The Economics of Oil and Gas 1911116274, 9781911116271

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THE ECONOMICS OF OIL AND GAS

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The Economics of Big Business This series of books provides short, accessible introductions to the economics of major business sectors. Each book focuses on one particular global industry and examines its business model, economic strategy, the determinants of profitability as well as the unique issues facing its economic future. More general cross-​sector challenges, which may be ethical, technological or environmental, as well as wider questions raised by the concentration of economic power, are also explored. The series offers rigorous presentations of the fundamental economics underpinning key industries suitable for both course use and a professional readership. Published The Economics of Airlines Volodymyr Bilotkach The Economics of Arms Keith Hartley The Economics of Cars Fabio Cassia and Matteo Ferrazzi The Economics of Construction Stephen Gruneberg and Noble Francis The Economics of Music Peter Tschmuck The Economics of Oil and Gas Xiaoyi Mu

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THE ECONOMICS OF OIL AND GAS XIAOYI MU

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© Xiaoyi Mu 2020 This book is copyright under the Berne Convention. No reproduction without permission. All rights reserved. First edition published in 2020 by Agenda Publishing Agenda Publishing Limited The Core Bath Lane Newcastle Helix Newcastle upon Tyne NE4 5TF www.agendapub.com ISBN 978-​1-​911116-​27-​1 (hardcover) ISBN 978-​1-​911116-​28-​8 (paperback) British Library Cataloguing-​in-​Publication Data A catalogue record for this book is available from the British Library Typeset by Newgen Publishing UK Printed and bound in the UK by TJ International

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CONTENTS

Preface  List of abbreviations  1. Introduction 

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2. Exploration, development and production 

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3. Licensing and fiscal issues 

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4. Petroleum transportation 

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5. Refining and marketing 

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6. Natural gas 

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7. Oil prices and OPEC 

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References  List of figures and tables  Index 

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PREFACE

This book has grown out of a course that I have been teaching since 2008 at the Centre for Energy, Petroleum and Mineral Law and Policy (CEPMLP) at the University of Dundee to postgraduate law, business and economics students. Although the interest in understanding the economics of oil and gas has never faded, there is a lack of an updated text covering the entire value chain of the petroleum industry. Partly for this reason, I agreed to write this book when the publisher approached me a couple of years ago. The book is primarily intended to provide students in business, economics, law, engineering and other related subjects with an introduction to the workings of the petroleum industry. It is also aimed at professionals who want a perspective and understanding on energy economics and policy, including such questions as these: are we running out of oil? What is the value of a petroleum find? How to monetize a gas discovery? Why is the oil price so volatile? Why is there a disparity between changes in crude oil price and gasoline prices at the pump? Can the “shale gas revolution” occur outside the United States? And why is it that countries with abundant natural resources do not always grow rapidly? These are important and exciting questions, and the interest in them is certainly not limited to those who might want a career in the petroleum industry or policy areas dealing with petroleum and energy issues. The emphasis of this book is the economics of the oil and gas industry, from upstream exploration and production to downstream refining and marketing. At each stage of the value chain we will present the economic theory and analytical tools, along with the technical and institutional knowledge necessary

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Preface

to understand the economic and policy issues. The gas industry is specifically discussed with an emphasis on ways of monetizing gas. The book begins with a chapter on why oil matters and the characteristics it has that make it difficult to be substituted by other fuels. We then move on to the relationship between oil price movements and macroeconomic performance, for both net oil-​importing countries and net oil-​exporting countries. This includes the nexus between oil price and economic growth rate, inflation and other macroeconomic indicators. For oil-​exporting countries, the focus is on understanding the “resource curse” and “Dutch disease”. Chapter 2 starts with a layman’s introduction to the technical aspects of petroleum exploration, development and production. The bulk of the chapter focuses on the economic concepts and analytical tools used for business decision-​making. For exploration, the emphasis is on the risks associated with the uncertain outcomes and methods of managing these risks. The calculation of expected monetary value and the decision tree as analytical tools for managing the exploration risks are illustrated. For development, we  introduce development planning, rate sensitivity, the common pool problem and unitization. For production, the focus is on production modelling with the introduction of different recovery methods. The optimal allocation of production over time is also discussed. In most countries other than the United States, the mineral rights of underground resources belong to the state. Consequently, the upstream petroleum industry has developed a system of rather unusual contracts. This is the focus of Chapter 3. We first provide an overview of the main international petroleum agreements, namely the concession system, production-​sharing contracts and risk service contracts, before moving on to the economic analysis. Financial modelling under different fiscal systems is illustrated with a few examples. Transportation connects the upstream and downstream industries. To stay focused, Chapter 4 considers only maritime transport and pipelines. In the section on tankers, we reiterate the concept of economies of scale in transportation and provide information on tanker jargon. For pipelines, we discuss the implications of the economies of scale, including the natural monopoly, the regulation of tariffs and third-​party access. As there is an increasing demand for cross-​border pipelines, the political economy and key challenges of cross-​ border pipelines are also discussed.

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Preface

Chapter  5 deals with the downstream side of the petroleum industry value chain, namely refining and marketing. The chapter starts with the technical background of the refining process, noting the global trend of tightening specifications for refined petroleum products. The economics of refinery operations again features significant economies of scale. The chapter presents estimates of the relationship between the investment required for a refining unit and its capacity. Countries that recently discovered oil may consider whether and where to build a refinery. Refinery location –​whether a refinery is better located near markets or the source of crude oil supply –​is also addressed. For marketing, we first present an overview of the marketing channels of international oil companies (IOCs) and highlight the rationale for changes. We then discuss the pricing issues of refined petroleum products. In developed countries, refined products are heavily taxed. Arguments for taxing petroleum products are presented. In developing countries, particularly the oil-​producing countries, the price is often controlled and subsidized; the effect of price control and subsidization is therefore analysed. As the upstream side of natural gas is covered in Chapter  2, Chapter  6 focuses on the monetization of natural gas and covers five topics. First, a brief introduction to the physical characteristics of natural gas, particularly the environmental attributes, and a general overview of natural gas consumption by sector are given. We then take a closer look at liquefied natural gas (LNG), including the evolution of the LNG industry, the cost structure, the traditional business model and the emergence of spot and short-​term markets. The third section provides an overview of gas-​to-​liquids (GTL) technology, noting its opportunities and challenges. The fourth section discusses gas pricing in the world. Finally, the chapter concludes with a review of shale gas development in the United States. Given the vital role of oil price to both the petroleum industry and the wider economy, Chapter 7 focuses on the understanding of oil prices. It begins with a history of oil prices going back to the birth of the modern oil industry in 1859, when the first commercially successful well was drilled in Titusville, Pennsylvania. This is followed by an economic analysis of oil price determination. The pricing policies of the Organization of the Petroleum Exporting Countries (OPEC) are discussed in light of a dominant firm model, as well as the recent empirical literature on OPEC behaviour. To help us understand the long-​and short-​run dynamics of oil prices, we introduce a widely used

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Preface

two-​factor model and a trend-​cycle model in the next section and discuss the insight gained from these models. In addition, a detailed account of the price formation mechanism in physical markets is also given. The chapter ends with an introduction to energy derivatives, particularly futures market. In writing this book, I  seek to explain economic concepts and theories in simple terms with the occasional aid of graphical presentations. Most of the content of the book is accessible to people with non-​mathematical backgrounds. At the same time, I  also include some model derivations for those who would appreciate a more rigorous treatment of the analytical tools, and provide references for further reading. The book was born out of the course notes on petroleum economics and policy that was first developed by Professor Paul Stevens, who taught this course until 2007. I am extremely grateful to Paul for his kindness in allowing me to use the notes in the first instance. An earlier draft of the book was critically reviewed by two anonymous reviewers, whose comments and suggestions have helped improve the quality of the book. I am also thankful to colleagues at CEPMLP who have encouraged me in one way or another during this journey, to Hanchen Xiao and Dilip Jena for very able assistance and to Steven Gerrard at Agenda for his patience and flexibility in publishing this book. Of course, I am the only one responsible for any remaining errors and omissions.

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LIST OF ABBREVIATIONS

$/​bbl dollars per barrel ADU atmospheric distillation unit API American Petroleum Institute bbl barrel bbl/​d barrels per day b/​cd barrels per calendar day BCF billion cubic feet BFOE Brent, Forties, Oseberg and Ekofisk b/​sd barrels per stream day CCGT combined-​cycle gas turbine CHP combined heat and power CIT corporate income tax CNG compressed natural gas DOT Department of Transportation (US) DWT deadweight tonnage E&P exploration and production EIA Energy Information Administration (US) EMV expected monetary value EOR enhanced oil recovery FCC fluidized catalytic cracking FDI foreign direct investment FERC Federal Energy Regulatory Commission FOB free on board FSU former Soviet Union

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List of abbreviations

GDP GTL GWh ICE IEA IGU IOC LNG LPG MCF MER MMbbl MMBTU MMCF MMCM MMscfd MMTPA MNC Mtoe NBP NCI NGLs NOC NPV NYMEX OECD OFGEM OOIP OPEC OTC PRA PSC PV ROR RRT RSC

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gross domestic product gas to liquids gigawatt hour (1 billion watt hours) Intercontinental Exchange International Energy Agency International Gas Union international oil company liquefied natural gas liquefied petroleum gas thousand cubic feet maximum efficient rate (of recovery) million barrels million British thermal units million cubic feet million cubic metres million standard cubic feet per day million tons per annum multinational company million tons of oil equivalent National Balancing Point Nelson complexity index natural gas liquids national oil company net present value New York Mercantile Exchange Organisation for Economic Co-​operation and Development Office of Gas and Electricity Markets (UK) oil originally in place Organization of Petroleum Exporting Countries over-​the-​counter (transaction) (oil) price-​reporting agency production-​sharing contract present value rate of return resource rent tax risk service contract

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List of abbreviations

TCF TPES TSO ULCC UNCTAD VAT VDU VLCC VOM WACC WTI

trillion cubic feet total primary energy supply transmission system operator ultra-​large crude carrier United Nations Conference on Trade and Development value-​added  tax vacuum distillation unit very large crude carrier variable operating and maintenance (cost) weighted average cost of capital West Texas Intermediate

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INTRODUCTION

Oil has become so central to modern civilization that language strains to convey its importance; the common metaphors for its role –​linchpin, lifeblood, prize –​seem tired and inadequate.1 Why petroleum matters Oil and gas are used in almost every aspect of modern life –​in our homes, in businesses, in industry and for travelling. Oil not only fuels the cars and trucks that we drive and aeroplanes that we fly but also provides plastics and chemicals, as well as many lubricants, solvents, waxes, tars and asphalts. Nearly all pesticides and many fertilizers are made from oil or oil by-​products. Similarly, gas is one of the most important fuels for generating electricity. It can also be directly burnt for cooking, and for heating houses, buildings and water. It is an important fuel for powering many industrial operations, including iron and steel foundries, aluminium or nickel smelters and many manufacturing industries. Both oil and gas are important petrochemical feedstocks for producing fertilizers and a wide range of industrial and consumer goods, including plastics and polymers, textiles and paints, detergents and perfumes. Partly because of its wide usage, oil becomes the largest single item in international trade, measured in value terms.2 It is also the most actively traded commodity in centralized exchanges such as the New York Mercantile Exchange (NYMEX) and the Intercontinental Exchange (ICE).3 The significance of oil

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BOX 1.1  WHAT IS CRUDE OIL AND WHAT ARE PETROLEUM PRODUCTS?

Petroleum is a mixture of hydrocarbons and was formed from the remains of animals and plants (diatoms) that lived millions of years ago in a marine environment before the existence of dinosaurs. Heat and pressure from these layers turned the remains into what we now call petroleum. The word “petroleum” means rock oil or oil from the earth. Crude oil is the hydrocarbon mixtures produced from underground reservoirs that are liquid at normal atmospheric pressure and temperature. Natural gas is the hydrocarbon mixtures that are gaseous at normal atmospheric pressure and temperature; the gas mixtures consist largely of methane –​the smallest natural hydrocarbon molecule (CH4). Petroleum products are fuels made from crude oil and other hydrocarbons contained in natural gas. Petroleum products can also be made from coal, natural gas and biomass. Source: www.eia.gov.

and gas as energy resources is best demonstrated by their shares in world total primary energy supply (TPES). As shown in Figure 1.1, even with the boost of renewables in recent years, oil and gas together still provided more than 50 per cent of world primary energy supply as of 2016.4 For statistical purposes, the use of oil and gas is usually categorized into energy use and non-​energy use. When they are burnt to produce energy or transformed as another fuel, it is referred to as energy use. Energy use can be further divided into four sectors:  residential, commercial, industry and transportation. Non-​energy use includes those used as raw materials in the different sectors –​that is, not consumed as a fuel or transformed into another fuel. For example, most lubricants and bitumen are used for non-​ energy purposes. Similarly, natural gas can be used as a raw material for the petrochemical industry, etc. Residential use of energy includes heating, cooking, lighting, air-​ conditioning, home appliances such as refrigerators and washing machines, and electronics in our homes. The ways we use energy in homes vary 2

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Figure 1.1  World total primary energy supply by fuel (Mtoe), 1990–​2016 Source: IEA (2018a).

Lighng and other 26% Refrigerators 4% Aircondioning 8%

Space heang 43%

Water heang 19%

Figure 1.2  Share of households’ energy consumption (United States), 2015 Source: Energy Information Administration, Table CE3.1, “Annual household site end-​use consumption in the U.S. –​totals and averages, 2015”; available at: www.eia.gov/​consumption/​ residential/​data/​2015/​c&e/​pdf/​ce3.1.pdf.

substantially over time and across countries. Figure 1.2 depicts the share of energy use in homes in the United States. Space heating has the largest share of residential energy consumption, which is followed by lighting and other appliances. As income increases, refrigerators, cooking equipment such as gas hobs and microwaves, and washing machines become ever more popular. It is 3

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Energy use per capita (kWh)

increasingly common for homes to use multiple televisions and computers. Additionally, as the home electronics market is constantly innovating, new products such as digital video recorders, game systems and rechargeable electronic devices are becoming integral to our modern lifestyle. As a result of these changes, appliances and electronics now account for nearly one-​third of all energy used in US homes. In general, households use more energy as income grows and living standard improves. As can be seen in Figure  1.3, there is a clear, positive correlation between per capita energy consumption and per capita gross domestic product (GDP), an indicator of income, among countries in the world. Commercial use of energy mainly refers to the heating, lighting and –​to a lesser extent  –​cooking in commercial buildings. Examples of commercial buildings include but are not limited to the following: offices, hospitals,

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Figure 1.3  Energy use per capita versus GDP per capita, 2013 Notes: The figure shows the correlation between per capita energy consumption and GDP in 2013; the size of each bubble represents the total GDP of the country. The international dollar is a hypothetical currency unit used by economists and international organizations to compare the value of different currencies. An international dollar has the same purchasing power as the US dollar has in the United States at a given point in time. Source: Our World in Data, “Energy production and changing energy sources”, available at: https://​ ourworldindata.org/​energy-​production-​and-​changing-​energy-​sources.

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1973 Nonenergy use 11.80%

2016 Non-energy use 16.60%

Residenal 13.40%

Other 10.20% Industry 19.90%

Navigaon 6.80% Rail 1.70% Road 30.80%

Industry 7.80% Aviaon 7.80%

Other 5.70% Navigaon 6.70% Rail 0.70%

Aviaon, 5.40% Total: 2,252 Mtoe

Residenal 5.40%

Road 49.30% Total: 3,908 Mtoe

Figure 1.4  World oil consumption by sector (Mtoe), 1973 & 2016 Note: “Other” includes agriculture, commercial and public services, pipeline and non-​specified transport and industry. Source: IEA (2018b).

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schools, police stations, churches, warehouses, hotels, libraries and shopping malls. In the industry (manufacturing) sector, there are many different uses of energy sources. One main use is as boiler fuel, which means producing heat that is transferred to the boiler to generate steam or hot water. Another use is as process heating and involves using energy to directly raise the temperature of products in the manufacturing process; examples are separating components of crude oil in petroleum refining, drying paint in automobile manufacturing and cooking packaged foods. A list of energy-​intensive industries would include iron and steel, basic metals, mining, construction and the energy use in the chemical industry. Transportation use of energy includes energy used by cars, trucks, aeroplanes, ships, railways and tractors in farms. Figure 1.4 shows the world oil consumption by sector in 1973 and 2016. Clearly, the transportation use of world oil consumption has expanded quite significantly (more than doubled) during the past 45  years, while all other factors have remained largely flat. In 2016 the transportation sector, including road transportation, aviation, rail and navigation, accounted for 65 per cent of the total final consumption of oil. Physical characteristics of oil Out of the primary energy sources, oil has certain key advantages because of its physical characteristics: its fluidity and its energy content. The fact that oil is a liquid attracts considerable economies of scale. The capital cost –​in particular, the material of a storage tank –​is largely determined by its surface area. However, the output of the tank is determined by the volume, and there exists an exponential relationship between the two. For example, the volume of a circular tank is the product of the square of its radius multiplied by pi (π) and the height, whereas the surface area is the product of the circumference and the height. Although the surface area is linear in the radius, the volume is squared.5 The point is illustrated in Figure 1.5. When the size of the tank doubles, the surface area increases by four times but the volume increases by eight times. As a result, the unit cost of the materials used in the storage tank halves. The example is illustrated using a storage tank. It works equally well for other stages of the petroleum industry such as pipelines, refinery towers and ocean-​going tankers. 6

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Height = 1 m Diameter = 1 m Surface area = 3.14 m2 Volume = 0.785 m3

Height = 2 m Diameter = 2 m Surface area = 12.56 m2 Volume = 6.28 m3

Figure 1.5  Comparison of unit storage costs between a big tank and a small tank Note: Because the materials cost of making the tanks is roughly proportional to the surface area of the tanks, doubling the size of the tanks reduces the average cost by 50 per cent.

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Figure 1.6a  Heat content of oil and different types of coal by weight

In addition, relative to other fuels, oil has a high energy density. Figures 1.6a and 1.6b make the comparison. Compared to coal, oil contains twice as much energy as coal on the same weight bases. Hence a ton of oil contains some 50 per cent more energy than a ton of bituminous coal. Compared to gas, oil contains 1,000 times more energy than the same volume of gas. As can be seen, gas in its natural state has virtually no energy content. The low energy content of gas in its natural state implies serious constraints for transporting gas, a point that will be discussed in great detail in later chapters. These two physical characteristics of oil provide two distinctive advantages for oil as a primary energy resource. First, because of the large economies of scale and high energy density, oil can be conveniently transported and stored, which greatly reduces the average transportation and storage cost. The low 7

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Figure 1.6b  Heat content of oil and gas by volume (at standard temperature and pressure) 160 140

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Figure 1.7  World crude oil prices, 1992–​2016

average transportation cost makes the market for crude oil a truly international market. This can be seen from Figure 1.7. Crude oil prices tend to be uniform throughout the world, in the sense that prices in different regions tend to move together and any price differential, adjusted for quality, will disappear quickly through arbitrage.6 In other words, the “law of one price” (LOOP) applies in the crude oil market. 8

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Introduction

Biofuel 5%

Others 3%

Natural gas 3%

Jet fuel 13% Diesel 22%

Gasoline 54%

Figure 1.8  Energy consumption in US transportation sector by sources, 2017 Notes: The data are based on energy content. “Gasoline” includes motor gasoline and aviation gasoline, excluding ethanol. “Others” includes electricity, liquefied petroleum gas, lubricants, residual fuel oil and propane.

Second, the high energy content and fluidity offer flexibility and convenience of use, making it difficult for oil products to be substituted for certain usage. For example, in the transportation sector, oil is still the dominant fuel even in advanced economies. Figure 1.8 shows the share of energy consumption by sources for the transportation sector in the United States in 2017. Petroleum products provided about 92 per cent of the total energy the US transportation sector used. Biofuels, such as ethanol and biodiesel, contributed about 5 per cent and natural gas contributed about 3 per cent. Despite the impressive increase in electric vehicle sales, electricity provided less than 0.3 per cent of the total energy used in transportation. The macroeconomic and political influence of oil As an important energy source, oil also matters in the broader economic and political sphere. Changes in oil prices have been shown to have significant effects on the macroeconomy, although the effect differs between oil importers and oil exporters. 9

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Channels of oil influencing the economies of importing countries For oil importers, oil importation often represents a major drain on the balance of payments and has a positive correlation with the inflation rate. It also raises important concerns over import dependence and supply security. Oil price shocks can affect the economy through several channels, including consumer demand, the supply of goods and services (production) and physical product rationing. Because the demand for petroleum products is inelastic, especially in the short run, the share of expenditures by consumers and firms on petroleum goes up when the oil price increases.7 If the oil shock is known to be temporary, consumers may make minimal adjustments to the rest of their spending and temporarily finance the additional oil consumption through savings. However, in practice, consumers do not know the duration of a price hike, and many or most would instead reduce their spending on other goods and services to pay for the more expensive fuel needed for daily life. Because expenditures on oil imports go abroad and not to the domestic economy, they do not count towards GDP, so the immediate effect of an increase in the price of an imported good, such as oil, that has inelastic demand is to decrease consumption of domestic goods and services and thus to decrease GDP. This effect on reducing domestic demand is as if the wealth of consumers were reduced, so this channel is sometimes referred to as the wealth channel. This

BOX 1.2  BALANCE OF PAYMENTS

The balance of payments is a record of accounts reflecting a country’s economic transactions with the rest of the world. It has two components: the current account and the capital account. The current account consists of the balance of trade (the physical movement of goods) and the trade in services such as banking, insurance, tourism and other intangibles. The capital account consists of long-​run and short-​run capital movements. There then has to be a balance through changes in foreign exchange reserves. A payment for the importation of oil is clearly a debit item to the current account.

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channel can be large. For example, if net oil imports are 2 per cent of the GDP of the importing country, a 10 per cent increase in the price of oil causes a reduction in spending on everything else and reduces GDP by 0.2 per cent. The extent to which this channel is offset depends on the source of the oil price increase. For example, an increase in overall world economic activity that drives up the demand for and price of oil would expand exports, at least partially offsetting the increased price of oil imports. An oil price increase, like a change in the relative price of any other good, also changes the composition of demand as consumers shift spending from items that are energy-intensive (such as air travel and cars with low fuel efficiency) to goods and services that are less energy-​intensive. Consequently, products of energy-​intensive sectors become more expensive, and those sectors will see a reduction in demand, and, even within sectors, demand can shift across products, such as to cars with greater fuel efficiency. Moreover, to the extent that shifting from energy-​intensive goods reduces purchases of durables such as automobiles or refrigerators, spending today is shifted into the future, depressing aggregate demand. Although this compositional shift increases demand in less energy-​intensive sectors, it takes time for displaced workers to find alternative employment, so incomes decline and unemployment rises. Oil price increases can also reduce economic activity through the supply side of the economy. To the extent that energy prices broadly move with oil prices, an increase in oil prices makes energy a more expensive factor of production, so firms will strive to reduce energy consumption and expenditures. Although capital and labour substitute for energy in the long run, in the short run they can be complements in production because of fixed technologies, so higher energy costs can result in layoffs in energy-​intensive firms and industries. Because it takes time for displaced workers to find jobs, incomes decline and unemployment rises. This supply-​side channel matters most if price increases are long-​lasting, and, because capital and labour are being used less efficiently, could also be associated with a slowdown or decline in productivity growth. There is a large body of empirical literature examining the link between oil prices and the macroeconomic performance for both oil-​importing countries and oil-​exporting countries. The results from early studies in the literature, mostly based on samples from Organisation for Economic Co-​operation and

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Development (OECD) countries, particularly the United States, suggest that oil price fluctuations, implicitly assumed to result from changes in oil supply, had significant and negative effects on the economy (see, e.g., Hamilton 1983, 1996). For instance, Hamilton (1983) shows that all US recessions but one since the Second World War were preceded by spikes in oil prices. However, more recent studies (e.g. Blanchard & Galí 2007) point to a weakening relationship between oil prices and economic growth. These authors find much larger effects from oil price shocks on inflation and real economic activity in the 1970s than in the 2000s. The weakening relationship between oil prices and macroeconomic indicators is partially explained by changes in the underlying forces that drive oil price changes. For example, Kilian (2009) argues that, unlike the previous oil price shocks, which were normally induced by supply disruptions, the fast-​growing demand from emerging market economies has been the primary driver of the oil price increases in the 2000s. Cashin et al. (2014) suggest that almost all countries experience long-​run inflationary pressures, an increase in real output and a rise in interest rates in response to a demand-​driven oil price increase. In contrast, a supply-​driven surge in oil prices would result in a long-​term fall in economic activity for oil-​importing countries. Another explanation for the weakening relationship lies in changes in the transmission of shocks. Blanchard and Galí (2007) and Blanchard and Riggi (2013) provide evidence that the transmission of oil price shocks can change with the structure of the economy and policy framework. For example, continued energy efficiency gains achieved over the past decades in advanced economies have mitigated some of the negative effects from higher oil prices. The “resource curse” for exporting countries If a country discovers substantial amounts of oil, gas or another natural resource, it will begin to export these goods, causing a substantial increase in GDP; this will improve tax revenues, improve the current account and create employment opportunities. However, the empirical results on the relationship between natural resource discovery and economic growth are rather mixed. While many resource-​rich countries have indeed grown more rapidly, such as Australia, Canada, Norway and the United States, many other countries that have discovered oil have gained much less than you might expect.

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Introduction

The negative effects associated with oil and natural resource abundance have been labelled the “resource curse”. The term was first used in the economics literature in 1993 (Auty 1993). It was found that, “between 1960 and 1990, the per capita incomes of resource poor countries grew between two to three times faster than those of the resource abundant countries” (Auty 2001: 3). However, while many countries did appear to suffer a “curse” as a result of the influx of large natural resource revenues, others did not (e.g. Australia, Canada and Norway). Thus, the “resource curse” phenomenon “is not an iron law, rather it is a strong recurrent tendency” (Auty 1994: 12). Why the abundance of resources might be a blessing for some countries and a curse for others can be understood from three perspectives. First is the so-​called “Dutch disease”. The term “Dutch Disease” was first coined by The Economist in 1977 to describe the decline in the Netherlands’ manufacturing after the discovery of the Groningen gas field in 1959. As Figure  1.9 shows, the Netherlands’ total exports relative to total GDP declined dramatically in the 1960s. Currency inflows, whether from the foreign direct investment in the oil and gas sector or the income generated from exports, increase the demand for local currency, causing it to appreciate. As the prices of other export goods are determined by the international market, the currency appreciation makes the country’s other tradable goods less price-​competitive on the international market. The result is a contraction in sectors other than the oil and gas sector. Apart from the currency appreciation effect, an oil boom can draw resources –​such as capital and labour –​out of other sectors because of the higher return of the oil sector. Factors moving into the oil sector bid up wages and rent in the market and cause other sectors to contract, resulting in a “deindustrialization” (Corden & Neary 1982). The latter effect is also referred to as the “crowding-​out effect”. In the case of the Netherlands, the problem did not last long, fortunately. The Dutch non-​gas exports increased markedly from late 1960s, and the fear of de-​industrialization linked to the Dutch disease did not materialize in the Netherlands. It’s worth noting that the Dutch disease is an economic phenomenon and can happen in economies with weak or strong institutions. For instance, the following quote from an article published in USA Today vividly depicts what happened in Stanley, North Dakota, a town with a population of only 1,458, according to the 2010 census, amidst the recent shale gas boom:

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Restaurants, motels and hospitals helplessly watch employees leave for higher-​paying oil jobs. A nursing home recently offered $1,000 signing bonuses for housekeepers. […] Schools started the Fall short of teachers priced out by a housing shortage that has seen rents double as oil companies snap up whole apartment buildings for their workers. USA Today (9 September 2008) The second reason for the resource curse thesis is broadly associated with weak institutions. This includes not only a lack of transparency and accountability, which lead to corruption and rent-​seeking, but also bad decision-​making. The availability of large amounts of money raises the temptation for corruption, particularly when the institutions are lacking in transparency and accountability. Resource wealth retards political change and entrenches incumbent regimes, since it allows governments to pacify dissent, avoid accountability and resist modernization (van de Ploeg 2011). Consequently, “public finances are opaque and corruption both by the elite and bureaucracy is rampant” (Auty 2001:  10). The view is supported by econometric studies showing that resource dependence is indeed strongly associated with high levels of corruption. The latter is often associated with high transaction costs in the economy, which divert productive resources away to sectors with low productivity and are bad for growth (Mauro 1995; Ades & Di Tella 1999).

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Figure 1.9  The Netherlands’ exports as a percentage of GDP, 1960–​2000 Source: World Bank, “World development indicators” database.

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Introduction

Additionally, a large windfall from resource revenues can lead to generally poor decision-​making, for two reasons. First, the development of oil, gas or minerals raises expectations among the population. This therefore pressures government to “do something”, which encourages speedy responses. Quick and ill-​coordinated decisions are often bad decisions. In addition, spending revenues too quickly is more likely to introduce distortions into the way the economy works, because there is less chance for the economy to adjust naturally (Auty 2001). Second, large windfall revenues tend to weaken prudence and the normal procedures of “due diligence”. Thus the importance of making the “right choices” seems somehow less important. Of particular importance is when governments decide on capital spending without thought to the recurrent spending implications (Sarraf & Jiwanji 2001). The third reason for the resource curse is revenue volatility. Commodity prices in general, and oil prices in particular, can be very volatile and have big boom–​bust cycles. As shown in Figure 1.10, the monthly price of crude oil (West Texas Intermediate: WTI) went from $135 per barrel in June 2008 to less than $40 per barrel in February 2009 and then from $105 per barrel in June 2014 to $47 a barrel in January 2015. As a result of commodity price fluctuations, resource revenues are highly volatile (much more so than GDP), because the demand for these resources exhibits low price elasticity (van der Ploeg 2011), with the result that, when the price declines, the quantity demanded increases less proportionally. This volatility can potentially create a variety of problems. Fluctuating revenue profiles make it very difficult to pursue a prudent fiscal policy. In the absence of a rainy-​day wealth fund and well-​developed financial markets, a plunge from resource revenues often leads to a significant budget deficit, the depreciation of real exchange rates and worsening terms of trade. Finally, the uncertainty induced by oil price volatility can result in companies postponing investment and hiring, thereby slowing the economy (e.g. Bernanke 1983; Bloom 2009; and, for oil investment specifically, Dunne & Mu 2010; Kellogg 2011). In this channel, oil price volatility can be causal (the volatility creates uncertainty that postpones investment, hiring or durables consumption), or the volatility can simply reflect broader market uncertainty about future economic or geopolitical events. A final point about the potentially negative effect of oil is that it tends to be associated with greater conflict, both within a country and internationally.

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The Economics of Oil and Gas 160 140 120

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Figure 1.10  Monthly average of WTI prices ($/​bbl), January 2000–​January 2018 Notes: The figure depicts the monthly average of WTI near month futures prices traded on the New York Mercantile Exchange. The “near month” is the expiration date for a futures contract that is closest to the present time.

Several factors may explain this. First, large-​scale resource revenues create a pot that is worth fighting for, since whoever is in power is better able to grab that pot. A recent quasi-​experimental study on the districts of Colombia offer evidence that capital-​intensive resources such as oil are much more prone to civil conflict than labour-​intensive resources such as coffee, rice or bananas (van der Ploeg 2011). Internationally, oil has been the cause of war and the cause of winning and losing wars. In 1990 the United Kingdom’s shadow foreign secretary, Gerald Kaufman, commented in reference to the Iraqi invasion of Kuwait: “If Kuwait grew carrots rather than pumped oil, Saddam Hussein would not have invaded Kuwait.” This was in reply to an MP, Tony Marlow, who had remarked:  “If Kuwait grew carrots rather than pumped oil, our forces would not be there.”8 Second, oil and gas projects themselves can often alienate local populations, especially if there already exists separatist tendencies. This can happen either through causing local environmental damage or because there is a feeling that resources are being siphoned away from the region to the capital. Such issues are increasingly influencing the behaviour of large oil corporations, which are concerned about their public image if they are found to be involved in despoiling the local environment or helping to infringe human rights.

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Introduction

Notes 1. Prugh, Flavin & Sawin (2005: 100). 2. According to the UNCTAD trade database, the largest single item in value terms that was internationally traded was cars in 2016. However, the sum of refined petroleum products and crude oil would exceed cars. 3. NYMEX is now owned by the CME Group, and the Intercontinental Exchange acquired the London-​based International Petroleum Exchange in 2001. 4. Primary energy refers to the energy sources that are formed in nature and have not been converted or transformed. Examples include coal, oil, gas, nuclear, hydro, geothermal, wind, solar and tidal. Secondary energy refers to the form of energy generated by the conversion of primary energy sources for the convenience of use. A typical example of secondary energy is electricity. 5. In this example, we ignore the cost of building the cap if it is a storage tank. However, the calculation applies perfectly for a pipeline. 6. Arbitrage is the practice of taking advantage of the price differentials in two markets to make a profit. 7. When the percentage change in quantity demanded is less than the percentage change in prices, it is said the demand is inelastic. Because of the lack of viable substitutes in the short term, the demand for oil and oil products are often found to be price-​inelastic. For example, Kilian and Murphy (2014) estimate the short-​run price elasticity of demand for oil to be approximately –​0.2, which indicates that for a 10 per cent increase in price the quantity demanded would decrease by only 2 per cent. Earlier estimates show even smaller elasticities. 8. See House of Commons Hansard debates for 7 September 1990, parliamentary publications and records, column 890 of 1989–​ 90 session; available at:  https://​ publications.parliament.uk/​pa/​cm198990/​cmhansrd/​1990-​09-​07/​Debate-​5.html.

