Comparative Tax Regimes in Oil Industries Operating in Selected Developing Countries Keith Dublin Abstract The operations of international oil companies operating in developing countries have a disproportionate impact on the finances of these countries as a result of the contributions made to these countries in terms of taxes and other payments in return for the right to extract and sell hydrocarbon resources. Given that these hydrocarbon resources are non-replaceable, once extracted, the governments and public in many host countries are concerned that the revenuereceipts from the sale of their hydrocarbon resources accruing to national governments are maximized since they are likely to constitute the single most important engine of growth in the foreseeable future. Recognizing that oil-production contracts signed between countries and international oil companies vary from country-to-country, this note provides a review of the variety of these arrangements in use, paying special attention to the tax regimes that they incorporate. Based on available information, the literature indicates that that there is no substantial difference between the different oil-production arrangements as revenue sources for national governments. This review of the different tax regimes implied by the contractual arrangements is followed by a description of the national tax arrangements applicable to the international oil companies that are in effect in a group of selected countries which include: Guyana, Suriname, Colombia, Trinidad and Tobago, Venezuela, Ghana, Kenya, and Angola.
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Comparative Tax Regimes in Oil Industries Operating in Selected Developing Countries 1. INTRODUCTION
The fiscal system that applies to the extractive industries, such as the international oil companies (IOCs), should ensure that the governments of the host countries obtain an adequate share of the benefits from their resources, taking into account that the resources extracted are assets owned by nationals of the host countries and, once extracted, are not replaceable. At the same time, to attract IOC investments, the fiscal regimes need to ensure that they provide a return to the investors commensurate with the risks. Governments, therefore, have to balance creating a supportive environment for large investments against the countries’ need for dependable revenue streams that are necessary for sustainable development projects. The IOCs are unique in many ways: they are typically characterized by high sunk-costs in the form of substantial investments that cannot be recouped if a project is unsuccessful; long lead times from initial investment to project start-up; volatile demand; fluctuating costs and oil prices on the world market that in turn influence the profitability of exploration, development and extraction; and often hostile physical environments. From the perspective of the host governments, the information and knowledge needed by governments to design and administer appropriate tax rules and regulations that apply to the IOCs may not be widely available. In designing an overall taxation regime and developing an appropriate administrative structure, each country must carefully determine not only its priorities and consider the array of choices available to it, but also be cognizant of competitive offers from other countries producing hydrocarbons. Moreover, it is essential that governments gain the trust and support of the public at large for the development of the oil industry, given the financial impact of the growth of this industry on the economy in general. To this end, public access to contracts signed between IOCs and national governments and their agencies is an important element of building trust and support for the development of an oil industry. Public support and trust can be enhanced if the public can be assured of full transparency. To promote greater transparency, many governments now require the publication of contracts signed with IOCs. In a number of instances this is being done using the standards of the Extractive Industry Transparency Initiative (EITI) as a universally acceptable frame of reference. This initiative was founded with the recognition that, while the extraction of oil, gas and other minerals can help to raise living standards in countries where these resources are located, if these resources are not managed appropriately, the extraction of the national resources may often lead to corruption, conflicts, and few benefits for residents of the host countries. Efforts to enhance transparency in the context of the EITI were formalized at a conference held in London in June 2003, where the following reporting requirements were agreed: (i) all investors doing business in other countries should report all payments made to governments or their agencies; (ii) governments of host countries should publicly report on the payments as having been received; and (iii) an independent audit and reconciliation should be done. Since that time, the Extractive
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Industries Transparency Initiative has evolved into a global coalition of government agencies, extractive entities and civil-society organizations working together to improve openness and accountable management of revenues from natural resources. Oil production arrangements between international oil companies and the host countries vary across the world. This note provides an overview of the oil production arrangements that exist in different countries, focusing on the tax regimes that underpin these arrangements. A description of the more frequently employed oil-production arrangements and their respective advantages is described in Section II. Section III describes the national oil-production agreements in effect in selected countries as well as the associated tax regimes. This group of countries includes Guyana, Suriname, Colombia, Trinidad and Tobago, Venezuela, Ghana, Kenya, and Angola.
