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Oil and Revenue Sharing between Iraq and the Kurdistan Regional Government

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Published: 9th Dec 2019

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Oil and Revenue Sharing between Iraq and the Kurdistan Regional Government


Chapter One: Introduction

  1. Introduction

Oil is the major source of government revenue in most oil rich countries such as Iraq, Iran, Saudi Arabia, Qatar, Libya, Venezuela and Russia. Collecting and sharing revenues is vital to the social, economic, and political stability of these nations. As far as oil revenues are concerned, the government’s task is one of wealth distribution rather than redistribution (Segal, 2012), but this distribution can be difficult in countries where oil is geographically unevenly spread. Furthermore, getting it wrong can have serious consequences; perceived inequality in regional distribution can lead to regional conflicts and even foster separatism. Such regional disputes have occurred in countries as far apart as the UK, Indonesia, Colombia, Canada and Iraq.

How revenues are distributed among regions depends on who has legal sovereignty over the resources. Where ownership is public rather than private, the oil may be owned by the country as a whole or by the specific region where it is found. If it is the latter, the producing region has the right to keep the resulting revenues in its territories. However, this can create inequality among regions, especially when revenues are concentrated in one area. If the oil is nationally owned, then the revenues can go to the central government and be distributed equally to all regions. Distribution among regions becomes even more challenging when the revenues are large and represent a big percentage of total government revenues. To understand how governments approach this challenge, it is necessary to investigate the fiscal regimes they apply to collect revenues and the criteria they adopt for distribution of these revenues.

A country may choose to develop its oil industry through its own national oil company. In this case, the state takes the whole mineral rent, provides all investment and assumes all the risk. This is the model adopted by countries throughout the Middle East. Alternatively, it may choose to establish agreements with foreign oil and gas companies to develop the industry. These agreements regulate the relationship between the foreign companies and the host government. They take two main forms: concessions and contracts (Johnston, 1994); in either case, they establish the share of exploitable natural resources to be given to each party. Since these agreements determine the government’s share of the oil revenues, they also determine its ability to achieve socio-economic objectives such as job creation, the transfer of technology and the development of local infrastructure.

Iraq’s oil governance has been completely reconstructed since the toppling of Saddam Hussein’s regime in 2003. The new constitution, which was set out in 2005, regulates the distribution of oil revenues among regions and the signing of contracts with foreign oil companies. However, the articles pertaining to these two issues are highly controversial as they are interpreted differently by the central government and the Kurdistan Regional Government (KRG). The constitution was followed in 2007 by a draft hydrocarbon law, but at the time of writing, this is still under discussion in Parliament, mainly because of ongoing disputes with the KRG over the interpretation of the constitution.

Since 2003, two different types of fiscal regime have emerged in Iraq; that adopted by the central government and that adopted by the Kurdistan regime (which is considered illegal by the central government). Kurdistan also differs from the rest of the provinces in how it receives its share of the oil revenues; it receives a direct share of oil revenues from the centre, while the remaining provinces have most of their revenues centrally distributed by the national government.

  1. The purpose of this study

This study aims to characterise Iraqi oil governance since the 2003 invasion and the toppling of Saddam Hussein, focusing on the distribution of oil revenues between Iraq and Kurdistan region. The main reason for this focus is the mounting disputes between central government, Kurdistan and other Iraqi provinces about oil revenue distribution, but the aim is also to add to the literature; there is as yet relatively little literature about revenue distribution among regions or about disputes between central governments and oil-rich provinces. The study investigates the key dimensions of Iraqi oil governance, including the exercise of Iraqi property rights over oil and gas resources, Iraqi political governance, and the petroleum fiscal regime through which oil and gas revenues are collected, in order to understand how oil revenues are being distributed among Iraq’s regions. It also examines how other countries with substantial oil and gas resources have resolved conflict over the regional distribution of oil and gas revenues and consider whether these practices might be transferred to the current Iraqi context.

The development of Iraqi oil governance was researched using the relevant legal documentation such as drafts of oil and gas laws, the national constitution and contracts signed with international oil companies; the available data about the petroleum fiscal regime. In order to gain a deeper understanding of the reconstruction of Iraqi oil governance, a series of semi-structured interviews were conducted with key players in the reconstruction process. These included politicians, state oil company executives and advisers.

The value of the thesis will be in clarifying the links between governance and the level and distribution of Iraqi oil revenues among regions – thereby enabling policymakers to understand both the nature of the governance regime which has been established and how it might be changed to enhance the benefits of oil for Iraqi citizens without igniting regional conflicts. Other countries facing similar decisions, such as what fiscal regime to adopt, what sort of contracts to sign with foreign oil companies, and how to distribute oil revenues without igniting disputes, may also benefit from the findings.

