s concern to exercise direct political control resulted in the NOC having no governing board of any kind for ten years. Another example of the state failing to keep a transparent and efficient NOC is Venezuela (IMF, 2003). The government replaced a highly professional board and management team at Venezuela’s NOC with a handpicked political team. Until recently, a similar situation prevailed in Mexico, where the government used taxes to capture a very high proportion of NOC’s net income. This leads to continuous budget negotiations with the ministry of finance, often under non-transparent circumstances. Box 2 lists successful reform initiatives undertaken by NOCs in several countries. In Cameroon, the government should ensure that the SNH regulator and commercial roles are separated and clear and separate institutional responsibilities are assigned accordingly. The SNH should become a strictly commercial company. In addition, all government fiscal revenues, with the exception of payments to the SNH for its participation in joint ventures, should be transferred directly to the budget.

  • Fiscal transparency. According to the model PSC, when the SNH participates in a joint oil venture, it is proportionally liable for CIT payments. However, the SNH’s reporting of its income tax payments does not break down these by project and it is not possible to distinguish CIT stemming from oil operations from other type of CIT owed by the SNH to the state. Moreover, projects are ring-fenced, which implies separate accounting and financial reporting for tax purposes. Improvement of the reporting of CIT payments by the SNH is a good candidate for improving fiscal transparency in the oil sector in Cameroon.

Selected National Oil Company Reforms

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Sources: Charles McPherson et al. 2003 and 2012.

18. Cameroon’s valuation guidelines for crude oil pricing provide appropriate protection against abuse. Valuation is the process by which tax authorities determine in advance what prices companies must use for valuing their oil production for computing their taxes. This advance pricing procedure is adopted because of transfer pricing risks prevalent in extractive industries. Abusive transfer pricing involves the under-pricing (in the case of sales) or overpricing (in the case of purchases) of transactions to lower taxable profits or sharable production. With respect to possible over-pricing of purchases, the model PSC requires procurement on an arm’s-length basis, a transaction in which both the buyer and seller act independently and in their best interests. According to the guidelines specified in Decree 2000/465, the authorities use the five-month average Brent oil market prices as benchmark for oil valuation for fiscal purposes. In addition, they subtract/add a discount/premium amount that accounts for the quality of oil and transportation costs in Cameroon. This methodology ensures that the oil prices used for valuation purposes in Cameroon follow international market prices and protect the government from under-pricing. However, the magnitude of the discount factor may impact the final oil price used in valuation. According to information provided by the authorities, the discount/premium is subject to negotiation between the government and the oil companies. Historically, the government has secured favorable average oil prices on its crude oil sales through SNH, as shown in Figure 10. Despite the mixed quality of Cameroon’s crude oil, sale prices have closely followed the trend in Brent crude oil prices and the discount factor is minimal.

Figure 10.
Figure 10.

Quarterly Average Oil Prices, 2004-2013

(USD per Barrel)

Citation: IMF Staff Country Reports 2014, 213; 10.5089/9781498396011.002.A003

Source: Société Nationale des Hydrocarbons (SNH).

19. Despite improvements since 2005, fiscal transparency remains an area for improvement (Akitoby et al. 2012). By law, the Minister of Finance may request external audits of public enterprises. In the case of the SNH, auditors from a local audit office carry out annual audits, the results of which are published in SNH’s annual reports and on its website. The government’s Audit Office also undertook an audit of the SNH. However, tax issues in the oil industry are complex and need thorough knowledge of the industry structure and auditing practices. It is not clear whether local audits follow Generally Accepted Accounting Principles. The SNH is not subject to external audits by an internationally reputable auditing firm (IMF, 2010). The only independent exercise to reconcile the financial flows related to oil revenue was conducted by the Extractive Industries Transparency Initiative’s Committee. For 2011 that exercise found only minor discrepancies (EITI, 2013). Another important element of fiscal transparency relates to the secrecy surrounding oil contracts. The government should consider requesting annual audits of the SNH’s accounts by international reputable auditing firms. In accordance with EITI recommendations on next steps, EITI new requirements,9 and the IMF Guide on Resource Revenue Transparency, 10 the government should consider making PSCs and CAs available to the general public, following the example of Liberia which has published all its mining and oil contracts on the EITI website.

Appendix I.

Appendix Figure 1.
Appendix Figure 1.

Stylized Oil Project Data

Citation: IMF Staff Country Reports 2014, 213; 10.5089/9781498396011.002.A003

Source: IMF staff estimates.
Appendix Table 1.

Cameroon: Assumptions for the Benchmark Fiscal Oil Regime

(Concluded)

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Appendix Table 2.

Example 450 Million Barrel Baseline Project

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Source: IMF staff estimates.

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1

Prepared by Jean-Philippe Stijns (formerly IMF) and Ejona Fuli.

3

Although not confirmed, the offshore Kribi/Campo oilfield is expected by some market analysts to bring crude oil production potentially back to 100 thousand barrels a day.

4

The model PSC was provided by the Cameroonian authorities.

5

Prior to 1999, the rules for corporate income tax (CIT) were different. The state guaranteed a 13 percent minimum rent (“rente minière nette garantie”) for the oil companies. When the rent was below the 13 percent threshold, the state paid an adjustment to the company to reach the threshold level.

6

Published on the SNH’s website: www.snh.cm.

7

Assuming a corporate income tax rate of 40 percent, for the special tax on revenues to yield the desired rate of 15 percent = 40 percent (CIT)* 37.5 percent (profit margin).

8

QUE$TOR is a project modeling and evaluation system for global application in the oil and gas industry. For more information, see: www.ihs.com.

9

Requirement 2.13 refers to publication of oil contracts. For a detailed list of the new requirements, see: EITI New Requirements 2013.

10

The case for publication of contracts is addressed in detail in the “IMF, Guide on Resource Revenue Transparency,” 2007.

Other IMF Content

Other Publishers

Cover IMF Staff Country Reports
Cameroon: Selected Issues
Author: International Monetary Fund. African Dept.
Volume/Issue:
Volume 2014: Issue 213
Publisher:
International Monetary Fund
ISBN:
9781498396011
ISSN:
1934-7685
Pages:
91
DOI:
https://doi.org/10.5089/9781498396011.002

Production of Crude Oil, 2011-2012

Cameroon: Oil Production, Exports, and Proved Reserves, 1980-2012

(Million of barrels)

Cameroon: Investment and Production in the Oil Sector, 1984-2012

(Percent)

Sub-Saharan Oil Exporting Countries: Oil Real GDP as Share of Total Real GDP

(Percent)

Concession Agreement Example

Production Sharing Contract Example

AETR far Selected Regimes AETR Discount Rate 10%

Breakdown of Government Revenu es in Example PSC

Cameroon: Comparative Analysis - Price and Cost Sensitivity

Quarterly Average Oil Prices, 2004-2013

(USD per Barrel)

Stylized Oil Project Data