II. OIL PRODUCTION ARRANGEMENTS
Petroleum contractual systems that establish fiscal regimes around the world have for many years been classified into two main categories: (i) concessions and licenses, involving royalty/tax systems, and; (ii) production sharing contracts. From a financial perspective, the similarities between these two categories easily outweigh the differences between them. The similarity of outcomes that result from the two systems means that countries in which oil reserves are located can achieve the same objectives under either system. Concessions or Licenses Involving Royalty/Tax Systems A Concession (or License) is a contractual agreement between a government or government agency in a particular country and an IOC or consortium granting the IOC or consortium the exclusive right to explore for and extract hydrocarbons within a specific area for a given timeperiod. In exchange for these rights, the IOC pays a license fee to the host government. In addition, the host government’s compensation will typically also include royalty and a variety of tax payments if hydrocarbons are produced. The typical feature of a concession granted to an oil or gas-company is that the oil company pays royalties and corporate income tax to the host government, in addition to the license fees. Nearly half of the countries worldwide use a concessionary (royalty/tax) system. After royalty payments made to the host government, the IOC is allowed to “recover costs” or take tax deductions. These costs consist of two components: capital costs and operating costs. Usually this aspect of a petroleum agreement will undergo scrutiny by government auditors to ensure that only legitimate costs are included. Almost all systems have specific costs that will not be allowed for cost recovery or as deductions. Production Sharing Contracts Production sharing contracts or agreements (PSCs or PSAs) give a contractor, an IOC, or consortium of companies the right to explore for and produce hydrocarbons within the contract area or block for a specified time-period. The IOC assumes all exploration risks and costs in exchange for a share of the oil and/or gas produced. Under this system, as with a license, if the
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IOC’s exploration efforts do not yield a commercial discovery, the IOC is not reimbursed by the host government. However, in the event of commercial discovery, production is split between the parties according to agreed formulas as specified in the PSCs. Unlike a license, however, the host government typically receives a large share of oil and/or gas, the monetary value of which would represent the equivalent of tax payments by the IOC. In principle, the government retains and disposes of its share of petroleum extracted, although joint-marketing arrangements may be made with the contractor. Such agreements were introduced in Indonesia in the mid-1960s, and for many years became the fiscal system-of-choice for many countries. They are now also used in many developing countries including Guyana, Malaysia, India, Nigeria, Angola, Trinidad and Tobago, and the Central Asian Republics of the Former Soviet Union. At present, slightly over half of the governments with hydrocarbon production worldwide use PSCs. Very often a PSC/PSA requires other payments to the host government, such as royalties, corporate income tax, and windfall profit taxes. Service contracts
Service contracts are an alternative form of contractual arrangement between a host government and an IOC which sets out the terms governing the exploration and production of oil and gas by the IOC. In this type of arrangement, the host government does not hand over control of the extracted hydrocarbons or sub-soil resources to the IOCs, but the IOCs explore and produce oil and gas in return for predetermined fees. Under a service or risk service contract, the fee which the IOC receives can be in cash or in kind, and it is the only payment received by the IOC since the company finances and carries out petroleum projects at its own expense. The fees typically permit the recovery of all or part of the oil and gas company’s costs. Service contracts are less frequently used by host countries than other types of contractual arrangements. These contracts which were originally used in South East Asia during the 1960s and 1970s were later modified to include elements of concessions or PSCs/PSAs. The Choice between Concessions (involving Tax/Royalty Schemes) and Production Sharing Contracts From the point of view of potential revenue yields, there is no substantive difference between a tax/royalty regime and a PSC regime since the fiscal terms of a tax/royalty regime can be replicated in a PSC regime, and vice versa. Observed differences in fiscal patterns across countries are usually explained by differences in negotiating abilities and strategies pursued by national governments, on one hand, and IOCs, on the other. There are some noteworthy differences, however. Tax/Royalty systems have some advantages over other types of taxation. Royalties ensure that IOCs make a minimum payment for the minerals they extract. Royalties are typically either specific levies (based on the volume of oil extracted) or ad valorem levies (based on the value of the oil extracted). However since royalties raise the marginal cost of extracting oil, they can deter investors if imposed at too high a level, and they discourage development of any marginal reserves that have been discovered. In the case of concessions, in addition to royalties, there are often concession fees that accrue to the host
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government. An added advantage of using concessions is that they often involve the submission of competitive bids by the IOCs for rights to extract oil from a specific block. With income taxes that generally apply to PSCs, the usual practice is for the profit tax rate for oil companies to be higher than the general rate for other companies. This ensures that a significant share of the resource-rents from the project is captured by the national governments. To a certain extent the share of resources accruing to national governments is impacted in many countries by the practice of allowing exploration and project costs to be recovered immediately, and incentives are also provided by allowing accelerated recovery of development costs over a truncated number of years. In addition, few questions are generally raised about the eligibility of a wide range of costs. This practice applies to both concessions and PSCs/PSAs.