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EXPLORATION, DEVELOPMENT AND PRODUCTION

The technical aspects Basics of petroleum exploration Oil and gas are stored in underground reservoirs. A reservoir is a geological formation where gas, oil and water are contained within porous rocks but prohibited from seeping upward towards the surface by a dense cap rock that is impermeable. Figure 2.1 shows a schematic petroleum reservoir. As oil and gas both have lower specific gravity than water, they float on top of water in a reservoir. Petroleum reservoirs can exist from surface seeps to subsurface depths over 4 miles (6.4 km) below sea level. Reservoirs vary from being quite small to covering several thousands of acres, and range in thickness from a few inches to hundreds of feet or more. Petroleum exploration is about finding oil. This requires geological and geophysical surveys to be carried out to determine the underground geology. Geophysical surveys can be magnetic, gravimetric or seismic, among which seismic surveys are the most expensive and sophisticated. Seismic surveys use vibration (induced by an explosive charge or sound-​ generating equipment) to provide a picture of subterranean rock formations at depth. This is accomplished by projecting sound waves downward into the Earth’s crust, which reflect off various boundaries between different rock strata. Developments in computer technology have allowed the use of three-​dimensional seismic surveys. The recorded data are processed by computer to provide a detailed, three-​dimensional picture of the formations

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Figure 2.1  Exploration: finding the field Source: Adapted from Maganga (2017).

and structures below the surface. The process is expensive, in the order of $30,000 per mile (as of 2017). But drilling a well can cost multiple millions of dollars, so time and money spent on accurate seismic surveys can be a good investment, since they help locate prospects and minimize dry holes. However, the only sure way to establish the presence of oil or gas is to drill an exploratory well, called a wildcat.1 Once an exploration well has found hydrocarbons, considerable effort will still be required to accurately assess the potential of the discovery. This is called “appraisal” in the industry. The role of appraisal is to provide cost-​ effective information that will be used for subsequent decisions (development). During appraisal, more wells are drilled to collect information and samples from the reservoir, and other seismic survey might also be required in order to better delineate the reservoir. Appraisal aims to: • reduce the range of uncertainty in the volumes of hydrocarbons in place; • define the size and configuration of the reservoir; and • collect data for predicting the performance of the reservoir during the forecast production life. Activities of the appraisal phase include: • • • • • 20

the planning and execution of a data acquisition programme (seismic); reprocessing existing seismic data; the drilling of appraisal wells; evaluation of the results obtained from the seismic and drilling activities; use of the data to update reservoir models; and

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Exploration, development and production

• carrying out initial development planning and an environmental impact assessment study. Petroleum exploration is a risky business. It is risky in two senses. First, there is no guarantee that exploration activity will find hydrocarbons and, if found, whether the discovery will be significant enough to be commercially viable. Second, exploration itself is costly. Exploration costs consists of both the cost of research and surveys, for locating the appropriate places to drill, and the cost of actually drilling exploration wells. Exploration wells are further divided into two types: wildcat wells and appraisal wells. Wildcat wells are drilled to find out whether there are hydrocarbons below the surface. When a discovery has been made, appraisal wells may be drilled to obtain more data about the size and extent of the discovery. Every year global investment in petroleum exploration is in the order of billions of dollars. For example, global exploration and appraisal spending in 2018 is estimated to have been around $40 billion (Wood Mackenzie 2019). Figure 2.2 presents the average cost of drilling a well in the United States for the period from 1980 to 2005 in 2000 real dollars. As can be seen, the offshore drilling costs are much higher than onshore, as the wells are

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Figure 2.2  Average drilling costs per well in the United States (2000 real dollars), 1980–​2005 Note: Dollar figures are converted to 2000 real dollars using a GDP deflator.

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The Economics of Oil and Gas

deeper, the technology is more sophisticated and it is much more costly to hire the drilling ships and crew. Recovery methods and depletion Oil and gas are stored in the underground reservoirs several miles below the surface, where pressure is much higher than the atmospheric pressure on the surface. Drilling a well to the reservoir is like punching a hole in a balloon; just as air will shoot out of the balloon, oil and gas will blow out of the reservoir when a well is drilled to the reservoir. Therefore, in order to prevent oil or gas from blowing out, precautionary measures must be taken when drilling wells into these reservoirs.2 Development involves drilling development wells and capping them with a “Christmas tree”,3 and building surface facilities including oil–​water separation systems, a desalination facility and a gathering system. Utilizing changes in reservoir pressure to push oil into the well bore and lift it to the surface is the simplest way of producing oil. This is called primary recovery. Depending on the source of energy that drives hydrocarbons towards and out of the production wells, there are different kinds of driving mechanisms, or “drives”: a dissolved gas drive, a gas cap drive and a water drive. Basically, as pressure in the reservoir falls and the oil flows out, the emptied pores in the rock must be replaced with something else. This “something else” can be dissolved gas, a gas cap or water. Dissolved gas drive: Petroleum is a mixture of hydrocarbons. The lightest components (with fewer carbon atoms) are the ones that make up natural gas. They can be liquid under the high pressure prevailing in the reservoir, becoming gaseous under normal temperature and atmospheric pressure. As production occurs, the reservoir pressure drops. Natural gas expands, and liquid natural gas becomes gaseous and expands, driving the oil towards the wells where pressure is the lowest. Gas cap drive: As we have seen, gas is often concentrated in the uppermost part of the reservoir, underneath the solid cap rock, which prevents the oil

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from seeping to the surface. As crude oil is extracted from the lower part of the reservoir, the gas cap expands, driving oil towards the wells. Water drive: Underneath the oil strata in a reservoir there is groundwater. As oil is extracted, water seeps into the reservoir and fills the pores that contained the oil. To maximize the recovery of oil, it is important to control the rate at which the pressure falls. Otherwise, some of the oil can be trapped by water in small pockets and become inaccessible. Typically, the primary recovery can recover about 20 to 30 per cent of oil originally in place (OOIP). However, if nothing is done the underground pressure decreases and, consequently, the production declines quickly. There are two reasons why the rate of production goes into decline. First, as more oil is extracted, the pressure in the reservoir falls and ultimately slows down the rate at which oil migrates towards the production wells. Second, in reservoirs with water drives, as production goes on water seeps in and blends with the oil. The wells start producing a mixture of oil and water. In some mature fields, a barrel of liquids produced from a well contains more water than oil. To maintain the reservoir pressure and to drive oil to the wellbore and lift them to the surface, gas or water must be injected through injection wells.4 This process is called secondary recovery. The successful use of primary recovery and secondary recovery together can produce up to 50 per cent of OOIP. In many offshore platforms, water and gas are often injected right from the beginning, to ensure the optimal utilization of expensive production facilities. However, eventually production will decline, unless tertiary recovery methods (enhanced oil recovery:  EOR) are introduced. Basically, tertiary recovery is the use of human intervention to increase the fluid mobility of oil so that oil can be pushed towards producing wells. This may be accomplished by washing it out with chemicals, raising its temperature with in situ burning or using steam hoses. There are three main types of tertiary recovery methods:  (a) thermal, (b)  chemical and (c)  miscible (see Box 2.1). Tertiary recovery can improve the recovery factor by another 5 to 15 per cent. Most gas reserves are produced during the primary recovery phase. Secondary recovery and tertiary recovery have significantly contributed to increasing oil recoveries.

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BOX 2.1  METHODS OF ENHANCED OIL RECOVERY

Thermal EOR: uses heat to improve oil recovery by reducing the viscosity of heavy oils and vaporizing lighter oils, hence improving the fluidity. The techniques include: steam injection, in situ combustion (i.e. injection of a hot gas that combusts with the oil in place), downhole microwave heating and hot water injection. Chemical EOR: uses chemicals added to the injected water to alter or improve the efficiency of the water flood. This can be achieved using several techniques, including increasing water viscosity (polymer floods), decreasing the relative permeability to water and increasing the relative permeability to oil. Miscible gas flooding: introduces a solvent that is miscible with the oil. Since gases have high mobilities and can easily enter all the pores in the rock providing the gas is miscible with oil, gas is often used as the solvent. The most commonly used solvents are carbon dioxide (CO2) and nitrogen.

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Figure 2.3  Production phases

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Exploration, development and production

A typical time profile of a reservoir is shown in Figure  2.3. Initially the output increases as more development wells are drilled and successfully brought online. After the desired number of wells has been drilled, production reaches a plateau, and it may stay there for a few years. Thereafter production starts to decline as the pressure in the reservoir falls, and it is ultimately discontinued when the value of production is not able to cover its operational cost. The rate of production decline is determined by a number of physical factors, including the viscosity of the oil, the permeability of the rocks and the reservoir characteristics. In Figure 2.3, the dashed line indicates that the output would decline quickly if there were no secondary recovery. With secondary recovery, the production plateau can be extended before declining. Tertiary recovery methods can marginally increase production rate and help moderate the production decline; however, they will not prevent production from declining. This is illustrated in the last declining curve. We will discuss in detail the modelling of production later. Figure 2.4 gives the production profiles of several oil fields in the North Sea. Economic analysis of petroleum exploration Risks associated with petroleum exploration The fact that petroleum is hidden underground and needs to be found gives rise to three types of risks for petroleum exploration. Prospect risk This is the risk that the well will fail to find hydrocarbons or be one that finds an insufficient amount to be commercially viable –​i.e. the wildcat well will be a dry hole. Because of improvements in three-​dimensional seismic surveys, the risk of a dry hole has fallen. In mature basins, the success rate of exploratory wells can be as high as 50 per cent. For example, according to the Norwegian Petroleum Directorate, about 380 wildcat wells were drilled on the Norwegian shelf between 2008 and 2018, more than 190 of which resulted in discoveries (Norwegian Petroleum Directorate 2019). However, the success rate in frontier basins is much lower. For example, according to an industry report, 61 wells were drilled at the frontier region along the west Africa margin of the Atlantic and from Guyana to north-​east Brazil in South 25

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America between 2007 and early 2018. These wells resulted in four commercial basin-​opening discoveries, with a commercial success rate of 7 per cent (Westwood Global Energy Group 2018). The presence of prospect risk has led to changes in the agreements that form the basis by which oil companies explore for and produce oil. The changes have been aimed at placing the prospect risk on the oil company. Hence, in joint ventures or service agreements, if no commercial oil is found, the loss falls entirely on the oil company and the government does not lose anything. Contract risk In most legal systems other than the United States’, the property rights of subsurface oil and gas (as with all other minerals) belong to the state. Therefore, if an oil company wishes to explore for the oil and gas, an agreement must

BOX 2.2  INDUSTRY JARGON

Prospect: A prospect is a geological structure that has some probability of containing hydrocarbons and is considered for exploration. Once exploratory drilling is complete, the term “prospect” is dropped; the site becomes either a dry hole or a producing field. Play: A play is a collection of oil or gas prospects that share certain ­geological attributes and lie within some well-​defined geologic boundaries (Walls 1994). Basin: A basin is a large, bowl-​shaped subsurface geological feature formed by downwarping of the underlying basement rock and filled with sedimentary rocks. Large basins such as the Permian Basin may be divided after initial formation by uplifts and platforms, which in effect create other basins (such as the Midland and Delaware Basins) within the original structure (United States Geological Survey 1980). Trap: A structural trap is formed as a result of changes in the structure of the subsurface, such as fracturing, folding and gravitational or compactional processes. These changes block the flow of hydrocarbons and can lead to the formation of a petroleum reservoir.

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be signed between the owner (the state) and the company. As oil and gas projects are notoriously capital-​intensive and require long payback periods, the agreement must be long term in nature and very complex. As with many other long-​term contracts in foreign direct investment (FDI), a challenge is how to discourage or prevent contracting parties from pursuing post-​contract opportunism. One of the tricky issues covered by the agreement is how the profit is to be divided –​the fiscal terms of the agreement, a topic we shall discuss in detail in the next chapter. The problem is that this division must be made without knowing what is to be divided, since the extent of the oil or gas reserves is hidden underground. Once the oil has been discovered and production begins, the bargaining power moves strongly in favour of the government, because of the sunk cost that the company has incurred. This leads to the obsolescing bargaining problem, whereby the government begins to try and squeeze ever better terms from the agreement. The obsolescing bargaining model explains how the nature of bargaining relations between a multinational company (MNC) and the host government changes as a function of the goals, resources and constraints of both parties. It was originally developed as an explanation for widespread expropriation and nationalization in the 1970s in the natural resource industry (Vernon 1977). The bargaining power of each party depends on the ability to withhold resources and capabilities, such as raw materials, capital, technology and access to country-​specific advantages. The outcome should favour the party with stronger bargaining power. In the oil and gas industry it may be argued that, before an investment is made, both parties have more or less equal bargaining power, as the host state is trying to attract investment and the international oil company (IOC) is seeking investment opportunities. Before the investment is committed, both parties have alternatives. However, over time, once the international oil companies have committed the investment, the bargaining power shifts to the host government, causing the original bargain to obsolesce. This is an acute problem in the international petroleum industry, considering that much of the investment (e.g. spending on seismic surveys, drilling for exploration wells and development wells, and infrastructure) becomes sunk once the investment is made. As the bargaining power shifts to the host state, its government imposes more conditions on the IOCs, ranging from higher taxes

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to asset expropriation. The situation usually worsens when the oil price is rising. Rising oil prices increase host states’ appetite for renegotiating their agreements with the IOCs, and renegotiation has often taken the form of outright expropriation. We saw this happening in the 1970s, early 1980s and 2000s. As a result, the IOCs lost control of numerous “sweetheart” deals with oil-​exporting governments. Commercial risk There are two types of commercial risks involved in petroleum exploration. First, the geology may turn out to be less than favourable. After all, although the geological and geophysical surveys suggest what may be underground, the development decision (see below) must be made on the basis of data from one or several exploration and appraisal wells. This information from geological surveys may be misleading, and the geology much more fractured than believed. The result is that the cost may be much higher or volumes much less than expected, thereby undermining the profitability of the field. Second, market conditions may not be as expected. Oil prices are known to be extremely volatile. Because of the long lead time in petroleum exploration and development, when an oil field is brought online for production the oil price may be lower than expected. On the other hand, costs could be higher than expected, because of inflation in engineering expenses and procurement costs for raw materials and equipment. Managing the exploration risk Expected monetary value Due to the uncertain nature of exploration outcomes, economic analysis often employs probabilistic techniques in evaluating exploration projects. A commonly used tool is the expected monetary value (EMV) approach. The idea is simple: to weigh each possible outcome –​a dry hole, a big discovery, a small discovery, etc. –​with a probability (or likelihood) and calculate the weighted average of net present values (NPVs). For example, if you believe the probability of finding a dry hole with a net present value5 of $1 billion is 30 per cent, the probability of finding a small reserve with NPV of $0.5 billion is 40

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per cent, the probability of finding a medium reserve with NPV of $1 billion is 20 per cent and the probability of finding a large reserve with NPV of $1.5 billion is 10 per cent, then the expected monetary value is EMV = (–​1)(0.3) + (0.5)(0.4) + (1)(0.2) + (1.5)(0.1) = $0.25 bn In this case, the exploration project can be undertaken, since the EMV is positive. Decision-tree analysis However, in practice, the economic analysis for petroleum exploration is not that straightforward, for two reasons. First, we often do not know the probability of each possible outcome with much confidence, and it is usually estimated with very little or no statistical data or experience. Additional data can usually be obtained by drilling additional wells or conducting more geophysical surveys. But we may not be able to afford to delay decision-​making until we are comfortable that there is sufficient information upon which we can base our probability assessments.6 Second, the value of each “possible outcome” often depends on a sequence of other possible outcomes and probabilities. A useful tool in exploration decision analysis is decision tree analysis. An example of a decision tree is illustrated in Figure 2.5. The example depicts the decision tree for a company considering whether to enter into a lease for a block of acreage. From available geological data, the block appears to have a potential oil structure. In the diagram, a square represents a decision node and a circle represents collection of possible outcomes (chance node). In the first step, the company considers whether to purchase the lease for seismic activities and drilling rights. If it enters the lease, the next step is to decide whether to conduct a more detailed seismic survey or directly drill a wildcat well. The outcome of the wildcat well is uncertain. For simplicity, only three outcomes are assumed: a large discovery, a small discovery, or a dry hole. In the case of a dry hole, the company further considers whether to dry the second wildcat well or not. If the seismic survey is carried out, then a wildcat well is drilled only if the survey confirms an oil trap, in which case the probability of success will be improved. If no structure is confirmed by further seismic activity, then the lease is dropped. At this point, it is helpful to put in some numbers. Let us assume that the cost of obtaining the lease (sign in bonus) is $3 million, the cost of carrying

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Figure 2.5  A decision tree for acquiring a lease Source: Based on Newendorp and Schuyler (2000: ch. 4).

out a more detailed seismic survey is $2 million and the cost of drilling for a wildcat well is $1 million. The NPV is $40 million for a large discovery and $15 million for a small discovery. The NPVs are production revenues net of all development costs, operating expenses, taxes and royalties, but do not include the costs of drilling the wildcat well and purchasing the lease. For convenience, the probability of each possible outcome and the financial payoff at each terminal node are also depicted on the diagram. For example, if the decision at node B is to drill the wildcat well, the probability of discovering a large field is 0.05 and the net payoff for the large field is $36 million (the NPV $40 million minus the $3 million lease purchase cost and the $1 million wildcat-​drilling cost). In the case of a dry hole, then we further evaluate whether to drill the second wildcat or give up the lease. The latter would result in a net loss of $4 million (the costs of purchasing the lease and drilling the wildcat). If it is decided to drill a second wildcat 31

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well, we move to node E, with three possible outcomes. In the case of a large discovery, the net payoff will become $35 million, because the cost of drilling the second wildcat is added in. If it is decided to conduct a further seismic survey, which confirms the oil structure, the probability of dry hole is reduced considerably. Clearly, each of the chance nodes (represented by a circle) requires the calculation of EMV so that we can compare alternatives at each decision node. The decision tree can be solved by backward induction –​starting from the terminal nodes and solving backwards. For example, the expected monetary value at node E is EMVE = (0.08)(35 mn) + (0.08)(10 mn) + (0.84)(–​5 mn) = –​$0.6 mn Moving backwards, at node D the decision is to decide whether to drill the second wildcat well or to drop the lease if the first wildcat turns out to be dry. Here we simply compare the expected monetary value from node E (EMVE) with the payoff of dropping the lease, which is –​$4 million. Clearly, the decision would be to drill the second wildcat well and cross out the “Not drill” option. Proceeding backwards again, the EMV at chance node C is EMVC = (0.05)(36 mn) + (0.05)(11 mn) + (0.9)(–​0.6 mn) = $1.81 mn In this process, although the “Dry hole” outcome initially does not have a monetary value, by working backwards we are able to find the EMV for the dry hole node. Now we need to solve the “Run seismic survey” portion of the decision tree. Similarly, this can also be solved backwards from the chance node J: EMVJ = (0.20)(33 mn) + (0.20)(8 mn) + (0.60)(–​7 mn) = $4.0 mn Hence, the decision at node I is to choose either to drill the second well, with an EMV of 4.0 million, or dropping the lease, with a loss of $6 million. Clearly, we would choose to drill the second wildcat well, so that the EMVJ is moved back to decision node I and the “Not drill” option is deleted. Next we can calculate the EMV at chance node H, as follows: EMVH = (0.15)(34 mn) + (0.15)(9 mn) + (0.70)(4 mn) = $9.25 mn

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Now we come to decision node G, and the choice is again between drilling the first wildcat well and dropping the lease. Clearly, we would choose to drill the first wildcat. This moves us back to chance node F. The EMV at F is EMVF = (0.5)(9.25 mn) + (0. 5)(–​5 mn) = $2.125 mn That is, the expected monetary value of running a more detailed seismic survey is $2.125 million. This takes us back to decision node B, where we compare the EMV from running the seismic survey with that of direct drilling –​ i.e. EMVC. Clearly, running the survey is sensible. The additional seismic survey costs an extra $2 million, but it reduces the dry hole probability and increases the success rate, contributing to the improved EMV. We finally come back to node A. Comparing the EMV $2.125 million of purchasing the lease with zero if we do nothing, we would recommend purchasing the lease. As a result of this analysis, we can recommend the following strategy to the decision-​maker: • buy the lease and immediately run the seismic survey; • if the survey confirms a favourable structure, then drill a wildcat well; • if the initial well turns out dry, then drill a second exploratory well rather than giving up the acreage. The advantage of this form of analysis is that it plans all contingencies and possible decision alternatives in advance. It provides a better chance for consistent actions in achieving a policy goal over a series of decisions. Each step in the sequence will be analysed ahead of time. This reduces the likelihood of a decision-​maker finding themselves at some future point wondering what they should do next (such as “Should I drill a second wildcat or quit?”) in the face of an undesirable outcome. In the above example, we  assumed the probability of each possible outcome for drilling a wildcat well. In practice, it is one of the more difficult probabilities to assess, because of the inherent complexity and uncertainty in petroleum geology.7 One of the most commonly used methods to estimate the probability of discovery is to calculate a wildcat success ratio by dividing the number of discoveries (i.e. productive wells) by the total number of test wells drilled in the basin. The problem with this approach is that it implicitly

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assumes that this ratio does not change with time. Given the finite number of prospects in a basin and the fact that, once a successful well is drilled, it is removed from the space of undrilled prospects, the sample space changes, and so does the discovery probability or success ratio. An alternative approach is to recognize the fact that a successful discovery depends on a number of factors and to decompose the probability of discovery into a conditional probability of each of these factors. For example, a successful discovery requires that a trap be present and in the position indicated from geological and geophysical evidence, that the objective formation must have sufficient thickness and that the reservoir rocks are sufficiently porous and permeable. All these factors must be present to yield the successful discovery. Assuming each of the contributing factors is independent, the discovery probability is the product of each of the individual factors. In mathematics, this can be written as P(Wildcat discovery) = P(Reservoir trap) × P(Formation) × P(Hydrocarbons) × etc. where P indicates probability. To see how this works, consider a structural prospect that is likely to contain hydrocarbons. Based on the existing seismic data, we estimate the following probabilities: probability of having a reservoir trap: 0.8; probability of sufficient formation thickness: 0.7; probability of hydrocarbons in the formation: 0.4. Thus, the probability of a wildcat discovery is P(Wildcat

discovery )

= 0.8 × 0.7 × 0.4 = 0.224

Conceptually, this approach has much merit. However, one of the challenges in applying it is that it may be difficult to reliably estimate the probabilities of the individual terms. If valid data are available, it poses no problem. If the prospect is in a new basin with little prior data, it may be very difficult to assess probabilities of the various factors, although it may be possible to use data from analogous geological basins. Despite these challenges, it remains a popular way of analysing the risks. Other popular tools of exploration risk analysis include simulation analysis, whereby a range of variables can be simulated according to some pre-​ specified probability distributions and the result will be a distribution of 34

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Exploration, development and production

the outcome variables. Interested readers are referred to Newendorp and Schuyler (2000: ch. 8) for examples. Clearly, decision-tree analysis also relies on the probabilistic assessment of possible outcomes and involves the calculation of EMV in almost every node of the decision tree. With decision-tree analysis, one could experiment with different probabilities and investigate the sensitivity of the outcomes to assumptions about probabilities. Even the outcomes themselves (small field, large field) are hypothetical, but the decision tree is a useful tool to systematically test the sensitivity of profits to different possibilities regarding probabilities and sizes of finds. Development plan, rate sensitivity and the common pool problem Having made a discovery, the next stage is to appraise the discovery to determine its characteristics. Following this, a decision must be made whether or not to develop the deposit. This is an investment decision. Hence, there is a key difference between exploration and development. The outcome of exploration can be highly uncertain. The outcomes of development decisions typically have much less uncertainty. Development plan Development involves creating the capacity to produce oil. This includes drilling development wells, then capping them with Christmas trees to control their flow and building processing and gathering facilities. A  development plan is needed before the investment decision is made to develop an oil field. The development plan considers all available geological and engineering data to make an initial estimate of reserves in-​place, to project recovery efficiencies and optimal recoverable reserve levels under various producing scenarios and to evaluate development plan alternatives. In other words, a development plan provides a road map for the oil company, and typically includes the following items: • the number of wells to be drilled and completed for production and injection; • well spacing and pattern; 35

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• • • • •

processing facility requirements; transportation options; cost projections; project schedules and depletion plans; and operational programmes.

The development of an oil and gas field costs millions or billions of dollars and may require a long time (five to ten years) to be fully realized. The costs and duration of the development phase depend on the location of the field, the size and complexity of the facilities and the number of wells needed to achieve the production and economic targets. The number of wells required is dependent on a combination of technical and economic factors used to determine the range of recoverable reserves relative to a range of potential investment alternatives. The investment decision requires a series of estimates or predictions, which are embodied in the cash flow of the project. First, the amount of oil originally in place must be estimated, along with the recovery factor.8 Then the method of recovery must be decided, which will determine the costs of the project. Since the 1980s there has been an incredible technological revolution in oil-​producing methods. A whole series of new technologies, such as three-​dimensional seismic surveying, horizontal drilling, subsea completion and many more, have been combined to dramatically reduce the cost of producing oil, especially offshore (see Box 2.3). Finally, some view must be taken about the future trajectory of oil prices in order to determine revenues. This is among the most difficult of the estimates, since the record of oil price forecasters has been, in general, very poor. One of the most important estimates is about the amount of oil or gas reserves that can recovered from a field. As there is always some degree of uncertainty regarding the recovery, reserves are generally classified into different categories according to the probability of their being ultimately recovered. • Proved/​proven reserves:  estimated quantities of petroleum that will be produced (with 80 to 90 per cent certainty) under current economic conditions and known technology. • Proved and probable reserves: a greater than 50 per cent chance of being produced.

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Exploration, development and production

BOX 2.3  NEW TECHNOLOGIES OF EXPLORATION AND PRODUCTION

Three-​dimensional seismic surveying is an advanced method for collecting, processing and interpreting seismic data in three dimensions. In two-​ dimensional seismic surveying both the sound source and the sound detectors (numbering up to 100 or more per shot) are moved along a straight line. The resultant product can be thought of as a slice through the Earth beneath the survey line. In three-​dimensional seismic surveying the sound detectors (numbering up to 1,000 or more) are spread out over an area and the sound source is moved from location to location through the area. The resultant product can be thought of as a cube of common-​ depth point-​stacked reflections. Sophisticated computer programmes can analyse these data to create a three-​dimensional image of the subsurface, which provides greatly improved resolution of subsurface features (Energy Information Administration, “Energy glossary”). Horizontal drilling means the ability to drill a well horizontally after reaching a specific vertical depth, rather than vertically. This creates two key advantages. First, much more of the oil-​bearing strata is exposed to the well, thereby dramatically increasing well productivity. Second, in offshore operations a multitude of wells can be drilled and operated from a single offshore platform rather than many offshore platforms. This dramatically reduces capital costs. Subsea completion is when the Christmas tree is located on the seabed and connected to a floating storage tanker on the surface by means of a flexible riser (pipe). This has been made possible in part by modern satellite technology, which allows the floating storage ship to stay on station and does away with the need for extremely expensive fixed platforms. The riser can also be installed fairly quickly, generating early revenue that is important to improve the value of the project. Finally, if the field is rather small, once depleted the storage ship simply moves on to the next field.

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• Proved, probable and possible reserves: a greater than 10 per cent chance of being produced. Clearly, among the three classes the most restrictive definition is proven reserves, as this indicates the amount of oil and gas that will almost certainly be recovered. As such, reserves are the most important asset held by an oil and gas company, and changes in the reserves of publicly listed companies are carefully monitored by the regulatory bodies to avoid manipulations of share prices. Up to 2009 the US Securities and Exchange Commission allowed only proven reserves to be publicly reported to potential investors. Another relevant reserve concept that is often reported is “technically recoverable reserves”. The term “technically recoverable reserves” refers to the amount of oil and/​or gas that can be produced using currently available technology and industry practices regardless of any economic or accessibility considerations. For example, oil and gas may exist in a location that can be produced using existing technology, but if it costs more than the oil is worth it therefore will not be commercially viable to produce. However, the oil is still technically recoverable. Once production begins, the performance of each well and reservoir is monitored and a variety of engineering techniques are used to progressively refine reserve estimates over the producing life of the field. Many technical assumptions become better understood and more certain with the evaluation of performance data over the producing life of a field. However, the total recoverable reserves are not known with complete certainty until the field has produced to its economic limit and abandonment. And one of the most critical assumptions remains uncertain and puts project success at risk to the very end: the oil and gas price forecast. Rate sensitivity A development plan not only provides a road map for developing an oil and gas reservoir, it is also necessary for the optimal exploitation of the resources for a given reservoir. This is because the number and pattern of wells, and hence the initial production rate, will affect not only the decline rate but also the amount of oil and gas that can be ultimately recovered from the reservoir. That is, for a given OOIP, the total recoverable reserves are affected by the initial production rate. 38

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Exploration, development and production

There are two countervailing effects by which the initial production rate and well pattern may affect the total amount of recoverable reserves.9 First, if the initial production rate is too high (that is, the reserve is depleted too quickly), the resulting drop in pressure may cause water flooding of the reservoir. Consequently, some of the oil may be trapped by water and never get produced. This would reduce the total amount of recoverable reserves. Second, having more production wells helps “drain” the reservoir more efficiently, increasing the ultimate recovery. The reason for the latter effect is that oil and gas do not flow without friction in their underground reservoirs. The rate at which they migrate towards the wells depends on the drive mechanism, the permeability of the rock and the viscosity of the oil itself. Few, if any, reservoirs could be extracted satisfactorily with a single well, as oil from more distant parts of the reservoir would not flow towards the well. Therefore, the recoverable reserves would increase with the number of wells drilled, albeit at a decreasing rate. However, if too many wells were drilled into one reservoir, the rapid pressure fall would ultimately dominate and cause recoverable reserves to decline. The relationship between the ultimate recoverable reserve and the number of wells drilled for a given reservoir is illustrated in Figure 2.6. Total production from the reservoir –​i.e. the total recoverable reserve –​initially increases as

Recoverable reserve

Possible MER

0

Number of wells drilled

Figure 2.6  The relationship between initial production and recoverable reserves

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more wells are drilled into the reservoir. However, sooner or later the increase in production by drilling more wells will decline, because the pressure drop causes “water flooding”, which traps oil in some pockets of the reservoir. The relationship between the total recoverable reserve and the initial recovery rate is usually referred to as the “rate sensitivity”. The key insight from the rate sensitivity model is that drilling more wells does not necessarily lead to higher recovery, and it is important to plan the well-​spacing patterns so that the recovery (production) rate does not result in lowering the ultimate recovery from a reservoir. At this point it is useful to discuss the concept of the maximum efficient rate (MER) of recovery. MER is the highest rate that can be sustained for an appreciable period of time without damaging the reservoir’s natural pressure, and which if exceeded would result in a decrease in ultimate recovery (Amit 1986). As such, MER is widely employed by governments and regulators around the world to prevent an avoidable waste of resource.10 The common pool problem and the rule of capture Another issue relevant for development concerns the rule of capture in the United States. In the United States, the property rights of subsurface minerals, including oil, belong to the landowners. Petroleum reservoirs can be expansive, covering many thousands of acres. But the ownership of land above the reservoir is often fragmented, so that no single landowner has property rights to the entire underground resource. Frequently multiple landowners can have property rights to the same underground resource. The problem is that hydrocarbons are fugitive. When one owner drills a well in his own land, he could be “stealing” oil from his neighbours. As illustrated in Figure 2.7, if landowner A drills a well into the reservoir, there is no guarantee that the oil will come only from the area under his land. If the oil flows without friction through the entire reservoir, then one well could completely deplete the reservoir. Even if this is not the case, the fact that oil flows allows one landowner to “steal” oil from his neighbours. There are two consequences of this problem. First, there are strong incentives for landowners to drill wells for the purpose of protecting their own interests and “stealing” from their neighbours. One additional well may

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Exploration, development and production

not add much value to the entire reservoir, as already explained, but for the owner of a small tract of land the well may be highly profitable, as otherwise the oil may be “stolen” by his neighbour. This has been the issue in Texas and Oklahoma, where landownership is very fragmented. The first wells drilled in the Cushing oil field in Oklahoma were all located at the corners of a property, followed by other wells drilled along the property line, and wells drilled on an adjacent property were typically offset by a well drilled on one’s own property (Boyce 2013, quoted from Stocking 1925). Second, as a result of competitive drilling, the fields will be overproduced, with production declining rapidly due to rate sensitivity. More than three wells were drilled per acre of land in the Spindletop field, discovered in Texas in 1901. Production peaked in 1902 at 17.4  million barrels and declined quickly. By 1903 production had decreased to 8.6  million barrels; in 1904 production was 3.4  million barrels; and by 1905 production was down to 1.6 million barrels (Zimmermann 1957: 284, tab. XV). Similar rates of decline were observed in other fields discovered during that time. The rule of capture is peculiar to the United States; in virtually all other countries oil belongs to the state. However, the problem still arises in situations where the oil deposit straddles an international boundary. For example, in the North Sea an oil field may straddle the UK and Norwegian continental shelves. In this case, licences for oil prospecting and production are

Owner A

Owner B

Owner C Land

Oil reservoir

Figure 2.7  The common pool problem in the oil industry

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Table 2.1  Norwegian share of North Sea oil fields, 1985 & 1995

Statfjord Frigg Murchison

1985

1995

84.09322 60.82 25.06

85.46869 60.82 22.20

Source: Hannesson (1998: ch. 4).

allocated by the respective governments. The problem may also happen when an oil field crosses two licence areas, even though the mineral rights belong to the same government, which grants licences to private companies. When an oil field extends across international boundaries, how to develop it often becomes a contentious issue, frequently leading to conflicts. The solution eventually reached was to create institutional control for the prorationing of production to prevent uncontrolled production.11 The most famous of these institutions was the Texas Railroad Commission, which was, effectively, the forerunner of OPEC. A second approach, which is also adopted in international settings, is unitization, whereby the landowners of the entire field or a substantial part of the field effectively consolidate and designate one operator to form a “unit”. Revenues are shared according to a pre-​arranged allocation mechanism. Table 2.1 lists the Norwegian shares of three cross-​ border fields in the North Sea in 1985 and 1995. Two things stand out. First, the shares change over time, as more is being learned about the reservoir, in particular how much oil there is on each side of the border. Second, the shares for Statfjord contain no fewer than five digits to the right of the decimal point, reflecting the fact that a large sum of money is involved. The objective of unitization is to provide for the unified development and operation of an entire geologic prospect or producing reservoir so that exploration, drilling and production can proceed in the most efficient and economical manner by one operator. Using detailed production data from the Anadarko basin of Texas and Oklahoma for the period from 1980 to 2009, Balthrop (2012) estimates that wells in Oklahoma, where policies encourage unitization, making property rights more secure, cumulatively produce 3,360 to 4,217 more barrels of oil per well than comparable wells in Texas, which is known to suffer from common pool externalities due to regulations that are biased in favour of small landowners.

