Petroleum Fiscal Systems and Contracts

CONTENTS

1 CLASSIFICATION OF PETROLEUM FISCAL SYSTEMS

2 PROJECT EVALUATION

3 CONTRACTS

4 GOVERNMENT AND OPERATOR TAKES, COSTS AND TAXES

5 PROJECT ECONOMICS

6 FINANCE

7 TAXES

8 FIELD DEVELOPMENT PLANNING

9 GEOPOTENTIAL OF THE GLOBAL EXPLORATION MARKET

10 DIFFERENT TYPES OF PETROLEUM FISCAL SYSTEMS

11 HIGH RISK COUNTRIES

REFERENCES

APPENDICES

FIGURES

Figure 1-1 Classification of petroleum fiscal systems

Figure 1-2 Detailed classification of petroleum fiscal systems

Figure 1-3 Typical project contract conditions

Figure 1-4 Example concessionary system flow diagram

Figure 1-5 Example calculation of government and contractor take

Figure 1-6 Basic equations for royalty/tax systems

Figure 1-7 Concessionary system structure from the oil company perspective

Figure 1-8 Basic equations for contractual systems

Figure 1-9 Example production sharing contract flow diagram

Figure 1-10 Production sharing contract structure from the contractor’s perspective

Figure 1-11 Sample rate of return contract cash flow projection

Figure 1-12 Sample sliding scale royalty

Figure 1-13 Joint venture structure with a PSC

Figure 1-14 Typical joint venture in Russia

Figure 1-15 Three phase technical assistance contract (TAC)

Figure 2-1 Allocation of revenues from production

Figure 4-1 Government and Contractor take

Figure 4-2 Division of the costs and profit

Figure 4-3 Changing fiscal terms

Figure 5-1 Profitability measures

Figure 5-2 Sensitivities of fiscal model

Figure 5-3 Influence diagram for typical stages in project development

Figure 5-4 Value of information to demonstrate commerciality

Figure 5-5 Value of information for development optimisation

Figure 5-6 Comparing options

Figure 5-7 Project definition

Figure 5-8 Cost probability curves

Figure 5-9 Accuracy of estimates through project development

Figure 6-1 Hierarchy of legislation and contractual agreements

Figure 7-1 UK tax regime

Figure 8-1 Legal framework

Figure 8-2 PDO approval flow chart

Figure 8-3 PDO approval administrative process

Figure 10-1 Algerian fiscal system

Figure 10-2 Azerbaijani fiscal regime

Figure 10-3 Dubai fiscal regime

Figure 10-4 Egypt fiscal regime

Figure 10-5 Egypt fiscal regime

Figure 10-6 Example Iraqi service contract

Figure 10-7 Ireland fiscal regime

Figure 10-8 Libyan fiscal regime

Figure 10-9 Libyan fiscal regime

Figure 10-10 Libyan EPSA developments

Figure 10-11 Malta fiscal regime

Figure 10-12 Norway fiscal regime

Figure 10-13 Russian fiscal regime

Figure 11-1 Plentiful reserves in Iraq - oil comes to the surface in many places

Figure 11-2 Location of auctioned licenses (map printed in The Wall Street Journal)

Figure 11-3 Oil refinery near the village of Taq Taq in the autonomous Iraqi region of Kurdistan

TABLES

Table 4-1 Contractor take, cost recovery limits and government participation rates

Table 5-1 Present value of one time payment

Table 9-1 Recoverable conventional oil by region

Table 9-2 Examples of block sizes worldwide

ACKNOWLEDGEMENTS

I would like to thank the many people who gave me their time and their views on this book.

I am particularly grateful for the helpful suggestions, reviews and comments received from the following:

Rod Searle

Paul Jeffs

Dr Radhwan Al-Saadi

Dr Sebastian Lüning

Daniela Freise

Jan-Christoph Muhl

Manfred Böckmann

Uwe Radde-Toepperwien

Christoph Koch

Sven Schäfer

Dr Curt-Albert Schwietzer

Dr Hendrik Rohler

Dr Mohammed A Zaini

Dr Muhammed Mazeel

This book is a result of long years of work and the experiences gained in different countries and petroleum fields. The encouragement to write this book and related publications comes exclusively from my family. Special thanks to them.