  1. Research Questions

The aim of this thesis is to analyse the revenue distribution between the central government in Iraq and the Kurdistan Regional Government (KRG). The distribution among regions is of central importance in a country as politically divided as Iraq since 2003.  The thesis is interested to find out whether the disputes of oil revenue collections affect the distribution of oil revenues among regions.

What are the principal characteristics of oil revenue distribution between Iraq and KRG between 2003 and 2013?

This question is at the heart of Iraqi oil governance. After 2003, the revenue distribution system changed from centralised to decentralised, but the new system has brought the central government into conflict first with Kurdistan and then with other provinces. The main aim of this question is to investigate the origins of these disputes and how they might be mitigated.

What fiscal regimes do the central government and KRG use?

To understand and answer revenue distribution among regions, we need to have a specific question about collection of oil revenues. The fiscal regime plays a crucial role in determining the effectiveness of oil governance, particularly in Iraq, where it has long been a source of dispute. The question also determines the size of revenues to be distributed and whether the performance of the fiscal regime affects how revenues are distributed among regions, especially Kurdistan, which uses a different type of contract from the central government.

  1. Thesis Structure

In order to achieve the purpose of the study set out in section 1.2 and to answer the research questions outlined in section 1.3, this thesis is organised into six chapters as follows:

Chapter Two discusses the assumption underpinning the research and the choice of methodological approach.

Chapter Three reviews the literature relating to the concepts and principles of oil governance which influence the collection of oil rent. The chapter aims to explore these ideas and establish a theoretical framework for understanding different forms of oil revenue collection governance. These ideas assist the study in evaluating Iraq’s previous and current oil governance, especially its collection of oil revenues through the petroleum fiscal regime.

Chapter Four discusses the petroleum fiscal regime in Iraq since 2003. The fiscal regime is important in shaping the success of the oil governance and in particular in determining the size of oil revenues to be distributed. The chapter discusses the two types of oil contracts employed in Iraq (those signed by the central government and those favoured by Kurdistan).  It examines one field in detail – West Qurna1 field, Basra, southern Iraq, which is operated by ExxonMobil under a Technical Service Contract (TSC) with the central government in Baghdad. Discounted cash flows and net present values (NPVs) are used to determine the government take, while the company’s combined internal rate of return (IRR) is used to determine company profitability. The chapter draws on other studies to examine the KRG’s use of Production Sharing Contracts (PSCs); similarly detailed cash flow analysis is impossible for the Kurdish fields because the data available in the public domain are insufficient and inconsistent.

Chapter Five analyses the present system of revenue sharing. It also analyses how the conflict between the central government and Kurdistan regarding the petroleum fiscal regime is affecting revenue distribution to other Iraqi regions, and examines the growing dissatisfaction of other Iraqi provinces. It also brings examples of other oil producing countries facing similar disputes over revenue distribution (i.e. the UK, Indonesia, Colombia and Canada) with a view to identifying useful lessons for Iraq.

Chapter Six summarises the findings and discusses the study’s contribution to the literature and policy analysis. Finally, it considers the limitations of the study and offers recommendations for future research.

Chapter Two: Research Methodology

Chapter Three: The Concepts and Principles of Oil Governance

  1. Introduction

This chapter analyses the issues which inform the structures of Oil Governance. These are revealed in the relationships between the following key concepts and issues: sovereignty over mineral resources, private versus public ownership, terms of access to natural resources and revenues, the concept of mineral rent and its different forms, the evolution of petroleum fiscal regimes and the role of state oil companies. The chapter aims to explore these ideas and establish a theoretical framework for understanding different forms of oil governance. These ideas will assist this study in evaluating Iraq’s old and new oil governance and reconstructing it in the most suitable way.

  1. Sovereignty Over and Ownership of Mineral Resources

Oil is a non-renewable resource. It is unlike other natural resources such as plants that we can grow. It is exhaustible – continued extraction of oil will lead eventually to its depletion. This means that states are likely to take a sovereign interest in it because depletion raises issues of control – is it wise to allow private companies to decide the rate at which the mineral is depleted or should the state, representing the wider society, make this decision?  Secondly, because oil is found in the subsurface, the issue of ownership is also posed: does the owner of the surface (the landowner) own the resources below the surface? Or should these automatically belong to the state on behalf of its constituent population? How have perceptions of these issues developed? The following simple typology can assist us in clarifying these issues (table 3.1).


Table 3.1: Patterns of Sub-surface Mineral Ownership

Sub-surface minerals owned by surface landowner Example: Cornish Tin & Copper mining, 16th-19th centuries Example: USA Oil Industry (except Federal & State Lands), 19th-21st centuries
Sub-surface minerals owned by the State Example: Spanish & Portuguese Colonial Gold & Silver Mining, 16th-19th centuries French Republic, late 18th & 19th centuries, and

Former Colonial & Semi-Colonial States (e.g. Middle East) 20th & 21st centuries.