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Exploration, development and production

Modelling production After exploration and development, the next stage in the value chain is production, although the previous two stages also involve the production of hydrocarbons since successful exploration and development wells also produce. What is actually produced from a well is a mixture of oil and gas. This mixture must be collected in a gathering system and then directed to a gas–​oil separator plant, where the gas is removed. The remaining crude then is sent to market. The associated gas that is extracted from an oil deposit may be flared, reinjected into the oil field for enhanced oil recovery, used for on-​site electricity generation, converted to liquid to produce synthetic fuel or utilized as a petrochemical feedstock.12 Historically, associated gas was often flared, because the quantity of output was not significant enough for commercial use or because of lack of pipelines for transportation.13

Decline in the production rate As explained above, the production rate from an oil field usually increases when the field is being developed. After a few years the production rate will peak, and it may stay on a plateau for a period of time before ultimately declining. For financial analysis, it is necessary to model the time profile of production from a reservoir, as it directly affects the cash flow. One of the important factors in modelling the production profile is, obviously, the declining rate: the rate at which production declines. The rate of production decline is determined by a number of physical factors, such as the viscosity of the oil, the permeability of the rocks, the rate at which the pressure in the reservoir falls, how quickly water seeps into the reservoir, and so on. It is possible to model these factors mathematically, and modern petroleum engineering employs sophisticated methods to study and simulate the production rate. For financial modelling purposes, some mathematically simple declining curves can be used to predict the decline in production from a reservoir. Some of the most popular ones are the family of “general hyperbolic decline”, the mathematical expression of which is given in Equation 2.1,

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dqt / qt = −1 / (a + bt )

(Equation 2.1)

where dqt denotes the change (in absolute terms) in production rate at time t, and hence the expression dqt / qt gives the decline rate, and a and b are constants, with b ranging between 0 and 1. When b = 1 we get the so-​called harmonic decline curve; with b = 0 the declining rate becomes constant, and we have an exponential decline curve. It is evident from Equation 2.1 that a large value of b (close to one) has a dominant effect on the shape of the curve as t becomes large. For a given set of values of a and b the short-​term shape of the curve is not largely affected by the value of b but the long-​term shape is. This implies that, in the short term, all decline curves –​exponential, hyperbolic and harmonic –​give similar results. Figure 2.8 illustrates the decline curves with different values of b. Clearly, the exponential decline curve (when b = 0) declines most rapidly for the same value of a (see Figure 2.8). Decline curve analysis is not necessarily grounded in fundamental theory but is based on empirical observation of production decline, although it can be demonstrated that, under the very general conditions of a reservoir, the equation of fluid flow is equivalent to exponential decline. However, for economic analysis it is the empirical nature of this term that has greater significance, since it allows the technique to be applied to multiple fluid streams.

Producon rate (MMbbl per day)

1.0 0.9

b=0

b=1

b=0.5

0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0 0

1

2

3

4

5

6

7

8

9 10 11 12 13 14 15 16 17 18 19 20 Year

Figure 2.8  Hyperbolic decline curves Note: In all three cases, a = 10 –​that is, the exponential decline rate is 0.1.

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Exploration, development and production 1.0

k=0.025

MMBPD

0.9 0.8

k=0.05

0.7

k=0.075

0.6 0.5 0.4 0.3 0.2 0.1 0.0

1

6

11

16

21

26 Year

31

36

41

46

Figure 2.9  Exponential decline curves

We will have a closer look at the exponential decline curve, as it has been a popular tool in modelling production trends, perhaps because of its simplicity. Let k = 1/​a denote the decline rate; the production rate with exponential decline can be written as follows:14 q t = q 0 ⋅ e − k ⋅t

(Equation 2.2)

where qt denotes the production rate at year t, q0 the initial output level at the beginning of the declining phase and k the decline rate. Figure 2.9 illustrates the exponential declining curves for the same initial production rate but different values of k. In this model, if production goes on indefinitely, the cumulative production from the reservoir would be equal to the technically recoverable reserve, Q, and we have ∞

Q = ∫q0 ⋅ e − k ⋅t dt = 0

q0 k

(Equation 2.3)

It can be easily shown that k = q0 / Q. For a given Q, k goes up with q0. In other words, the higher the initial rate of production (q0), the higher the decline rate (k). The decline rate is sensitive to the initial rate of production, or to the total number of wells drilled. If more wells are drilled, 45

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the pressure falls more quickly. This corroborates the rate sensitivity discussed earlier. Not all wells exhibit exponential behaviour during depletion. In many cases a more gradual hyperbolic decline is observed. In such cases, the hyperbolic decline arises from natural or artificial driving energies slowing down the pressure decline. Finally, the hyperbolic declining curves result in smooth production profiles. In reality, the time profiles of individual reservoirs are rarely smooth. Nonetheless, the decline curves still provide a good enough approximation for calculating present values, as deviations from the decline curves will cancel out. This is particularly the case when a company has a number of fields. Cost structure of petroleum production The total cost of producing a barrel of oil includes the exploration cost, development cost and direct production cost or lifting cost.15 Exploration and development costs include expenditure for geological and geophysical surveys, land acquisition, drilling costs (including dry holes), well completion and facility costs and gathering, processing and transportation costs. Exploration cost and development cost are together often called the finding costs and represent the fixed cost of producing a barrel of oil. Other 23%

Rig and drilling fluid 15% Casing and cement 11%

Compleon fluids, flowback 12%

Proppant 14%

Fracking pumps, equipment 25%

Figure 2.10  Cost shares of US onshore oil and gas drilling and well completion Source: Energy Information Administration.

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Exploration, development and production

Figure 2.10 presents five key cost categories that, together, account for more than three-​quarters of the total costs for drilling and completing typical US onshore wells.16 Rig and drilling fluids costs make up 15 per cent of total costs, and include expenses incurred in overall drilling activity, driven by larger market conditions and the time required to drill the total well depth. Casing and cement cost 11 per cent of total costs, and relate to the casing design required by local well conditions and the cost of materials. Fracking pumps and equipment costs make up 24 per cent of total costs, including the costs of equipment and horsepower required for the specific treatment. Proppant costs make up an average of 14 per cent of total costs and include the amount and rates for the particular type of material introduced as proppant in the well.17 Completion fluids and flowback costs make up 12 per cent of total costs, and include the sourcing and disposal of the water and other materials used in hydraulic fracturing and other treatments that are dependent on geology and play location, as well as available sources. Over time, these costs can change with technology and market conditions. In fact, as shown in Figure 2.11, the growth of the oil price and well-​drilling

Growth in oil price

0.10

0.1

0.05

0

0

–0.1

–0.2

Growth in drilling costs

0.15

0.2

–0.05 2005

2007

2010

2012

Year Growth in oil price

Growth in drilling costs

Figure 2.11  Growth in the three-​year moving average of the real oil price and drilling costs (in percentage terms), 2005–​2012 Note: The growth in drilling costs is measured by the growth in the “Upstream capital cost index” provided by IHS Markit; available at https://​ihsmarkit.com/​info/​cera/​ihsindexes/​index.html. Source: Naumov and Toews (2016).

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costs often have a good correlation. When prices fall, either more expensive production would be reduced to ensure profitability at the new prices, or costs would fall with improvements in technology or organizational efficiency, or some combination of the two. The complexity and cost of drilling wells and installing all the necessary equipment to produce reserves vary significantly depending on location and geology. For example, the development of an onshore shallow gas reservoir located among other established fields may be comparatively low in cost and nominally complex. A deep oil or gas reservoir located in over 4,000 feet of water depth and miles away from other existing producing fields will push the limits of emerging technology at extreme costs. Individual wells in deep water can have costs in excess of $50 million to drill, complete and connect to a producing system. Onshore developments may permit the phasing of facility investment as wells are drilled and production established to minimize economic risk. However, offshore projects may require 65 per cent or more of the total planned investments to be made before production starts up, and impose significant economic risk. As exploration and development are generally very capital-​intensive, fixed costs take a large share of the total cost of supplying a barrel of oil. In contrast, the variable costs are relatively small. According to the US Energy Information Administration (EIA), in 2006 the average lifting cost of the 30 major energy companies ranged from about $4 per barrel (excluding taxes) in Africa to about $8.30/​barrel in Canada, with an average of $6.83/​barrel. In comparison, the finding cost for US offshore was $63.71/​barrel in the same year. Although technological advances in finding and producing oil have made it possible to bring oil to the surface from more and more remote reservoirs at steadily increasing depths, such as in the deep water Gulf of Mexico, the total cost of producing from these deposits remain relatively high. The presence of high fixed costs and low variable costs has important implications for the operations of the oil industry. In economics, the decision to increase or decrease production is determined by the comparison between marginal cost and marginal revenue. Whenever marginal revenue exceeds marginal cost, production should be increased, because doing so would increase the total profit. In the short run, the variable cost is a marginal cost.18 Because the variable cost is so low, prices are rarely lower than

48

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the variable costs, and so a small producer is almost always better off keeping producing even in a “low”-​price environment. Therefore, there is always an incentive for producers to pump more oil while the capacity allows, because doing so would allow them to not only cover their variable costs but also recoup some of their fixed costs. The consequence of this is that the industry tends to operate at full capacity, leading to oversupply. Another implication from low variable costs concerns the bygones rule. This means that, even if elements of the oil industry make losses, production will continue. Hence, those who suggest that low-​cost producers cut prices so as to put competitors out of business tend to neglect the fact that, because of the bygones rule, existing producers can continue for some time despite carrying losses. The working of the bygones rule further reinforces the tendency of the oil industry to oversupply, leading to even lower prices. Allocating production over time An important decision for an oil producer is how to allocate production –​i.e. how soon to deplete the reservoir – over time. To gain some insight, let us consider a simple two-​period model with competitive markets and no production costs, before introducing a more complex model with production costs. The goal of the producer is to maximize the present value by deciding how much to produce in each period. Let P1 , P2 and Q1 ,Q2 , respectively, denote the price and production in the two periods, where the subscripts 1 and 2 indicate the current and future periods; r is the interest (or discount) rate. Since there is no cost, the present value of production over the two periods is as follows: PV = P1Q1 +

P2Q2 1+r

(Equation 2.4)

The producer maximizes the present value subject to the resource constraint, which is R = Q1 + Q2 Replacing Q2 with R − Q1 , we have

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PV = P1Q1 +

P2 ( R − Q1 ) 1+r

(Equation 2.5)

To solve the profit-​maximizing problem, we find out the first-​order condition of Equation 2.5 with respect to the choice variable Q1: P1 −

P2 = 0 1+r

(Equation 2.6)

Hence, we have P1 =

P2 1+r

or P2 = P1 (1 + r )

(Equation 2.7)

Equation 2.7 is the essence of the famous Hoteling model in natural resource economics, which says that the price of a non-​renewable resource will grow at the rate of interest. Why does this maximize the present value of reserves? Suppose the price increases more slowly than the interest rate, as in the following: P2 < P1 (1 + r ); then the money in the bank is worth more than the oil in the ground. It is better to produce more oil this period, sell it at P1 and save the money in the bank to earn the interest. However, as more people do this, the price in this period will go down and the price in the next period will go up, until Equation 2.7 holds in equality. To see this more clearly, let us look at a numerical example. Suppose the prices and interest rate are P1 = $100/​bbl, P2 = $105/​bbl and r = 0.1. In this case, if we leave the oil in the ground and produce in the next period, we will earn $105/​bbl. However, if we produce more oil now, sell it at $100/​bbl and put the money in the bank, we will get $110 for a barrel of oil. Thus, we should produce more in this period. In fact, any rational producer would do the same. However, if everyone produces more in this period and less in the next period, the price in this period P1 will go down and the price in the next period, P2 , will go up until the price increases at the rate of interest. Conversely, if the price increases more rapidly than the interest rate, then producers will produce less in this period and produce more in the next period. This will drive up P1 in 50

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Exploration, development and production

this period and drive down P2 in the next period. In summary, in this simple stylized world, producers’ arbitrage over the two periods, by adjusting production, leads to price increase at the interest rate in equilibrium. Now, what happens when cost is added? For simplicity, suppose the marginal costs of oil production in both periods are constant at MC1, and MC2, respectively. Solving the first-​order condition of maximizing the present value of the reservoir, we have P1 − MC1 =

P2 − MC2 1+r

(Equation 2.8)

Here P1 − MC1 and P2 − MC2 , respectively, represent the profit from producing in each period. Thus, Equation 2.8 tells us that the profit (or the price net of the marginal cost) increases at the rate of interest. In other words, the present value of profits in the two periods is equal in the margin. To see why, again suppose the present value of the profit is greater in this period than in P − MC2 the next period: P1 − MC1 > 2 . Here money in the bank is worth more 1+r than oil in the ground. It is better to produce the oil now, sell it, earning the profit of ( P1 − MC1 ), and put this money in the bank, because doing so would give a return of ( P1 − MC1 )(1 + r ), which is a better return than producing in the next period. However, if everyone does the same, the price in this period will fall and the price in the next period will rise. This “arbitrage” will continue until profits in both periods equalize in present value terms. We can rewrite Equation 2.8 as follows: P2 − P1 (1 + r ) = MC2 − MC1 (1 + r )

(Equation 2.9)

Thus, if the marginal cost rises more quickly than the interest rate, (MC2 > MC1 (1 + r )), then the price should also rise more quickly than the interest rate. If the marginal cost rises exactly at the interest rate (MC2 = MC1 (1 + r )), then the price rises at the interest rate. If the marginal cost rises more slowly than the interest rate, the price rises more slowly than the interest rate. In circumstances when the marginal cost declines enough, prices will fall. The above model results have important implications in helping us understand the relationship between the price and costs of oil. The costs of 51

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producing petroleum and other depletable resources are influenced by the constant battle between technology improvement and depletion. Depletion tends to increase costs while technology reduces them. When the depletion effect dominates, costs rise, as it will be more difficult to extract the remaining resources.19 On the other hand, when the technology effect prevails, costs fall, as the technological effect more than offsets the depletion effect. We shall have a fuller discussion on long-term oil price trend in Chapter 7. Notes 1. A wildcat well is an exploratory well drilled in an attempt to establish whether petroleum exists in an unproven or not fully exploited area, in which either there has been no historic production record of oil or gas or it has not been fully exploited as a site for oil and gas production. The name “wildcat” reflects the amount of uncertainty associated with the outcome of the drilling. 2. There have been many fatal accidents when an uncontrollable oil and gas blowout caused an explosion, killing many people. The most famous example in recent history is the Deepwater Horizon blowout on 20 April 2010, in the Macondo Prospect, off the coast of Louisiana, operated by British Petroleum (BP). 3. A “Christmas tree” is a set of valves, pipes and fittings that sits above the basic wellhead. It is used to control the flow of oil and gas as it leaves a well and enters a pipeline. 4. This is called water flooding or gas flooding. 5. PV is the current value of a future money or a stream of future cash flows for a given discount rate. Net present value is the total present value (PV) of a time series of cash flows. It is a standard method for using the time value of money to appraise long-​term projects. It measures the economic surplus or shortfall of a project in present value terms after taking into account all capital outlays. 6. In other industries, it is usually possible to obtain relatively inexpensive statistical sample data prior to major investment decisions through opinion polls, market surveys, etc. But, with exploration, we have to live with probabilities based on meagre information. 7. Although advances in technology have reduced the uncertainty. 8. OOIP can be considered the maximum amount of oil in a reservoir. The recovery factor measures the proportion of oil in place that can eventually be recovered. 9. This section draws heavily on Hannesson (1998: ch. 4). 10. However, it must be noted that MER may not result in maximizing the present value from developing a reservoir. 11. Prorationing is the allocation of production quotas by pro rata allocations based on acreage, wells drilled or some combination of the two. The quota allocations in prorationing were often associated with efforts to restrict output in order to increase the price paid to producers. The prorationing was initially voluntary. In 1914 producers and purchasers on the Cushing field reached an agreement to allocate production on a pro rata basis across producers as a percentage of potential production. However,

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as the number of producers involved gets larger, it is more difficult to reach a voluntary agreement. In response, prorationing was gradually institutionalized as state regulations and laws in many oil-​producing states in the United States, including Texas, Oklahoma, Kansas, New Mexico, Colorado and Illinois. 12. See Chapter 6 for details of gas utilization. 13. Gas flaring is often a contentious issue between governments, local communities and international oil companies, as it is a source of air pollution and global warming and a waste of a valuable fuel source. Although gas is flared in some countries, such as Nigeria, there are frequently severe power shortages in these countries. 14. For simplicity, here we ignore the initial development phase, when production is rising, and the plateau phase. 15. Lifting cost is the cost of bring the oil to the surface –​effectively, the direct operating  cost. 16. US onshore wells in shale plays are generally multi-​stage wells, hydraulically fractured and drilled horizontally. The costs identified relate, in part, to the application of these technologies. 17. Proppant is usually sand or other small particles designed to keep a hydraulic fracture open. 18. In economics, the distinction between the short run and the long run is the fixed cost. There is a fixed cost in the short run while in the long run all costs become variable, because firms can invest and divest, and enter and exit an industry. 19. Generally speaking, the low-​cost resources –​such as oil and gas in shallow reservoirs, and minerals in open or surface mines and in easy-​to-​access areas –​will be produced first. This applies to industries in which producers behave competitively.

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3

LICENSING AND FISCAL ISSUES

In most countries other than the United States, the state is the owner of the underground resources and exercises sovereign rights over their exploration and exploitation.1 The state decides on its long-​term petroleum policy and in particular on the role it selects to grant to private investors, mostly foreign companies, in the exploration and production of petroleum in the country. To implement the petroleum policy, the host country may promulgate laws and regulations that define how to authorize foreign investors to carry out petroleum exploration and exploitation operations, how to define the terms and conditions in specific exploration and production (E&P) agreements and how the benefits derived from the exploitation of petroleum resources are divided. These laws, regulations and the associated fiscal systems collectively define the legal, regulatory and financial environment in which the petroleum industry operates and are critically important for both the investor and the hosting country. This chapter studies the main types of upstream licensing arrangements and examines the related fiscal systems. The first section provides an overview of the main forms of upstream agreements, drawing heavily on Le Leuch (2013) and Tordo, Johnston and Johnston (2010). The second section focuses on the economic analysis of different fiscal regimes.2 There is an extensive literature on the design of fiscal regimes (e.g. Johnston 1994; Cameron & Stanley 2017). The discussion in this chapter is from the point of view of understanding the business and financial environment in which oil companies operate.

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The main types of upstream agreements Depending on the legal system and regulations of each country, the agreements concluded between host countries and investors in upstream oil and gas industry may take different forms. This may consist of the award of oil and gas licences or concession agreements without the signing of a distinct agreement, or the signing of a quite detailed E&P contract when the petroleum law provides only for a main framework of principles and when the fiscal system is not fully defined by national law. In countries where the petroleum law and regulations have detailed stipulations about the conduct of petroleum activities and the related fiscal regime, the licences or concessions are usually awarded according to terms entirely defined in the national legislation and regulation. The licence may be (a) an exploration licence (or permit) over an area authorizing exploration or (b) a production licence (or lease or concession), in case of commercial development, over a restricted development area authorizing the development and production of a field. In this case, no E&P contract per se is signed, because all the terms are stipulated by the law and detailed regulations, as in the United States, Canada and Australia, etc. Even if such licences are not governed by a distinct concession contract they are categorized from a legal point as concession agreements. Sometimes the award of a licence under the country legislation is subject to the execution of a short licence (or concession) agreement providing for a few specific terms regarding exploration work obligations (such as in the United Kingdom, Norway and Denmark) and selected tax terms (e.g. related to an additional profit tax). In countries that have not yet issued comprehensive legislation and regulation, there is the need for a detailed E&P contract that provides for the terms and conditions applied to exploration and production not covered under national law and regulation. This is often the situation in many developing countries or countries without a long history of petroleum production. In many cases, the contract also deals with terms and conditions relating to certain tax aspects and the subsequent award of administrative exploration and exploitation licences. In both cases, the award of E&P licences or contracts is often based on competitive biddings organized by the country pursuant to a transparent tender procedure. However, in some cases a contract may be awarded following

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direct negotiations when the petroleum law so provides and the conditions justify it, as, for example, when the competition would be insufficient for the concerned area. However, in both systems of awarding E&P licences, often only a few terms, including the fiscal regime, are subject to bidding or negotiation. The contract is often established on the basis of a model E&P contract or licence before the open tender or the negotiation. There are three main types of E&P contracts and related fiscal regimes in the world today, namely modern concession agreements, production-​sharing contracts (PSCs)3 and risk service contracts (RSCs). Of these, PSCs are the most popular among developing oil-​producing countries, as they do not confer ownership rights for the petroleum to the company or consortium that concludes the contract. In all these arrangements, the state retains ownership of the petroleum resources when in the ground and the contract-​holder is obliged to undertake and fund, at its sole risk, the petroleum operations, receiving remuneration only if the exploration is successful and leads to the exploitation of commercial fields. Concession agreement A concession grants an oil company (or a consortium) the exclusive right to explore for and produce hydrocarbons within a specific area for a given time. The company assumes all risks and funds the operations in the area covered by the concession agreement. The produced oil and gas, but not the resource in the ground, belong to the company. Often a licence fee or bonus is paid to the government. The host government gets revenues from royalties, corporate income tax and, possibly, additional income tax on the investors’ excess or windfall profits if petroleum is produced. As a result of these fiscal features, the licence or concession agreement is often referred to as a “tax and royalty agreement”. Title to and ownership of equipment and installation permanently affixed to the ground and/​or destined for the E&P of hydrocarbons generally passes to the state at the expiry or termination of the concession (whichever is earlier), and the investor is typically responsible for abandonment and site restoration. Modern concessions are used in almost all the OECD countries in one form or another and some Asian countries. However, there is considerable

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BOX 3.1  CONCESSIONS

Concessions are an old legacy from the regime used in the mining industry in the nineteenth century, whereby the government grants the mining rights (generally a named exploration licence or production lease) to all the petroleum extracted by the company from the licensed area. The original concessions (a) granted rights to petroleum development over a vast area; (b) had a relatively long duration; (c) granted extensive control over the schedule and manner in which petroleum reserves were developed to the investor; and (d) reserved few rights for the sovereign, except for the right to receive a payment based on production. The provisions of modern concession agreements are much different from the original model. In addition to reducing the area coverage and the duration of the agreement, modern concessions also contain relinquishment clauses and express obligations to enter a work programme (Tordo, Johnston & Johnston 2010).

diversity in terms of fiscal arrangements among these countries, such as the rate and structure of the royalty, the use of corporate taxes and/​or special taxes, incentives such as investment allowances and credits, and so on. One of the major drawbacks of concession contracts was their lack of flexibility, as in many countries most of the components of the fiscal package are entirely fixed by the tax laws, except for some fiscal parameters. Production-​sharing contracts A production-​sharing contract is an agreement concluded between a state agency, such as a government ministry or a special department, or the national oil company (NOC), and one or more (usually foreign) investors. First introduced in 1966 by Indonesia, the use of PSCs has spread rapidly in many developing countries, for political and economic reasons and, above all, for their fiscal flexibility. Indeed, the PSC provides in the contract itself for specific progressive production-​sharing percentages when the law does not fix them. Another frequent advantage of PSCs, especially when there is no efficient additional profits tax used by the country under the concession 58

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agreement, is that they allow the country to get a higher percentage of the profits from the first years of production. Under a PSC, the investor (typically the foreign oil company) does not directly hold the mining rights related to the area concerned but is legally appointed as a contractor to explore for and produce hydrocarbons within a specified area and for a limited time period. The company assumes all the risks and funds the exploration, development and production of oil and gas in the contract area. In the event of commercial production, the company’s eligible expenses and capital expenditures (capex) are repaid from the total produced oil (or gas), called the cost petroleum (or cost oil and cost gas), up to a maximum annual percentage of total production, called the cost recovery limit (or cap). As an incentive to invest, the company also receives a profit element from the portion of the remaining amount of petroleum produced after deducting the cost petroleum. This is called the profit petroleum (or profit oil and profit gas). The profit petroleum is shared between the contractor and the state according to the terms agreed upon when signing the PSC, prior to the commencement of exploration. Under a PSC, the investor does not own the total production, but only a share of the production at the delivery point or export point, as defined in the contract. Consequently, the investor can book only a portion of the proved reserves. Changes in the oil and gas price result in adjustments to the investor’s share of reserves and production entitlement. The equipment and installation permanently affixed to the ground and/​or destined for exploration and production of hydrocarbons are generally passed to the state upon commissioning. Furthermore, unless specific provisions have been included in the contract or the relevant legislation, the government or the national oil company is typically legally responsible for abandonment. The access by the state to a share of the production is the major difference with the concession contract. Under PSCs, the state agency or NOC is directly involved in operational decisions, either as concessionaire or participating as a member of a management committee with the investor. In some countries the NOC may participate in the project as a shareholder. The contractor under a PSC is also subject to tax obligations stipulated in the law. These may include royalty, corporate income tax (CIT) and various taxes or quasi-​taxes (such as bonuses, surface rentals and social fees). To render the PSC simpler in its understanding and implementation, the sharing

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of the profit petroleum may be agreed on an after-​tax basis, under which the income tax is deemed included in the state’s share of profit petroleum allocated to the host country. Risk service contracts The risk service contract was originated in oil-​exporting countries such as Iran, Iraq, Qatar and Venezuela, which nationalized their petroleum industry and gave their NOC the monopoly of exploration and production. An RSC gives the national oil companies the right to use international oil companies as service contractors, mainly to take advantage of their technical capacity and access to third-​party finance. Under an RSC, the state (or the NOC) hires the contractor to perform exploration and/​or production services within a specified area for a specific time period. The contractor is compensated by a fixed or variable fee, called a service fee, paid in cash, during the contract’s duration. The state maintains ownership of the petroleum at all time, whether it is in situ or produced. The contractor does not acquire any ownership rights to the petroleum, except when the contract stipulates that the contractor is to be paid its fee “in kind” (with oil and/​or gas) or grants a preferential right to the contractor to purchase part of the production from the government. The service fee is typically designed with two objectives: (a) to reimburse over several years the eligible investment and operating costs (opex) incurred, by allocating up to a certain percentage of the annual production value; and (b) to provide for a profit element, such as a fee per barrel, which may vary in line with certain parameters (e.g. levels of production). The service fee is generally subject to the payment of corporate income tax on profits. The company is often entitled to purchase at market price and lift a share of the oil produced equal in value to the payable service fee. This type of arrangement provides security to the contractor for receiving its remuneration in case the country encounters problems making timely cash payments in terms of the service fee. Worldwide, there is a trend towards the increased use of PSCs in emerging and developing countries. Concessions continue to predominate mostly in developed countries, but they also appear in some developing countries, where a concession contract is often associated with state participation rights. Meanwhile, some emerging and developing countries that used concession

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agreements have switched to PSCs; for example, Brazil in 2010 considered PSCs more consistent with its petroleum policy for its new pre-​salt province.4 RSCs have been signed in certain exporting countries, mainly for redeveloping producing fields, such as Iraq (with the exception of the Kurdistan region, which continues to prefer PSCs for E&P projects), Mexico and Ecuador. Economic analysis of fiscal systems Economic basis of fiscal systems The foundation of a fiscal system is economic rent, which, in its simplest terms, is the difference between the cost of production and the value of the product. The cost of production in the petroleum industry consists of the exploration, development and lifting costs, as well as the normal return to capital or normal profit.5 In other words, economic rent deals with surplus. Host governments (also the resource owner in most legal systems) attempt to capture as much as possible of the economic rent through various means, including taxes, levies, royalties and bonuses. In the petroleum industry, economic rent derives from two sources. First, there is excess profit arising from the fact that the market is controlled, as producers (such as OPEC) frequently restrict supply in order to force up prices. Second, as shown in Figure  3.1, even if the market is competitive with no excess profit, low-​cost producers will gain a surplus as the price is set by high-​cost marginal producers. This is especially relevant in oil, because some producers (such as Saudi Arabia) are blessed with very large onshore oil fields, which can have very low costs compared with offshore fields. A fiscal system allows a host government to extract revenues from the exploitation of its natural resources, and it therefore drives a wedge between the host government and oil companies. In designing fiscal systems, host governments aim to maximize the expected present value of their natural resources while attracting foreign investment. They also have development and socioeconomic objectives, such as job creation, the transfer of technology and the development of local infrastructure. Oil companies aim to maximize the return on their investment, giving consideration for the risks associated with the project. These two objectives may not necessarily align with each

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Field input costs, market price

The Economics of Oil and Gas

Market price CB Rent

CA

A

B

C

D (Marginal

E

F

field)

Oil fields

Figure 3.1  Economic rent in the petroleum industry

other. The challenge of an efficient fiscal system is how to incentivize investment from the oil companies while ensuring that the host government is adequately compensated (Tordo 2007). To reconcile these objectives, it is important to use fiscal systems that are progressive and neutral. A fiscal system is progressive when the government’s share of economic rent increases as the underlying project’s profitability rises. Conversely, the system is said to be regressive if the government’s share of economic rent decreases when the underlying project profitability increases. The idea is that the government, as the resource owner in most countries, should take an increasing share of the rent as the total profit increases. However, the government should always leave enough incentives for the private investor to explore, develop and produce. A fiscal system is neutral when it does not distort companies’ economic decisions, in the sense that companies would do exactly the same thing with or without tax. For example, in the context of the petroleum industry, a tax is neutral if it does not induce companies to change production over time or investment decisions over a portfolio of projects. In other words, companies’ decisions are made solely on economics, not for tax reasons. From a company’s perspective, the key in the fiscal analysis is to balance the prospectivity6 of a project with tax and other obligations imposed by the fiscal

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system. One country may tax profits at a rate of 85 per cent or more (such as Indonesia and Malaysia), while another country may have an effective tax rate of only 40 per cent (such as the United Kingdom). Yet it is not necessarily the case that Malaysia is less attractive to investors than the United Kingdom. What really matters to a company is the after-​tax profitability, often measured by the return on capital.7 Prospectivity is affected by many factors, such as: • the field size distribution; • the reservoir characteristics, including porosity, permeability and hydrocarbon saturation; • the estimated success probability:  source of the hydrocarbon, seal, migration, etc.; • the properties of the hydrocarbons: fluidity, API gravity,8 the share of water and sulphur, etc.; • the reservoir depth and drilling costs; • post-​discovery costs: development drilling, production facilities, transportation cost and operating costs; • the water depth and climate; and • the country and political risk. Although it is not a fiscal instrument, a work programme commitment is often included in contract bidding and negotiations. A work programme indicates the type of work and budget that the bidder is committed to if it wins the licence or contract. For example, bidders in the United Kingdom submit a proposed work programme for the first exploration period, the duration of which depends on the type of licence. The type of work to be performed may include geophysical analysis, surveying or drilling, depending on the type of licence. The work commitment and signature bonus represent hard risk dollars, while fiscal terms govern the allocation of revenues from oil and gas production (Johnston 2003). Fiscal terms will also impact the success ratios of exploration efforts, because fiscal terms will determine to a large extent how big a discovery must be to justify commercial development. Figure 3.2 shows a hypothetical size distribution of a drilling prospect. If the probability of finding hydrocarbons in this prospect is 20 per cent but the reserve must be greater than 30  million barrels to be economic, then the commercial success ratio in this prospect will be only 15 per cent (20% × 75% = 15%). The

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75%

25%

0

10

20

30

40

50

60

70

80

90

100

Field size (MMbbl)

Figure 3.2  The size distribution of a drilling prospect Note: Here it is assumed that the probability of having a discovery with a field size of 2 to 100 MMbbl is 20 per cent, of which the probability finding a field greater than 30 MMbbl is 75 per cent.

commercial success ratio is always less than the technical success ratio. Tax, royalty and the contractor’s share of profit oil all have an impact on the minimum field size threshold. Main fiscal instruments A variety of fiscal instruments exist in the modern petroleum industry. Some are common to all sectors in the economy, such as corporate income tax, customs duties, value-​added tax (VAT), employment tax and capital gains tax. Others are specific to the sector, such as royalties, resource rent taxes or additional profits taxes, bonuses and production-​sharing mechanisms. On the basis of when they are applied to the upstream petroleum value chain, the fiscal instruments can be classified into three categories: pre-​discovery provisions, post-​discovery contract terms and profit-​based elements. Pre-​discovery signature bonuses Signature bonuses are one-​off (sometimes staged) payments that may be fixed, negotiated or bid on upon the award of a licence or signing of a contract. 64