III. NATIONAL PRODUCTION & TAX ARRANGEMENTS 1 Guyana ExxonMobil signed an agreement with Guyana in 1999 to explore offshore for recoverable oil reserves. Exxon, which is in a joint venture with Hess and the China National Offshore Oil Corporation (CNOOC), initiated oil and gas exploration activities in 2008 in the Stabroek block and made its first discovery in May 2015. Following additional discoveries across a number of blocks, gross recoverable reserves are now estimated to be in excess of 9 billion barrels of oil. Guyana joined the ranks of oil-producing nations at the end of December 2019, after Exxon and its partners began oil production and shipments. The fiscal regime for upstream petroleum (exploration and production) is set out in the production sharing agreements (PSA). The agreements provide for a modest explicit royalty, which can be paid directly by the contractor or included in the government’s share of profit oil. At present, the royalty rate is set at 2 percent on an ad valorem basis. A portion of production (after royalty) can be retained by the consortium to recover extraction costs. This is referred to as “cost oil.” The fiscal package specifies a maximum cost recovery ceiling of 75 percent of the value of crude oil sold from the contract area. The petroleum remaining after royalty and cost oil, is considered “profit oil” and is divided equally between the government and the consortium. The implication is that the government`s share of “profit oil” is fixed at a rate of 50 percent. It should be noted that the contractor’s corporate income tax liability in Guyana is paid out of the government share of profit oil. The fiscal tax framework in Guyana applicable to the oil consortium extracting oil can be summarized as follows: (i) a maximum cost recovery ceiling of 75 percent of the value of crude oil and natural gas produced and sold; (ii) a maximum government share of “profit oil” of 50 percent on a per field basis, and (iii) an ad valorem royalty of 2 percent.
The sources for these arrangements are the EY “Global Oil and Gas Tax Guides 2019” and the PWC “Oil and Gas Tax Guide for Africa 2017.” 1
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Issues •
According to the PSA, interest expenses payable on any capital employed in acquiring income are permitted to be recovered. This treatment of interest expense appears to be generous and is susceptible to abuse since the use of debt can have a detrimental impact on the amount of profit oil to be shared between the government and the IOC.
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A fixed government share of profit oil is uncommon in modern PSAs. The main disadvantage of this type of sharing mechanism is that it does not allocate an increasing share of profit oil to the government linked to the profitability of projects. Most PSAs around the world usually have a formula in which the government’s share increases as a function of production or a combination of production and oil prices.
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Based on the agreement between the Guyana government and the consortium, the IOC’s corporate tax liability is paid out of the government share of oil profit. In other words, the government share of profit oil/gas is inclusive of the Company Income Tax (CIT) and, therefore, the contractor does not have to make separate corporate income tax payments. This practice is at variance with the system that exists in many other oil-producing countries.