  1. Modern mineral governance under State ownership

Due to the fact that this thesis investigates the current state of revenue distribution in Iraq, part of the Middle East, and due to length restrictions only the modern model of sub-surface minerals owned by the State will be discussed here.

The advent of Republican government in late 18th century France meant the transfer of sub-surface mineral ownership from the Monarch to ‘the People’. According to the French Mineral Law of 1791  devised by Mirabeau, minerals are a gift of nature, and because of their natural origins they belong to the community as a whole – there was no reason to allow a  particular individual (i.e. the King) or a group of individuals to benefit from them exclusively (Montel, 1970: 104). These natural, free gifted and valuable resources were now in “public ownership”. However, this did not mean the same as “state ownership” but only the opposite of private property (Mommer, 1994: 3). The French law of 1791, which is to this day the basis of French law of mineral property, specified that ownership of minerals should not be given to the state; the state only acts as administrator of the resources and these cannot be exploited without its consent and then only under its supervision; and since the government does not own the minerals it does not charge a royalty when it leases a mineral property to a private company. So, because the mining sector of the economy was thought of as a purely domestic industry whose only beneficiaries were French citizens, there would be no need for a royalty payment.

However, the situation changes dramatically when the mineral industry is no longer a purely domestic one – that is, where the mining or Oil Company is a foreign concern. This was the situation faced by the emerging new nations in the period when European colonialism and imperialism were in decline. The newly independent countries, e.g. Iraq, Algeria, Kuwait, and Nigeria, and those which had previously been under a kind of semi-colonial rule, e.g. Persia (Iran) and Venezuela, were confronted by oil companies which they did not own but were owned and controlled by citizens of the former colonial and imperialist powers.

Initially these new states granted Concessions to the foreign oil companies for very long periods and with fairly low royalty rates and taxes (Mikdashi, 1966). However, by the 1960s the belief in full state ownership of sub-surface minerals became dominant as is reflected in the  United Nations (UN) Resolution on “permanent sovereignty” over mineral resources – Resolution 1803 (XVII) of 14 December 1962.

“The right of peoples and nations to permanent sovereignty over their natural wealth and resources must be exercised in the interest of their national development and of the well-being of the people of the State concerned”. “The exploration, development and disposition of such resources, as well as the import of the foreign capital required for these purposes, should be in conformity with the rules and conditions which the peoples and nations freely consider to be necessary or desirable with regard to the authorization, restriction or prohibition of such activities.”

This was the ideological and legal basis of the wave of nationalisations of foreign oil companies which took place during the 1970s (See Sampson, 1975: 283-318; Yergin, 199: 633-698; Rutledge, 2005: 42-46). All countries in the world today, except very few such as the United States where private ownership still has a substantial presence, exercise sovereign rights over the subsurface to manage and distribute the revenues of these. In practice this means that state ownership of the sub-surface minerals – the most important of which is oil – is exercised either by means of a national oil company (NOC), or allowing private sector operators access to national resources, but at the same time charging them for the extraction and depletion of the resource in the form or royalties, taxes or some other form of petroleum fiscal regime.

  1. Petroleum Fiscal Regimes

After discussing the theory of mineral rent, the questions now are: what are the instruments for capturing them? What are the advantages and disadvantages of these instruments? Which one generates more revenues for the government and targets the excess profits of these resources? How does the government maintain a tough fiscal system and not discourage investment? What is the effect of the instrument on oil and gas production? Does the chosen system discourage exploration, development and production, especially of the marginal fields?

A high level of total oil revenues can be the mutual objective of the host government and the investor (Tordo, 2007: 13).  At the same time the government would want the maximum share of the revenue. Tordo, (2007:13) argues that “the host governments want to gain the maximum value (not oil volume) for their countries over time in terms of net receipts for wealth. Their goal is to increase their income from natural resources, and at the same time attract foreign investment”. He adds that “host governments also have socioeconomic objectives, such as: job creation, transfer of technology, and development of local infrastructure”. On the other hand, the investor aims to maximise returns by exploring and producing oil and gas fields at the lowest cost and highest possible profit margin, which is consistent with the risk of the project.

Johnston (1994:21) identifies two basic petroleum fiscal arrangements: Concessionary and Contractual. The latter is divided into a number of different types of which the most common are: (1) Production Sharing Contracts (PSCs); and (2) Service Contracts. The fundamental difference between the concessionary and contractual arrangement is the attitude towards ownership. The concessionary system, as the term implies, allows private ownership of mineral resources, while under the contractual system the government holds the ownership of minerals. Johnston (2007:56) argues that while concessionary and contractual systems can be differentiated from a mechanical and financial view, there may be particular differences between them. When we examine specific fiscal systems, there are more systems in the world than there are countries. In some countries more than one fiscal system is used during the transition period when they are applying new terms. Other countries offer two types of fiscal options concessionary system and also service or production contracts. Peru used to have that system (Johnston, 1994: 5). Others have a hybrid form which is a combination of the other basic systems, e.g. USA, Shallow water Outer Continental Shelf – Bonus Bidding combined with Royalty.