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The application of pre-​discovery payments in petroleum fiscal arrangements is common worldwide. Nearly a half of all countries with petroleum fiscal systems include at least one form of pre-​discovery payment to the host government. When competitively bid, signature bonuses can be sizeable. For example, in 2013 the Liberian National Oil Company announced that it had agreed on a signature bonus from Exxon Mobil of $21.25 million, its largest bonus to date. In 2007 a consortium of Chinese mining companies agreed to pay the government of Afghanistan a signature bonus of $808 million and a further $566 million upon the commencement of commercial production. In addition to signature bonuses, pre-​discovery payments also include “rentals” and discovery or prospectivity bonuses.9 In general, pre-​discovery payments are easy to administer and provide early revenue for the government, and so they are welcomed by the government. From companies’ perspective, bonus payments are sunk costs and deductible for CIT calculations only if there is successful development of the project. Economists generally favour bonus bidding, for two reasons. First, as it is a lump sum payment before production begins, it does not alter the producer’s production decision. Second, when there are multiple bidders, competition can bring in a competitive outcome so as to maximize the government’s revenue. Post-​discovery royalties and production-​based instruments Royalties represent one of the possible means by which the resource owner is compensated for the loss of valuable, non-​renewable resources. For this reason, they are, strictly speaking, not a tax. Traditionally, royalties may be one-​eighth, or 12.5 per cent, of production; however, they can be any fraction of production, depending on the royalty clause in a lease or contract. The main type of royalty is the ad valorem royalty on production, payable in cash or in kind and equal to a percentage of the monthly (or quarterly) petroleum revenues. In some cases, a unit royalty (for example, per ton) may apply. The royalty rate can be fixed by law either as a unique rate or a progressive royalty scale based on different technical or economic parameters, although the tendency is to define royalties using a sliding scale according to water depth, location and hydrocarbon type and/​or value. A sliding-​scale royalty may look as in Table 3.1. From the government point of view, royalties have two advantages. First, they are relatively predictable, in the sense that companies must make some 65

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Table 3.1  A sliding-​scale royalty Average daily production

Royalty

Up to 10,000 bbl/​d 10,001–​20,000 bbl/​d >20,000 bbl/​d

5% 10% 15%

payments to government even in times of low profitability. Second, they are relatively simple to administer, as there are no deductions allowed. Further, royalties are long-​lived, in that royalties are paid from the start of the producing life of a project right through to the end of the field. The major drawback of royalties is that they are regressive rather than progressive,10 because they are calculated on production, not profits. A high level of production does not necessarily equate to a high level of profit. A project with high costs may end up paying the same amount of royalty as one with low costs if the production is the same. The company may also tilt production towards the back end in order to minimize the present value of royalty obligations. A production bonus is similar to a signature bonus, in that it is also a one-​ off payment to the government, made when certain levels of production are reached. Typically, a sliding scale is applied in production bonus calculations, to rectify the regressiveness of production bonuses on the economic performance of E&P projects. For example, a production bonus scheme may look like the following: when the production level is below 25,000 bbl/​d, there is no need to pay the bonus; when production reaches 25,000 bbl/​d, the company pays a $1.5 million production bonus to the government; when the production rises further to 50,000 bbl/​d, the production bonus increases to $2.0 million. It is also apparent that the production bonus is regressive, as it does not consider the profitability of the project. Companies may also be able to avoid paying the bonus by controlling production from the reservoir so that it remains just under the tranche threshold. Thus, the determination of production bonuses is usually allowed to be contract-​specific Crypto fees are indirect means through which a government can receive additional revenue through levies, the application of duties and other financial obligations imposed on oil-​and gas-​producing companies. For example, the crypto fees or taxes in Nigeria include 3 per cent of a project’s

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annual capital budget as a contribution to the Niger Delta Development Commission and an education tax of 2 per cent of a project’s assessable profit (Iledare, 2015). It is important to note that the instruments and terms highlighted above are not favourably disposed to assets’ profitability. They are front-​end-​loaded and tend to lower the profitability of assets in economic terms. Profit-​based instruments Corporate income tax is a tax imposed on the net profit of a corporation computed after deducting eligible expenses, costs and capital allowances in a particular jurisdiction. The application of CIT is a common practice and attributable to doing business in the country itself, not specifically to the oil and gas sector. It ensures that the normal return to equity at corporations is taxed in the way it is in non-​extractive sectors. However, countries may tax the upstream petroleum industry at a higher rate. For example, in the United Kingdom the CIT for petroleum sector is 30 per cent while the general CIT is lower and set to fall to 17 per cent by 2020. The corporate income tax is often determined on a consolidated country basis for all the upstream activities of a company, and not per contract, concession or field unless there are specific ring-​fencing provisions. CIT is normally computed at the corporation level. However, countries may include in their tax code a ring-​fencing provision for the oil and gas sector such that taxes are calculated at the project or licence level or for the sector. A frequently applied tax rule in the extractive industries is to restrict deductions to be ring-​fenced in the sector –​not allowing non-​sector activities to be deductible from the extraction sector, and vice versa. Norway and the United Kingdom, for example, allow ring-​fencing only for the offshore petroleum sector.11 When the tax is ring-​fenced in the sector, as in Norway and the United Kingdom, costs on one field can be deducted against the revenues of another. However, if it is ring-​fenced at project level, it could eliminate companies’ incentive to spend on new exploration and development projects outside the producing area, as it does not allow investors to consolidate new costs with existing income for tax purposes. Although the profit-​based income tax is progressive, in practice it typically requires extensive and well-​informed monitoring. The taxes are based

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on accounts from the oil companies, which typically are international and with diverse activities. By suitable internal pricing (i.e. transfer pricing), they can move profits from high-​tax jurisdictions to low-​tax jurisdictions. This requires tax auditors to be able to track the transactions. Easier monitoring may justify the existence of “crude” instruments such as royalties. Additional profits tax (APT) or resource rent tax (RRT), which may have different names, is an annual tax payable, in addition to CIT, only when some conditions of profits or petroleum price are met. The idea is to “target returns made on investments that exceed the minimum reward necessary for capital to be deployed” (Land 2010: 241). It gives an investor relief, since this type of tax will not affect the company’s cash flow until a satisfactory rate of return has been achieved. Dramatic swings in commodity prices have made this type of supplementary tax a popular topic as a possible means of collecting revenue from what is commonly known as “windfall profit” since the 1970s and 1980s. It has been argued that the government is a silent partner whose share in the project is determined by the tax rate. However, each partner contributes something additional to the partnership –​private firms contribute rents associated with their expertise and the government contributes rents associated with the rights to the community’s nonrenewable resources. These rents are also shared according to the tax rate. Tax Review Panel (2010: chs 1–​3) APT is assessed in many producing countries on an adjusted cumulative cash flow basis determined per company or per concession, such as in the United Kingdom, Norway, Denmark, the Netherlands, Australia, etc. APTs are now applied under different mechanisms in more and more countries with the objective of achieving a more progressive fiscal scheme when the effective profitability of projects exceeds predefined levels. Profit oil is the remaining hydrocarbon revenues after the deduction of royalties and cost oil from the gross revenue. Cost recovery limit specifications, which cap the amount of revenue available for cost recovery, determine the amount of profit oil to be shared between the host government and the contractor. Worldwide, cost recovery limits typically range between 40 and 70 per cent, with an average of 65 per cent (Johnston 2003). The cost recovery 68

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limit is to ensure some minimum profit oil for distribution until all eligible costs are recovered. The government share of profit oil is often determined on a sliding scale, to make it more progressive. There are several variants of profit-​oil-​sharing mechanisms, each of which is aimed at increasing the government’s profit share on the more profitable projects. Daily production-​based: the government share of profit petroleum increases with the daily rate of production from the field or licence, often with several tiers. Cumulative production from a project: the government share of profit petroleum increases as total cumulative production increases. This is not commonly used. R-​factor: the government share of profit petroleum increases with the ratio of the contractor’s cumulative net revenues to the contractor’s cumulative investments (or costs) from the award of the licence or contract. This variant is increasingly used. Rate of return:  the government share is set by reference to the cumulative contractor’s rate of return achieved from the award of the licence. Production-​sharing regimes share to a large extent the same advantages and disadvantages of income taxes. Specific issues relating to natural gas To compensate the low profitability of upstream natural gas projects, many countries have specific provisions on natural gas to enable more favourable fiscal terms for gas operations. These include the following: • Reduced royalty rates for natural gas under tax and royalty systems, for example in Nigeria the maximum royalty rate for natural gas is 7 per cent whereas for oil it is 20 per cent. • Under PSCs, more favourable cost recovery and profit-​sharing terms to the investor in relation to gas production. For example, in Indonesia, the contractor’s share of profit gas can be as high as 30 to 40 per cent, whereas for oil projects it is typically 25 to 35 per cent. • Low CIT rates, for example in Papua New Guinea and Tunisia. • Exemption from certain petroleum taxes. For example, in Trinidad and Tobago, there is an exemption for the supplementary petroleum tax for gas projects. 69

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It must be noted that the fiscal regime applied to the upstream oil and gas sector contrasts with the typical tax regime regarding downstream activities, which generally consists of the general tax code of the country applicable in the same way as to any other sector of the economy. Downstream oil and gas projects tend to be treated as general industrial projects and subject only to standard corporate income tax. Financial modelling of the royalty/​tax system and PSCs To better understand how each of the fiscal instruments works, we now turn to the financial modelling of royalty/​tax and PSC systems, respectively, by working through a series of examples. Because the difference between service agreements and PSCs is relatively modest, the study of PSCs effectively covers all aspects of contractual systems. The terminology and arithmetic of most PSCs and service agreements are almost identical. Royalty/​tax systems Example 1: Assume the gross revenue from one project in a particular year is $60,000 and the royalty rate is 10 per cent, with the operating costs and depreciation, depletion and amortization (DD&A) totalling $24,000. The country has a special petroleum tax (SPT) rate of 20 per cent, which is deductible against income tax, and the corporate income tax rate is 30 per cent. The flow chart is as shown in Figure 3.3. In both the royalty/​tax and PSC systems, royalties are typically computed on the gross income before any deductions, although some countries allow transportation cost to be deducted from gross revenue calculations. As in any other standard tax calculations, the contractor is allowed to deduct opex, DD&A and intangible drilling costs to arrive at taxable income. Usually depreciation is used only for tangible capital costs. The taxable income after royalty and cost deductions is subject to two layers of taxation in this case, namely a 20 per cent special petroleum tax and a 30 per cent corporate income tax. Since the SPT is deductible against income taxes, the effective tax rate is 44 per cent (20% + 80% × 30%). With tax deductions, the contractor share of gross revenue is ($16,800 + $24,000)/​$60,000 = 68 per cent. The contractor share of the profit is 47 per

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Licensing and fiscal issues Gross revenue $60,000 Royalty (10%) $6,000 Net revenue aer deducng royalty $54,000 Cost $24,000

$6,000

Aer deducng capex and opex $30,000 Special Petroleum tax (20%)

$6,000

Net revenue aer SPT $24,000 $16,800 profit

Income tax rate 30%

47% $16,800/($60,000– $24,000)

Take

$7,200 53% $19,200/($60,000– $24,000)

Figure 3.3  Typical revenue distribution under the royalty/​tax system

cent ($16,800/​$36,000). This is called “contractor take” in the industry.12 The complement of contractor take is government take, which is one minus the contractor take. In this case, the government take is 53 per cent. Production-​sharing contracts On the face of it, PSCs appear quite different from royalty/​tax systems. The terminology is certainly different and there are legal and philosophical differences, as explained above. However, from a financial and arithmetic point of view, they are not so different. For practical purposes, the only difference is the cost recovery limit. When the cost recovery limit is binding, unrecovered cost will be carried forward to the next years until it is fully recovered. Figure 3.4 illustrates the flow chart of a stylized PSC for a given year. Here it is assumed that the total available petroleum, and hence the gross revenue, is $60,000 and the total cost (the sum of opex and capex) is $35,000. The cost recovery limit is 50 per cent of gross revenue and the profit oil is shared between the government and the company at a 60:40 ratio in favour of the government (that is, the government share of the profit oil is 60 per cent and the contractor share is 40 per cent). Because the cost recovery limit is binding, only $30,000 of the cost can be recovered this year and the remaining $5,000 will be carried forward to the next year. This leaves $30,000 of profit

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Available petroleum All oil produced in contract area

60 Assume costs are 35

Less cost oil (Assume capped at 50% of available petroleum)

Leaves profit oil Assume 60/40 split in favour of government

18 Government’s share of profit oil

30

30

Unrecovered costs of 5 are usually carried forward to next years

12 Contractor’s share of profit oil

Contractor’s equity oil

42

Figure 3.4  A flowchart of a stylized production-​sharing contract Note: All figures are in thousands of US dollars.

oil, which is to be shared between the government and the company. Thus, the contractor’s equity oil includes both the cost oil of $30,000 and the profit oil of $12,000. This equity oil forms the basis for taxation. What happens if the company also needs to pay royalty and income tax? Example 2 illustrates such a case. Example  2: Let us continue to assume that the gross revenue for one year is $60,000 and the royalty rate is 10 per cent. The sum of opex and capex totals $35,000 and the cost recovery limit is 50 per cent of gross revenue. Profit oil will be shared at 60:40 ratio favourable to the government. Corporate income tax rate is 30 per cent and there is no special petroleum tax. Figure 3.5 shows the calculation. Before the sharing of production, the contractor is allowed to recover costs out of net revenues. However, most PSCs will place a limit (or cap) on how much production (or revenue) will be made available for the recovery of costs in any given accounting period. In this example, only $30,000 of total cost is

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Company share

Gross revenue $60,000

Government share

Royalty (10%)

 $6,000

Net revenue $54,000 (Total cost: $35,000) Cost recovery $30,000

Cost recovery limit 50%

$9,600

Profit oil split 40:60

 $14,400

($1,380)

Income tax rate 30%

 $1,380

$3,220

Net profit

13% $3,220/($60,000–$35,000)

Take

87% $21,780/($60,000–$35,000)

Figure 3.5  Revenue allocation under a PSC with royalties and taxes

allowed to be recovered from this year’s revenue, because of the cost recovery limit. The other $5,000 will be carried forward to future years. Hence, the equity oil to the contractor is $30,000 + $9,600 = $39,600. For tax purposes, because there is enough revenue to cover the cost, the $5,000 is deductible from the company’s share of profit oil. The taxable income is simply the difference between the contractor’s equity oil and the total cost: $39,600 –​ $35,000 = $4,600, and the income tax is $1,380.13 This leaves $3,220 net profit for the contractor. Thus, the contractor’s take is 13 per cent in this case. Note that, if the cost recovery limit is not binding, then the company’s taxable income will be equal to the contractor’s share of profit oil. In fact, over the life of a field the accounting profits subject to ordinary income taxes will be equal to the company share of the profit oil. However, this does not mean that profit oil ordinarily constitutes the tax base in any accounting period, because in any given accounting period a company will receive a share of profit oil if there is a cost recovery limit, but the company may not be in a taxpaying position. This can be clearly seen in ­example 3. Example 3: To further illustrate how the financial modelling works under a PSC when the company also pays royalties and taxes, we consider a full cash

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flow model for developing a 100,000 barrel oil reservoir. Assume the 100,000 barrels of proven reserve will be fully recovered by the end of the project life. Let us further assume that the project is equity-​financed, so that there is no financing cost, nor inflation.14 The cost parameters and timeline to develop the field are as follows. • The exploration cost is $1.2 million. All exploratory effort will take place in year 0. • The development cost is proportional to the size of the reserve and averaged at $10/​bbl. The lifting cost is $7.5/​bbl of oil produced. • The royalty is 5 per cent. The cost recovery limit is 80 per cent of gross revenue. The profit oil will be split 40:60 in favour of the government. The capital cost is straight-​line-​depreciated within five years starting from production. • The corporate income tax rate is 25 per cent. There are no other taxes. • The discount rate is 10 per cent. • The oil price is constant at $70/​bbl for the project life and there is no inflation. • Capital cost will be straight-​line-​depreciated within five years from the year when it occurs. • It takes two years (year 1 and year 2) to develop the field. The peak output capacity will be reached at year 2 and is targeted at one-​tenth of the total proven reserve. The development cost is to be equally spread between the two years. The output in year 1 is 50 per cent of the peak production capacity. • Once the output reaches its peak capacity, it will stay at a plateau for two years (that is, the output in year 3 is equal to the output in year 2), then declines exponentially at the rate of 10 per cent every year. Table 3.2 shows the cash flow calculation. In this example, the company receives its share of profit oil in year 1 and year 5. However, it does not need to pay income taxes, because there is no taxable income in those two years. The total gross profit over the life of the project is $4,050,000 (total revenue minus capital costs and operating costs). The contractor’s after-​tax profit (net cash flow) is $1,088,743. Thus, the contractor’s take is 27 per cent and the government take is 73 per cent, which includes royalties, the government share of profit oil and income tax. However, at a 10 per cent discount rate, the net present value of the operator is –​$3,281. Therefore, the project will not be undertaken. 74

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Table 3.2  A sample PSC cash flow projection Year

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Total

Output (bbl)

Gross revenue

A

B

0 5,000 10,000 10,000 9,048 8,187 7,408 6,703 6,065 5,488 4,966 4,493 4,066 3,679 3,329 3,012 2,725 2,466 2,231 1,133

0 350,000 700,000 700,000 633,386 573,112 518,573 469,224 424,571 384,168 347,610 314,530 284,599 257,516 233,010 210,836 190,772 172,618 156,191 79,285

100,000

7,000,000

Royalties C

Net revenue

Capital costs

C

E

0 17,500 35,000 35,000 31,669 28,656 25,929 23,461 21,229 19,208 17,380 15,727 14,230 12,876 11,650 10,542 9,539 8,631 7,810 3,964

0 332,500 665,000 665,000 601,717 544,456 492,644 445,763 403,343 364,960 330,229 298,804 270,369 244,640 221,359 200,294 181,234 163,987 148,382 75,320

1,200,000 500,000 500,000

350,000

6,650,000

2,200,000

Note: CRCF = cost recovery carried forward.

Operating costs

Depreciation

CRCF

F

G

H

37,500 75,000 75,000 67,863 61,405 55,561 50,274 45,490 41,161 37,244 33,700 30,493 27,591 24,965 22,590 20,440 18,495 16,735 8,495

340,000 440,000 440,000 440,000 440,000 100,000

97,500 52,500 7,500 8,654 51,569

750,000

2,200,000

217,723

Cost recovery I 280,000 560,000 560,000 506,709 458,489 207,131 50,274 45,490 41,161 37,244 33,700 30,493 27,591 24,965 22,590 20,440 18,495 16,735 8,495 2,950,000

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Table 3.2 continued Year 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Total

Total profit oil

Government share

Company share

J

K

L

52,500 105,000 105,000 95,008 85,967 285,513 395,489 357,853 323,799 292,985 265,104 239,876 217,049 196,394 177,705 160,794 145,492 131,647 66,826

31,500 63,000 63,000 57,005 51,580 171,308 237,293 214,712 194,279 175,791 159,062 143,926 130,229 117,836 106,623 96,476 87,295 78,988 40,095

21,000 42,000 42,000 38,003 34,387 114,205 158,196 143,141 129,520 117,194 106,042 95,950 86,820 78,558 71,082 64,318 58,197 52,659 26,730

3,700,000

2,220,000

1,480,000

Taxable income M (76,500) 87,000 87,000 36,849 (8,529) 165,775 158,196 143,141 129,520 117,194 106,042 95,950 86,820 78,558 71,082 64,318 58,197 52,659 26,730 1,480,000

Income tax N

Contractor cash flow O

–​ 21,750 21,750 9,212 –​ 41,444 39,549 35,785 32,380 29,299 26,510 23,988 21,705 19,639 17,770 16,079 14,549 13,165 6,683

–​1,200,000 –​236,500 5,250 505,250 467,637 431,471 224,331 118,647 107,356 97,140 87,896 79,531 71,963 65,115 58,918 53,311 48,238 43,648 39,494 20,048

391,257

1,088,743

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The cost recovery limit under a PSC ensures that the government always get a share of profit oil, because a certain percentage of production is always reserved for the profit oil split. In a way, the cost recovery limit functions like a royalty, and is regressive as it does not target specifically the economic rent. To see this, e­ xample 4 illustrates the regressive effect of a 10 per cent royalty and a 50 per cent cost recovery limit under high-​, low-​and zero-​cost cases. Example 4: This example compares three scenarios with varying costs and profits under a PSC. The system is regressive as a result of the cost recovery limit and royalties. To simplify matters, we ignore the units and assume that the gross revenue is 100 for full cycle, the royalty rate is 10 per cent, cost recovery is capped at 50 per cent of gross revenue, the government share of profit oil is 60 per cent and the CIT rate is 30 per cent. The sum of capex and opex is 60 for the high-​cost case, 40 for the low-​cost case and zero for the zero-​cost case. Table 3.3 presents the take calculations. For comparison, I add a column for the high-​cost case when there is no cost recovery limit. Table 3.3  Take calculation with varying costs

Gross revenue Royalties Net revenue Total cost recovery Profit oil Government share (60%) Contractor share (40%) Unrecovered cost Taxable income Income tax (30%) Contractor cash flow Contractor take Government take

Zero cost (cost = 0)

Low cost (cost = 40)

High cost (cost = 60) C/​R limit

without C/​R limit

(1) 100 –​10 90 0 90 –​54 36 0 36 10.8 25.2 25.2% =25.2/​ (100–​0) 74.80%

(2) 100 –​10 90 –​40 50 –​30 20 0 20 6 14 23.3% =14/​(100–​40)

(3) 100 –​10 90 –​50* 40 –​24 16 –​10 6 1.8 4.2 10.5% =4.2/​(100–​60)

(4) 100 –​10 90 –​60 30 –​18 12 0 12 3.6 8.4 21% =8.4/​(100–​60)

76.67%

89.50%

79%

Notes: C/​R = cost recovery. In the high-​cost case, the total cost is 60, although only 50 is recovered from the cost recovery channel.

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Comparing columns (1), (2) and (3), it is notable how the government take increases as the project profitability decreases. This is precisely the result of the royalty and cost recovery limit effect. As costs increase (and profits decrease), the royalties and profit oil going to the government take an increasing share of the profits. Furthermore, to see the effect of the cost recovery limit, let us consider the high-​cost case when there is no cost recovery limit, in column (4). The contractor take in this case rises, remarkably, to 21 per cent, from 10.5 per cent in column (3), which clearly demonstrates the effect of the cost recovery limit. Nonetheless, it is still lower than in the low-​and zero-​cost cases (columns (1) and (2)), as a result of royalties. Finally, it is worth noting that the company’s taxable income is equal to the company’s share of profit oil when the cost recovery limit is not binding (columns (1), (2) and (4)), consistent with our early expositions. In summary, each of the fiscal instruments has its own advantages and disadvantages and can influence the decision-​making of investors. Some instruments (e.g. royalties) are easy to administer and provide early revenue for the government but are non-​neutral and regressive. A production-​sharing agreement allows risk sharing and progressivity by sharing profit oil, but the cost recovery limit may function as a royalty. Thus, it is important for oil companies to take a holistic approach when evaluating the influence of fiscal terms on the commerciality of a project. The profitability of a project is affected by a variety of factors, including fiscal regime, the geology, the infrastructure, the prices of oil (or gas) and –​above all –​the technology. Because the fiscal terms constitute only one of the elements that determine the project economics, a contract with “tough” fiscal terms may be highly profitable, while a very “favourable” contract may not be. Notes 1. In the United States, it is the landowner above the reservoir who owns the property rights of the underground mineral resources, according to the rule of capture. 2. Here the terms “fiscal system” and “fiscal regime” are used interchangeably and refer to all the taxes, levies and bonuses that a company is obliged to pay in relation to the petroleum operation within a sovereign country. 3. Here the term “contract” is interchangeable with “agreement”. For example, production-​ sharing contracts are frequently called production-​sharing agreements. In some countries, these are also called exploration production-​sharing agreements (EPSAs) or exploration and development production-​sharing agreements (EDPSAs). 78

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4. The pre-​salt layer is a geologic layer that was formed before a salt layer accumulated above it. It was formed by the separation of the current American and African continents, a process that started about 150 million years ago. See www.petrobras.com. br/​en/​our-​activities/​performance-​areas/​oil-​and-​gas-​exploration-​and-​production/​ pre-​salt. 5. Normal profit: the amount that a producer must receive to induce it to stay in business. 6. Prospectivity, loosely speaking, is the geological attractiveness of a potential field. It is similar to “land fertility” in agriculture. 7. In addition to profitability, some companies, particularly the major international oil companies, are concerned about “materiality”; that is, the project should not be too small to meet their investment threshold. 8. The API degree is a measure of the specific gravity of crude oil using a formula developed by the American Petroleum Institute: API = 141.5/​specific gravity –​131.5. For more details, see Chapter 5. 9. Rentals are annual payments to governments, which are usually flat or may be escalated at some pre-​arranged rate. 10. A tax is said to be regressive if the tax rate decreases as the amount subject to taxation increases. A tax is progressive when the tax rate increases as the amount subject to taxation rises. 11. In Norway the offshore sector is ring-​fenced, but costs on one field can be deducted against the revenues of another. 12. Strictly speaking, “take” should be measured over the life of a field, not any one accounting  period, because there could be no profit in a particular year. The take statistics focus on the division of profits. They also correlate directly with reserve values, field size thresholds, tax rate, and so on. The main limitation of the take statistics is that they do not account for other aspects of a given fiscal regime, such as the cost recovery limit, ring-​fencing and work programme commitments. Nonetheless, they provide a useful tool for the comparison of fiscal systems. 13. Here the depreciation rate for tax purposes is assumed to be the same as for cost recovery calculations. 14. Alternatively, this is to say that the price and cost figures are all in real dollars instead of nominal dollars.

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PETROLEUM TRANSPORTATION

Oil can be transported by a variety of methods, including water-​borne barges and tankers, pipelines, railways, trucks and even horse wagons. Which mode is the most appropriate depends on the volume of oil that is being shipped, the distance and the destination. In comparison, gas transportation is pretty much limited to pipelines unless it is converted to liquid. The pipeline is the most commonly used method of transporting oil and gas on land. Pipelines are typically used to move crude oil from the wellhead to gathering and processing facilities and from there to refineries and tanker-​ loading facilities. Pipelines require significantly less energy and manpower to operate than trucks or shipping by railway and therefore are usually the most economical way of shipping oil and gas on land, particularly over long distance and large volume. Railways are another mode of transporting oil over a long distance to areas where there are no pipelines. Although the capacity of each railway tank car may be limited, when many tank cars are used a lot of oil can be transported. For example, a common tank car used in the United States is the DOT-​111 car, which can hold 34,500 US gallons (820 bbl). If 20 such tank cars were pulled, the train would be carrying 690,000 US gallons (16,400 bbl) of oil. Compared to pipelines, the advantages of railways are that the capital cost required is lower and the construction period is shorter. However, railways tend to have higher carbon emissions and are more prone to accidents than pipelines. Where transportation over land is not suitable, oil can be transported by tankers and barges. A tanker is a ship with separate tanks for the bulk transport of oil or its products. Tankers remain the only practical way of shipping

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oil and liquefied natural gas across oceans. Barges are smaller and do not have any method of propulsion. Rather, barges are often pushed or towed by tugs, and cannot travel across rough seas. The capacity of tankers and barges can be very large. A typical 30,000-​barrel tank barge can carry the equivalent of 40 rail tank cars at about one-​third of the cost. Trucks are often the last step in the transport process, delivering oil and refined petroleum products to their intended storage facilities and gas stations. Trucks offer the greatest flexibility. The main drawback of trucks is the relatively high cost of operation, because of their limited transporting capacity. Trucks are typically used for short-​distance transportation. Like other forms of transportation, petroleum transportation is often a sequence of modes, with tankers and pipelines the most used for large volumes. For example, crude oil may be shipped using pipelines or tankers to a refinery, from which refined petroleum products such as gasoline, diesel and jet fuel are transported with railway or trucks to the market. Because of the crucial role of pipelines and tankers in petroleum transportation, in this chapter we focus on the economics of tankers and pipelines. Tankers Oil has a long history of transport by water. It dates back almost to the start of the modern oil industry. In 1861 a sailing ship of oil barrels was sent from Philadelphia to London. Oil was also loaded in wooden barrels and shipped by horse wagons on land. Originally barrels held 50 gallons, but contracts were written on a 42 gallon per barrel basis to allow for spillage. This practice has lasted to today: each oil barrel contains 42 gallons. The first bulk crude ocean carrier began its commercial operation in 1863. To prevent oil from sloshing and destabilizing the vessel, tanks were used to separate oil in these carriers; this is how the tankers were named. Since the first oil tanker began shipping oil, in 1878 in the Caspian Sea, the capacity of the world’s maritime tanker fleet has grown substantially. As of 2016 about 3,055 million tons of oil and gas products were shipped by tankers, including 1,838 million tons of crude oil –​roughly 42 per cent of crude oil production –​and 1,218 million tons of petroleum products and liquefied natural gas (UNCTAD 2017). The maritime circulation of petroleum follows a set

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of maritime routes between regions where it is extracted and regions where it is refined and consumed. About half the petroleum shipped is loaded in the Middle East and then shipped to Japan, the United States and Europe. Tankers bound for Japan use the Strait of Malacca while tankers bound for Europe and the United States will either use the Suez Canal or the Cape of Good Hope, depending on the tanker’s size and its specific destination. Tanker classification Petroleum tankers are usually classified on the basis of either usage (the types of products they carry) or size. On the basis of usage, tankers are classified into the following categories. Crude tankers: tankers specifically used to transport crude oil. Compared to product tankers, crude oil tankers are generally larger, ranging from 55,000 DWT Panamax-​sized vessels to ultra-​large crude carriers (ULCCs) of over 440,000 DWT.1 Product tankers: tankers used to transport refined petroleum products such as gasoline, kerosene, diesel, jet fuel and naphtha.2 LNG tankers: tankers used to transport liquefied natural gas. Because it must remain cooled at extremely low temperatures (–​260°F) and has a higher propensity to burn, tankers carrying LNG require careful and delicate design and handling. Chemical tankers: tankers used to transport chemicals in various forms. Chemical tankers are specifically designed in order to maintain the consistency of the chemicals they carry. These tanker ships are applied with coatings of certain substances that help in the easy identification of the chemicals that need to be transported. On the basis of size, there are two systems of classification. One is the AFRA3 (average freight rate assessment) system, which classifies tankers by capacity range. The AFRA scale was introduced in 1954 but later added upper ranges as tanker sizes increased. It is comprised of: general purpose (GP, below 25,000 DWT); medium range (MR, below 50,000 DWT); large range 1 (LR1, below 80,000 DWT); large range 2 (LR2, below 60,000 DWT);

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very large crude carrier (VLCC, below 320,000 DWT); and ultra-​large crude carrier (ULCC, below 550,000 DWT). The other classification system, which is more popularly used today, is the flexible market scale, which classifies tankers according to their capacities as well as the capacity of typical routings, such as the maximum capacity that can pass through the Suez Canal. The flexible market scale has the following categories. Panamax: tankers than can pass through the Panama Canal. As will be explained below, until 2016, when the expansion of the Panama Canal was finished, the Panamax was in the range of 60,000 to 80,000 DWT. However, a neo-​Panamax has been introduced, which has a maximum capacity of 120,000 DWT, since the Panama Canal expansion. Aframax: tankers with capacities in the range of 80,000 to 120,000 DWT. Aframax-​class tankers are mainly used in the basins of the Black Sea, the North Sea, the Caribbean Sea, the South and East China Seas and the Mediterranean Sea. Suezmax: Just like Panamax, Suezmax tankers are those that can pass through the Suez Canal, with capacities ranging from 120,000 to 200,000 DWT VLCCs: Very large crude carriers:  tankers with capacities of 200,000 to 320,000 DWT. ULCCs: Ultra-​large crude carriers: tankers with capacities up to 500,000  DWT. Table  4.1 compares the classification of the two systems. Although the terms “VLCC” and “ULCC” are used in both systems, the VLCC in the AFRA system has a wider range, which includes tankers in the range 160,000 to Table 4.1  Oil tanker size categories AFRA scale General purpose (GP) Medium range (MR) Large range 1 (LR1) Large range 2 (LR2) VLCC ULCC Source: Evangelista (2002a).

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Flexible market scale 10,000–​24,999 DWT 25,000–​44,999 DWT 45,000–​79,999 DWT 80,000–​159,999 DWT 160,000–​319,999 DWT 320,000–​550,000 DWT

Product Panamax Aframax Suezmax VLCC ULCC

10,000–​60,000 DWT 60,000–​80,000 DWT 80,000–​120,000 DWT 120,000–​200,000 DWT 200,000–​320,000 DWT 320,000–​550,000 DWT

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Figure 4.1  Size of oil tankers Source: Marine Insight, “Tanker size”; available at: www.marineinsight.com/​wp-​content/​uploads/​ 2011/​08/​tanker-​shize.gif, enhanced by the author.