The last available Extractive Industry Transparency Initiative (EITI) report covers the financial year ending in December 2017. It therefore does not include information on the contribution of the consortium of oil companies to the public finances of Guyana, given that oil production and shipments began in December 2019. However, according to reports prepared by the Natural Resources Ministry, the balance in the Natural Resources Fund at mid-March 2021 stood at US $267.6 million which is equivalent to the totality of government receipts, inclusive of royalties, after five lifts of oil. Suriname Oil was first discovered in Suriname in 1928 on the coastal plain, close to the border with Guyana, but systematic exploration both onshore and offshore only started in the 1960s when various international oil companies (IOCs) became interested in Suriname’s oil reserves. Recent estimates put Suriname’s oil reserves at between three billion and four billion barrels. The oil sector has been dominated since 1980 by Staatsolie, a public limited company, which has combined its original role of ‘agent of the State’ , responsible for assessing and managing the sector, with the role of the country’s sole oil producer, extracting crude from three onshore oilfields. At the present time, Staatsolie holds all mining rights to hydrocarbons, and private oil companies wanting to do business in Suriname can participate in the Suriname oil industry by signing a production sharing contract with Staatsolie. In this arrangement, the oil company explores at its sole risk and on its account. If a commercial discovery is made and hydrocarbons are produced, the contractor gets reimbursed for its investment (cost oil) and also gets a share of
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the profit oil. Exxon Mobil, Royal Dutch Shell, Total, Apache and several other companies are gearing up for operations off Suriname’s coast, having signed PSCs with Staatsolie. A PSC is only awarded after an IOC or consortium wins a successful competitive bid. Under this arrangement, the IOC is awarded a 60 % equity stake in the venture, while Staatsolie retains an interest of 40 %. In terms of the proceeds from the oil-production arrangements that accrue to the Government, Suriname levies an income-tax rate on companies at a flat rate of 36 percent of profits, and royalties of 6.25 percent of the value of gross production. In determining profits, recoverable oil costs are limited to 80% of the value of production. In addition to the profit taxes and royalties levied by the government, Staatsolie benefits from the proceeds of the payments made in the bidding process for exploration rights and the dividends paid to the government for their equity stake. According to the second EITI report which covers the calendar year 2017, the revenue streams from the oil sector to the government—direct and indirect taxes and dividends—have been considerable. The oil sector’s important contributions to Suriname’s public finances—totaling US$2.15 billion in 2004–2015—have been significant, though they fluctuate over time. These contributions are influenced by international oil prices, volume of oil produced, exchange rate, and Staatsolie’s profits. Colombia The fiscal regime in Colombia is complex. The oil and gas contract model was changed from a system of production sharing contracts (PSCs) in 2003 to a system of exploration and production (E&P) contracts. This is a type of contract similar to a concession contract (royalty and tax system) which an IOC is required to sign with the National Hydrocarbon Agency (ANH) which represents the interests of the Government. In Colombia, ownership of minerals found beneath the surface, including oil and gas, is vested in the national Government and standard contracts require the contractor to make payments to the ANH for the right to explore Colombia’s subsoil assets. These amounts are payable in US dollars per hectare, depending on the location and area of the block and the duration of the phase. As is standard in these arrangements, the contractor (IOC) autonomously explores and produces at its own risk and cost. The fiscal regime that applies to the oil industry consists of a combination of corporate income tax (CIT) and royalty-based taxation, combined with concession fees. Companies engaged in the exploration and extraction of nonrenewable resources (i.e., oil and gas) must pay the ANH a royalty, in addition to concession fees, determined by the Ministry of Mining. The royalties to be paid are based on volumes produced as follows:
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Royalties New oil discoveries (Monthly average in barrels of crude per day) Up to 5,000 5,001 to 125,000 125,001 to 400,000 400,001 to 600,000 More than 600,000