The following sections will briefly describe some different fiscal regimes, then Production Sharing and Technical Service contracts are examined in more detail due to their relevance to this research.

  1.     Royalty

Royalty has been historically the most popular method of extracting rent used by governments (Tordo, 2007). It is usually a per-barrel charge levied as a proportion of the per-barrel gross revenue. It can be paid in cash or in kind. Royalty is the first percentage taken from the gross revenue; it is usually tax-deductible as it represents “the cost of doing business”. The royalty scale generally ranges from 1% to 20%.

  1.     Concessionary System

Concessionary arrangement was the only petroleum fiscal system available before the end of the 1960s (Johnston, 2007: 58). It can be traced to the discovery of oil in the Middle East in the 1920s (see Mikdashi, 1966). This system had several features:

  • Oil and gas companies were given the rights to explore for hydrocarbons
  • If a discovery was made, then the international oil and gas company had the right to develop and produce hydrocarbons
  • The principal type of mineral rent charge was a signature bonus and fixed royalty payments
  • Upon the production of hydrocarbons, the international oil company took title to its share at the wellhead ( gross production minus royalty)
  • IOC owned exploration and production equipment
  • IOC’s paid taxes on profits from oil sales

This system is also called a tax/royalty system; the government transfers the title of mineral ownership to the company. The latter then pays royalties and taxes.

  1.     Joint Ventures

Joint ventures started in the Middle East from 1957 to the mid-1960s.  The first joint venture agreement was between the National Iranian Oil Company (NIOC) and Azienda Generale Italiana dei Petroli (AGIP), an Italian Oil Company (Dam, 1970). In joint ventures, governments participate in decision-making and management of hydrocarbon projects via a government owned Oil and Gas Company. The difference between concessions and joint ventures is that the government acquires in addition to royalty and tax, a share of the petroleum and/or profits (United Nations, 1995).

  1.     Production Sharing Contracts (PSCs)

Production sharing contracts started to surface in the 1960s when governments demanded more involvement in mineral exploration and development and more rights in resources ownership. The first model PSC was signed in 1966 between the independent Indonesia American Petroleum Company (IIAPCO) and PERTAMINA, Indonesia’s National Oil Company (Johnston, 2007: 60). The features of this system are as follows: (Johnston, Johnston and Roger, 2008; Johnston, 2007; Johnston, 1994; United Nations, 1995)

  • The government sometimes actively partakes in exploration and development operation and this system may even provide a joint committee from both parties to monitor the operations
  • The state maintains ownership of the resources. The contractor receives a share of production for the performed services
  • As in the relevant concessionary system, the IOC assumes all exploration risks and if there is no discovery then the government will not reimburse the cost
  • In the event of discovery, production is split between the parties according to negotiated percentages and the company can recover its costs
  •  Contractor share of profit is subject to taxation

The company is reimbursed for its expenditures through allocation to it of a certain quantity of oil which, at prevailing market prices, would be equal to the value of the investment and operating expenditures incurred by the company. This quantity of oil is called the cost oil and the company usually sells this oil back to the state at the current market price. The oil remaining after costs deduction is called the Profit oil. This is divided between the oil company and the state according to agreed proportions.

Mommer (2002:16) argues that profit sharing requires a deep understanding and careful monitoring. This system may allow the contractor to gain premium profits. The contractor may import costs from downstream or from any other unrelated business to minimise the calculation of the shared profits.

The costs which are allowable for Cost Recovery via the cost oil usually include the following:

  • Exploration costs (where appropriate)
  • Operating cost
  • Annual Capital Expenditure or current depreciation charge
  • Interest charges on financing (where allowed)
  • Provision for abandonment costs
  • Unrecovered costs carried over from the previous year

Profit oil splits in most countries range from under 15% to over 55% for the contractor.

  1.     Service Agreements

In this system, the contractor is paid a fee for producing hydrocarbons. All the production is owned by the state. These contracts started to be used in the late 1960s in Iraq and Iran followed by Venezuela (Dam, 1970). There are two types of service agreements: risk service agreements and non-risk service agreements.

In non-risk service agreements, the government pays the contractor a fee for petroleum services and this fee covers all costs. This arrangement prevails where the state has the capital but seeks technical expertise (Johnston, 1994:24).

In risk service agreements the contractor provides all the costs for production and development of hydrocarbon resources as in concessionary and PSC systems. In return if the exploration is successful, the government allows cost recovery after payment of oil and gas and gives the contractor a percentage of fees on the remaining revenues. The fee is normally taxable. IOCs are sometimes allowed to purchase petroleum at reduced prices (Johnston, 1994:87-89; Johnston, 2007:62-64; Wright et al., 2008:29).