200,000 DWT, whereas, in the flexible market scale, these tankers would be classified as Suezmax. Figure 4.1 illustrates the length of a typical tanker in each category. Tanker chartering International oil companies may own or rent tankers for transportation. The latter is commonly referred to as chartering. They more often rent than own tankers. According to one statistic, around two-​thirds of the world’s tanker capacity is owned by independent tanker owners.4 When there is a need to ship a cargo, oil companies charter tankers from an independent tanker company. This way, when the oil company does not need it, the tanker does not sit idle, as other companies may hire it. 85

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There are three common chartering agreements:  voyage charter, time charter and bareboat charter. A voyage charter is the act of hiring a vessel and crew for a specific trip between a load port and a discharge port. The charterer (the user) pays the vessel owner on a per-​ton or lump-​sum basis. The owner pays the port costs (excluding stevedoring), fuel costs and crew costs. This would be analogous to hiring a taxi for a specific trip. A time charter is the hiring of a vessel for a certain time period, ranging from several months to several years. The owner of the vessel still manages it but the charterer selects the ports and directs the vessel where to go. The charterer pays for all the fuel the vessel consumes, settles the port charges and gives a fair return to the owner of the vessel. The analogy would be hiring a car with a chauffeur for a period of time. A bareboat charter is an arrangement for the hiring of a vessel whereby no administration or technical maintenance is included as part of the agreement. The charterer pays for all operating expenses, including fuel, crew, port expenses and hull insurance. This would be similar to renting or leasing a car from a car rental company with the renter responsible not only for driving, maintenance and fuel but also for paying a rental fee. The charter rate, or the price paid for hiring a tanker for a voyage, is typically quoted in an index called “Worldscale”. The index was developed by the London Tanker Brokers’ Panel (LTBP), based on a wartime practice. The idea is that a benchmark average cost figure for shipping oil on a specific route can be computed by summing the expenses incurred by an average tanker, operated in an average manner. This benchmark cost can be used as a basis for freight rate negotiations by tanker owners and charters. For each conceivable voyage in the world, the LTBP estimates a dollar cost per ton of carrying the oil in a standard tankship under specific conditions, including a return for the owner. These baseline figures, published annually, are designated “Worldscale 100”. The actual rate for the voyage is often negotiated between the charterer and the ship owner around Worldscale. For example, if the Worldscale 100 for a trip from A to B is $4 per ton and the actual vessel is hired at $2 per ton, this is reported as Worldscale 50. Tanker charter rates are influenced by a variety of factors, including the demand and supply conditions in the tanker market, the price of oil or petroleum products, the overall demand and supply for shipping (since there could be spillover effects between the tanker market, the dry cargo market and the containers market)5 and environmental regulations. Of particular

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BOX 4.1  THE CALCULATION OF WORLDSCALE

The basis of the Worldscale calculation is a hypothetical, laden tanker of 75,000 tons capacity, with a voyage speed of 14.5 knots and running on heavy (380#) fuel oil, of which it consumes 55 tons per day for propulsion and 100 tons for all other purposes during the voyage. Included in the cost calculations is a fixed daily hire element of $12,000 per day to account for expenses such as crew costs and maintenance. This hypothetical tanker is then sent on a hypothetical journey, a model voyage from load to discharge port. The costs it incurs on that voyage –​ port tariffs, canal charges, bunker prices, layovers, and so on –​are summed, and divided by the cargo volume. The resulting figure expresses the cost per ton of making that voyage. Doing this for every feasible voyage in the world will end up with the figure group for Worldscale. Source: Evangelista (2002b)

importance is the amount of slack capacity in the tanker market. The shipping industry considers 90 per cent utilization of the tanker fleet as “full utilization”, because tankers must dock routinely for maintenance (Robert Strauss Center 2008). Therefore, if more than 90 per cent of the tanker fleet is utilized for transporting oil, the freight rate is likely to spike. Figure 4.2 plots the Baltic Exchange’s clean and dirty tanker indices from August 2002 to December 2017.6 The indices reflect the chartering costs for dirty and clean tankers, respectively. As shown in Figure 4.2, the indices fluctuate constantly, sometimes dramatically. For example, the dirty tank index almost doubled from the second quarter to the fourth quarter of 2004. The pattern was repeated in 2005. The freight rate was relatively high in the period from 2002 to 2008, dropped remarkably in 2009 amidst the global financial crisis and recovered only modestly between 2010 and 2017. The strong tanker market during the period from 2003 to 2008 was principally due to sustained demand growth not only for tankers but also for dry cargoes.7 The higher freight rates led to higher demand for new ships and lower scrapping, which resulted in a glut of ships when demand dropped because of the weakened global economy in the period after 2010. The charter rate for very large crude 87

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Balc Exchange Index

3,000

Clean

2,500 2,000 1,500 1,000 500

Oct-17

Mar-17

Jan-16

Aug-16

Jun-15

Apr-14

Nov-14

Sep-13

Jul-12

Feb-13

Dec-11

Oct-10

May-11

Mar-10

Jan-09

Aug-09

Jun-08

Apr-07

Nov-07

Sep-06

Jul-05

Feb-06

Dec-04

Oct-03

May-04

Aug-02

Mar-03

0

Figure 4.2  Baltic Exchange tanker indices, August 2002–​December 2017 Note: The Baltic Dirty Tanker Index is an index of charter rates for crude oil tankers on selected routes published by the Baltic Exchange. The Baltic Clean Tanker Index is an index of charter rates for product tankers on selected routes published by the Baltic Exchange.

carriers peaked at $309,601 per day in 2007, then dropped to $7,085 per day in 2012, far below the operating costs of these ships. Flags of convenience A notable phenomenon in the tanker market is that many tankers sail under the flags of their registered country, which is the home country of neither their owners nor their charterers. This phenomenon is commonly referred to as “flags of convenience”. According to United Nations Conference on Trade and Development (UNCTAD), more than 70 per cent of the commercial vessel fleet is registered in a country that is different from the country of ownership. This system of open registries provides opportunities for developing countries, notably small island developing countries, such as the Marshall Islands, and the least developed countries, such as Liberia. The country of registration determines the laws under which the ship is required to operate and exercises regulatory control over the vessel. The registry country inspects the ships, certifies the equipment and crew and issues safety and pollution prevention documents. From a business perspective, the major advantage of this practice is the lower tax rates and more relaxed operating and environmental standards in the registry countries. Table 4.2 lists the top ten countries of registration for oil tankers by tonnage 88

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Table 4.2  Leading flags of registration oil tankers, 2017 DWT in thousands Marshall Islands Liberia Panama Greece Hong Kong SAR (China) Bahamas Singapore Malta China United Kingdom World total Top 3 countries’ percentage Top 10 countries’ percentage

79,678 76,418 66,622 45,778 38,368 36,614 35,762 29,199 12,706 11,012 535,864 41.6% 80.6%

Number of ships 772 728 812 407 339 286 714 345 489 171 10,216 22.6% 49.6%

Source: UNCTAD (https://unctadstat.unctad.org/wds/TableViewer/tableView.aspx?ReportId=93).

in 2017. The Marshall Islands, Liberia and Panama are the top three, none of which is a large oil-​producing or -​consuming state. The top ten countries accounted for 80 per cent of the world oil tanker fleet measured in DWT while the top three countries’ share was 40 per cent. In contrast, there are only 65 tankers registered in the United States. Economies of scale in tanker transportation The main economic characteristic of oil tankers is economies of scale. Since surface area increases as the square and volume goes up as the cube of the radius, the average cost of building a tanker declines as the size of tankers increases. There are other sources of economies of scale as well. The longer the ship, the more easily it can move through the water.8 Hence, the horsepower for operating a 200,000 DWT tanker is similar to that of a 100,000 DWT tanker. Furthermore, crew size is pretty much the same on a 50,000 DWT tanker compared to a 250,000 DWT one. As a result, there are also significant economies of scale in tanker operations. Table 4.3 presents some cost data for different sizes of petroleum tankers in 2006 and 2011. The column of new build prices reflects the capital cost of building a new tanker. As the size of tankers goes up, the capital cost increases, 89

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Table 4.3  Oil tanker costs Ship type

1

DWT

Newbuilding prices, $

2

3

Vessel Costs for depreciation, capital daily in $a employed, daily in $b

Total vessel procurement costs, daily in $c

Costs for operations, daily in $d

4

5

6

7

Total costs Share of (operations + procurement vessel), costs in total daily in $ costs

Average building cost ($/​ DWT)

8

10

11

12

9

Average operating cost, daily ($/​DWT/​ day)

Total average cost, daily ($/​DWT/​ day)

2011 Product Panamax Suezmax VLCC

50,000 75,000 160,000 300,000

36,100,000 44,500,000 64,100,000 101,300,000

3,956 4,877 7,025 11,101

1,978 2,438 3,512 5,551

5,934 7,315 10,537 16,652

8,740 8,872 10,102 11,342

14,674 16,187 20,639 27,994

40.4% 45.2% 51.1% 59.5%

722 593 401 338

0.175 0.118 0.063 0.038

0.293 0.216 0.129 0.093

2006 Product Panamax Suezmax VLCC

50,000 75,000 160,000 300,000

46,800,000 48,000,000 75,500,000 124,900,000

5,129 5,260 8,274 13,688

2,564 2,630 4,137 6,844

7,693 7,890 12,411 20,532

6,541 6,640 7,560 8,489

15,915 16,236 21,914 31,202

48.3% 48.6% 56.6% 65.8%

936 640 472 416

0.131 0.089 0.047 0.028

0.318 0.216 0.137 0.104

Notes: a  Depreciation costs determined on the basis of a period of 25 years. b  Financial costs determined by multiplying half the procurement costs (newbuild price) by an assumed interest rate of 4.0 per cent per year. c  Column (6) is the sum of columns (4) and (5). d  Operating costs include crew costs, spares, repairs and maintenance, insurance and administration. Source: UNCTAD (2012: tab. 3.5).

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1,000 900

2011

800

2006

$/DWT

700 600 500 400 300 200 100 0 50,000

1,00,000

1,50,000 2,00,000 DWT

2,50,000

3,00,000

Figure 4.3a  Average tanker construction costs Source: UNCTAD (2012: tab. 3.5).

but less than proportionally. As a result, the average cost of building a new ship (measured in $/​DWT) declines as the tanker size increases (column 10). This is clearly displayed in Figure 4.3a. In both years the average tanker construction cost declines as the size increases. It declines quickly as the size moves from the 50,000 DWT product tanker to the 75,000 DWT Panamax and to the 160,000 DWT Suezmax. A similar pattern applies to the average operating cost and average total cost, as shown in Figures 4.3b and 4.3c, respectively. In order to calculate the average total cost, we first calculate a daily fixed cost, which consists of vessel depreciation and a financial cost for 50 per cent of the new build cost. The depreciation is based on a 25-​year straight line depreciation method and the annual interest rate is assumed at 4 per cent. The pattern is clear. As the size of the tankers increases, the average cost falls. Another point worth noting is that the slope of the average operating cost appears steeper than that of the average construction cost (a fixed cost). This is also manifest in column 9 of Table 4.3; as the tanker size increases, the percentage share of the vessel cost (a fixed cost) becomes larger. In other words, the share of operating cost becomes smaller, indicating stronger economies of scale in operating costs than in fixed costs.9

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0.200 2011 2006

$/DWT/day

0.150 0.100 0.050 0.000 50,000

1,00,000

1,50,000 2,00,000 DWT

2,50,000

3,00,000

Figure 4.3b  Average tanker operating costs, daily Source: UNCTAD (2012: tab. 3.5).

0.350

2011

$/DWT/day

0.300

2006

0.250 0.200 0.150 0.100 0.050 50,000

1,00,000

1,50,000

2,00,000

2,50,000

3,00,000

DWT

Figure 4.3c  Average total costs, daily Source: UNCTAD (2012: tab. 3.5).

The direct result of the economies of scale for oil tankers is that the average seaborne transportation cost is very low compared to the value of oil. Figure 4.4 shows the annual average of crude oil transportation cost of major routes from 2010 to 2017. For most routes, the transportation cost is between $1 and $3 per barrel.10 The relatively low transportation cost in turn leads to the integration of global oil markets, as low transportation costs make it possible to arbitrage between regions (or continents), which will ultimately eliminate price differentials. 92

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2010

2011

2012

2013

2014

2015

2016

ME/East

ME/West

WAF/East

WAF/USGC

West/USGC

Indo/East

2017

Figure 4.4  Crude oil transportation cost of major routes ($/​bbl), 2010–​2017 Notes: ME= Middle East; East = Far East; West = North-​west Europe; WAF= west Africa; USGC = US Gulf Coast; Indo= Indonesia. Source: OPEC (2018: tab. 6.5).

However, size has disadvantages. Not every port can handle the VLCCs. The larger the ship, the more limitations there are on which routes they can sail through, as there are some chokepoints on the sea routes (see next section). For example, a VLCC larger than 200,000 DWT loaded from the Middle East must travel around the Cape of Good Hope in South Africa to be discharged in a port in Europe. Further, the larger the tanker, the harder it is to stop (a 250,000 DWT tanker travelling at 16 knots takes 3 miles and 20 minutes to stop) and to manoeuvre (a 300,000 DWT tanker travelling at less than 5 knots cannot be steered). Finally, the large volume of oil makes a good target for pirate attacks. Major chokepoints of international oil transport As previously noted, more than 40 per cent of total world oil production is transported by ocean tankers on fixed maritime routes. The international energy market is dependent upon reliable transport. However, there are a few chokepoints along the global sea routes. The chokepoints are narrow, and often shallow, water channels, such as the Panama Canal, the Suez Canal and 93

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Table 4.4  Volume of crude oil and petroleum products transited through world chokepoints (million barrels per day), 2011–​2016 Location

2011

2012

2013

2014

2015

2016

Strait of Hormuz Strait of Malacca Suez Canal and SUMED pipeline Panama Canal World maritime oil trade World total petroleum and other liquids supply

17 14.5 3.8 0.8 55.5 88.8

16.8 15.1 4.5 0.8 56.4 90.8

16.6 15.4 4.6 0.8 56.5 91.3

16.9 15.5 5.2 0.9 56.4 93.8

17 15.5 5.4 1 58.9 96.7

18.5 16 5.5 0.9 n/​a 97.2

Source: Energy Information Administration.

the Strait of Malacca, which could cause problems for navigation and impose capacity constraints on the size and number of vessels passing through (see Table  4.4). These chokepoints are important for the security of the global energy supply, because many of them are next to politically unstable countries and regions. The blockage of a chokepoint, even temporarily, can lead to substantial increases in total energy costs, because transporting through alternative routes can significantly increase the costs. Further, chokepoints leave oil tankers vulnerable to hijacking by pirates, terrorist attacks and political unrest, as well as shipping accidents, which can lead to disastrous oil spills. These potential risks and impacts are commonly used to justify a naval presence in order to protect sea lanes, even if such benefits are difficult to demonstrate. Figure  4.5 depicts the major maritime routes for oil transportation. The Panama Canal, the Suez Canal, the Strait of Malacca and the Strait of Hormuz are the world’s four most important strategic maritime passages. The Strait of Hormuz Located between Oman and Iran, the Strait of Hormuz connects the Persian Gulf with the Gulf of Oman, the Arabian Sea and the Indian Ocean. At its narrowest point the Strait of Hormuz is 21 miles wide, but the width of the shipping lane in either direction is only two miles wide, separated by a two-​mile buffer zone. The Strait of Hormuz is deep enough and wide enough to accommodate the 94

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Figure 4.5  Major seaborne oil transportation routes and transit volumes Note: The transit volumes are in million barrels per day, including crude oil and petroleum products, based on 2016 data. Source: EIA (2017).

world’s largest crude oil tankers, with about two-​thirds of oil shipments carried by tankers in excess of 150,000 DWT coming through this strait. The Strait of Hormuz is the world’s most important oil chokepoint. In 2015 approximately 17  million barrels of oil per day were transited through the strait, accounting for 30 per cent of all seaborne-​traded crude oil and other liquids.11 About 80 per cent of the petroleum transited through the strait are exports to Asian markets, including China, Japan, India, South Korea and Singapore. The importance of Hormuz to global oil trade cannot be overstated. For instance, 75 per cent of all Japanese oil imports come from the Middle East and are transited through Hormuz. There are very few alternatives to oil exports from the Middle East if the Strait of Hormuz is blocked.12 In addition, Qatar exported 3.7 trillion cubic feet per year of liquefied natural gas through the Strait of Hormuz in 2016. This volume accounts for more than 30 per cent of global LNG trade. The Strait of Malacca The Strait of Malacca, located between Indonesia, Malaysia and Singapore, links the Indian Ocean to the South China Sea and to the Pacific Ocean. The 95

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Strait of Malacca is the shortest sea route between Persian Gulf suppliers and the Asian markets –​notably China, Japan, South Korea and the Pacific Rim. It is the primary chokepoint in Asia, with a flow estimated at 16 million barrels per day in 2016. About 80 per cent of Japan’s, South Korea’s and Taiwan’s imports of petroleum transits through this strait. At its narrowest point the Strait of Malacca is only about 1.5 miles wide, creating a natural bottleneck, with the potential for collisions, grounding and piracy attacks. If the Strait of Malacca were blocked, nearly half the fleet would be required to reroute around the Indonesian archipelago, such as through the Lombok Strait between the Indonesian islands of Bali and Lombok, or through the Sunda Strait between Java and Sumatra. Such rerouting would tie up global shipping capacity, add to shipping costs and potentially affect energy prices. In an effort to bypass the Strait of Malacca, China and Myanmar commissioned the Myanmar–​China pipeline in 2013, which stretches from Myanmar’s ports in the Bay of Bengal to the Yunnan province of China. The pipeline has both an oil portion and a gas portion, both of which became operational as of 2017, allowing China to bypass the Strait of Malacca for a portion of its imports. The Strait of Malacca is also an important transit route for liquefied natural gas from Persian Gulf and African suppliers, particularly Qatar, going to East Asian countries with growing demand for LNG. The Suez Canal13 The Suez Canal is an artificial waterway of about 120 miles in length, running across the Isthmus of Suez in north-​eastern Egypt, which connects the Mediterranean Sea with the Red Sea. It acts as a short cut for ships to travel between the Atlantic Ocean and the Indian and Pacific Oceans. Without the Suez Canal, the maritime route from Europe to Asia must navigate around the Cape of Good Hope, at the southernmost point of the continent of Africa. The Suez Canal was constructed between 1859 and 1869 by French and Egyptians interests, with a cost of about $100 million. Since its opening the Suez Canal has been expanded several times. The current capacity of the canal is 240,000 DWT and it can accommodate up to 25,000 ships per year

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(about 78 per day). Prior to its expansion, in 2015, the canal could handle only unidirectional traffic, with crossings organized into convoys of about ten to 15 ships. The transit time was about 17 hours. Since the 2015 expansion two simultaneous convoys per day have been organized, as a longer section of the canal has become bidirectional. Because of its strategic location, the Suez Canal was subject to a number of geopolitical tensions between Israel and Arab nations in the 1960s and 1970s. The Six-​Day War between Israel and Egypt and the subsequent invasion of the Sinai Peninsula by Israel caused the closure of the Suez Canal between 1967 and 1975. The closure was so sudden and unexpected that several ships were caught stranded in the canal. The canal became the ceasefire line, and again saw hostilities during the Yom Kippur War of 1973. The canal was reopened in 1975, when Egypt agreed to let Israel use it. Significant improvements were made between 1976 and 1980, mainly the widening of the canal to accommodate VLCCs of about 200,000 tons. The current capacity of the canal, at 240,000 tons, means that ultra-​large crude carriers (tankers with more than 300,000 tons capacity) cannot pass through the canal when fully loaded. A common practice is to unload a share of Mediterranean-​bound ships and use the Sumed pipeline. The Panama Canal The Panama Canal runs for 51 miles across the Isthmus of Panama, joining the Pacific Ocean with the Caribbean Sea and the Atlantic Ocean. The Panama Canal was initially constructed between 1904 and 1914 by American engineers, at a cost of $387 million. The old locks of the canal can handle ships with a draft of 40 feet (12.2 m), a width of 106 feet (32 m) and a length of 965 feet (294 m). The Panamax standard (65,000 DWT) reflects the maximum capacity of a tanker that can pass through the canal. To make the canal more accessible, the Panamanian government has expanded the canal by deepening and widening some portions and constructing an additional, larger set of locks. The expansion project was completed in 2016, after some delays. The expanded locks can handle ships with a draft of 50 feet (15.2 m), a width of 160 feet (49 m) and a length of 1,200 feet (366 m). Unlike the old lock system, which had two lanes of side-​by-​side

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traffic, the new set of locks comprises one large lane and allows four transits per day, supplementing the 25 daily transits using the older lock system. The wider and deeper navigation channels and larger locks allow for the larger vessels to pass through the canal. A new ship classification, Neopanamax or New Panamax, was created. The New Panamax is equivalent to the Aframax, with capacity of up to 120,000 DWT. According to the Panama Canal Authority, more than 13,000 vessels travelled through the Panama Canal in fiscal year 2016, carrying roughly 204 million tons of cargo. Goods originating in or travelling to the United States accounted for more than 67 per cent of the total shipments. Some 921,000 bbl/​ d of petroleum and petroleum products were transported through the canal, of which 843,000 bbl/​d were refined products and the remainder was crude oil. Pipelines Economic characteristics The other major means of transporting oil and gas is by means of pipelines. Gas is more dependent on pipelines than oil, because, unless gas is converted to liquid, a pipeline is the only feasible method of transportation. As with tankers, there are also clear economies of scale in pipeline transportation. The capacity of a particular pipeline (oil, gas or petroleum products) is determined by its diameter. Since the surface area increases with the square and the volume increases with the cube of the radius, when the pipeline diameter increases, the volume, and hence capacity, increase more quickly than the surface area. As the amount of material that is required for the pipes, and hence the capital cost, is determined by the area of the surface, the average capital cost of pipelines falls with the diameter. In other words, a bigger pipeline is generally more cost-​effective than a smaller pipeline when fully utilized. For a pipeline, the rule of thumb is that the capacity (the maximum throughput) is proportional to the square of the diameter. For example, a 36-​inch pipeline is approximately equal to the total capacity of nine 12-​inch pipelines. The costs of laying the pipes and installing pumps or compressors constitute the fixed cost of a pipeline. The throughput of a pipeline is influenced by

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the operating pressure of the pipeline, which is determined by the number and size of pumps (for an oil pipeline) or compressors (for a gas pipeline) and the utilization of these pumps or compressors.14 In fluid dynamics, the pressure loss due to friction, or viscosity, is proportional to length, and is positively related to velocity. The longer the pipeline, the greater the need to increase the pressure in order to deliver the desired throughput. The relationship between the throughput of a pipeline, the diameter and pressure can be best seen from the flow equation. The general flow equation15 of natural gas is α

 T   P 2 − P22  β Q =C b 1  D  Pb   GT f LZf 

(Equation 4.1)

where C is a constant, Tb and Pb are the base temperature and pressure, respectively, P1 is the upstream pressure, P2 is the downstream pressure, G is the specific gravity of gas, Tf is the average gas flow temperature, L is the pipe segment length, Z is the gas compressibility factor, dimensionless, f is a friction factor, D is the diameter and α and β are constant parameters, with α ~ 0.5 and β ~ 2.5. For a given length of a pipeline, the base temperature and pressure, the friction factor, the gravity of gas and the gas compressibility factor are all predetermined, so the throughput depends on the pressure difference between the upstream and downstream and the diameter of the pipe. Therefore, Equation 4.1 can be simplified as follows:16 Q = A ⋅ H α ⋅ Dβ where A is a constant, H is the horsepower of compressors, with α ~ 0.5, and D is the diameter, with β ~ 2.5. Hence, the pipeline throughput has significant economies of scale with diameter, but diseconomies of scale with pressure. Figure 4.6 further illustrates the relationship between the diameter, the unit cost and the throughput. Here the unit cost is normalized for illustration purposes. As the diameter of the pipeline increases, the throughput increases and the average cost falls. However, for a given diameter of pipeline, there are a range of capacities for which the maximum throughput can be achieved. This offers a degree of flexibility and has important implications for the design

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Figure 4.6  Pipeline maximum throughput and average transportation cost assuming 100% utilization Adapted from McLellan (1992).

of pipeline systems, particularly for natural gas. This is because the development of a downstream gas market, especially the retail market, also depends on the availability of pipeline networks; there will be no firm demand until customers are connected to the distribution network. It could take a few years before the gas market is fully developed. In such cases, it may be worthwhile to lay a bigger-​diameter pipeline and leave room for future expansion by adding more pumps or compressors. Differences between oil and gas pipelines There are some key differences between oil and gas pipeline operations. Perhaps the most notable one is the line-​packing flexibility in natural gas pipelines. As shown in the general gas flow equation, gas flow in a pipeline is driven by the pressure difference between upstream and downstream. Furthermore, pipelines can be operated at a range of pressures, with an upper 100

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bound of the maximum pressure, which is dependent on the pipe material characteristics, and the lower bound, the minimum pressure that is required to ensure gas flow. In other words, the system operator can ensure the safe operation of the pipeline network by operating within the pressure band. Thus, it is possible to utilize the pressure difference to store gas in the pipeline without compromising gas flow. This process is called line packing. Line packing is usually performed during off-​peak times so that gas can be stored for peak demands the next day. Because natural gas in a gaseous state is compressible, the “storage” provided by line packing can be significant. Therefore, line packing provides the system operator a temporal buffer so that greater amount of gas can be withdrawn from the pipeline during peak times. In comparison, because oil is not compressible, the amount that is being withdrawn from a pipeline will be equal to the amount that is put in. It is not possible to store oil using line packing. Second, in the event of any leakage, gas pipelines will cause less environmental damage than oil pipelines. When it is leaked, natural gas is simply released into the air, causing minimal damage. In contrast, oil does not dissipate easily, and can cause more severe damage to the air, the soil or the water. However, the safety hazard of gas pipelines is much more severe than that of oil pipelines. Due to the compressibility of gas, natural gas pipelines are usually operated under higher pressure than oil pipelines. If there is a leakage, the stored gas can tear the pipeline apart, causing an explosion. Last, the risk of supply disruption is more critical for gas pipelines, as consumers can not easily hedge against the unavailability of the pipeline by storing a large amount of gas and there is no other substitutable transportation method. However, in the case of oil there is greater flexibility in transportation, which lowers its volume risk. If an oil pipeline is not available, oil supply can be readily restored by other modes of transportation, such as trucks, railway or barges. Pipelines as a natural monopoly Because of the clear economies of scale in pipeline operations, pipelines are often considered natural monopolies.17 It is quite common that the outputs from several large oil fields are carried by one bulk pipeline. This is true not

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only for a pipeline between two points but also for a network of pipelines within an oil-​producing basin. For example, in the North Sea there are four key pipeline networks in different locations: the Brent and Ninian systems, which deliver to Sullom Voe; the Flotta system, which delivers to Orkney; and the Forties system, which delivers to Cruden Bay. Therefore, pipelines are normally either publicly owned or regulated if owned by private investors. Otherwise, the owners of pipelines may use their monopoly position to earn excessive profits by charging a high tariff, or they may use their ownership to deny access to users, thereby restricting competition at both ends of the pipeline. It is worth remembering that the Standard Oil Trust of Rockefeller, which at one time controlled much of the US oil industry, began as a pipeline operation. In the United States, the full cycle of pipeline operations, from the permitting and construction of new pipelines, tariff setting and decommissioning, are all regulated by state or federal agencies. Tariffs for interstate pipelines are set by the Federal Energy Regulatory Commission based on the cost of service methodology,18 in which a pipeline’s specific allowable rate of return (ROR) is calculated according to the weighted average cost of capital (WACC). Each customer pays an allocated share of fixed costs in the form of a monthly reservation charge, and a per unit usage charge for services provided (Oliver 2015). Pipeline companies are obliged to provide non-​ discriminatory “open access” to their transportation infrastructure to all other market players equally.19 This allows marketers, producers, local distribution companies and even end-users themselves to contract for transportation of their natural gas via interstate pipeline, on an equal and unbiased basis.20 Trans-​boundary pipeline issues Trans-​boundary or cross-​border pipelines refer to pipelines that originate in one country, the exporting country, and are bound to another country (the importing country) by crossing country borders. These include simple cross-​border pipelines, where only the exporting and the importing countries are involved, and transit pipelines, where a third country (transit country) is involved along the pipeline route. In Figure 4.7, the pipeline starts from the exporting country A, transits through country B and ends in the consuming

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Figure 4.7  Trans-​boundary pipelines

country C. This is a transit pipeline. An example of a transit pipeline is the West African Gas Pipeline, which starts in Nigeria, transits through Togo and Benin and ends in Ghana. If there is no country B, such that the pipeline simply starts from country A and ends in country C, then it is not a transit pipeline. An example is the gas pipeline from east Siberia, Russia (“Power of Siberia”), to China, for which no transit country is involved. The number of transboundary pipelines has increased dramatically since the 1990s. There are two principal reasons for the rapid increase. First, after the collapse of the former Soviet Union (FSU), many pipelines that previously belonged to one country (i.e. the Soviet Union) became cross-​border pipelines  –​for example from Russia to Ukraine. Second, more oil and gas resources have been discovered in landlocked regions or landlocked countries –​e.g. Kazakhstan. Thus, more transboundary pipelines are needed to transport the oil or gas to consumer markets. In essence, a cross-​border pipeline is an asset dedicated to cross-​border trade. However, as a type of fixed asset requiring huge sums of investment, cross-​border pipelines have little alternative use other than serving that trade. This “asset specificity” requires specific contracts to be drawn to establish the property rights and responsibilities of the participating parties from potentially different legal and regulatory frameworks. However, in the absence of an

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overarching jurisdiction and given the number of parties involved, reaching an agreement on cross-​border pipelines is not always easy. Several issues may arise in the operation of such pipelines. First, in the absence of an overarching jurisdiction, there is no obvious mechanism for conflict resolution. International arbitration offers a solution to this problem, but recourse to such arbitration must be agreed to and adhered to. And reconciling different legal and regulatory regimes will increase the transactions costs of building and operating a pipeline. The interests of different parties will probably differ. There is a natural conflict of interest between the buyer and the seller. The seller naturally seeks a higher price while the buyer prefers a lower price. The conflict of interest is magnified by the presence of large amounts of rent in the oil and gas projects, of which the pipeline is often an integral part (Stevens 2003). This rent must be shared between the interested parties, but there is no obvious and objective way of dividing the rent. Pipelines are highly vulnerable. Interruptions to operations not only threaten the return on the pipeline but also may jeopardize the return (profit and rent) on investments at both ends. Another source of potential conflict is the possible competition for the market of the importing country and competition for resources in the exporting country. An example is the West African Gas Pipeline, which transports gas produced from the Niger Delta in Nigeria to Ghana, crossing Togo and Benin. The construction of the pipeline started in 2005 and was completed in 2008. The designed initial capacity was 170  million standard cubic feet per day (MMscfd), and this was projected to reach a peak capacity of 460 MMscfd over time. However, actual gas supply has been below the designed capacity most of the time ever since the inception of the project. For example, in 2011 a volume of 133 MMscfd was contracted, but only an average of 84.0 MMscfd was delivered throughout the year. Several factors account for the under-​delivery of natural gas, including political instability and social unrest in the Niger Delta region, which resulted in repeated vandalization of the gas infrastructure, and increased demand from power generation in Nigeria. Strategically, there may be security of supply concerns for importers and security of demand concerns for exporters. Neighbouring countries often have a record of hostility, for example, and pipelines in the past have become victims. Alternatively, the monopoly power of the seller or monopsony power of the buyer may create an economic motive for the cessation of supplies.

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The problem can be compounded when the pipeline crosses a third country  –​that is, when the cross-​border pipeline becomes a transit pipeline. The transit country would demand a transit fee to be paid for the right of passing through the country and also as a reward for helping to realize the value added in the cross-​border oil or gas trade. The transit fee is often negotiated. However, as discussed below, there is no obvious mechanism of setting the transit fee. Furthermore, once the pipeline is built and operating, transit countries are in a very powerful position to demand a renegotiation of transit fees, as they stand to lose only their transit revenue when actively interfering with a deal. In comparison, the exporting country could lose a significant source of export revenue and the importing country could lose its energy supply unless there is an immediately available alternative source of supply (demand). Put simply, exporting and importing countries have more to lose by spoiling a deal than transit countries. The setting of transit fees In principle, transit fees are supposed to cover the costs of transportation, including a normal rate of return to investment, plus a payment for the right of way. Transit fees can be a fixed sum per barrel of oil or per cubic metre of gas transported and/​or the right to offtake a certain amount of oil and gas from the line, often at favourable rates. What often complicates the comparison of transit fees in different countries is that the services included in the transit tariff vary. In some cases transit may include storage and other load-​balancing services. In practice, transit fees and conditions are the result of negotiations between commercial interests. When transit can take place through alternative routes, the maximum price that will be paid is the opportunity cost –​i.e. the cost of arranging for transit through an alternative route. In cases when there are no alternatives, the maximum price for transit is the price that makes the gas sales agreement unprofitable for the seller. These price levels could be considered as ceilings for the transit fee. The corresponding floor would be the real cost of transit. At the same time, the transit country, and its industry in some cases, will benefit from getting new or additional domestic gas supplies. Once the transit facilities have been built, the negotiating position of the parties involved changes. The transit country will be tempted to increase

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the transit fees once the investment has been made. This position may be weakened if the transit country receives domestic energy supplies from the same line. However, the relationship between the buyer of transit services and the transit service provider remains one of interdependence. Notes 1. DWT: deadweight tonnage is a measure of how much weight a ship can carry. It is the sum of the weights of cargo, fuel, fresh water, ballast water, provisions, passengers and crew. 2. Tankers that carry crude oil and heavy fuel oils are often referred to as “dirty tankers”. And product tankers, particularly those carrying gasoline, diesel, kerosene and jet fuels, are frequently referred to as “clean tankers”. 3. The AFRA system was developed by Shell in 1954 with the consultation of the London Tanker Brokers’ Panel. It was developed for tax reasons, as the companies needed to demonstrate to the tax authorities that their financial records were correct. This was not an easy task. Before crude oil futures were traded, in 1983, it was even difficult to determine the exact price of oil, because the transportation cost could complicate the calculation. Although the AFRA system was later abandoned by the major oil companies, it is still used by many governments, traders and oil companies. 4. Independent tanker owners include non-​ oil companies and non-​ state-​ controlled tanker owners. According to the International Association for Independent Tanker Owners (INTERTANKO), as of January 2018 the organization’s combined fleet comprised some 3,976 tankers totalling over 353 million DWT. 5. There are potentially two spillover effects (Beenstock & Vergottis 1989). The first is that combined vessels can be switched between tanker markets and dry cargo. The second is that shipbuilders may build dry cargo vessels instead of tankers. 6. These indices are determined from standardized information provided by shipowners, shipbrokers and charterers and reflect the time charter costs. For example, the dirty tanker index takes into account 17 main shipping routes and records the time charter costs for four ship classes (VLCC, Suezmax, Aframax and Panamax). Only the real demand for and the real supply of the transport of oil on standard routes are included in the price. In contrast to the economic data, the data of the Baltic Dirty Tanker Index is not subject to any subsequent changes. 7. Between 2003 and 2007 world seaborne trade in dry cargoes grew at an average of 6.9 per cent per year. 8. This is because the hauling speed increases with ship size, whereas water resistance against the ship’s hull does not increase at the same rate as the volume of the hull. Therefore, large ships face lower water resistance than small ships, and large vessels have higher hauling speed than small ships. 9. The pattern is consistent with Jansson and Shneerson’s (1978) study of economies of scale for general cargo ships. They report a size elasticity of 0.52 and 0.32 for capital costs and operating costs, respectively, indicating stronger economies of scale in operating costs.