INTRODUCTION

The petroleum fiscal system for a country is essentially the taxation structure, including royalty payments, that has been established by legislation. More broadly, the fiscal system includes all aspects of the contractual and taxation framework that governs the relationship between the host government and an international oil company. Worldwide, there are many different fiscal systems with different taxation and contractual terms. These vary from country to country and some countries use more than one system. Countries, for example, may offer concessionary system arrangements or service and production sharing agreements. Whichever system prevails, the issue for an oil company is how can it recover costs expended and how will the profit be divided. This depends upon tax regulations and the principles of the economics of the life of a field.

The focus of this book is on the mechanics of the various kinds of fiscal systems and the factors that drive exploration and development economics. The emphasis is on practical aspects of petroleum taxation and industry/government relationships. There is also fertile ground for considering the philosophy of petroleum taxation which has changed the industry. Legal and operational aspects of contract/fiscal terms are also examined to provide a foundation in the dynamics of international negotiations.

Both industry and government viewpoints are addressed in this book since a complete grasp of the subject requires an understanding of the aims and concerns of both sides. There are few things more discouraging for a government’s national oil company than an unsuccessful licensing round. Yet prolonged, inconclusive negotiations can be equally frustrating for oil companies.

This book has been written for those interested in petroleum taxation and international negotiations, and the way to carry out successful exploration and development projects. Much of the subject has evolved years ago whilst some aspects of taxation are timeless. Examples are included to give the reader a wide perspective about the implementation of fiscal systems.

The terminology has changed over the years and will continue to develop. There is little standardisation of terms in the industry and the abundance of jargon can be rather daunting. The subjects covered in this book are often simple concepts wrapped up with industry and legal jargon. A glossary is provided to help with this.

Much of the material provided here was inspired by questions most frequently asked on the subject. The best answers are supported with specific examples and many of these are used throughout the book. The summaries and analyses of various fiscal terms and contract conditions are believed to be accurate, and every practicable effort has been made to gather up-to-date information about the current conditions in the countries cited. Examples of fiscal terms used here are drawn from numerous public sources. Confidential information has been carefully excluded.

Perhaps more effort could be directed toward the cultural aspects of negotiations and doing business in the international arena. Unfortunately it is beyond the scope of this book to cover that ground.

1 CLASSIFICATION OF PETROLEUM FISCAL SYSTEMS

Petroleum fiscal systems whereby the owner of mineral resources receives levies from the extraction company can be classified into two main categories These are concessionary systems and contractual systems as shown in Figure 1-1.

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Figure ‎1-1 Classification of petroleum fiscal systems

In most countries, except the United States of America, the owner of the mineral resources is the government. In the USA, the owners are private individuals or companies that pay taxes on production to the state.

Worldwide, every country has developed its own petroleum fiscal systems to be applied. Under concessionary systems, the government will transfer title of the oil and gas to a company if they are produced. The producing company then pays royalties and taxes.

Contractual systems are in most cases either production sharing agreements or service contracts. The private companies under contractual systems have the right to receive a share of production or revenues from the sale of oil and gas in accordance with a production sharing agreement (PSA) or a service agreement (SA). The state companies either self produce or share the production and selling of the oil or gas. Revenues then flow into the finance ministries’ treasuries.

In most contractual systems, the facilities installed by the contractor within the host government’s territory become the property of the state either as soon as they are landed or upon start up or commissioning. Sometimes, the asset or a facility does not pass to the government until the expended costs have been recovered. This transfer of title for asset facilities does not apply to leased equipment or to equipment brought in by service companies.

The difference between service contracts and production sharing contracts depends on whether the contractor receives compensation in cash or in crude. Under a production sharing agreement, the contractor receives a share of production and hence takes title to this crude. In a concessionary system, the transfer of title occurs at the point of export instead of at the wellhead. In a service contract, there is no issue of title since the contractor gets a share of profits rather than production. Under some service agreements, however, the contractor has the right to purchase crude from the government at a discount. Despite the differences between the systems the same economic results are achieved.