The nature of payment is the main difference between PSCs and service contracts (Johnston, 1994:88). In service contracts the contractor receives his share in cash or crude oil, while with PSCs the contractor receives his share only in kind. This doesn’t seem to be a bigger difference than the absence of risk in a non-risk service agreement.

  1. Evaluating Petroleum Fiscal Regimes

For a petroleum fiscal regime to be satisfactory to the state, ideally the following three criteria should be satisfied:

  1. The absolute size of the mineral rent received should be acceptable to the state
  2. The proportion of the mineral rent which is received by the state should be equitable
  3.  The tenant Oil company should not be permitted excess profitability   

To satisfy the first criterion, the state may insist on receiving a certain payment per barrel, for example in the form of a high royalty. However, the oil lease in question may offer an exceptionally high differential rent, so the proportion of the total mineral rent may be below the proportion considered equitable by the state. Therefore, in the ideal system the state should insist on receiving high payment per barrel

We conclude this section by answering the questions that we have posed in the introduction of the section. There are a number of different forms of petroleum fiscal regime to choose from, and although some differences exist between them, these differences are limited to mechanical, political and financial points. It is not really possible to characterise any of the fiscal and contracted systems described above as ‘strong’ or ‘weak’ per se, as it depends on the precise details of the regime. For example, a regime of royalties can be tough or weak depending upon the percentage royalty chosen (from 1% to 30%). There is no better fiscal regime per se which generates more revenues for the government, but the toughness of the system depends on the fiscal terms of the specific contract. In order for the country to determine whether it should establish a tough or weak fiscal regime and not discourage investment or development of marginal fields, it should consider the geological potential of the wells, the extent of existing knowledge about the country oil and gas reserves and whether they are explored, the degree the reserve in the ground is proved, competing oil companies seeking access to state oil reserve, extraction costs and political costs.

  1. National Oil Companies (NOCs)

As an alternative to levying very high royalties and taxes on foreign oil companies, the state can obtain the whole of the mineral rent by establishing a monopoly national oil company. However, the ‘downside’ of this is that the state has to provide all the capital investment and take on all the risk. It may also lack the managerial and technical capacity that can be gained from employing IOCs.

However, today, NOCs are recognised as a basic element of petroleum policy in almost all petroleum exporting and importing nations (Khan, 1985). The rationale for direct state participation is to secure national interests more effectively than market forces and private initiative allow (Noreng, 1997).

The first NOC was created in Austria in 1908 due to the private producers of crude being faced with a surplus and being unable to agree how to manage it (Stevens, 2008). Early nationalisation of the oil industry in Russia in 1917 and in Mexico in 1938, with the formation of PEMEX (Petroleos Mexicanos), saw a major expansion of state oil companies (Bentham, 1988).

However, it was during the 1970s that the most rapid growth of national oil companies occurred, especially in the Middle East. The governments of these countries believed they had the right to exercise their sovereign rights over their depletable natural resources (Olorunfemi, 1991). They wanted to establish ownership and dictate the pace at which national reserves are exploited.

The actual role of the NOC differs among countries. While they play a major role in development and exploration and operate with private companies’ in some countries, e.g. Italy, Canada and Saudi Arabia, they do not manage all aspects of operation in others although they have the petroleum rights of states, e.g. the U.K (Khan, 1985).

The NOC can act as a channel for technology transfer (Nore, 1980). Economic power in oil stems from control of oil reserves/ or market openings (Philip, 1982). Hence, “the IOCs are willing to contract out other aspects such as the production of technically sophisticated capital goods to competing specialist firms and this technology is available for the NOCs to use” (Stevens, 2008:14). This allows the local staff of NOCs to gain technical training and thus the NOC and the state acquire greater control over the natural resources. Thereby, as the example of Saudi Arabia amply illustrates, an NOC can move from being a sleeping partner or absentee landlord to being a fully active oil company (Khan, 1987: 188).

The formation of a state company may assist in promoting national interests such as security of supply for the domestic market, the conservation of resources, regulation of safety, health, welfare and environmental matters, the obtaining of a proper return and the training and employment of its own nationals in the industry. “Oil rich” countries, as is the case with some OPEC countries, can exploit their own natural resources, use only their capital and buy in outside technical expertise as needed (Bentham and Smith, 1987).

However, exploitation through a national company can be extremely expensive. The risks are high, and it may be that other regulated contracts serve a state’s interest better (Bentham and Smith, 1987). NOCs have some other drawbacks. Stevens (2008) discussed that although the NOC was created to defend the government’s interests, the NOC might use the government to fulfil its own interests, especially in a situation where there are few balancing powers. Al-Mazeedi (1992) argues that NOCs, recruitment policies are influenced by tribal and religious considerations, instead of qualifications, performance or personal attributes. This is especially in the Middle Eastern NOCs. The practise has exerted an adverse effect on the Gulf NOCs’ managerial and technological expertise.