Royalty Percentage 8% 8%+ ([production — 5,000] × 0.10) 20% 20% + ([production — 400,000] × 0.025) 25%
The CIT rate was 32% for 2020, but will decline to 31% for 2021 and 30% for 2022 and the period beyond. Costs and expenses may generally be deducted from income subject to the CIT, provided that they are necessary and related to the generation of taxable income. In addition, a production levy may be payable in cash or in kind that is linked to international prices for hydrocarbons. The rates vary depending on the quality of produced hydrocarbons and the projects’ logistics. Historically, the general assessment of the natural resource sector in Colombia is that it carried a moderate to high corruption risk for companies. In particular, there have been reports of corruption in the granting of mining rights and monopoly rights. Since joining the EITI in 2014, Colombia has published five EITI Reports covering fiscal years 2013 to 2018 and it has been recognized as the first country in the Americas to reach the highest level of progress in implementing the EITI standards. This determination is supported by the publication of specific EITI information which shed light on revenue distribution to regions and focused on challenges in environmental regulations. Recent reports noted that the country has surpassed the requirements of the EITI Standard on aspects such as disclosure of data on extractives contracts, revenue management and expenditures, economic contribution of the extractive sector, and subnational transfers of extractives revenues. Trinidad and Tobago Trinidad and Tobago, traditionally a major gas producer, is now experiencing declining oil production and low energy prices. Average daily oil production had declined by 2016 to some 71,500 barrels per day from around 143,500 in 2006. Gas production, on the other hand, has increased over a period of 25 years to a peak of 4.3 billion standard cubic feet (scf) of gas per day in 2010, before plateauing, and then declining to 3.3 billion scf per day in 2016. An entity engaged in the business of exploring for petroleum in Trinidad and Tobago, on land or offshore, must do so either under an exploration and production license or a production sharing contract (PSC). As a result, two distinct fiscal systems operate for petroleum producers. Under the Exploration & Production (E&P) system, the major fiscal regime applicable to the petroleum sector is royalties, a petroleum profits tax (PPT) and a supplementary petroleum tax (SPT) at rates based on the weighted average crude oil price. IOCs are also liable to a Petroleum production levy (PPL) which affects those contractors whose average daily production is in
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excess of 3,500 barrels. Companies operating with a PSC settle their tax liabilities out of profit oil or profit gas. Similar to the companies operating with an exploration and production license, the PSCs pay the following taxes: the petroleum profits tax (PPT); the Unemployment levy (UL); the Supplemental petroleum tax (SPT); the petroleum production levy (PPL); the petroleum impost (PI); and royalties. •
The rate of the petroleum profits tax (PPT) is 50% of taxable profits of petroleum operations. The PPT is charged at a reduced rate of 35% on petroleum operations in deepwater blocks where at least half of the acreage is more than 400 meters below sea level. Expenses that are wholly and exclusively incurred in the production of taxable income are deductible in arriving at the taxable profits for PPT purposes.
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The unemployment levy (UL) is set at 5% of taxable profits. The UL is not deductible in the calculation of taxable profits.
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The supplemental petroleum tax (SPT) is imposed on windfall profits, calculated on gross income from the sale of crude oil. The applicable rate of the tax is based on the weighted average of crude oil prices and is applied to the gross income from the disposal of crude oil. The rates of SPT are as follows: Weighted average crude oil prices US$ 0.00—50.00 50.01—90.00. 90.01—200.00 200.01 and over
SPT Rates Marine New field development Land and deep water 0% 0% 0% 33% 25% 18% SPT rate = base SPT rate+ 0.2% (Price – US$90) 55% 47% 40%
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The petroleum production levy (PPL) applies to production if the business produces petroleum at a daily average rate in excess of 3,500 barrels. The levy is set at 4% of income from crude oil.
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Royalties payable are 12.5% of crude oil and natural gas produced from the licensed or contract area.