When the contractor is paid a fee for conducting exploration and production operations, then this system is a risk service contract. The difference between risk and pure services contracts depends on whether there is a fee on the profits or not. The pure service contract is without risk in exploration and development. Consequently, this is usually used by conservative nationalised companies or by states that have capital but are lacking in technology and management capability.

The different fiscal systems are further illustrated in Figure 1-2, showing the differing points of transfer of title and methods of remuneration.

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Figure ‎1-2 Detailed classification of petroleum fiscal systems

In addition to the concessionary and contractual systems, which are the two most used systems, there are some further variations that could be considered as types of fiscal system.

The joint venture is a variant fiscal/contractual system. It is used where the national company and contractor company establish a working interest arrangement. This is found in both concessionary and contractual systems.

Technical assistance contracts (TACs) are sometimes used for enhanced oil recovery (EOR) projects or restoration and redevelopment managed under a production sharing agreement or a concessionary system.

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Figure ‎1-3 Typical project contract conditions

CONCESSIONARY SYSTEMS

Under a concessionary system, the state government grants a Concession or License to an international oil company (IOC) or a consortium which gives rights for a fixed period to explore for and produce hydrocarbons within a certain area (License Area or Block). The IOC may be required to pay a signature bonus or a license fee to the government to secure the Concession or License. Thereafter, the government will obtain compensation usually through royalty and tax payments when hydrocarbons are produced.

Concessionary systems are used by around half of the countries worldwide including the US, UK, France, Norway, Russia, Australia, New Zealand, South Africa, Colombia, and Argentina. These countries have fiscal regimes which vary widely in terms of royalty and tax rates, tiers of taxation and other features such as incentives to promote investment.

Examples of how concessionary arrangements work through paying royalties and taxes to the state in different tiers are shown in Figures 1-4 to 1-6. The first point of government tax may be royalty in the start as in Figure 1-4. This may be followed by local and federal level taxation on income after allowing for operating costs, depreciation, depletion and amortisation. The cash flow projection and the calculation of the net present value (NPV) and internal rate of return (IRR) of a project needs to take account of the full range of royalties and taxes to be applied.

Calculation of Government and Contractor Take

The concession agreement determines how profits will be shared between the government take and the contractor’s take. The balance between these is critical for investment in exploration and development activities.

Figure 1-4 shows a typical model of how revenue is distributed under a simple concessionary system. Royalties, deductions, and taxation are subtracted sequentially. The royalty, in this case 40% of the gross revenues, comes right off the top. The balance remaining after royalties is the net revenue. Certain deductions of contractor’s costs are allowable from the net revenue. These deductions include operating costs (Opex), depreciation, depletion, and amortisation (DD&A) and intangible drilling costs (IDCs). Most countries follow this DD&A format but will allow different rates of depreciation or amortisation for various costs. Some countries are liberal in allowing capital costs to be expensed.

Revenue remaining after royalty and deductions is called taxable income. In this example, it is subjected to two layers of taxation with 10% provincial tax and 40% federal tax. Since provincial tax is deductible against federal tax, the overall effective tax rate is 46%.

After tax deductions, the contractor share of profit is USD 6.48, making a share of gross revenues of USD 18.48. This equates to a contractor take of 47%. The profit in this example is USD 28 (USD 40 gross revenues minus USD 12 costs). This is different from contractor’s profit margin, which in this example is 16.2% (USD 6.48/USD 40).

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Figure ‎1-4 Example concessionary system flow diagram

Figures 1-5 and 1-6 further outline terminology and the hierarchy of arithmetic for calculating contractor cash flow. This example gives more of a financial perspective. The cash flow projection is based on the assumption that some classes of capital cost are intangible and are immediately deductible whilst tangible capital costs are depreciated over five years. The development example in Figure 1-5 is for a field with 50 MMbbl of recoverable oil. Total capital costs (Capex) are USD 174 million and estimated operating costs during the life of field (Opex) are USD 300 million. Production of the field is expected to generate gross revenues of USD 2 billion based on an oil price of USD 40 per barrel. Calculation of the respective takes comes from the cash flow projection. The government take of 52% is derived from 40% royalties plus 20% tax on net profit.