Whether or not state oil companies are used as vehicles for state ownership of reserves, it still remains the case that it is the terms of access rather than ownership per se which determine the return to governments. National Oil Companies may be used as levers to achieve desired terms of access, but they may equally impede the achievement of this goal if they start to develop autonomous interests which determine national policy.

  1. Conclusions

This chapter reviews the literature relating to oil governance up to the point of revenue distribution. It also explores patterns of sub-surface mineral ownership and how these have changed. In the pre-modern period (the 16th to 19th centuries), sub-surface minerals were owned by the. In modern times (the 19th to 21st centuries), sub-surface minerals are generally owned by the state, apart from some countries such as the US, where they still belong to the landowner.

Numerous instruments and fiscal systems have been developed to capture mineral rent and ensure that governments maximise their share. Which is the most appropriate system will vary from case to case, depending on the terms of the contracts involved. Alternatively, the state can create a national oil company and establish a monopoly over the resource. This ensures that the whole mineral rent goes to the state, but this step has its own advantages and disadvantages.

Chapter Four: Analysing Iraq’s Oil Contracts

  1. Introduction

The fiscal regime is the central pillar of oil governance. Given the importance of the fiscal regime in determining the success of oil governance, and its specific importance in Iraq as a source of dispute, this chapter investigates in detail the performance of the fiscal regime since 2003. It seeks to answer the first research question: whether the federal and Kurdistan governments are successfully capturing oil rents on behalf of the Iraqi people, who, under Article 111 of the constitution, are the owners of the country’s mineral resources.

Prior to nationalisation, the government clearly failed to capture rent from oil companies, both by concession-type contracts in the early days of the industry and in production-sharing contracts (PSC’s) from 1952 onwards. The two types of contract differ mainly in terms of ownership rights. In the concession type, the contractor retains ownership of the field and pays royalties and taxes on profits to the state, while in PSCs, international oil companies may only own cost oil plus profit oil.

Shortly before the 2003 war, opponents of Saddam’s regime met with representatives from foreign oil companies in London. Immediately after the invasion, production-sharing contracts with IOCs were mooted as an option for developing the Iraqi oil industry. However, Iraqi oil policy makers disagreed on whether to involve foreign oil companies again or to have a completely nationalised industry, and there were strong objections to PSCs in the Iraqi Parliament, mainly on the grounds that most Iraqis were against the shared ownership and entitlement these contracts offered to IOCs. A compromise was eventually reached in 2009 with the signing of the first technical service contracts (TSCs). TSCs had the advantage of releasing Iraq from the financial burden of raising the capital for investment while preserving the principle of national control. Under a service contract, the state retains all ownership of the oil and its production. The IOC is merely a contractor and is paid a cash fee for producing mineral resources.

But while the central government has signed TSCs, the KRG prefers PSCs. The central government considers the latter to be illegal and too generous to the IOCs, but the KRG disputes this, arguing that not only are PSCs legal, but they offer better terms than the service contracts signed by the central government. Accordingly, this chapter analyses these two types of contract in more detail. The West Qurna1 field in Basra, south Iraq, is examined as an example of a TSC (between the central government in Baghdad and Exxon Mobil). Discounted cash flows and net present values (NPVs) are used to calculate the government take, the company’s combined internal rate of return (IRR) and company profitability. This field was chosen primarily because of the availability of a considerable amount of technical and economic information, which was absent in most other oil fields. This is certainly the case in the Kurdish fields – the data available in the public domain is inadequate and inconsistent, rendering detailed cash flow analysis impossible. Consequently, the chapter draws on existing studies to analyse the KRG’s use of PSC contracts in more general terms.

  1. Contract Negotiations

The first oil field to be contracted with an IOC after 2003 was the Al Ahdab field, in an agreement with the China National Petroleum Corporation (CNPC). In November, 2008, CNPC signed a development service contract with the Ministry of Oil. This contract was a continuation of an agreement signed in June 1997 with the Saddam regime to develop the field. Jiyad (2010a:13) describes this contract as disadvantageous to Iraq in comparison with the later first and second  general bid rounds. Arguing that the contract should be reconsidered, Jiyad claims that the annual cap on cost repayments (100%) is around twice what it should have been, and that the $3m signature bonus was far too low. Compare it, for example, to Sinopec’s (another Chinese company) payment of $2.2 billion for two exploration blocks in Angola (IHS, 2006).

Perhaps realising the deficiencies of the Al Ahdab contract, the Iraqi government decided to offer its remaining oil and gas fields for investment by means of a competitive bidding process. Applicants must meet technical, financial, legal, training and HSE (Health and Safety and Environment) criteria, most of which are standard in bidding contracts around the world (e.g. Brazil, Mexico, UK, Australia and Yemen) (Tordo et al., 2010:22). Companies that have signed contracts with the KRG without the central government’s approvalare barred from applying(Business Monitor International, 2009).