Energy revenue accounted for only 27 percent of total government revenue in FY 2015, compared to around 55 percent during the preceding decade. Low oil prices, combined with fiscal incentives for the energy sector have depressed energy revenues during the past few years. Nevertheless, the authorities recognize that the extraction of natural resources needs to result in some minimum payments to the government. According to the last EITI report, which covers the fiscal year 2017, checks and balances in the system are working, and there is evidence that Trinidad and Tobago is achieving revenue transparency and accountability at the level of the
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award of exploration and production contracts and licenses, and the honoring of revenue payment commitments by extractive companies to the government. Venezuela With over 298 billion barrels of proven crude oil reserves, Venezuela is recognized as the country with possibly the largest volume of proven oil reserves in the world today. Venezuela’s colossal oil sector, which shaped the economy of the country and the international energy market for a century, has in recent years come to a near halt, with production reduced to a trickle after years of gross mismanagement and American sanctions. All foreign-owned oil companies were nationalized in 1976 and were replaced by Venezuelan companies with ownership assumed by a holding company- Petróleos de Venezuela S.A. (PDVSA ) which, in turn, is owned by the State. Due to the heavy nature of the crude oil reserves found in Venezuela, the extraction of oil is particularly challenging and the Venezuelan government invited international oil companies into the country to participate in the development of these reserves. Companies like ExxonMobil, BP, Chevron, Total and ConocoPhillips invested billions of dollars in technology and infrastructure to turn the extra-heavy oil into crude oil exports. These assets were eventually expropriated. Due to continued US sanctions, there is minimal involvement of foreign companies in the Venezuelan oil industry. Based on the laws on the books, any IOC intending to do business in Venezuela must do so in the context of a joint venture with PDVSA which has the authority to grant concessionary rights to explore and extract crude oil. Joint-venture corporations that undertake oil activities are subject to a 50% corporate income tax (CIT) rate on their annual net profits and royalties. The tax rates for the CIT and royalties can be summarized as follows: •
CIT rate — 50% of net profits. A corporation that undertakes oil activities is subject to a 50% CIT rate on its annual net profits from Venezuelan income. Annual net profits are determined by subtracting the costs allowed by the income tax legislation from the gross receipts of the taxpayer.
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Royalties —.according to the amended legislation of August 2006, the royalty to be paid to the state is equivalent to 30% of the extracted crude. However, the royalty may be reduced to 20% if the oil field is proven to be not economically exploitable.
Venezuela does not adhere to the standards of the EITI and no formal assessment is prepared of the contribution made by the extractive industries to the public finances of Venezuela. Ghana Ghana's Jubilee Oilfield, which contains up to 3 billion barrels of sweet crude oil, was discovered in 2007 and is one among many oilfields from which oil is being extracted in Ghana. Commensurate with the discovery of Ghana’s huge oil reserves, oil and gas exploration in Ghana continues to increase. Commercial production, which stood at 110,000
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barrels per day in January 2013, is expected to a peak at over 200,000 barrels per day in the late 2020s. The state-owned oil company Ghana National Petroleum Corporation (GNPC) is responsible for promoting hydrocarbon exploration and production. In July 2011, the Petroleum Commission (PC) was established by an Act of Parliament and given institutional oversight over these upstream petroleum industry activities. All petroleum companies which intend to operate in Ghana are required to register with the PC and be issued with a permit before commencement of operations. The principal form of contract granted to a contractor or to an IOC is a Petroleum Agreement (PA) which is similar to Production Sharing Agreements or Contracts that are frequently used in other countries. Under terms of a PA, the Government of Ghana grants right to IOCs to explore and produce petroleum in a designated contract area. The State, through the GNPC, usually holds at least 15% carried interest at the exploration and development stage of any petroleum operations. The GNPC also has the option to acquire additional participating interest as determined in the PA. In addition to the dividends that accrue to the government through the carried interest of the GNPC, most PAs in Ghana apply a corporate tax rate of 35% on taxable profit calculated according to the tax laws. The chargeable income is arrived at after deducting all specified expenditures, including prior-year losses of not more than five years, and permitted capital allowances for the year in question, A contractor is also subject to royalty at rates which are not fixed, but can range from 3% to 12.5% of the value of gross production of crude oil and natural gas. Royalty payments are tax deductible in determining the taxable profit of the contractors. The Government of Ghana and GNPC have the right to choose oil and gas lift as payment for royalties, or to receive a cash payment in lieu of petroleum lift. Ghana has over the past decade witnessed an improvement in the governance of its extractive sector with transparency and accountability being placed at the center of the resource governance agenda. This can mainly be attributed to initiatives such as the Extractive Industry Transparency Initiative (EITI) which Ghana joined in 2003. According to the general assessment of the Ghana EITI report, which covered the period through the 2018 financial year, performance relative to the planned programs and activities shows that over eighty per cent of these activities were successfully executed, while the remaining planned activities have been initiated and were at various stages of implementation as at the end of 2018. Kenya The discovery of commercially viable oil deposits was made in 2012 by Tullow, a British oil company. Since this discovery, exploration has continued and the company estimates that the Lokichar sub-basin within the Tertiary Rift contains about 4 billion barrels of crude oil.