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10. In comparison, the crude oil price (Brent) averaged about $110 from 2011 to the first half of 2014. 11. EIA (2017). This volume increased to 18.5 million bbl/​d in 2016. 12. The security of the Strait of Hormuz has been often compromised and its commercial usage has been the object of contentions. Between 1984 and 1987 a “Tanker War” took place between Iran and Iraq, when each side of the war (in the Iran–​Iraq War of 1980–88) began firing on tankers bound for their respective ports. Shipping in the Persian Gulf dropped by a quarter, forcing the intervention of the United States to secure the oil-​shipping lanes. 13. This and the following sections on maritime chokepoints draw on Rodrigue and Notteboomean-​Paul (2017) and EIA (2017). 14. In transportation problems, the economic output is the throughput for a period of time, which is typically measured in unit distance for a period of time –​e.g. passenger-​ kilometres for passengers, ton-​kilometres for oil and cubic feet-​miles for natural gas. 15. American Gas Association. It is also called the Weymouth equation. See also Oliver (2015). 16. Although the equation is derived from the natural gas flow equation, it is also applicable to oil. 17. A natural monopoly occurs when the most efficient scale of operation is so large in relation to the demand that it is best to have only one supplier. More than one supplier would imply higher costs than necessary, which would be socially undesirable. Furthermore, because of the cost structure –​high fixed costs and low operating costs –​ any incumbent would be able to undercut any new entrant by virtue of the bygones rule. Hence, more than one supplier would be impractical. 18. The basic principle of cost of service regulation (also known as rate of return regulation) is that firms are allowed to earn zero economic profit. The revenue requirement consists of an expense and an allowed return to investment. 19. Open access was achieved only after unbundling, which permits pipelines to provide only transportation services, had taken place in 1992. Before that interstate pipeline companies acted as both transporters of natural gas and sellers of gas, both of which were rolled up into a bundled product and sold for one price. 20. See www.naturalgas.org.

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REFINING AND MARKETING

Technical background of petroleum refining The refining process Crude oil is a mixture of chemical compounds and needs to be separated into useful products, such as gasoline, kerosene, diesel, jet fuel, fuel oil, lubricants, and so on. Essentially, refining breaks crude oil down into its various components, which then are selectively reconfigured into new products. Conceptually, all refineries perform three basic functions:  separation, conversion and treatment. The refining process involves both physical and chemical processes.1 The dominant physical process is distillation, which enables the separation of the lighter components from the heavier components. The most widely used conversion method is called cracking, because it uses heat –​pressure or catalytic –​to “crack” heavy hydrocarbon molecules into lighter ones. Other refinery processes, instead of splitting molecules, rearrange them to add value. Alkylation, for example, makes gasoline components by combining some of the gaseous by-​products of cracking. The outputs from the primary distillation process can rarely meet market requirements, either in quality or in quantity. Modern refineries usually have a series of secondary processing units to increase the output of lighter, cleaner, high-​value products. Each of the secondary processing units after the distillation unit has a specific purpose, whether to increase separation; to upgrade low-​value products, such as residual fuel oil, to high-​value products, such

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as distillate; to increase octane; or to enhance environmental compliance by removing sulphur and other impurities. A modern refinery typically has the following main processing units. Atmospheric distillation unit (ADU): The refining process always begins with atmospheric crude distillation. The simplest refinery may have nothing but the distillation process. Figure 5.1 shows a simple version of a refinery with only the distillation process, whereas Figure 5.2 shows the flow diagram of a relatively complex refinery. In this very first step of the refining process, crude oil is piped through a hot column, which is fuelled typically by natural gas or residual fuel oil. As oil is heated, various fractions of oil boil off. The resulting liquids and vapour are discharged to distillation and cooling towers. The lighter products, such as liquefied petroleum gas (LPG), naphtha and straight-​run gasoline, rise to the top, to be separated out; then the middle distillates, such as kerosene and gas oil. Heavier products, such as fuel oil, asphalt and cokes, are the last to be separated. Table 5.1 shows an example of the boiling range of different refining product. However, the cut points have some slack and can be adjusted.2 For example, if the cut point of gasoline was changed to 230°F from 220°F, then more gasoline and less naphtha would be produced. Vacuum distillation unit (VDU): This utilizes the fact that heavier oils are easier to boil off under low pressures. The maximum boiling temperature of an ADU is about 750°F. Above this temperature the oil will thermally crack, or break apart, which impedes the distillation process. To increase the production of high-​value petroleum products, the heavier oils that remain at the bottom of the ADU are run through a vacuum distillation column to be further refined. At low pressures the boiling point of the ADU bottoms is lowered, so that lighter products can vaporize without cracking, or degrading the oil.3 Thermal cracking, catalytic cracking and hydrocracking: These processes use heat, fluidized catalysts or hydrogen to break or “crack” the large gas oil molecules into a range of smaller ones, specifically gasoline, low-​quality diesel stocks and residual fuel oil. A cracking unit consists of one or more tall, thick-​ walled, bullet-​shaped reactors and a network of furnaces, heat exchangers and other vessels. 110

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Catalytic reforming: This uses heat, catalyst and moderate pressure to raise the octane number of heavy naphtha molecules to produce a high octane reformate that is essential for premium-​grade gasoline or petrol. Alkylation and isomerization: The alkylation process uses an acid catalyst to combine unsaturated small molecules into larger ones, collectively called alkylate, which has a high octane and is the cleanest-​burning of the gasoline blendstocks. Similarly, isomerization rearranges the atoms in a molecule so that the product has the same chemical formula but a different structure, such as converting normal butane into isobutane.4 Hydrotreating: This uses hydrogen to remove sulphur and nitrogen from some of the intermediate product feedstocks. Sulphur and nitrogen can be detrimental to the equipment, the catalysts and the quality of the finished product. Hydrotreating is usually done before such processes as catalytic reforming and catalytic cracking, so that the catalyst is not contaminated by untreated feedstock, in order to reduce sulphur and improve product yields. The hydrogen used in this process is usually obtained from the reformer. Hydrotreating is particularly important for processing high-​sulphur crude. Delayed coking: This uses extreme heat (over 900°F) to crack very heavy residual oils into end-​product petroleum coke, as well as naphtha for reforming and diesel oil. Not all refineries have all these units, and many complex refineries have more than these units. The exact configuration of a refinery is determined by the products it wants to produce and the type of crude oil it processes. In general, more complex refineries are able to produce lighter and higher-​value products from the same type of crude oil, although they are also more costly to build. For example, some of today’s complex refineries can produce more than 95 per cent light products with less than 5 per cent residuals. A refinery’s level of complexity is often based on how much secondary conversion capacity it has. Since the details of how a refinery operates are difficult to comprehend without specialized industry knowledge, the Nelson complexity index (NCI) provides an easy metric for quantifying and ranking the complexity and sophistication of different refineries.5 The NCI measures the relative cost of each of the processing units that make up a refinery. It is an 111

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BOX 5.1  OCTANE AND CETANE NUMBERS

Octane is a flammable liquid hydrocarbon found in petroleum. The octane number (or octane rating) measures the anti-​knock properties of motor fuel. In a gasoline engine, fuel is mixed with air, compressed by pistons and ignited by sparks from spark plugs. The higher the octane number, the more compression the fuel can withstand before igniting. Generally speaking, fuels with a higher octane number are used in high-​ performance gasoline engines that require higher compression ratios. There are two recognized laboratory engine test methods for determining the octane rating: the research method and the motor method. Different countries use different conventions in measuring the octane number. Most countries in Europe as well as Australia and New Zealand use the research method, called research octane number (RON). But the United States, Canada, Brazil and some other countries use the average of the RON and the motor octane number (MON), called the anti-​knock index, which is (RON + MON)/​2. Cetane is the chemical compound with chemical formula n-​C16H34. Cetane ignites easily when exposed to a small amount of heat. The cetane number (cetane rating) is an indicator of the combustion speed of diesel fuel. In a diesel engine, the air is compressed first and then the fuel is injected into the air. Because air heats up when it is compressed, the fuel ignites. Fuels with lower octane numbers (but higher cetane numbers) are ideal for diesel engines. Diesel fuels with higher cetane ratings have shorter ignition delays, providing more complete combustion and allowing engines to operate more effectively (Dabelstein et al. 2007).

index that provides a relative measure of the construction costs of a particular refinery based on its crude oil and upgrading capacity. The NCI compares the costs of various upgrading units –​such as a fluid catalytic cracking (FCC) unit or a catalytic reformer –​to the cost of a crude distillation unit. In forming the index, the cost of atmospheric distillation unit is assigned a value of one. All other units are rated in terms of their costs relative to the cost of the crude distillation unit. For example, assuming

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a crude distillation unit costs $400 per barrel per calendar day to construct and another secondary unit costs $1,200/​b/​cd to build, this unit would have a complexity factor of three.6 The complexity rating of a refinery is calculated by multiplying the complexity factor for each downstream unit by the proportion of the downstream capacity to the crude-​oil-​processing capacity. The NCI for the refinery is the sum of the complexity factor of each process unit. To illustrate, consider a refinery with 100,000 b/​cd of crude distillation capacity, 60,000 b/​cd of vacuum distillation capacity and 30,000 b/​cd of catalytic reforming capacity. Because the complexity factor of the vacuum unit is two and the reforming unit is five (see Table 5.2), the NCI will be 1 × (100/​100) + 2 × (60/​100) + 5 × (30/​100) = 1.0 + 1.2 + 1.5 = 3.7.

Table 5.1  Boiling ranges for petroleum products Degrees F

Product

70 0.77

< 10 ppm 48–​51 0.82–​0.84

Sources: Brown (2013); European Union Directive 2009/​30/​EC.

vehicle (e.g. in litres per 100 km) with GTL fuel will be higher compared to conventional diesel. Consequently, although GTL fuel has been showcased as a “neat fuel” in combustion engines, it is primarily marketed as a blend stock, allowing refineries to improve the qualities of their diesel pools to meet the sulphur requirement of ULSD. This is particularly valuable to refiners with insufficient conversion or desulphurization capacities, as they can modify their gasoil and diesel yields (Brown 2013). Whether sold as a neat fuel or blend stock, the value of GTL products largely depends on the value of their competing products –​e.g. the conventional diesel or naphtha –​and so is influenced by the price of crude oil. Commercial GTL plants are limited Although it is more than 90 years since the invention of the Fischer–​Tropsch process, the commercialization of GTL remains very much in its infancy. To date only five plants are operating commercially, four of which are relatively small in scale, namely Petro SA’s 22,500 bbl/​d facility in South Africa, Shell’s 14,700 bbl/​d Bintulu plant in Malaysia, SASOL’s 34,000 bbl/​d Oryx facility in Qatar and Chevron’s 33,200 bbl/​d Escravos plant in Nigeria. Only Shell’s 140,000 bbl/​d Pearl GTL facility, in Qatar, can be described as world-​scale. The low number of GTL plants reflects several factors. The capital costs associated with constructing GTL facilities remain substantial. In part, this is because it is very difficult to increase the capacities of F-​T reactors. These reactors operate under high pressures, ranging from 20 to 30 bars, and are therefore extremely explosive (Wood, Nwaoha & Towler 2012). It is very difficult to increase reactor capacity, and, consequently, commercial GTL projects 169

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operate a number of reactor units, each unit having a capacity of 8,000 to 17,000 bbl/​d depending on the technology. To build a commercial plant with significant output is thus extremely expensive. For example, the development cost for the Pearl GTL project was estimated to be around $18–19 billion.10 GTL is a very energy-​intensive process. Overall, roughly 40 per cent of the energy value of the natural gas used in the process is lost, with extensive associated production of carbon dioxide.11 For example, Shell’s Pearl GTL facility processes around 1.6 billion cubic feet per day of gas (or 270,000 barrels of oil equivalent per day) to produce 140,000 barrels per day of oil products. This contrasts with the production and shipping of LNG, which loses about 13 per cent energy during the liquefaction and transportation (through “boil-​off ”), and an oil refinery’s consumption of around 7–9 per cent of its crude oil feedstock. Figure 6.12 further illustrates the energy loss. In summary, GTL provides an alternative for countries with substantial, low-​cost gas resources to monetize their gas and diversify their sources of revenue by producing high-​value transport fuels and lubricants rather than LNG or other low-​value-​added, methane-​based chemicals, such as methanol and fertilizers. The advantage of GTL as a method of monetizing natural gas is that it utilizes existing infrastructure for transportation fuels. However, the main obstacles are the substantial capital cost and poor energy efficiency.

GTL energy balance

LNG energy balance Liquefacon losses 11%

Losses 40%

LPG 1%

Naphtha 17%

Shipping losses 2%

Diesel 42% LNG value 87%

Figure 6.12  Comparison of energy balance between GTL and LNG

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GTL’s future role in energy markets thus depends on the extent to which technology can bring down the capital costs and the direction of future oil and gas prices. In the foreseeable future I suspect that GTL will very much retain an important but niche role in hydrocarbon liquids production. Natural gas pricing Natural gas price formation mechanisms Despite the rapid growth in spot and short-​term trading of LNG in recent years, which has increasingly linked the regional gas markets, natural gas is not yet produced into a globally fungible market, as is the case with crude oil. The natural gas market is primarily regional in nature, and the pricing of natural gas depends largely on regional supply and demand balances and the social and regulatory environment. Consequently, the prices of natural gas are determined rather differently across different parts of the world. Figure 6.13 shows natural gas prices in different regions for the period from 1990 to 2017. Unlike crude oil prices, which tend to follow the “law of one price”,12 the prices of natural gas across regions are not uniform and the differences are frequently more than what is implied by the cost of transportation. Several factors explain the large regional disparity in recent years. First, the “shale gas revolution”, which we will turn to later in the chapter, effectively made the United States disconnected from the rest of the world.13 Second, the loss of nuclear power following the accident at Fukushima in March 2011 dramatically increased the Japanese demand for LNG. In the aftermath of the Fukushima accident, Japan lost almost all its nuclear power. According to EIA data, Japanese electricity generation from nuclear reduced from 280 GWh in 2010 to 156 GWh in 2011, then 17 GWh and 14 GWh in 2012 and 2013, respectively. At the same time, Japanese natural gas consumption jumped 12 per cent from 2010 to 2011 and another 7 per cent in 2012. Third, as argued by Ritz (2013) and Mu and Ye (2018), the difference between the prices of Japanese LNG imports and prices in Europe is supportive of the idea that the major supplier in the LNG market (i.e. Qatar) has market power across different

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Japan LNG

Average German import

UK NBP

US Henry Hub

Canada Alberta

$/MMBTU

12 10 8 6 4 2 2016

2014

2012

2010

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2004

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0

Figure 6.13  Natural gas prices, 1990–​2017 Source: BP (2018).

markets and the level of market power could change following a large demand shock such as the Fukushima accident. How natural gas is priced in each country varies depending on the regulatory framework and the level of market development. According to the International Gas Union (IGU), global gas price formation mechanisms can be classified into the following categories.14 Gas-​on-​gas (GOG) competition. The price is determined by the interplay of supply and demand. Trading takes place at physical hubs (e.g. Henry Hub) or notional hubs (e.g. the NBP in the United Kingdom) and over a variety of periods (daily, monthly, annually or other periods). There are possibly developed futures markets. The wholesale markets in the United States and United Kingdom are examples in this category, as the industry has been fully liberalized and there are actively traded spot and futures markets. Also included in this category are any spot LNG cargoes, any pricing of which is linked to hub or spot prices, and also bilateral agreements in markets where there are multiple buyers and sellers.

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Oil price escalation (OPE). The price is linked to competing fuels, typically crude oil, gas oil and/​or fuel oil. In some cases coal prices can be used, as can electricity prices. This type of price formation mechanism is mainly seen in Europe, where the imported gas (from Russia) is dominated by oil-​indexed long-​term contracts, and in Asia, where the prices of imported LNG are also primarily linked to oil prices. Bilateral monopoly (BIM). The price is determined by bilateral discussions and agreements between a large seller and a large buyer. The price is, typically, fixed for a period of time such as one year. This scheme is primarily used in some of the intra-​FSU trade and indigenous production in Qatar, Australia and New Zealand. Netback from final product or competing fuels (NET). The price received by the gas supplier is a function of the price received by the buyer for the final product the buyer produces or the price of competing fuels in a certain location (e.g. Shanghai) minus transportation costs. The former occurs where the gas is used as a feedstock in chemical plants, such as ammonia or ethanol, or for power generation. It is widely used in Latin America and, more recently, in China. Regulation: cost of service (RCS). The price is determined, or approved, by a regulatory authority, or possibly a ministry, but the level is set to cover the “cost of service”, including the recovery of investment and a reasonable rate of return. Regulation: social and political (RSP). The price is set, on an irregular basis, probably by a ministry, on a political/​social basis, in response to the need to cover increasing costs, or possibly as a revenue-​raising exercise. Regulation: below cost (RBC). The price is knowingly set below the average cost of producing and transporting the gas, often as a form of subsidy by the state to its population. No price (NP). The gas is either flared or provided free to the population and industry, possibly as a feedstock for chemical and fertilizer plants.

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BOX 6.3  CHINA’S NETBACK PRICING

China changed its domestic wholesale gas (city-​gate) prices for natural gas to netback pricing from Shanghai in 2012. The Shanghai city-​gate price is determined by a weighted average of fuel oil and LPG prices measured in heat values, specifically: PG = K * (αCPFO + βCPLPG ) where PG, PFO, and PLPG are the prices of natural gas, fuel oil and LPG respectively, K is a constant and α and β are the weights, with α = 0.6 and β = 0.4. K was set at 0.9 to encourage the use of natural gas. Thus, the price of natural gas at Shanghai city-​gate is 90 per cent of the weighted average price of fuel oil and LPG. The city-​gate prices in other cities are adjusted by the cost of transportation from Shanghai.

The three regulated categories  –​cost of service, social and political and below cost –​are found predominantly in indigenous production in the FSU, Middle East and Malaysia and Indonesia. The categorization of price formation mechanisms in individual countries is not an exact science, and many countries may use several methods. For example, in China, although netback pricing is used for city-​gate prices, the prices of shale gas and coalbed methane are left to the market. According to the IGU’s natural gas pricing surveys, there is a clear trend of the share determined by gas-​on-​gas competition to increase at the expense of oil price escalation, largely as a result of Europe moving away from oil price indexation in contractual terms and increased spot and short-​term LNG trading. Between 2005 and 2017 the share of GOG competition rose by almost 15 percentage points, while OPE declined by five percentage points and BIM declined by 2.5 percentage points. In the next section we will have a closer look at the natural-​gas-​pricing mechanisms in the United States and Europe, where wholesale prices are predominantly determined by market forces.

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Natural gas pricing in the United States The deregulation process Since wholesale prices in the United States are determined in the market via gas on gas competition, it is helpful to start with a brief review of the deregulation process. The natural gas industry in the United States has gone through a full cycle, from being unregulated to regulated, then deregulated. The deregulation started in 1978, with the passing of the Natural Gas Policy Act (NGPA), which began the partial deregulation of wellhead prices and instituted a scheme for phasing out price ceilings at the wellhead. However, the complete deregulation of wellhead prices was not legislated until Congress passed the Natural Gas Wellhead Decontrol Act (NGWDA) in 1989, under which all remaining regulated prices on wellhead sales were repealed. As of 1 January 1993 all remaining price regulations were eliminated and the wellhead prices were completely determined by the market. Among the most important measures in restructuring the natural gas industry were Order no.  436 and Order no.  636 by the Federal Energy Regulatory Commission (FERC). FERC Order no.  436, issued in 1985, introduced voluntary open access to interstate pipeline transportation and limited the use of long-​term contracts (Juris 1998b). Local distribution utilities and large end-users were allowed to purchase natural gas directly from producers, bypassing interstate pipeline companies. Pipeline companies were allowed to charge an open access tariff, which was regulated by FERC. This was followed by FERC Order no. 636, in 1992, which mandated pipelines to separate their transportation and sales services, so that all pipeline customers have a choice in selecting their gas sales, transportation and storage services from any provider, in any quantity. This order required the interstate pipeline companies to restructure their production and marketing arms as arm’s-​ length affiliates. These affiliates could in no way have an advantage (in terms of the price, volume or timing of gas transportation) over any other potential user of the pipeline. The order established a level playing field for all natural gas sellers in moving natural gas from the wellhead to the end-user or local distribution companies. It allows the complete unbundling of transportation, storage and marketing; the customer now chooses the most efficient method of obtaining its gas.

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Order no.  636 also requires pipelines to establish “capacity release” programmes allowing the resale of unwanted pipeline capacity between pipeline shippers (any users of pipeline transportation). This order required interstate pipeline companies to set up electronic bulletin boards, accessible by all customers on an equal basis, which show the available and released capacity on any particular pipeline. A customer requiring pipeline transportation can refer to these bulletin boards, and find out if there is any available capacity on the pipeline, or if there is any released capacity available for purchase or lease from one that has already purchased capacity but does not need it. The capacity release market promotes the efficient allocation of transportation contracts among shippers and allows gas market participants to match transportation contracts to their gas supply contracts. Deregulation has changed the structure of the US gas industry. Until 1985 the industry was vertically separated into production, pipeline transportation and distribution. The introduction of open access to interstate pipeline transportation in 1985 and the unbundling of interstate pipelines completed the wholesale market’s transformation into a fully competitive market by 1993. Figure 6.14 illustrates the industry structure before and after the deregulation. Natural gas price formation through trading The liberalization of gas marketing and wholesale gas prices attracted many new companies into the US wholesale market. Gas producers, pipeline companies, marketers, distribution companies and large consumers all engage in gas trading under different commercial arrangements. Most transactions are facilitated by gas marketers that match customers’ differing needs by aggregating a large number of buyers and sellers. In addition, marketers and other buyers and sellers of natural gas are able to use financial instruments traded on exchanges to hedge the risks associated with price volatility.15 Natural gas trading takes place at different locations throughout the country. These locations, referred to as “market hubs”, exist across the country and are located at the intersection of major pipeline systems (Figure 6.15). Natural gas is traded at these locations and prices are established, although the level of trading activity varies between locations. The most important market hub is the Henry Hub, located in southern Louisiana. The Henry Hub is the most active natural-​gas-​trading hub in North America, where nine interstate and four intrastate pipelines interconnect to

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Natural gas Before 1985 Pipeline companies

Producers

Distribuon companies

End users

Gas transportaon Gas sales Aer 1992 Residenal Distribuon companies Producers

Pipeline companies

Commercial

Industrial Marketers

Spot market

Electric ulies

Gas transportaon Gas sales

Figure 6.14  Change in natural gas industry structure in the United States Source: Juris (1998b).

provide natural gas to major markets in the Midwest, Northeast, Southeast and Gulf Coast. Because of its central location and high degree of interconnectedness, the Henry Hub is used as the delivery point for the New York Mercantile Exchange’s natural gas futures contract. Although the Henry Hub has served as the pricing reference point for virtually the entire North American natural gas market, other locations have also become important market trading points, such as Alberta, Chicago Citygate and Dawn, Ontario. Market participants buy and sell natural gas on a “spot” basis every day at the trading hubs shown in Figure 6.15, as well as at dozens of other points. Spot market transactions are normally conducted over the internet or by telephone, with the buyer agreeing to pay a negotiated price for the natural gas to be delivered by the seller at a specified delivery point. Such transactions

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Figure 6.15  Natural gas hubs in North America Source: Powerex, “Gas marketplace”; available at: www2.powerex.com/​ProductsAndServices/​ NaturalGas.aspx.

are usually referred to as over-​the-​counter (OTC) transactions. Natural gas spot prices reflect daily supply and demand balances at the local market and can be volatile. In addition to daily spot transactions, a large volume of gas is traded in the last week of every month, known as “bid week”. This is when producers are trying to sell their expected production and consumers are trying to buy for their core natural gas needs for the upcoming month. During the bid week buyers and sellers arrange for the purchase and sale of physical natural gas to be delivered throughout the upcoming month, including making delivery arrangements with pipelines. Many customers purchase natural gas under longer-​term contracts, which provide for the delivery of gas for a specified period. The length of time can vary. Frequently the prices in longer-​term contracts are not fixed but are, instead, indexed to prices that are regularly published in the trade press or the price of front month futures at the NYMEX. A number of trade publications publish index prices based on their surveys of natural gas buyers and sellers, to

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determine the prices they pay (or receive) for natural gas at different locations in daily or monthly transactions. Gas pricing in Europe Except in the United Kingdom, natural gas pricing in Europe has been dominated by oil-​ indexed long-​ term contracts. The long-​ term contract structure not only provides gas producers and suppliers with the necessary assurances on end-user demand to support capital-​intensive investment decisions (pipelines and, in some cases, large offshore production facilities) but also gives customers security of supply. Oil indexation, developed in the absence of a functioning spot market for gas, allows the contract price of the gas to fluctuate, albeit in line with the price (and hence the supply and demand dynamics) of a competing source of primary energy. One of the reasons that the spot market was less developed in Europe than in the United States is the physical infrastructure. Although the United States has an extensive and interconnected pipeline system, Europe’s pipeline infrastructure was designed to allow gas to flow from the key suppliers in the north (Norway), east (Russia) and south (Algeria) to the key demand centres in the south and west (Germany, France, the Netherlands, Spain and Italy) and does not have the ability to reverse flow or link the key centres of consumption. The infrastructure, combined with the contract structure, effectively impedes the free movement of gas around Europe. Although gas sold under long-​term contract continues to dominate the European gas market, there is a clear trend of moving away from oil price escalation to gas-​on-​gas competition. According to the IGU, in 2017 around 70 per cent of natural gas traded in Europe was based on GOG competition. The changes reflected several factors. A number of countries, including the Netherlands, Germany and Italy, have switched the pricing of domestically produced and consumed gas away from oil indexation. A series of disputes between Russia and Ukraine (2005/​6, 2007/​8 and January 2009) reduced the oil-​indexed gas supply to Europe and led to a push towards the development of more effective spot markets. The decline in oil-​indexed contracts was mirrored by a rise in imports of spot and short-​term LNG. Finally, some of the long-​term contracts were renegotiated to include a proportion of hub/​

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BOX 6.4  HENRY HUB NATURAL GAS FUTURES

The New York Mercantile Exchange, now part of the CME Group, began trading natural gas futures in April 1990. It is based on delivery at the Henry Hub in Louisiana. According to CME, the Henry Hub natural gas futures is the third largest physical commodity futures contract in the world by volume. Some of the key contract specifications are as follows. Contract unit Price quotation Trading hours

Product code Listed contracts

Settlement method Termination of trading

10,000 million British thermal units US dollars and cents per MMBTU Sunday–​ Friday 6.00 p.m. –​5.00 p.m. (5.00 p.m. –​4.00 p.m. Chicago Time/​C T) with a 60-​minute break each day beginning at 5:00 p.m. (4:00 p.m. CT) NG The current year plus the next 12 calendar years. A new calendar year will be added following the termination of trading in the December contract of the current year. Deliverable Trading of any delivery month shall cease three business days prior to the first day of the delivery month.

spot price indexation in the pricing terms, or even a move to 100 per cent hub price indexation. It is notable that a number of spot market trading hubs have emerged in the process. Besides the National Balancing Point in the United Kingdom, the key hubs in Europe are TTF (Netherlands), ZEE (Belgium), PEG (France), PSV (Italy), CEGH (Austria) and NCG/​Gaspool (Germany). Of particular interest is the fact that the TTF has surpassed the NBP in terms of trading volume since 2016 and become the largest natural gas hub in Europe, although the NBP still has the greatest physical volume. 180

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The development of a spot market in the United Kingdom The UK gas wholesale market was the first in Europe to liberalize and one of the first globally. The deregulation process started in 1986, when British Gas was privatized. Before then BG, publicly owned and vertically integrated, was a monopsony, buying gas from all producers across the country, as well as a monopoly supplier to end-users. Only gas production was open to competition, and this segment was dominated by multinational oil companies. In 1986 the government privatized British Gas through the Gas Act (1986). At the time of privatization the government chose to leave BG a single, vertically integrated company in order to facilitate the privatization and maximize the sale proceeds. However, the Gas Act removed BG’s monopoly to supply large customers using more than 25,000 therms per annum, while obliging it to transport competitors’ gas through its own pipelines.16 The residential market remained closed to competition, and BG continued to be the sole supplier of natural gas to small consumers. The initial decision not to unbundle BG in 1986 hindered the development of a competitive gas market. Because BG controlled the entire pipeline system and held long-​term gas supply contracts with producers, it was able to retain a de facto monopoly in the wholesale markets and control entry by independent gas suppliers (Juris 1998a). Possibly the most important legislation in liberalizing the British gas market was the Gas Act (1995). This act set out in law a timetable for full competition in the British gas market. It established a new licensing system defining pipeline operators (gas transporters), wholesalers (gas shippers) and retailers (gas suppliers). This paved the way for competition in the residential market. The process of transformation was completed in 1996 when the Network Code came into being; the statutory document sets out the rules and procedures for third-​party access to the British pipelines and introduced a regime of daily balancing. As a result of these regulatory and legislative measures, British Gas lost a significant proportion of its market share to independent suppliers (see Table 6.5) (Heather 2010). After some further regulatory interventions, British Gas was eventually split into two companies in the mid-​1990s; the BG Group took over all the upstream assets of the old company while Centrica took over all the downstream assets. The transportation and storage assets were first transferred to

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Table 6.5  British Gas’s declining market share (%), October 1991–​January 1996 Market Small firm supply (< 2,500 therms per year) Large firm supply (>2,500 therms per year) Interruptible (exc. power stations) Power stations Total (exc. power)

Oct. 91 Oct. 92 Oct. 93 Dec. 94 Apr. 95 Jan. 96 100

100

77

52

45

43

80

57

32

9

10

19

100 9 91

100 26 81

100 12 77

93 17 47

57 32 35

34 24 29

Source: Price (1997), cited in Heather (2010).