Companies which are qualified to do so participate in sealed bid rounds. The bid parameters and evaluation criteria are the remuneration fee bid (RFB) and the plateau production target (PPT). Countries differ in their bidding parameters;  the Gulf of Mexico uses cash bonuses as bidding parameters, Brazil uses cash bonuses, local content and minimum exploration work programmes[1], and Austria uses work programmes together with indicative cost (for detailed discussion of the allocation of petroleum exploration and production rights, see Tordo et al., 2010:22). Since increasing production is of paramount importance for Iraq, the central government favours the use of PPTs.

The Iraqi government held three bidding rounds in June 2009, December 2009, and October 2010. The objective was to develop/redevelop eight, then, and three contract areas (oil and gas fields) respectively. Some of the contracts awarded under TSC and Production and Development Service Contracts received wide criticism for various reasons such as the signature bonuses and the fact that the contracts has not been passed through the Parliament. Tables 4.1A and 4.1B show the basic parameters of the awarded oilfields.

Table 4.1A: Basic parameters of the awarded oilfields

Oil Field Governorate N/IOCs

Consortium (75%)




CP- mbd


PPTs- mbd/Y
Al Ahdab Wasit CNP (100) SOMO 0.000 0.115a/*Y
Rumaila (N&S) Basrah, Missan BP (50.666),

CNPC (49.333)

SOMO 1.050e 2.850/


West Qurna1 Basrah, Missan Exxon Mobil (80),

Shell (20)

OEC 0.300




Zubair Basrah Eni (43.747), Oxy (31.253),

Kogas (25)

MOC 0.200




Missan (Buzurgan


Abu Ghirab)



CNOOC (85),

TAPO (15)

IDC 0.100 0.450
West Qurna2 Basrah, Missan Lukoil (75),

Statoil (25)

NOC 0.000 1.800/


Majnoon Basrah, Missan Shell (60),

Petronas (40)

MOC 0.045d 1.800/


Halfaya Missan


CNPC (50), Total (25),

Petronas (25)

SOC 0.003 0.535/


Garraf Thai Qar Petronas (60),

Japex (40)

SOC 0.000 0.230/


Badra Wasit Gazprom (40), Kogas (30),

Petronas (20), TPAO (10)

OEC 0.000 0.170/


Qaiyara Nineveh Sonangol (100) SOC 0.000 0.120/9Y
Najma Nineveh Sonangol (100) IDC 0.000 0.110/9Y
Total   1.698 11.730

Source: Jiyad (2010b), Petroleum Law Annexes (2007)

Notes:*: Not available

N/IOC: National and international oil companies

CP: Current production; BLP: Baseline production

PPT: Proposed production target

RF: Remuneration fee

SB: Signature bonus

MEO: Minimum expenditure obligation

IPT-FCP: Improved production target-first commercial production as payment commencement condition

Y: Duration in years (how many years it will take to reach the production plateau)

IR-bln: Investment requirements in $ billions comprising Capex and Opex

a: MoO announced that new information made available would increase the production plateau to 200,000 per day (as reported on government-run TV Channel AlIraqia on 29 January, 2010)

b: Loan with LIBOR+1

c: More than

d: http://www.upstreamonline.com/live/article209880.ece [Accessed March 29, 2010]

e: MEES reported 1,066 mbd (MEES, 53, January 11, 2010)

f: revised after contractual setting of baseline production http://www.upstreamonline.com/live/article207648.ece [Accessed March 1, 2010]

Table 4.1B: Basic parameters of the awarded oilfields continued







Reserve billion barrels MEO




6 3 * 1.00c 350 1.6
2 500b 10%


17.8 300 15-20
1.9 100 10%


8.6 200 40-50
2 100 10%


4.1 200 35
1.15 150 120 12.876 200 *
2.30 300b 10%


2.5 200 *
1.39 150 175 12.580 300 *
1.40 150 70 4.098 200 *
1.49 100 35 0.863 150 7-8
5.50 100 15 0.109 100 3.52
5.00 100 30 0.807 150 2.0
6.00 100 20 0.858 100 *
Total 1853 67.285 2500 *

Source: see Table 6.1A

  1.     Signature Bonuses

These are upfront payments made by the contractor and are generally non-recoverable. Signature bonuses were not included as parameters in Iraq’s bidding process, although they are applied elsewhere (e.g. Angola, Brazil, US Gulf of Mexico) (Tordo et al., 2010). Jiyad (2010a) expressed surprise that signature bonuses were not included in the bidding parameters in Iraq, arguing that where oilfields are highly prized and allocated by competitive bidding, signature bonuses may become a key factor. This was the case in Angola when the Chinese company Sinopec paid $2.2 billion in 2006 to outbid its competitors to gain the rights for oil and gas exploration in two blocks.