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Figure ‎1-5 Example calculation of government and contractor take

Basic Equations for Royalty/Tax Systems

Figure 1-6 sets out the basic equations for calculating net cash flow under a royalty/tax fiscal system.

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Figure ‎1-6 Basic equations for royalty/tax systems

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Figure ‎1-7 Concessionary system structure from the oil company perspective

PRODUCTION SHARING CONTRACTS

Production sharing contracts or agreements (PSCs or PSAs) give an international oil company (IOC) or consortium exploration and production rights for a fixed period in a defined Contract Area or Block. The IOC bears all exploration risks and costs in exchange for a share of the oil or gas produced. Production is split between the parties according to formulae in the PSC that may be fixed by statute, negotiated, or secured through competitive bidding. If the IOC does not find a commercial discovery, there is no reimbursement of costs by the government.

The advantage to the host government of this system is that the government will generally receive a large share of the oil or gas. This can be sold and the revenue used according to the government’s development programmes and economic needs. Following the introduction of PSCs in Indonesia in the mid 1960s, they are now also used in Malaysia, India, Nigeria, Angola, Trinidad, the Central Asian Republics of the Former Soviet Union, Algeria, Egypt, Yemen, Syria, Mongolia, China, and many other countries.

Essentially, control of the oil remains with the state. National companies are maintained to manage the resource whilst the contractors have execution responsibility. Contractors are required to submit a programme and a budget to be approved by the national company. The type of contact depends on the level of reserves and political economic aims of the host government.

It is important to note in such contracts both the level of percentage of recovery of costs and also the way in which the exploration or development costs may be recovered. If there is costs recovery before sharing of production, the contractor is allowed to recover the costs out of net revenues. The costs recovery limit is the only true distinction between concessionary systems and PSCs. The amount of revenues remaining after royalty and cost recovery, is termed profit oil or profit gas. This is the equivalent of taxable income in a concessionary system. Within the service agreement, it would be termed the service fee rather than profit oil or gas. The contractor share of profit oil or gas is taxed at the rate of sharing.

Basic Equations for Contractual Systems

Figure 1-8 sets out the basic equations for calculating net cash flow under a product sharing contractual system.

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Figure ‎1-8 Basic equations for contractual systems

The example in Figure 1-9 illustrates the way in which the contractor and government shares may be calculated in a production sharing contract.

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Figure ‎1-9 Example production sharing contract flow diagram

Contractor Take

In Figure 1-9, with one barrel of oil worth 40 USD, the total profit is USD 16. Considering the 20% royalty, profit oil split, and taxation, the contractor share of profits is 20%, or USD 3.2. The presence of a cost recovery limit forces some profit sharing under all circumstances where production is achieved.

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Figure ‎1-10 Production sharing contract structure from the contractor’s perspective

Cash Flow Projection

In the cash flow projection example illustrated in Figure 1-11 the calculation of government and contractor takes can be seen. It is necessary to define the royalty, cost recovery limit, DD&A, profit oil split and taxes. The gross revenues, less the total costs, then gives the total profit, less the government profit oil and taxes. The results are the respective contractor take and government take.

The PSC terms include:

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The development costs are all capitalised, and depreciation starts when production begins. The last column, net cash flow, is the undiscounted cash flow.

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Figure ‎1-11 Sample rate of return contract cash flow projection

Basic Elements

There are two basic elements in the production sharing fiscal structure. The first is the operational element and the second is the revenue or production sharing element. Each of them have national legalisation and contractual aspects. The national legalisation aspects such as government participation, mediation, insurance and ownership transfers are unchangeable in the operational period, as are revenue factors (royalties, taxation, depreciation rates, investment credit and domestic obligations). The contract conditions, however, are negotiable. For example, the oil ministry can negotiate the split of oil but cannot negotiate the tax rate which is fixed. The oil companies are able to negotiate the structure of production sharing contracts. Negotiable aspects include the area of lease, work commitment, commerciality, renouncement, bonus payments, cost recovery limits, and production sharing percentages.

Work commitments are generally defined in terms of kilometres of seismic data to be acquired and the number of wells to be drilled. There are some cases, however, where only seismic commitments are defined and drilling is optional.