Transco, a subsidiary of British Gas, which was then sold to National Grid. The storage functions of Transco were separated from the rest of the business and sold to Dynegy, before they were bought back by Centrica, under the name of BG Storage Ltd. Although natural gas markets are substantially deregulated, gas transportation remains heavily regulated, because of the natural monopoly characteristics of pipeline transportation. A secondary transportation market has also emerged, with the resale of pipeline capacity among shippers permitted since 1996. Market liberalization has fostered new ways of trading natural gas, reflecting market participants’ need for more flexible gas supply arrangements (Juris 1998a). Spot markets formed at major terminals and within the pipeline system, allowing market participants to balance their short-​term supply and demand. As the spot markets developed, it became more difficult to always negotiate all aspects of supply contracts, and demand increased for the standardized contracts suited for spot market trading. This led to the development of the on-​system market and the National Balancing Point. The on-​system market is, basically, a natural gas spot market, with the delivery point at the NBP, a virtual point created by the Network Code. It is where market participants nominate their buys and sells and where the National Grid operator balances the system on a daily basis. In effect, all gas supplies transported through the high-​pressure pipelines can be traded at the NBP. In order to trade in the on-​system market, a company must reserve pipeline capacity through transportation contracts. Sellers use their reserved pipeline capacity to deliver natural gas to the NBP, where they sell it to interested buyers. Buyers then use their pipeline capacity to transport

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the gas from the NBP to the desired location. Transaction arrangements are facilitated by the National Grid, which keeps track of traded volumes and provides transportation services. The price of the NBP reflects the commodity price in the entire market without geographic differentials due to transport costs. Transport costs are levied separately and are regulated by the British energy regulator. Although the NBP was established purely as a balancing tool for the United Kingdom, it rapidly evolved as a trading point. Traders had confidence in buying and selling gas on a standardized basis at the most liquid point in the United Kingdom’s high-​pressure transmission system. The NBP was used as the basis for the standardized “NBP 1997” and “NBP 2015” contracts, which have become the cornerstone of the British OTC traded market and the delivery point for ICE futures natural gas contracts. Requirements for a functioning natural gas market The primary goal of deregulation is to increase competition between natural gas suppliers and consumers and let market forces determine the price. Ultimately, a functioning wholesale market delivers a reliable price signal that accurately reflects the balance of supply and demand, now and in the future. International experience has shown that a move from monopolized to truly competitive gas markets requires structural and regulatory changes that encourage new entrants and provide a level playing field. In order to create a functioning natural gas market, governments must proactively provide the foundations for the market and make the necessary institutional and regulatory changes. According to the IEA (2013), a successful attempt at increasing competition will meet the following institutional requirements (in no specific order). A hands-​off government approach to natural gas markets. This implies a shift in government involvement in the natural gas industry, from direct policy-​ making and market involvement to market monitoring and consumer protection through an independent antitrust and regulatory agency (e.g. the FERC in the United States and the Office of Gas and Electricity Markets (OFGEM) in the United Kingdom). However, the particular institutional arrangements

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for withdrawing direct government influence from the market may differ significantly between countries. Separation of transport and commercial activities. A functioning natural gas market is dependent on the pipeline network, which is normally considered a natural monopoly due to the high costs of infrastructure investments. It is crucial to separate these vertically integrated supply systems in order to avoid conflicts of interest and encourage new entrants into the market. Normally this is achieved through unbundling the transportation services from commercial activities. The transport activities would be subject to regulation and all market participants should be guaranteed unbiased third-​party access or open access. The transmission fee is levied to reflect the cost of service. Wholesale price deregulation. Part of the governmental hands-​off approach would involve letting the market set the wholesale price level for natural gas. This wholesale price would include the cost of producing natural gas and a profit margin. It would allow large customers to seek the supplier that can deliver the product that suits their needs at the lowest possible cost. This choice in selecting suppliers can also be offered to individual households, so that the retail market is also deregulated, but it is not strictly necessary for a functioning wholesale market to emerge (although it would spread the socio-​economic benefits of greater economic efficiency to these customers). Eventually, competition would force the suppliers (both producers and wholesalers) to improve efficiency and lower their costs. In addition to institutional requirements, it is generally accepted that some structural changes are necessary to ensure that the market is actually competitive. The government’s role will then shift from active participant to regulator, setting rules and monitoring the sector. These structural requirements include the following (again, in no specific order). Sufficient network capacity and non-​ discriminatory access to networks. Essential to a well-​functioning natural gas market is its accessibility via non-​ discriminatory access to networks, and the availability of capacity on these networks. Non-​discriminatory access will increase the number of market participants, while sufficient network capacity will ensure smooth operation of the market. One of the essential elements to guarantee these structural

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requirements is an independent transmission system operator (TSO), either divested or functionally separated; it is also necessary to have and a clear and unbiased investment regime, based on a well-​developed network code (set of rules). Competitive number of market participants. A  genuinely competitive gas market requires a number of parties with competitive market shares along a non-​regulated value chain (upstream and downstream). The question of how many market participants, and with what share of the market, constitutes true competition depends on market-​specific circumstances and needs to be answered by the government/​regulator. The regulator then needs to enforce the appropriate structure, increasingly behaving as a competition authority. Involvement of financial institutions. Enabling a market to efficiently service supply and demand will require investment throughout the natural gas value chain (upstream development, transportation, storage and distribution). Apart from capital investments that will be recouped by operational revenues, a competitive natural gas market will also need financial parties that are willing to cover financial/​operational risks for parties involved in the natural gas trade, providing tools for customers to smooth out and optimize revenue streams from their activities in the natural gas market. If a natural gas trading platform is established, a link between natural gas markets and financial institutions is needed to reduce counterparty risk and provide a clear, long-​term price signal. These structural requirements are essential to kick-​start a natural gas market. They should be guaranteed by a regulator (ideally, independent of companies and the government) that monitors the market and can act independently, when needed (e.g. force an incumbent company to facilitate more competition). The existence of an independent regulator should also boost the confidence of parties in the market. However, a transparent natural gas price that reflects the current and future state of the market will not be realized unless a platform for the title exchange of natural gas is developed, which requires the development of either a physical or a virtual hub, such as the Henry Hub in the United States and the National Balancing Point in the United Kingdom.

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TCF

25 20 15 10 5 0 2007

2008

2009

Non-associated gas

2010

2011

2012

Associated gas

2013

2014

Shale gas

2015

2016

2017

Coalbed methane

Figure 6.16  US natural gas production, 2007–​2017 Source: Energy Information Administration.

The development of shale gas Perhaps the most significant “game changer” in the oil and gas industry in the new millennium is the “shale gas revolution”, which has dramatically changed the global natural gas demand and supply landscape. As shown in Figure 6.16, shale gas production in the United States grew from less than 2 trillion cubic feet in 2007 to nearly 20 trillion cubic feet in 2017, accounting for 57 per cent of total production. As a result, the United States has for the first time become a net exporter in natural gas (Figure 6.17) in 2017. Shale gas is natural gas produced from shale formations (as shown in Figure  6.1). Shale is a type of fine-​grained, sedimentary rock composed of mud from flakes of clay minerals and tiny particles of other materials. These rocks are both the source and the reservoir for the natural gas. Because of the low permeability of shale, shale gas does not naturally flow into a well. Additional stimulation by hydraulic fracturing (“fracking”) is required to produce gas from shales. An advantage of shale formations is that they tend to overlie conventional oil and gas reservoirs. Thus, if there has been extensive exploration for conventional oil and gas, the existing wells can generate large amounts of data to locate the potential shale resource, thereby reducing exploration costs (Stevens 2010b).

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2017

2015

2013

2011

2009

2007

2005

2003

2001

1999

1997

1995

1993

1991

Export

1987

1985

1983

1981

1979

1977

1975

Import

1989

5 4.5 4 3.5 3 2.5 2 1.5 1 0.5 0 1973

TCF

Natural gas

Figure 6.17  US natural gas imports and exports, 1973–​2017 Source: Energy Information Administration. 9 8 7 $/MCF

6 5 4 3 2 1 0

Figure 6.18  US natural gas wellhead prices, 1980–​2012 Source: Energy Information Administration.

Producing natural gas from shale formations is not new. The first natural gas well in the United States was completed in 1821, in Devonian-​aged shale near the town of Fredonia, New York.17 The natural gas from this first well was used by town residents for lighting. Following the Fredonia well there was additional production from small discoveries, with the first field-​scale development of shale gas from the Ohio Shale in the Big Sandy Field of Kentucky

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during the 1920s. However, it was not until the early 2000s that the shale gas began to “revolutionize” the natural gas industry. What led to the shale gas revolution? A number of factors combined, in terms of mineral property rights, market structure, high natural gas prices, technological innovations  –​particularly in horizontal drilling and hydraulic fracturing –​and natural gas pipeline infrastructure, have led to the shale gas revolution in the United States (Wang & Krupnick 2015). In addition, government-​sponsored research and development programmes facilitated technology innovations, and fiscal policies, such as tax credits for unconventional oil and gas projects, created incentives for drilling shale gas. The combination of sequenced hydraulic fracturing and horizontal drilling has been crucial in facilitating the expansion of shale gas development. Neither horizontal drilling nor hydraulic fracturing is a “brand new” technology. Horizontal drilling has been used for nearly a century. However, the technology was initially used almost exclusively in oil wells (EIA 1993) and did not achieve commercial viability until the late 1980s. The process involves drilling a well vertically to a certain depth and then bending the path of the drilling, usually with a hydraulic motor, until it extends horizontally. The length of the horizontal section of a well can range from a few hundred feet to several miles. Because they are longer, and the drilling process is more complex, a horizontal well is generally more expensive to drill than a vertical well, but it is expected to produce more crude oil and natural gas because it can reach a much larger geographical area than a single vertical well in the same shale formation (EIA 2018). Like horizontal drilling, hydraulic fracturing has been practised for many years. It was first developed in Texas in the 1950s, but was not used commercially until the 1980s, when Mitchell Energy begin to apply it to the Barnett Shale play. Hydraulic fracturing involves forcing a liquid under high pressure from a wellbore (a drilled hole) against a rock formation until it fractures. The injected fluid contains a proppant –​small, solid particles, usually sand or a man-​made granular solid of similar size –​that wedges open the expanding fractures. By keeping the fractures open, the proppant allows hydrocarbons

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such as crude oil and natural gas to flow more easily from the additional surface area to the rock formation provided by the fractures, back to the wellbore and then to the surface. Prior to the successful application of these two technologies in the Barnett Shale, shale gas resources in many basins had been overlooked because production was not viewed as economically feasible. Through continued improvements in the techniques of hydraulic fracturing and horizontal drilling, development of the Barnett Shale has accelerated, especially after the acquisition of Mitchell Energy by Devon in 2002. The successful development of the Barnett play subsequently led to the shale gas boom. Apart from technology improvement, several other institutional and market factors in the United States have also been important in making the “shale gas revolution” (Wang & Krupnick 2015; Stevens 2010b). Chief among them are the following. High natural gas prices in the 2000s. As shown in Figure 6.18, natural gas prices increased significantly in 2000 and 2001, from an average wellhead price of about $2/​MCF from 1994 to 1999 to an average of $3.85/​MCF in 2000 and 2001. Mitchell Energy accelerated its development of the Barnett play partly in response to the gas price increase. The wellhead price dipped to an average of about $3/​MCF in 2002 but remained above $5/​MCF for most of the period from 2003 to 2008. Given the success in drilling and fracturing technologies, high natural gas prices encouraged companies to drill more wells in shale gas plays in the 2000s, which, ironically, eventually drove down the natural gas price. Land and mineral rights ownership. Recall that, in the United States, the property rights of underground minerals belong to the landowners. This has important implications for the development of shale gas. First, as gas production could financially benefit the landowners in the form of royalties, the prospect of revenue generation from future gas sales helps mitigate possible obstructions from local communities, either as a result of environmental concerns or disruptions –​ as has happened in other countries, such as the United Kingdom.18 Second, the possibility of selling the lease once the production potential is proved provides a strong incentive for firms to engage in risky exploration such as shale gas exploration and development. This mechanism helps overcome the difficulty of

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monetizing technology innovations in the industry. Recall that Mitchell Energy was partly motivated by this incentive to develop the Barnett play. The market structure of the oil industry. The United States has thousands of natural gas companies, but, somewhat surprisingly, it was an independent natural gas company  –​Mitchell Energy  –​that made large amounts of investments before the shale gas business was proved to be profitable in 2002 and 2003. The large international oil companies (i.e. the majors) did not take any serious interest in shale gas until the late 2000s. They did not have an incentive to do so, as investments in conventional oil and gas fields (offshore or in other countries) were more profitable and less risky (Wang & Krupnick 2015). Had there been no independent oil and gas companies, the shale gas revolution probably would not have happened. A dynamic and competitive service industry. It is well known that shale gas wells deplete much more quickly than conventional gas wells. The production profile of a shale gas well is often characterized by an early peak in the first month or so followed by a rapid decline. Thus, the expected lives of shale wells are much shorter than conventional gas wells. Consequently, the development of shale gas requires many more wells to be drilled, and the existence of a dynamic and competitive service industry is essential to sustain the shale gas boom. The United States has a very vibrant oil service industry, which can be clearly seen from the Baker Hughes rig count statistics. The number of active rigs in the United States is often more than a half of the total number of drilling rigs in the world (see Table 6.6). Water availability. The hydraulic fracturing of shale gas wells requires a few million gallons of water per well. In the United States, water supply is generally not an issue. However, this may not be the case in some other countries; in China, for example, the water supply in some of the shale gas regions must be prioritized for drinking, irrigation and other purposes. The pipeline infrastructure. An extensive network of natural gas pipelines existed in the United States before shale gas became a major gas resource. Another important feature was the policy of open access to these interstate

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Table 6.6  Worldwide count of rigs, 2010–​2018

2010 2011 2012 2013 2014 2015 2016 2017 2018

Latin America

Europe

Africa

Middle East

Asia-​ Pacific

Canada United States

Total world

356 424 423 419 397 319 198 185 190

84 118 119 135 145 117 96 92 85

62 78 96 125 134 106 85 83 98

252 291 356 372 406 406 390 388 396

243 256 241 246 254 220 187 201 219

221 423 365 355 380 193 128 207 191

2,304 3,465 3,518 3,412 3,578 2,337 1,593 2,029 2,211

1,086 1,875 1,919 1,761 1,862 977 510 875 1,032

Source: Baker Hughes, “International rig count”; available at: https://​rigcount.bhge.com/​intl-​rig-​count.

natural gas pipelines and storage facilities, as a result of the deregulation in the 1980s and early 1990s. In addition, a few other factors also contributed to US shale gas development. These include: easy access to capital markets; government-​sponsored research and development programmes; fiscal policies in the form of tax credits; favourable geology and topography; low population densities in shale-​gas-​producing regions; and a history of conventional oil and gas development (for details, see Stevens 2010b). In conclusion, there is an enormous amount of oil and gas contained in shale formations. According to a recent EIA estimate (EIA 2013), the world’s technically recoverable shale resources are 345 billion barrels of oil and 7,299 trillion cubic feet of gas. These figures will probably change over time as additional information becomes available, and not all the technically recoverable resources will be economically recovered. Nonetheless, it is evident that the volume of technically recoverable shale resources is substantial. The key question for policy-​makers in countries outside the United States attempting to develop their own shale gas resources is how to create a policy and market environment in which firms have the incentive to invest and will eventually profit from exploiting the shale gas. The US experience, while unique in some respects, could provide useful insights for these countries’ decision-​making.

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Mitchell Energy and shale gas development19 Few businesspeople have done as much to change the world as George Mitchell.20 In “making” the “shale gas revolution”, Mitchell Energy & Development (Mitchell Energy), a relatively small company in the oil and gas industry, played a primary role by developing the Barnett play in the Fort Worth area in Texas. George Mitchell, the founder of the company, was dubbed “the father of the Barnett natural gas field” by The Economist. Mitchell Energy started to drill in the Barnett play in 1981. The initial incentive for Mitchell Energy to develop the Barnett play was its demand for a new source of natural gas, to feed a large gas-​processing plant and a gas-​gathering system and to fulfil its long-​term contractual obligations to Natural Gas Pipeline Company of America (NGPL). As the largest gas producer in north Texas in 1981, Mitchell Energy had a long-​term natural gas supply contract with NGPL that guaranteed prices considerably higher than market prices, and the company was in a financial position to undertake some risky investments. Initially Mitchell Energy stimulated the early exploratory wells with foam fracturing before switched to nitrogen-​assist, gelled water fracturing in 1984. The costs of the gelled water stimulation were high, in the region of $350,000 to $450,000 per well, nearly 50 per cent of the total cost of developing a Barnett well. Then, in 1997, Mitchell engineers began to experiment with slick water fracturing, a technique developed by other companies for use in tight gas formations. This method uses a large amount of water as the fracture fluid and a small amount of sand as the proppant. It has later been proved that the technique of using slick water in fracturing shale gas formations was a major breakthrough, because it helped reduce the cost of stimulation by about 50 per cent while maintaining similar initial production rates and higher subsequent production rates. Mitchell Energy drilled more than 800 vertical wells but attempted to drill only four horizontal wells in the 1990s. With technical and financial assistance from the government, it drilled its first horizontal well in 1991. However, it was not until 1998 that Mitchell Energy drilled its second and third horizontal wells. Both wells were mechanically successful, but neither met Mitchell Energy’s minimum economic criteria. In late 2000 Mitchell Energy attempted to drill

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a horizontal well for the last time. That project was plagued with technical problems and was terminated after expenditure of over half a million dollars. Mitchell Energy was sold to Devon Energy, one of the largest independent oil and gas operators in North America, for $3.5 billion in January 2002. The merger greatly accelerated the development of the Barnett play. Shortly after the merger Devon Energy started to drill horizontal wells in the Barnett. Five horizontal wells were drilled in 2002, which outperformed all the previously drilled wells in the Barnett. Devon Energy subsequently drilled more than 80 horizontal wells in a five-​county area in 2003. After the production rates of the first five wells were made public in July 2003, 25 other operators filed for more than 100 horizontal well permits over a seven-​county area that year, which eventually ushered in the shale gas boom. Notes 1. This is the standard used by the International Energy Agency. According to the Russian standard, the gas volume is measured at 20°C (68°F). This means that 1 BCM of natural gas by the IEA standard is equivalent to 1.017 BCM of natural gas by the Russian standard. 2. Conversion efficiency is the ratio between the useful output of a power plant and its input in energy terms. The typical thermal power plants (coal, oil or simple-​cycle gas turbine) have a conversion rate of 30 to 35 per cent: 100 units of energy input only produces 30 to 35 units of electricity output; the rest is wasted. 3. The details of the NBP and Henry Hub prices are explained in the “Natural gas pricing” section of this chapter. 4. JCC more correctly stands for the Japanese Customs-​cleared Crude. The price of JCC represents the average price of a basket of crude oils imported into Japan. 5. LNG contracts can be either free on board (FOB) or delivered ex ship. Traditionally, LNG contracts are mostly DES contracts, in which the seller is responsible for transporting the LNG to the receiving terminal, where the title is transferred. 6. However, since the “shale gas revolution” made LNG imports to the US Gulf Coast rarely profitable, US LNG imports have largely been restricted to end-​of-​pipe markets, where local prices can become disconnected from the Henry Hub price. 7. The NBP is a virtual location for trading natural gas in the United Kingdom. See the section on natural gas pricing for more details. 8. Markets are said to be integrated when the “law of one price” holds –​that is, the prices of the same good in different regions differ only by transportation costs, and any significant price differentials between regions are quickly removed through arbitrage. For a study of market integration in natural gas markets, see Li, Joyeux and Ripple (2014) and Mu and Ye (2018).

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9. The cetane number is an inverse function of a fuel’s ignition delay, and the time period between the start of injection and the first identifiable pressure increase during combustion of the fuel. In a particular diesel engine, higher-​cetane fuels will have shorter ignition delay periods than lower-​cetane fuels. 10. The project incorporates some upstream activity, including 22 development wells, two unmanned wellhead platforms in about 100 feet of water and two 30-​inch pipelines running about 90 miles to shore, together with onshore gas-​processing facilities. In addition to the 140,000 bbl/​d GTL products, the project also produces 120,000 bbl/​d of natural gas liquids and ethane. See www.shell.com/​about-​us/​major-​projects/​pearl-​gtl/​ pearl-​gtl-​an-​overview.html. 11. GTL plants also generate carbon losses of around 30 per cent, due to the extensive production of carbon dioxide and water. Optimal carbon efficiency of around 75 per cent may be achieved (depending upon the product slate). 12. The “law of one price” means that prices of the same good (the same quality) in different regions differ only by transportation costs. When LOOP holds, the markets are said to be integrated. 13. The only LNG-​exporting facility in North America before 2016 was the Kenai LNG plant in Alaska, which is disconnected from the mainland United States. And it was mothballed from mid-​2011. 14. Here the typology concerns the wholesale price only, which refers to the hub prices in fully liberalized markets, such as the United States and United Kingdom; the border price for importing countries; and the wellhead prices or city-​gate prices for other indigenous supplies. Practically, the wholesale price is likely to be determined somewhere between the entry to the main high-​pressure transmission system and the exit points to local distribution companies or very large end-users. 15. The majority of the information in this section is sourced from American Petroleum Institute (2014) 16. A therm is a unit of heat energy equal to 100,000 BTU. 17. This and the following paragraphs rely partly on Ground Water Protection Council and ALL Consulting (2009). 18. Water contamination and induced seismicity are the typical concerns over shale gas production. However, these concerns are frequently overstated or misunderstood. Evaluating the risks associated with hydraulic fracturing in the United Kingdom, the Royal Society and the Royal Academy of Engineering conclude: “The health, safety and environmental risks associated with hydraulic fracturing (often termed ‘fracking’) as a means to extract shale gas can be managed effectively in the UK as long as operational best practices are implemented and enforced through regulation” (Royal Society & Royal Academy of Engineering 2012). 19. The material in this section is based on Wang and Krupnick (2015). 20. The Economist (2013).

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This chapter starts with a brief review of the price of internationally traded crude oil. The second section presents the economic theories of oil price determination, with a focus on the analysis of OPEC behaviour. The third section introduces a widely used two-​factor model and a trend-​cycle model for understanding the long-​and short-​run dynamics of oil prices. The fourth section gives a detailed account of the price formation mechanism in physical markets, while the final section briefly introduces energy derivatives, particularly futures markets. A brief history of oil prices From the birth of the industry to the Second World War The modern oil industry is generally considered to date back to 1859, when Edwin Drake drilled the first commercially successful well in Titusville, Pennsylvania.1 Figure 7.1 shows the history of oil prices since 1861, measured both in 2017 dollars and the money of the day. There are several boom and bust cycles in the history of oil industry. Drake’s success prompted numerous entrepreneurs to enter the oil business in the 1860s, which can be understood from the perspective of the law of capture. Once oil is discovered, each landowner who is lucky enough to be sitting on the top of the reservoir has an incentive to drill into the “common pool” and produce as much as possible.

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Figure 7.1  History of oil prices, 1860–​2017 Notes: The figure depicts the history of oil prices from 1861 to 2017, both in real terms (2017 dollars) and in nominal terms (money of the day). The series is the US average for 1861–​1944, Arabian Light posted at Ras Tanura for 1945–​1983, Dated Brent for 1984–​2017. Source: British Petroleum, “Statistical review of world energy”; available at: www.bp.com/​ statisticalreview.

The early days of the industry were characterized by fierce competition and chaos (Stevens 2010a). In the ten years following the US Civil War the nominal price of crude oil declined sharply, from $8.04 per barrel in 1864 to $1.17 per barrel in 1874. However, the subsequent rise of Standard Oil, which was accomplished largely by controlling refining and shipping, effectively consolidated the industry and stabilized the price.2 By 1904 Standard Oil controlled over 91 per cent of US refinery output and 85 per cent of final sales. Most of its output at the time was kerosene, 55 per cent of which was exported around the world. The United States was going through a period of rapid industrialization and fast population growth in the 1890s, eventually overtaking the United Kingdom as the world’s leading centre for manufacturing. As a result, domestic consumption of kerosene increased from 1.6  million barrels in 1873/​74 to 12.7 million barrels in 1900. However, the annual oil production from Pennsylvania not only failed to increase but fell by nearly 50 per cent

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from 1890 to 1900. It was the strong demand growth combined with declining production that led to the price increase in the 1890s. The oil industry outside the United States in the nineteenth century was relatively competitive. In the 1890s Royal Dutch made oil discoveries in Indonesia, while Shell Transport and Trading started to transport kerosene from Russia to the Far East in 1892 (Dahl 2014).3 The Nobel brothers and the Rothschilds started to produce oil in Baku. During the First World War the UK government acquired a controlling share in Anglo-​Persian, which was producing oil in Persia (Iran) in order to fuel the British naval fleet. The company later evolved into British Petroleum. Oil production in the United States was concentrated in Appalachia until 1901, when a huge oil field at Spindletop near Beaumont, Texas, was discovered. Increased supply from oil fields in the Gulf Coast of Texas and Louisiana, and the middle of the continent (Oklahoma in particular), effectively ended any monopoly attempt by Standard Oil and led to a secular price decline in the 1900s. When Standard Oil was finally broken up in 1911 the nominal oil price was as low as $0.61 per barrel, and it stabilized at low levels for the early 1910s. However, the rapid expansion of the automobile, shipping and airline industries and the outbreak of the First World War significantly drove up demand in 1910s. Between 1915 and 1920 the number of registered cars in the United States jumped from 2.3 million to 8.2 million and the total consumption of crude oil increased 94 per cent. This was gauged against a generally disappointing period of new discoveries in the late 1910s, which fuelled a fear of the imminent depletion of oil resources among US petroleum industry personnel and many in the US government.4 For example, the director of the US Bureau of Mines prophesized in 1919 that “within the next two to five years the oil fields of this country will reach their maximum production, and from that time on we will face an ever-​increasing decline” (Yergin 1991: 178). Consequently, the oil price spiked in the late 1910s as a result of the rapidly rising demand coupled with expectations of a supply shortage. After the First World War the demand for oil dropped while production from the oil fields in Texas, Oklahoma and California continued to grow, which induced another round of price declines (Hamilton 2011).5 The nominal price in the United States fell 60 per cent between 1920 and 1929. The situation was exacerbated by the Great Depression and the discovery of the

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gigantic East Texas Oil Field, which started production in 1930. By 1931 oil prices had dropped another 40 per cent from their value in 1929. As the economy recovered from the Great Depression, the oil price also gradually recovered. Subsequently the breakout of the Second World War again drove up demand for oil, as it was needed not only for fuelling cars, trucks, tanks and aeroplanes and for oil products, but also for laying runways (asphalt), making toluene (the chief component of TNT) for bombs, the manufacture of synthetic rubber for tyres and as a lubricant for guns and machinery. However, on the supply side, the lack of significant new discoveries from the mid-​1930s fuelled another period of pessimism about the future oil supply and pushed up the price again. As an example of the pessimism about the future US oil supply, in December 1943 the secretary of the interior published an article entitled “We’re Running Out of Oil!” (Yergin 1991: 377). In addition, increased regulation at both federal and state levels, most noticeably the prorationing of production by the Texas Railroad Commission, effectively restricted competition (Stevens 2010a).

The “As-​Is Agreement” and the basing point system Before the late 1920s there were a series of price wars between the major oil companies. The most significant one was in India, between Standard Oil of New York and a subsidiary of Royal Dutch Shell, to fight for market share. The price wars threatened the profits of the major oil companies, especially those from relatively high-​cost production in the United States. In an attempt to shore up oil prices, the leaders of the Anglo-​Persian Oil Company (later BP), Royal Dutch Shell and Standard Oil of New Jersey (later Exxon) met in August 1928 at Achnacarry Castle in Scotland and agreed to share the world markets, in what is known as the “As-​Is Agreement”. In the same year the shareholders of the Turkish Petroleum Company, including the Anglo-​Persian, Shell, Compagnie française des pétroles (CFP), Standard Oil of New Jersey, Standard of New York (later Mobil), Standard Oil of Ohio (Amoco) and Calouste Gulbenkian, agreed to cooperate in much of the old Ottoman Empire. This was later known as the “Red Line Agreement”, because of the red lines marking the agreement area on a map. These two agreements formed the basis of what a US Senate subcommittee in 1952

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BOX 7.1  PRINCIPLES OF THE AS-​I S AGREEMENT

The purpose of the As-​Is Agreement was to limit the “excessive competition” that had led to the overproduction in the 1920s. It consisted of such measures as dividing markets, fixing prices and limiting the expansion of production capacity. As a result, the agreement limited the development of oil production capacity in the Middle East and supported the high-​cost producers, primarily the American producers. This strategy was implemented with a “basing point” system under which the delivered prices of petroleum products were calculated as the sum of free on board (FOB) prices at one or more specific locations –​basing points –​plus a standardized freight charge from that point to the point of delivery. Such a system is very effective in limiting competition, because all sellers quote the same prices, and producers with low costs cannot use that advantage to expand their market shares. The impact of the As-​Is Agreement on Middle Eastern oil producers was profound. It was substantially responsible for the reluctance of concession holders to expand production in this region. In 1928, when it was adopted, more than a third of worldwide production capacity was shut down due to oversupply. Owners feared that expanding low-​cost capacity in the Persian Gulf would only add to their losses. The As-​Is and Red Line Agreements not only retarded the development of Middle Eastern oil resources until after the Second World War but also established a pattern of ensuring oil profits by exercising market control –​something that the members of the Organization of Petroleum Exporting Countries later tried to emulate. Source: “As-​Is Agreement”, Encyclopedia of the Modern Middle East and North Africa; available at: www.encyclopedia.com/​humanities/​ encyclopedias-​almanacs-​transcripts-​and-​maps/​agreement called “the international petroleum cartel”. From 1928 to the early 1950s the world’s crude oil trade was controlled by the major multinational oil companies, known as the “Seven Sisters”.6 A key part of the “As-​Is” agreement was the establishment of the “Gulf Plus basing point system”. Under this system, the delivery price of an oil product

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was determined by the sum of the domestic price of oil products in the Gulf of Mexico and the freight cost of moving the product to its destination. An example for supplying Bombay, with fictitious numbers, is given below to illustrate. ($ per barrel) FOB price at Gulf of Mexico7 Freight from Gulf of Mexico to Bombay Landed price in Bombay

$2.00 $1.50 $3.50

Now if the oil product was delivered from, say, Abadan in the Persian Gulf, the cost numbers might look as follows: ($ per barrel) FOB price Abadan Freight from Abadan to Bombay Total cost

$1.50 $0.50 $2.00

However, in this case, a phantom freight rate of $1.50 per barrel would be added to the Abadan total so that the landed price in Bombay would also be equal to $3.50 per barrel, irrespective of where the oil product came from. This system was deliberately designed to prevent low-​cost Persian Gulf crudes from undercutting higher-​cost suppliers in the United States. During the Second World War the US and UK navies both complained to their governments about this pricing scheme, as they were obliged to fuel their warships at Abadan and pay as though the fuel had come from the United States. Eventually, in 1944, Abadan was named as a second basing point. This effectively opened up the markets for Persian Gulf crude to both the west and the east, determined by relative transportation costs. By 1945 the watershed was Italy. The west coast was supplied by the Gulf of Mexico, the east coast by the Persian Gulf. As the production cost differentials between the Gulf of Mexico and the Persian Gulf widened and freight costs fell, the Persian Gulf market grew, reaching the East Coast of the United States by 1948 (Stevens 2010a). Postwar to the 1970s During the period from 1949 to 1973 the oil price was set by the major international oil companies. Thanks to the strong economic growth in OECD 200

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countries, world oil demand experienced a period of spectacular growth; during the 1960s world oil demand was growing around 8 to 10 per cent every year.8 Most of this increase was met by OPEC, which massively increased its production, from around 14 million bbl/​d in 1965 to close to 30 million bbl/​d in 1973. OPEC’s share in global crude oil production increased from 44 per cent in 1965 to 51 per cent in 1973. However, as the oil market was dominated by the majors, which are vertically integrated and had control both upstream and downstream, they were able to maintain the nominal posted price at $1.80 per barrel for the entire period from 1961 to 1970, which was $0.10 to $0.20 per barrel lower than in the 1950s. The result was that, during the 1960s, the real price of oil eroded, and tax receipts paid to the governments of oil-​producing countries slid. The formation of the Organization of Petroleum Exporting Countries in 1960 was an attempt by member countries to prevent the decline in the posted price, and hence the tax income, of its member countries.9 From its formation until the early 1970s OPEC did not manage to increase prices but, rather, acted as a trade union, to prevent the posted price from declining (Fattouh 2011). The oil industry witnessed a major transformation in the 1970s, when some OPEC governments stopped granting new concessions and started to claim equity participation in their existing concessions, with a few of them opting for full nationalization.10 By 1980 nationalization was complete in the Gulf states of OPEC. Equity participation gave OPEC governments a share of the oil produced that they had to sell to third-​party buyers, which led to the introduction of new pricing concepts. As owners of crude oil, governments had to set a price for third-​party buyers, and this gave rise to the concept of the official selling price (OSP) and the government selling price (GSP), which is still used by some oil exporters today. However, for reasons of convenience, lack of marketing experience and an inability to integrate downwards into refining and marketing, most of the governments’ shares were sold back to the companies that held the concession and had produced the crude oil in the first place. In the fourth quarter of 1973, as a result of failed negotiations between OPEC and the majors and the subsequent Arab oil embargo associated with the Yom Kippur War, members of the Organization of Arab Oil Producing Countries (less Iraq) unilaterally announced an immediate increase in the

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posted price of the Arabian Light crude from $3.65 to $5.12 in October. This was followed by another increase to $11.65 in December 1973. Thus, in the last quarter of 1973 the oil price was more than tripled. This is the so-​called first oil crisis. The year 1973 represented a dramatic shift in the balance of power towards OPEC. For the first time in its history OPEC assumed a unilateral role in setting the posted price (Terzian 1985). However, it must be noted that, because of the strong economic growth in OECD countries and the presence of capacity constraints, the oil price would probably have been rising in the 1970s even without the oil embargo. The reason is that the 1970s also saw substantial increases in non-​oil industrial commodities prices, which had nothing to do with the geopolitical events in the Middle East (Kilian 2008). In terms of capacity constraints, the world’s excess crude production capacity was halved from 3 million bbl/​d in 1970 to 1.5 million bbl/​d by 1973 (Yergin 1991: 566), which was less than 3 per cent of world consumption for that year. Thus, even in the absence of geopolitics, a price increase would probably have occurred as a result of the strong demand growth and capacity constraints. Then, in 1978/​9, came the Iranian Revolution. A series of massive protests against the shah and strikes by oil workers, starting in October 1978, severely disrupted the Iranian oil sector, with production initially being reduced from 6  million bbl/​d to about 1.5  million bbl/​d and exports suspended (Phillips 1979). Although other countries, particularly Saudi Arabia and Kuwait, were able to step in to quickly increase production, so that the actual loss to the global oil supply was much less, the widespread panic sent the price far higher. The price of crude oil more than doubled, to $31.61 per barrel in 1979 compared to $14.02 per barrel in 1978. This was the second oil crisis. The subsequent outbreak of the Iran–​Iraq war in 1980 further fuelled the frenzy. Eventually OPEC managed to reach an agreement in October 1981 and set a price of $34 per barrel. After the 1980s OPEC moved to a production quota system in 1982, and since then an important task of their biannual meetings has been to set the production quota. The quotas are usually allocated among member countries, although