The model contracts in the three bidding rounds had different provisions for signature bonuses. The first bid round generated a total of $1500 million (Rumaila: $500m, West Qurna1: $400m and $300m each for Missan and Zubair) (Jiyad, 2010a:3). However, the first bid round bonuses were actually interest bearing loans at (LIBOR+1), payable with interest over five years, starting two years after the contract’s effective date (Iraq Ministry of Oil, 2009a:31). This is a most unusual form of signature bonus and was heavily criticised.In fact, it doesn’t make much sense to call it a bonus at all – it’s just a loan.

The second bid round generated $850 million in unrecoverable signature bonuses ($150m each for Halfaya, Majnoon and West Qurna2, and $100m each for Badra, Garraf, Najma and Qaiyarah) (Jiyad, 2010b:3). Contract terms improved as the government responded to the criticisms of the first bid round, but critics argued that the bonuses were still too small given the characteristics of the fields (production plateau, duration and total proven reserve) and qualitative aspects such as the quality of the crude, type of reservoir and location (Jiyad, 2010b). To compare once more with Sinopec’s deal in Angola: two exploration blocks with a high level of associated risk generated $2.2 billion in revenues, while in Iraq, eleven oil fields which are already producing around 1.6 million b/d, and which upon full development could produce 11.2mbd, generated $2.05 billion ($805m in bonuses and a further $1.2b in loans) (Jiyad, 2010a:3).

In the third bid round there were no signature bonuses. It appears that the government was desperate to encourage companies to invest in these non-producing gas fields in order to increase its production for both domestic and export use.

  1.     Remuneration Fee (RF)

These are the fees international oil companies receive for each barrel of oil produced. The RF was one of the two main bidding parameters in the bidding process; IOCs were competing against each other and against a pre-specified maximum RF the Oil Ministry was willing to pay. The RF varies according to oilfield parameters. The actual payment of RF is reduced by the R-factor[2], which is the ratio of cumulative cash receipts to cumulative expenditures. The R-factor is standard and fixed for all oil fields in the relevant model contract. In effect, the R-factor reduces the RF or the potential profitability of the project increases (Jiyad, 2010a; Iraq Ministry of Oil, 2009a).  This in turn reduces the company’s profitability in the next accounting period (see Table 4.3A).

   Table 4.3A: R-factor for first bid round (PFTSC)

Field 0<R<1










Rumaila 2.00 1.60 1.20 1.00 0.60
West Qurna1 1.9 1.52 1.14 0.95 0.57
Zubair 2.00 1.60 1.20 1.00 0.60
Missan 2.3 1.84 1.38 1.15 0.69

    Source: Iraq Ministry of Oil (2009a), Jiyad (2010a)      

   Table 4.3B: R-factor for second bid round (DPSC)

Field 0<R<1










West Qurna2 1.15 0.92 0.96 0.46 0.23
Majnoon 1.39 1.112 0.834 0.556 0.278
Halfaya 1.40 1.12 1.84 0.56 0.28
Garraf 1.49 1.192 0.894 0.596 0.298
Badra 5.50 4.4 3.3 2.2 1.1
Qaiyarah 5.0 4.0 3.0 2.0 1.0
Najma 6.0 4.8 3.6 2.4 1.2

Source: Iraq Ministry of Oil (2009a; 2009b), Jiyad (2010a)

As can be seen from the above tables, the R-factor’s effect on remuneration fees changed from 50% and 30% in the first bid round to 40% and 20% in the second bid round. These changes were to the advantage of the government as they meant Iraq had to pay less to IOCs in remuneration fees.

Remuneration fees can be reduced further if the net addition in production is lower than the agreed PPT (the second bidding parameter) (see Tables 4.1A and 4.2A). Jiyad (2010a:11) argues that companies adhering to the PPT could face a dilemma, as it may be incompatible withBest International Petroleum Industry Practices (BIPIP). Many experts question the production plateau target on the grounds that it is unrealistic, and even if it is achievable, it is not sustainable, or if it is obtained and sustained this might be at the expense of optimal depletion and inflict damage on the oilfield (Wells, 2009). Conversely, if an IOC commits to BIPIP, this could lead to production below PPT. In this scenario the contractor would be penalised according to their R-factor performance, or ROC could even terminate the contract.

[1] Work programme: oil companies make a commitment to undertake a specific exploration activity during a set period of time (Tordo et al., 2010)

[2] R-factor: is the ratio of cumulative receipts from the sale of petroleum to cumulative expenditures. An R-factor less than 1 would mean that costs have not been fully recovered yet: total expenditure exceeds total receipts. The larger the R-factor, the more profitable the operation. The government’s share of production may increase with increasing R-factor (Johnston, 2003).

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