Bonus Payments

Cash bonuses are sometimes paid upon finalisation of negotiation and contract signing, or these will be paid when production reaches a certain cumulative level. Sometimes part of the costs of equipment is calculated as a bonus. Production bonuses may be payable at the start of production or when a certain level of accumulated production is achieved.

Royalties

The basic concept of royalties which is similar under all fiscal systems is that royalties are taken straight off the top of gross revenues.

Many production sharing contracts (PSCs) do not have a normal royalty because of the ownership issue. Payment of royalty implies ownership on the part of the royalty payer but in a PSC the contractor has no ownership at this stage. The primary reason that this terminology is used is because of the hierarchy of the arithmetic associated with royalties. Where PSCs do include a royalty, this can typically range as high as 15%. A PSC royalty is treated just as it would be under a concessionary system; it is the first calculation made. The royalty level is clearly very important and rates above 15% may be considered by the contractor as excessive. Governments may now scale royalties accordingly to the field size since it can be inefficient and counterproductive if royalties are set too high.

Sliding Scales

A characteristic encountered in many petroleum fiscal systems is the sliding scale (or progression of steps) used for royalties, taxes, and various other items. The aim is to create a flexible system with sliding scale terms so that as production rates increase, government take increases. Terms can be set appropriately for the development of varying sizes of field. Some contracts will provide flexibility through a progressive tax rate. Others will tie more than one variable to a sliding scale such as cost recovery, profit oil split, and royalty. The most common approach is an incremental sliding scale based on average daily production.

The following example, Figure 1-12, shows a sliding scale royalty that steps up from 5% to 15% on portions of the daily production rate. If average daily production is 20,000 bopd, the aggregate effective royalty paid by the contractor is (10,000 bopd at 5% + 10,000 bopd at 10%).

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Figure ‎1-12 Sample sliding scale royalty

Production levels in sliding scale systems must be chosen carefully. If rates are too high, then the system effectively does not have a flexible sliding scale. In some situations steps of 50,000 bopd can be too high or conversely 10,000 bopd steps may be too low. The choice should be determined by the anticipated size of discoveries.

SERVICE CONTRACTS

Many service agreement are identical to PSCs in all but the method of payment, either by production sharing or profit sharing. Many service agreements, however, have unique contract elements that are used in calculating the service fee.

Pure Service Contracts

A pure service contract is one where the contractor carries out exploration and/or development work on behalf of the host government for a fee and the contractor bears no exploration risk. This kind of contract is not used widely but may be used sometimes, typically in the Middle East, where the state has substantial capital but seeks only expertise. Examples exist in Iran, Saudi Arabia, the Philippines and Kuwait.

The pure service contract is similar to contracts used in the oil service industry with companies such as Halliburton and Schlumberger where the contractor is paid a fee for performing a service. Examples are contracts placed for drilling services, development services and some exploration services. Drilling service contracts may be let as pure service arrangements e.g. whereby the contractor is paid on a footage basis while drilling and on an hourly basis for completion and testing operations.

Risk Service Contracts

A risk service contract is radically different from a pure service contract and bears little similarity to an oil service industry service contract.

Under a risk service contract awarded by a host government, the contractor provides all capital associated with exploration and development of petroleum resources, bearing all the exploration risk. If exploration is successful, the contractor is allowed to recover costs through sale of the oil or gas and also receives a fee based on a percentage of the remaining revenues. This fee is often subject to taxes.

As well as bearing exploration risk, the contractor does not get a share of production. However, although there is no production sharing or profit oil, the contract terms allow the contractor a share of revenues similar to that derived from a share of production in a PSC. The host government maintains ownership of the hydrocarbons produced and the contractor does not acquire any rights to oil and or gas unless the contractor is paid its fee in kind as oil or gas. The contractor may also be given preferential rights to purchase production from the government.

OTHER FACTORS THAT INFLUENCE PRODUCTION SHARING CONTRACTS Rate Of Return Contracts

Some countries have developed progressive taxes or sharing arrangements based on project rate of return (ROR). As with sliding scale systems, the ROR system is used to ensure that terms are flexible and that government take increases appropriately with increased production. Unlike sliding scale taxes and other attempts at flexibility based on production rates, ROR is more progressive since it is based on a direct measure of profitability. ROR systems take into account product prices, costs, timing, and production rates. All these factors influence project profitability.