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Although Kenya only recently began producing oil, it is estimated that exports will far exceed the initial volume of 200,000 barrels of crude that were shipped to a Chinese company in 2019. The Petroleum (Exploration and Production) Act of 1986 vests ownership of hydrocarbons in the hands of the Kenyan government but day-to-day responsibility for managing activities in the sector lies with the National Oil Corporation of Kenya (NOCK), a limited liability company, incorporated by the Government of Kenya for exploration, prospecting and production of oil and gas. An entity or contractor, such as an IOC, seeking to engage in oil and gas activities in Kenya is required to enter into a PSC issued by the NOCK. The petroleum company provides the funds and bears the risk of exploration, appraisal, and development as well as the operating costs. When oil is produced, the PSC allows the petroleum companies to recoup the costs incurred on exploration and development prior to sharing the production with the Government according to the formulas specified under the PSC. Allowable deductions, based on audited financial statements, include expenses incurred wholly and exclusively in the production of petroleum. The fiscal regime that applies to the petroleum industry in Kenya consists mainly of a corporate income tax (CIT) and royalties. A non-resident company is taxed on income derived or accrued from Kenya at the CIT rate of 37.5%. The tax regime for PSCs specifies that their tax liability will be paid out of the Government’s share of production. This means that the portion of crude oil which the Government is entitled to take includes all taxes based on income or profits directly attributed to petroleum. In addition, IOCs are liable to pay withholding taxes, which include royalties of 20 % of the value of oil produced. The following additional taxes are payable by companies operating with a PSC. The applicable rates are negotiated at the time of signing each PSC: • Signature bonus • Surface fees • Training fees • Windfall profits As Kenya prepares to start large-scale oil exportation, it is imperative for the government to establish a framework that promotes implementation of sound fiscal policies and enhances good governance. In 2015, Kenya made a commitment to join the EITI and to this end, pledged to establish a government office as the central point for EITI implementation within six months. Despite this commitment being made, Kenya has neither joined the EITI nor established a central point for EITI implementation.
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Angola Crude oil reserves in Angola amounted to 8.2 billion barrels in 2020. The country is the second biggest oil producer in Sub-Saharan Africa, producing 1.9 million barrels per day. There are three types of contracts under which a contractor or IOC can explore for and produces oil in Angola. Each of these contracts is associated with different tax regimes. The state concessionaire, NOC, is a distinct department of Sonangol, the Angolan national oil company, through which the Government manages its oil and gas properties and its contractual relationships with other oil companies. •
The Production Sharing Agreement (PSA): The PSA is a contractual arrangement between a contracting group ( e.g. an IOC) and the state concessionaire, the Angolan national oil company (NOC), under which the contracting group bears all expenditures for exploration and extraction of hydrocarbons in the contract area, together with related losses and risks. It is the most common form of arrangement under which oil and gas are produced by IOCs in Angola. These contracts require the IOCs to pay the petroleum profits tax (PIT) on profit oil when oil is produced at a rate of 50%. Profit oil is defined as the difference between the total oil produced and the share of oil produced that is allocated for recovery, exploration, development, and production. Cost oil is limited to a maximum percentage of the total amount of oil produced in each development area, in accordance with the terms of the PSA. PIT is payable on the actual profit computed at a rate of 50%. There is also a surface fee (SF) which is charged at the rate of US$300 per square kilometer (km²) in which the oil is produced. This surcharge is deductible for PIT purposes.