Under an ROR contract, the government does not receive payments until the contractor has recovered its initial financial investment plus a predetermined threshold rate of return. The government share is calculated by accumulating the negative net cash flows and compounding them at the threshold rate until the cumulative value becomes positive. When that happens, additional resource rent taxes (RRT) are levied but the contractor still receives some of the profits in excess of the threshold rate of return.

Contracts with Factors

Some contracts use factors such as R, K, a and b factors.

The most common use of such a factors is found in Algerian, Tunisian, Colombian and Peruvian contracts. In these contracts the definitions are virtually identical:

R factor = Accrued Net Earnings/Accrued Total Expenditures.

R = X/Y

Where:

X = Cumulative net revenue actually received by the

contractor. This equals turnover (gross revenues) for all

tax years less taxes paid.

Y = Total cumulative expenditure (exploration and appraisal expenses and operating costs) actually incurred by the contractor from the date the contract is signed.

Some variants on the use of R factors are given below.

Tunisian R Factor with Sliding Scale Taxation

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Colombian R Factor

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Where:

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Colombian Sliding Scale R Factor

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In these contracts the R factor is based on a return on investment (ROI). Once the contractor has received his costs plus 50%, or an ROI of 150%, the tax rate increases from 50% to 55%. In some respects it is similar to a rate of return (ROR) contract but a typical ROR contract triggers on internal rate of return (IRR).

JOINT VENTURES WITH GOVERNMENT PARTICIPATION

International oil companies often form joint venture (JV) partnerships with industry partners to share risk and reward for large scale or high risk ventures. Joint ventures may also be formed with direct government participation.

In a pure joint venture, the host government and the contractor would share equally in costs and risks but in practice the extent of government participation varies. In most JVs with government participation, the contractor oil company bears the costs and risks of exploration so that the government is carried through exploration. In some of the proposed Russian JVs which apply to proven and well-delineated reservoirs there is a 100% carry for the production association partner through development including operating costs

Government participation has the effect of reducing the potential rewards of exploration. Where the government actually pays its share of JV costs, the government share of profits cannot be considered as a tax on income. However, if government is carried through exploration, government participation acts like a capital gains tax. In extreme cases such as Russia where the contractor pays all rehabilitation, development and operating costs, the government share of JV profits constitutes an added layer of taxation.

The contractor will recover exploration and development costs by means of either cost recovery, deductions, or direct reimbursement but there is an important difference of timing between direct reimbursement and cost recovery.

Figure 1-13 illustrates an example of how a contractor/government joint venture operates. Here, the government through the national oil company is a 30% working interest partner. The proceeds are divided under a PSC with a 60%/40% profit oil split in favour of the contractor group. The contractor group here, however, includes the government as a partner. Both partners receive their pro-rated share of cost oil and profit oil is split according to working interest shares.

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Figure ‎1-13 Joint venture structure with a PSC

Figure 1-14 shows an alternative example for a typical Russian JV.

The Extent of Government Participation in a Joint Venture

The range of government participation can be characterised from Light to Heavy:

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Figure ‎1-14 Typical joint venture in Russia

TECHNICAL ASSISTANCE CONTRACTS (TACs)

Technical assistance contracts (TACs) are commonly applied for work on existing fields in production or abandoned fields with the purpose of field rehabilitation, redevelopment, or enhanced oil recovery (EOR) projects. The contractor will undertake to provide capital and specialist expertise and will take over control of operations including equipment and personnel if applicable.

If there is existing production, a production profile with a specified decline rate is negotiated. Future production as defined by the negotiated decline rate is exempt from the sharing arrangement and goes directly to the government. Increased production above the negotiated rate is deemed to be due to the contractor’s technical assistance. This incremental production is normally subject to a production sharing arrangement although TACs can be found under a variety of systems. Figure 1-15 outlines a three phase TAC. The decision to proceed is based on the technical results of each previous phase.

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