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Partnerships: This is usually an arrangement between the national concessionaire and the oil companies. Partnerships pay the PIT after deducting from gross revenues costs incurred in exploration operations, drilling costs of developing wells, and building storage facilities. The PIT tax rate is 65.75%. There is also the petroleum production tax (PPT) of 20% which is applicable to partnerships. The PPT is computed on the quantity of crude oil and natural gas measured at the well head, less the costs incurred in production as approved by the state concessionaire. In addition, a Surface fee (SF) of US$300 per square kilometer (km²), and a petroleum transaction tax (PTT) of 70% of taxable income are payable. The PTT is computed on taxable income and is deductible for the computation of PIT. The government also benefits from dividends that are paid on its participating interest in the partnership.
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Risk service contract (RSC). The contractor or IOC has no title to oil produced but undertakes exploration, development and production activities on behalf of the national concessionaire. The Contractor is reimbursed and remunerated from the sale of oil produced. PIT is payable on the actual profit, computed at a rate of 65.75% for RSCs. A
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petroleum production tax (PPT) of 20% is also applicable. The PPT is computed on the quantity of crude oil and natural gas measured at the well head, less the cost incurred in producing the oil. Finally, there are the Surface fee (SF), which is charged at the rate of US$300 per square kilometer (km²), and the Petroleum transaction tax (PTT) which is computed on taxable income at the rate of 70 percent. Although Angola does not participate in the EITI, the Angolan government has indicated for some time that it is willing to join the Extractive Industries Transparency Initiative (EITI) and that the Minister for Mineral Resources, Oil and Gas will be responsible for coordinating efforts with this entity. To this end, the Angolan officials sent a letter to the Chairman of the EITI Board in September 2020 describing the steps already taken to implement the standards of the EITI.
15 Table I: Summary of Contractual and Other Arrangements In Effect in Selected Oil-Producing Countries Country Guyana
Applicable Contractual Arrangement
Sources of the Tax Revenues and Other Receipts Accruing to the Government
Production Sharing Arrangement
Profit Tax (50%) Royalties (2%) Company Income Taxes (36%) Royalties (6.25%), Concession or Bidding Fees, Dividends Concession fees Royalties (8%-25%), rates based on production levels Corporate Income Taxes (30-32%) Petroleum Profits Tax (35-50%), Royalties (12.5%), Petroleum Production Levy (4%), Supplementary Petroleum Tax (18%-55%) Petroleum impost (variable rates, determined by the Ministry of Energy and energy Industries unemployment levy (5% of taxable profits) Corporate Income Tax (50%) Royalties (30%) Dividends Concession fees
Suriname
Production Sharing Service Contract, Joint Ventures
Colombia
Exploration and Production Contract
Trinidad and Tobago
Exploration and production license, Production Sharing Contract
Venezuela
Joint Ventures Production Sharing Service Contract
Ghana
Kenya
Angola
Partnerships Production Sharing Contract Production Sharing Contract, Partnership, Risk Service Contract
Corporate Income Taxes (35%) Royalties (3-12.5%) Dividends Corporate Income Tax (37.5%) Royalties (20%) Surface fee; windfall profits tax; training fees; and signature bonus Petroleum Profits Tax (50-65.75%) Petroleum production tax (20%) Petroleum Transactions Tax (70%) Surface fee--US$300 per square kilometer (km²)
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References Busisipho, S., (2021, January), “An assessment of the Extractive Industries Transparency Initiative”: Policy Briefing (Good Governance Africa) Johnston. D., and others, 2008,” International Petroleum Taxation” Independent Petroleum Association of America, Washington DC. Ernst & Young Global Limited (EY), 2019, “Global Oil and Gas Tax Guide 2019” International Monetary Fund (IMF), 2019, “Guyana: 2019 article IV Consultation—Press Release; Staff Report; and Statement by the Executive Director for Guyana.” International Monetary Fund (IMF), 2018, “Trinidad and Tobago: 2018 Article IV Consultation-Press Release: Staff Report” PricewaterhouseCoopers”, 2018, “Oil and Gas Tax Guide for Africa 2017” The World Bank Group (World Bank), 2017, “Suriname Sector Competitiveness Analysis”