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they are frequently violated. Within OPEC, the role of Saudi Arabia is critical, because it is the largest producer and the largest exporter and possesses the largest reserve. It is also the only “swing producer”, and was initially not allocated a quota but voluntarily adjusted its production to “balance” the market, and often the country takes the largest hit in production cuts. For this reason, Saudi Arabia is considered the de facto “ruler” of OPEC by many commentators. The price hikes in the 1970s and the early 1980s have had a profound impact on demand and supply. First, the demand for oil was significantly reduced in the early 1980s. World oil consumption fell by 10 per cent between 1979 and 1984. Moreover, high oil prices accelerated the development and adoption of energy-​saving technologies, which proved to have a long-​lasting effect on the demand. For example, the United States raised its fuel efficiency standard for the automobile industry in 1975, requiring the average fuel efficiency of a new car sold in the country to double over a ten-​year period, from 13 miles per gallon to 27.5 miles per gallon. Second, the high oil price encouraged supply from non-​OPEC countries, while making it more difficult for OPEC to remain integrated as a cartel. As the nominal oil price jumped from $14 per barrel to over $30 per barrel in the aftermath of the Iranian Revolution, major capacity build-​ups were taking place in Alaska, Mexico and the North Sea.11 Consequently, the share of OPEC in world oil supply declined from nearly 50 per cent in the mid-​1970s to below 30 per cent in every year between 1983 and 1985 (see Figure  7.2). Saudi Arabia initially defended the OPEC-​ administered price by cutting production from 10 million bbl/​d to less than 3 million bbl/​d between 1981 and 1985, but this was not enough to prevent a 25 per cent decline in the oil price, because other countries increased their output. In response to the falling oil revenues and the frequent violations of quotas by some key OPEC members, Saudi Arabia then abandoned its efforts to defend the oil price and ramped up its production in 1986, causing the oil price to collapse. The oil market in the late 1980s and 1990s was generally well supplied, and Saudi Arabia’s excess capacity was sufficient to dampen any short-​term price spikes caused by such geopolitical events as the Iraqi invasion of Kuwait and the first Gulf War (Stevens 2010a). The oil price bottomed out in 1998 amid an array of factors, including the Asian financial crisis and frequent violations of OPEC production quotas. At lower prices, demand increased while non-​OPEC supply declined. The

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Figure 7.2  OPEC’s share of oil production, 1960–​2016 Source: Organization of Petroleum Exporting Countries (2018).

price surge from 2003 to 2008 was, arguably, driven by rising demand, particularly from emerging economies such as China and India (Kilian 2009; Hamilton 2009; Mu & Ye 2011). However, a non-​negligible factor is the fact that OPEC’s supply has remained flat since 2005, in spite of a nearly 100 per cent increase in prices. It must be noted that the stagnation in OPEC supply has little to do with resource depletion. Rather, it is a result of commercial choices by OPEC members to restrain investment in production capacity (Smith 2009). Consequently, as demand surges there is very little room to increase output in a short time. As depicted in Figure  7.3, OPEC’s spare capacity fell significantly between 2007 and the first three quarters of 2008. In an industry that is extremely capital-​ intensive and has long lead times for bringing new production projects on line, the short-​term supply curve becomes nearly vertical when there is no excessive capacity. A small shift in demand can cause a large swing in the oil price and, hence, high volatility. In addition, some argue that the financialization of commodity futures and the depreciation of the US dollar exchange rate also contributed to the 2007/​8 oil price spike (see Gilbert 2010; Tang & Xiong 2012; and Chen, Rogoff & Rossi 2010 for a detailed discussion). World oil prices remained elevated until the summer of 2008 before plummeting to below $40 per barrel in December that year (Figure 7.4). The world’s real GDP growth rate nearly halved in 2008 and became negative in 204

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BOX 7.2  SAUDI ARABIA AS THE SWING PRODUCER

Saudi Arabia officially played the role of swing producer for only a short period in the early 1980s. At a ministerial meeting in March 1983 OPEC agreed to establish a ceiling for total OPEC production and allocated the quotas to individual member countries. However, no quota was allocated to Saudi Arabia, because it would “act as a swing producer to supply the balancing quantities to meet market requirements” (New York Times 1983). Before 1983 Saudi Arabia had often acted as an informal swing producer, but this was the first time the role had been formalized. Saudi Arabia’s role as a swing producer formally terminated in 1984, when it opted instead for a quota of 4.35 million bbl/​d. However, in practice, Saudi Arabia continues to assume the role of swing producer from time to time, in order to balance the market. For example, in March 1999 Saudi Arabia took the lead in cutting production to shore up the oil price after the Asian financial crisis. And, in the recent round of production cuts that started in December 2016, Saudi Arabia and its Persian Gulf allies again shouldered the biggest share, despite spending months insisting that this was not what they would do again. Several factors explain why Saudi Arabia is the country that has acted as the swing producer. First, Saudi Arabia is the only country that exports enough to have a major influence on global prices (7 to 8 million bbl/​d) and has production centralized in one company (Saudi Aramco). Other major oil-​producing countries are either net importers, have production that is split between many independent companies or are too small to have much influence on global prices. Second, Saudi Arabia is also a low-​ cost producer with the operational flexibility to adjust its production up or down by several million barrels per day. Third, Saudi Arabia has a relatively small population (32 million at the end of 2016), which makes it easier for the country to meet its social demographic demand with its oil revenues. 2009 amid the global financial crisis. It has rebounded since 2010, although it has remained sluggish in OECD countries. World oil prices gradually recovered in 2009 and 2010 and remained relatively high until late 2014. The Brent price was above $100 per barrel for a large part of 2011 through to the 205

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The Economics of Oil and Gas

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summer of 2014. During this period the world oil market was well supplied, with an increasing supply from US tight oil.12 Several factors contributed to the price increase. First was the Libya civil war, starting in 2011, which intermittently removed Libyan production from the market. Libya’s production

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dropped from 1.66 million bbl/​d in 2010 to an average of 0.48 million bbl/​d in 2011 (zero in August 2011). It rebounded to 1.51 million bb/​d in 2012 but dropped again to 0.98 and 0.50 million bbl/​d in 2013 and 2014, respectively. The second reason is the sanctions imposed by the United States on Iran relating to the Iranian nuclear programme, which removed Iranian production –​another 0.5 to 1 million bbl/​d. Third, the “Arab Spring” and the subsequent political unrest in the Middle East and North Africa region removed small amounts of oil from the market with the loss of Yemen and then Syria, but the events scared the futures markets, as fears that the major oil exporters of the Gulf Cooperation Council would follow the path of Tunisia, Egypt and Libya in some sort of contagion effect (Stevens 2010a). These supply interruptions together withdrew 1.5 to 3.5 million bbl/​d from the market, as shown in Figure 7.5. Similarly, the price drop since the second half of 2014 also reflects several factors impacting the demand for and supply of oil on world markets. Although the resumption of Libyan oil exports may have served as the immediate trigger for the price plunge, the seeds had been sown years earlier. From the demand side, although the slowdown of the economic growth rate in China and other emerging economies may have played a role, as some analysts have argued, it is important to realize the effect of so-​called “demand destruction” –​consumers switching to more efficient vehicles and appliances or to other fuels, 3.5 3 Million bb/d

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such as electricity –​in the United States and other advanced economies. In an effort to promote energy conservation and reduce the demand for imported oil, a number of laws and regulations were introduced in the United States and Europe between 2004 and 2014. The year 2005 proved to be the peak year for oil consumption in the United States and other advanced economies. For example, US consumption of motor gasoline, diesel, jet fuel and other refined products declined by more than 2 million bbl/​d, almost 12 per cent, between 2005 and 2013 (Figure 7.6), even though the country’s population increased by more than 20 million over the same period and real economic output grew by 10 per cent. It was the biggest drop in fuel demand in history, and it was mirrored around the industrialized world. From the supply side, technological advances in horizontal drilling and hydraulic fracturing led not only to a “shale gas revolution” but also to an extraordinary renaissance in oil production in the United States. US crude oil output surged from 5 million bbl/​d in 2008 to an average of more than 8.5 million bbl/​d for the first eight months of 2014 and stood above 9 million bbl/​d until April 2016 (Figure 7.7, about a half of which are tight oil). The increased output from North America was offset by a loss of production across the Middle East and Africa because of sanctions and other “interruptions” 20,000

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Figure 7.7  Monthly averages of US crude oil production, 1981–​2017 Source: Energy Information Administration.

during 2012 and 2013. So it was that, when Libya resumed oil exports in 2014, it served as a trigger for a price decline. Lastly, Saudi Arabia’s “market share” strategy further exacerbated the crisis. Senior policy-​makers in Saudi Arabia appeared to have learned the lesson from the 1985/​6 price collapse. Cutting production to keep prices artificially high would only sacrifice the market shares of Saudi Arabia and OPEC and allow shale production to continue expanding. Instead, the Saudis decided to let prices decline enough to begin curbing investment in new shale formations. On 27 November 2014 OPEC announced that it would maintain its combined production at 30  million bbl/​d. Brent, which had already fallen to $77 per barrel by the time of the OPEC meeting, dropped another quarter, to $59, over the next month as the market digested the fact that the group would not come to the rescue. OPEC was unable to reach an agreement on production quotas in subsequent meetings until November 2016. Economic analysis of oil price determination Understanding the oil price is complex, and a framework for analysis is required. Economists, when explaining any price, will inevitably use supply and demand curves. However, building from the previous material in this

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book, we can now adjust both the supply and demand curves to take account of the particular characteristics of the industry. Price determination in a competitive market In a competitive market, the intersection of demand and supply curves determines the price. In the context of the oil market, this is illustrated in Figure 7.8, where MC1, MC2, …, MC6 represent the marginal costs of different oil fields in the world.13 Imagine we rank all oil fields in the world according to their long-​run marginal costs; we would obtain a diagram like Figure  7.8. If no producers cut their output  –​that is, all producers produce as long as they can recover their marginal cost –​then the curve connecting each marginal costs is the market supply curve:  as the price increases, the quantity supplied will increase as higher-​cost fields will be called upon. Suppose the demand curve is as shown in Figure 7.8; the oil field with marginal cost MC5 is the marginal field setting the price.14 Any

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Figure 7.8  Oil price determination in competitive markets

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oil fields with a marginal cost higher than MC5 will not produce, as doing so will incur a loss. The impact of an OPEC production cut As can be seen from Figure 7.9, the OPEC countries together held 72 per cent of the world’s proven reserve as of 2016. Furthermore, the Middle Eastern countries are the low-​cost producers, as their reserves can be tapped easily and require little exploration, implying that the oil fields in the Middle East are on the left corner of the world supply curve. For example, according to EIA data, the average crude oil finding cost (i.e. the sum of the exploration and development costs) in the Middle East was $5.26 per barrel over the three-​year period from 2004 to 2006. This compares to $63.89 per barrel in the offshore sector of the United States during the same period. Now, what is the effect of a production cut by OPEC? This can be seen in Figure 7.10, Equatorial Guinea (2017) 0%

Saudi Arabia (1960) 16% Iran (1960) 9%

Venezuela (1960) 18%

Non-OPEC 28% OPEC 72%

Iraq (1960) 9%

Gabon (1975) 0% Indonesia (1962– 2009, 2016) 0% Ecuador (1973– 1992, 2007) 0%

Angola (2007) 1%

Algeria (1969) 1% Qatar (1961) 1%

Kuwait (1960) 6% UAE (1967) 6%

Nigeria (1971) 2%

Libya (1962) 3%

Figure 7.9  World proven crude oil reserve, end of 2016 Note: Numbers in parenthesis indicate the year when the country became a member of OPEC. Source: BP (2017).

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$ Demand

P*

Supply

MC6 MC5 MC4

MC1

MC2 Q*

Q

Figure 7.10  The effect of an oil production cut by OPEC

which is otherwise the same as Figure 7.8 except that MC3 (which can be considered as a production cut by OPEC) is dropped. When MC3 is dropped, other higher-​cost fields have to be called upon. The oil field represented by MC6 now becomes the marginal field and sets the price. As the cost of this new oil field (represented by MC6) is higher than the previous marginal field (MC5), the new market price will also be higher. Note that, in both Figure 7.8 and Figure 7.10, the low-​cost fields, such as those represented by MC1, MC2, MC3 and MC4, will earn an economic rent or producer surplus, which is the target of government taxation, as already discussed in Chapter  3. The marginal fields (MC5 and MC6) will earn exactly enough to cover their total cost, including the opportunity cost of capital. The dominant firm model Why would an OPEC country (or the whole of OPEC) cut production? Will the gain resulting from the rising price more than offset the loss due to the

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Oil prices and OPEC

restricted output? To answer these questions, one needs to look at the demand curves faced by the producer. However, there are so many suppliers in the world, which oil producer’s demand curve should we look at? To answer these questions, we introduce a dominant firm model of the world oil market. In this model, the whole market is supplied by two sets of firms: a dominant firm and a set of other firms called the competitive fringe. The dominant firm has lower costs and the competitive fringe firms have higher costs. In the context of the world oil market, OPEC can be thought of as the dominant firm and non-​OPEC oil-​producing countries can be thought of as the competitive fringe. Because the fringe firms have higher costs, they are price takers, and hence their supply curve is equal to their marginal cost curve. In Figure  7.11, the supply curve of the competitive fringe firms is indicated by the line MCCF. They accept current market price and produce to their capacity so long as the market price is higher than the minimum price (P0). When the price is below P0, no fringe firms will produce, because doing so would incur a loss. The demand curve for the dominant firm is called residual demand, which is derived by subtracting the quantity supplied by the fringe firms from the world demand (Dw). This is indicated by the dark line DDF in Figure 7.11. It is kinked, because, if the price is below P0, the minimum price acceptable to the competitive fringe, the supply from the fringe firms will be zero and the residual demand for the dominant firm effectively equals world demand. In the context of the world oil market, the residual demand facing the dominant firm would be equivalent to the “call on OPEC”, which is the expected world demand at various prices minus the non-​OPEC supply. The dominant firm will maximize its profit by equalizing marginal cost and marginal revenue. Mathematically, this maximization problem can be solved by finding out the equilibrium price and quantity (P* and Q*DF, respectively). At price P*, the quantity of world demand is supplied by the output from the dominant firm (Q*DF) and the output of the competitive fringe (Q*CF). The example below illustrates how this model works.15 Let world demand (QW), the marginal cost of the competitive fringe (MCCF) and the marginal cost of the dominant firm, OPEC, be as follows: QW = 200 − 2 P

(Equation 7.1)

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Dw (total demand)

MCCF (marginal costs of compeve fringe)

MCDF (marginal cost of dominant firm)

P*

P0

DDF

Q CF

Q DF

MRDF

Figure 7.11  The dominant firm model and the oil market

MCCF = 40 + 0.6QCF

(Equation 7.2)

MC DF = 20 + 0.5QDF

(Equation 7.3)

The first step is to find the demand for the dominant firm, which is the world demand minus the supply of the competitive fringe. We know that the fringe firms are price takers, so that P = MCCF . From Equation 7.2 we have QCF = 1.67 MCCF − 66.67 = 1.67 P − 66.67

(Equation 7.4)

The kink in the demand curve is where the fringe firms do not produce (i.e.QCF = 0). From Equation 7.2, we know this is when P  =  40. When the price is lower than 40, the fringe firms do not produce. For any price above 40, the demand for the dominant firm is QDF = QW − QCF

(Equation 7.5)

Using Equations 7.1 and 7.4, we can rewrite Equation 7.5, the demand curve for the dominant firm, as follows: QDF = QW − QCF = 200 − 2 P − (1.67 P − 66.67 ) 214

(Equation 7.6)

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Oil prices and OPEC

or P = 72.66 − 0.27QDF

(Equation 7.7)

Since the total revenue of the dominant firm is TRDF = PQDF = (72.66 − 0.27QDF )QDF

(Equation 7.8)

the marginal revenue must be MRDF =

∂TRDF = 72.66 − 0.54QDF ∂QDF

(Equation 7.9)

Setting marginal revenue equal to the marginal cost for the dominant firm, we solve the optimal output of QDF : 72.66 − 0.54QDF = 20 + 0.5QDF QDF = 50.63

(Equation 7.10)

Taking QDF back to Equation 7.7, we get the price P = 72.66 − 0.27QDF = 72.66 − 0.27 (50.63 ) = $58.99

(Equation 7.11)

The quantity demand in the world at price P = $58.99 is QW = 200 − 2 P = 200 − 2 (58.99 ) = 82.02

(Equation 7.12)

And the quantity supplied by the fringe firms is QCF = 1.67 P − 66.67 = 31.84

(Equation 7.13)

It can be easily verified that the following holds: QW = QDF + QCF .16 In the literature, it is arguable whether it is OPEC as a whole or Saudi Arabia that is best characterized as the dominant firm in the world oil market (Alhajji & Huettner 2000). There is also a debate as to whether maximizing profit is the only goal for OPEC when setting the production quota.17 Nonetheless, the dominant firm model provides a useful framework for us to understand the interplay of key players in world oil price determination. 215

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Demand elasticity for OPEC’s oil As noted above, the optimal output for the dominant firm (OPEC) depends on the price elasticity of demand. So, what is the demand elasticity (ηDF ) for the dominant firm in this model? Recall that the demand for the dominant firm is world demand minus the supply of the fringe: QDF = QW − QCF Taking the derivatives of QDF with respect to P, we have ∂QDF ∂QW ∂QCF = − ∂P ∂P ∂P

(Equation 7.14)

Multiplying Equation 7.14 by P / QDF , we get the dominant firm’s elasticity:

ηDF =

∂QDF ⋅ P ∂QW ⋅ P ∂QCF ⋅ P = − ∂P ⋅ QDF ∂P ⋅ QDF ∂P ⋅ QDF

(Equation 7.15)

We can rewrite Equation 7.15 as follows:

ηDF =

∂QDF ⋅ P ∂QW ⋅ P ⋅ QW ∂QCF ⋅ P ⋅ QCF = − ∂P ⋅ QDF ∂P ⋅ QDF ⋅ QW ∂P ⋅ QDF ⋅ QCF

(Equation 7.16)

∂QW ⋅ P ∂QCF ⋅ P is the world price elasticity of demand (ηW ) and ∂P ⋅ QW ∂P ⋅ QCF is the fringe price elasticity of supply (ηCF ). Equation 7.16 can be rewritten as Note that

ηDF = ηW

QW Q − ηCF CF QDF QDF

(Equation 7.17)

Equation 7.17 tells us that the price elasticity of demand for the dominant firm is the price elasticity of world demand weighted by the ratio of world demand to the dominant firm’s supply, minus the price elasticity of fringe suppliers weighted by the ratio of fringe supply to the dominant supply. Thus, the greater the elasticity (absolute value) of the world demand and the greater the total of world demand relative to OPEC supply, the greater the elasticity

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of OPEC demand. On the other hand, the larger the elasticity of the fringe supply and the quantity supplied by the fringe relative to OPEC, the smaller the elasticity of demand for OPEC’s oil. This helps explain why it is that, when the supply elasticity from US shale producers increases, the demand elasticity for OPEC’s oil becomes smaller. Is OPEC a cartel? In its statutes, OPEC states its mission as to coordinate and unify the petroleum policies of its member countries and ensure the stabilization of oil markets, in order to secure an efficient, economic and regular supply of petroleum to consumers, a steady income to producers, and a fair return on capital for those investing in the petroleum industry. Probably because of the role it has played in coordinating production policies, OPEC is frequently referred to as a cartel. However, it has never worked as an effective cartel. Like any other cartels involving multiple members, OPEC is inherently faced with two problems. The first is how to detect and deter cheating. Even if everyone had a fairly good idea of who was cheating, there was no “win-​win” mechanism to deter. Saudi Arabia, acting as the swing producer, has the ability to “punish” the cheater (the country producing more than the allocated quota) by increasing its production and flooding the market. However, doing so would hurt not only the cheater but also Saudis themselves and all other oil-​exporting countries. This is what happened in the mid-​1980s and, more recently, from late 2014 to November 2016. In the early 1980s Saudi Arabia cut its production from a peak of more than 10 million bbl/​d in 1980/​1 to fewer than 3 million bbl/​d in some months of 1985. However, this was not able to prevent the price from falling. In September 1985 Saudi Arabia abandoned its role as the swing producer and moved to netback pricing for a short period of time in 1986.18 Average Saudi production was raised to 5.2  million bbl/​d that year, and the oil price plummeted from $27.53/​bbl to $13.10/​bbl. Obviously, this “punishing strategy” hurt not only the member countries that violated their quotas but also the Saudis themselves.

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Most recently, when the oil price collapsed from more than $100/​bbl in July 2014 to less than $50/​bbl in January 2015, perhaps because they had learned from their experience in the 1980s, the Saudis insisted that the burden of cutting output had to be shared by all OPEC members, as well as Russia, the largest non-​OPEC oil-​exporting country, and pursued a “market share strategy”. They finally reached an agreement to restrict their output in November 2016. The second problem is that of information. As has been discussed in previous sections, to set the quota for their oil (“call on OPEC”), OPEC must estimate global oil demand and non-​OPEC supply. The problem is that the quality of the information (both historical data and forecast) on both global oil demand and non-​OPEC supply is poor. As more oil is both produced and consumed outside the OECD, the data gets even poorer. Faced with the problems of dividing the call on OPEC between the various members, virtually all of which invariably want more, it is always tempting to use data that overestimates the call to ease quota negotiations. Since the early 1980s economists have made numerous attempts to investigate whether OPEC has collectively acted as a cartel, using empirical data. Although some of the earlier studies (Griffin 1985; Loderer 1985) suggest that, at times, OPEC members have behaved as if they were part of a collusive cartel, studies with longer and more recent data generally find no support for such a claim (Spilimbergo 2001). For example, Alhajji and Huettner (2000) find evidence that the world oil market is best described with a dominant firm model in which Saudi Arabia rather than OPEC is the dominant firm. Although Smith (2005) argues that OPEC’s market structure lies between a non-​cooperative oligopoly and a cartel, Almoguera, Douglas and Herrera (2011) suggest that OPEC’s behaviour over the period from 1974 to 2004 is consistent with Cournot competition in the face of a competitive fringe, constituted by non-​OPEC producers. Modelling the short-​and long-​run dynamics of oil prices The two-​factor model of commodity prices Although the dominant firm model provides a useful framework for analysing the determinants of oil prices, in practice it is rarely directly used for business

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forecasting, partly because many of the explanatory variables (e.g. investment, income, technology) are difficult to forecast over a long horizon (Pindyck 1999). Furthermore, it is difficult to reconcile the seemingly extremely high volatility in short-​run oil prices with the structural models. For example, the oil price reached its all-​time high of $147/​bbl in July 2008 and then quickly plummeted to nearly $40/​bbl in December that year. It is hard to believe that the fundamental demand and supply conditions had shifted so much in a matter of several months. Another popular commodity-​pricing model is the two-​factor model, developed by Schwartz and Smith (2000). This model views commodity prices as consisting of two components: a long-​r un equilibrium (or mean) price and a short-​term deviation. Figure  7.12 illustrates the basic idea. The long-​r un equilibrium price is determined by long-​r un demand and supply factors, such as the discovery of new resources, the depletion of existing resources, technological improvements for production and consumption and political and regulatory conditions. In the short term, the price can (and does) deviate from the long-​r un equilibrium level, because of temporal demand and supply disruptions, political events, weather conditions, and so on. However, it will never completely drift away from the long-​r un equilibrium, and will eventually revert to it. Intuitively, when the price of a commodity is higher than the long-​r un equilibrium price level, the supply of this commodity will increase, and then demand will drop, thereby putting downward pressure on prices. As we have seen in

Price

Long-term price equilibrium

Time

Figure 7.12  A two-​factor commodity pricing model

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our brief review of the history of the oil price, as the oil price escalated in the 1970s and 1980s many energy-​efficient technologies were developed, while new resources were discovered and developed thanks to technology advancement, such as three-​dimensional seismic surveying, horizontal drilling and deep water completion. More recently the shale gas revolution and the booming supply of US tight oil have also been induced by the rising oil and gas prices in the period from 2000 to 2008, to say the least. Conversely, when prices are relatively low, demand will increase and supply drops, thereby lifting the price. Obviously, these types of adjustment are not instantaneous, and prices may be temporarily higher or lower than the equilibrium price level. Formally, Schwartz and Smith (2000) decompose spot prices into two stochastic factors, as follows: ln ( St ) = χt + ξt

(Equation 7.18)

where St denotes the spot price, χt is the short-​term deviation in prices and ξt is the equilibrium price level.19 The short-​term deviation, χt , is modelled using a mean-​reverting process: d χt = −κχt dt + σ χ dzχ

(Equation 7.19)

where κ measures of the speed of mean reversion (i.e. how soon the deviation will revert back to the mean) and is supposed to be less than one, σ χ is the standard deviation of χt and zχ is a standard Brownian motion process (mean zero and unit variance). In other words, although the short-​term deviations have a degree of randomness (driven by zχ), the price will not drift away from the long-​run equilibrium price. The equilibrium price level, ξt, is assumed to follow a Brownian motion process (random walk with drift): dξt = µ ξ dt + σ ξ dzξ

(Equation 7.20)

where µ ξ is the drift term (i.e. the average growth rate) and σ ξ is the standard deviation of ξ and, likewise, follows the standard Brownian motion process. The innovation terms dzξ and dzχ can be correlated. In this system, changes in short-​term deviations, as represented by Equation 7.19, are assumed to be 220

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Oil prices and OPEC

temporary and will revert to the mean over time at a speed that is determined by the parameter κ . Changes in equilibrium price levels, for example, due to structural demand and supply changes, as represented in Equation 7.20, are assumed to persist. Modelling the cyclical behaviour of oil prices As neither of the two factors (ξ and χ) is directly observable, Schwartz and Smith (2000) suggest that the model may be estimated from spot and futures prices, because, arguably, changes in long-​maturity futures would reflect changes in equilibrium prices. Alternatively, the model can be estimated probabilistically using a Kalman filter.20 In this spirit, Mu and Ye (2015) estimate an unobserved components model that captures the long-​run trend and cyclical behaviour of the oil price.21 Specifically, the model decomposes the logged real oil price (p) into a time trend (µt), two cyclical components (φt and γt) and an irregular white noise term (εt): pt = µ t + γ t + φt + δwt + ε t , ε t ~ NID(0, σ 2ε )

(Equation 7.21)

where pt is the logged real oil price, µt is the trend component, γt is a short cycle component, φt is a long cycle component, wt is a level shift dummy that takes on the value of one for the period after the first oil price shock (i.e. after 1973), and zero otherwise, and εt is the white noise component, with a normal and independent distribution of mean zero and variance σ 2ε. The model was initially estimated with annual data from 1861 to 2010. The cyclical components are represented by a mixture of sine and cosine waves:  φt   cos λ φ  *  = ρφ  − sin λ φ φt  

sin λ φ  φt −1  κ φ ,t   +  cos λ φ  φt* −1  κ φ* ,t     

(Equation 7.22)

where ρφ is a damping factor, such that | ρφ | St + Ut + It, then one can always sell the futures, buy the commodity on the spot market, store it and deliver at T. To see this more clearly, let us look at a numerical example. Suppose the spot price for crude oil is St = $100/​bbl, the storage cost is $2/​ bbl for three months and the interest rate is 2 per cent for three months. Thus, the cost of carry is St + Ut + It = $100/​bbl + $2/​bbl + 0.02 × $100/​bbl = $104/​bbl Now let us see what could happen if the three-​month futures price at time t, Ft,T, is above $104/​bbl –​say $105/​bbl. In this case, one can make a sure profit by (a) selling the futures at $105/​bbl and (b) borrowing money to buy from the spot market at $100/​bbl, storing it and delivering in three months. The cost of doing so is $104/​bbl. As more and more sell the futures and buy on the spot market, the price of futures will fall and the spot price will rise. In equilibrium, the no-​arbitrage condition means the price of futures cannot go above the cost of carry. In other words, the cost of carry (St + Ut + It) gives the upper boundary of futures price. The next question is whether the futures price can be lower than the spot price. To answer this question, we will introduce the concept of “convenience yield”. For commodity producers and consumers, holding an inventory yields a benefit, because inventories can help smooth the production process, thereby avoiding costly adjustment in the face of fluctuating demand. For example,

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when there is a supply shortage, prices are likely to be high. If you hold inventories during these periods you can sell from the inventory and benefit from the higher prices. Conversely, in periods of weak demand or supply surplus prices will be low and the benefit to inventory holders will probably be less. This benefit to inventory holders is called convenience yield. There is normally an inverse relationship between convenience yield and the level of inventory. Since the benefit accrues only to inventory holders, not those who hold only futures contracts, convenience yield will offset, at least partially, the cost of holding the inventory. Thus, in equilibrium we can subtract the convenience yield from the cost of holding the inventory and have the following equation: Ft,T = St + Ut + It − Ct

(Equation 7.24)

where Ct denotes the convenience yield. From Equation 7.24 we note that, when Ct > Ut + It, Ut + It​ – Ct < 0 and Ft,T < St. Thus, when the convenience yield more than offsets the cost of carry, futures prices will be lower than the spot price. This usually occurs when inventories are relatively low. Such a market is called backwardation. On the other hand, when Ct < Ut + It, Ut + It​ – Ct > 0 and Ft,T > St. In this case, the cost of carry is higher than the convenience yield and the futures price will be higher than the spot price. Such a market is called contango, which usually occurs when inventories are relatively high. Note that the convenience yield is a theoretical construction, but it can be estimated from data. Dahl (2014) estimates that convenience yields averaged 2 per cent of the monthly price in the United States based on data from January 1986 to June 2014. Table 7.4 shows the WTI futures prices observed at two different points of time in November:  05:55:52 on 24 November 2017 and 16:37:31 on 23 November 2018, respectively.29 As both dates are past the third business day prior to the 25th of the month, the December contract had expired and the January contract had become the front month. In November 2017 the prices of nearby futures were higher than those distant in the future (i.e. the forward curve was downward-​sloping), so the market was in backwardation. One year later the market conditions had changed and the prices of further-​out futures had become higher than those of near-​term futures (i.e. the forward curve was upward-​sloping). The market was in contango. How does the change correspond to inventory levels? Data from the EIA show that the US crude oil inventory level (excluding strategic reserves) was decreasing on a weekly basis

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Table 7.4  WTI futures prices observed at different times 05:55:52 CST 24 November 2017

16:37:31 CST 23 November 2018

Contract month

Price

Contract month

Price

Jan. 2018 Feb. 2018 Mar. 2018 Apr. 2018 May 2018 Jun. 2018 Jul. 2018 Aug. 2018 Sep. 2018 Oct. 2018 Nov. 2018 Dec. 2018 Jan. 2019

58.76 58.73 58.60 58.36 58.10 57.76 57.37 56.97 56.60 56.21 55.97 55.67 54.60

Jan. 2019 Feb. 2019 Mar. 2019 Apr. 2019 May 2019 Jun. 2019 Jul. 2019 Aug. 2019 Sep. 2019 Oct. 2019 Nov. 2019 Dec. 2019 Jan. 2020

50.39 50.54 50.75 50.88 51.02 51.09 51.15 51.20 51.29 51.38 51.52 51.58 52.00

Source: www.cmegroup.com.

in November 2017, but it was increasing in November 2018, although the absolute level of inventories in November 2017 was higher than in November 2018. It appears that it is not necessarily the levels of inventories but the change in inventories that affects the convenience yield, and hence the spread between futures and spot prices.30 Figure 7.17 plots the daily prices of the first and fourth month futures for WTI from January 2000 to December 2018. During this period the price of the fourth month futures was higher than that of the first month contract, indicating contango, 61 per cent of the time. The market was in backwardation for the remainder of the time. An alternative model of futures pricing explains futures prices in terms of expected future spot prices and a risk premium. The idea is that, if the futures market is efficient in processing information, the futures price provides the best predictor of the future spot price. A risk premium is necessary to induce speculators to take the risk of buying and holding the futures. Thus, we would have Ft,T = E(St, T) –​ RPt

240

(Equation 7.25)

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Oil prices and OPEC 160

WTI–1

140

WTI–4

120 $/bbl

100 80 60 40 20 Jan-2018

Jan-2017

Jan-2016

Jan-2015

Jan-2014

Jan-2012

Jan-2013

Jan-2011

Jan-2010

Jan-2009

Jan-2008

Jan-2007

Jan-2006

Jan-2005

Jan-2004

Jan-2003

Jan-2001

Jan-2002

Jan-2000

0

Figure 7.17  WTI one-​and four-​month futures prices, 2000–​2018 Note: WTI–​1 and WTI–​4 are the prices of the first and the fourth month futures, respectively. Source: Energy Information Administration.

where E(St) indicates the expected spot price at a future time T and RP is the risk premium. Subtracting the spot price, St, from both sides of Equation 7.25, we have the following: Ft,T –​ St = [E(St, T) –​ St] –​ RPt.

(Equation 7.26)

Equation 7.26 explains the spread between future and spot prices in terms of  the expected change in spot prices and a risk premium. In equilibrium, E(St, T) –​ St reflects the cost of carry. The risk premium can be positive or negative depending on investors’ beliefs, storage levels and preferences. Whether a market is in contango or backwardation thus depends on both the cost of carry and the risk premium.31 Notes 1. The total depth of the first well that Drake drilled was merely 69.5 feet (21 m). In contrast, the average onshore oil well in the United States today is more than 6,500 feet (2,000 m) deep. The first well drilled with percussion tools for oil exploration was in Baku in 1846. 2. Unless otherwise noted, Yergin (1991) is the source of all historical facts.

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3. These two companies later merged to become Royal Dutch Shell in 1907. 4. The “disappointment” in new discoveries in the late 1910s can be seen from the history of proven reserves which showed a modest decline between 1921 and 1924 (Energy Information Administration). 5. Notably, the 1920s also saw major technological innovations in the petroleum industry, particularly the development of geophysics and its application to petroleum exploration, development and production. 6. “Seven Sisters” was a common term for the seven multinational oil companies of the “Consortium for Iran” oligopoly or cartel, which dominated the global petroleum industry from the mid-​1940s to the mid-​1970s. The group consisted of the Anglo-​ Iranian Oil Company (now BP), Gulf Oil (later part of Chevron), Royal Dutch Shell, Standard Oil Company of California (SoCal, now Chevron), Standard Oil Company of New Jersey (Esso, later Exxon, now part of ExxonMobil), Standard Oil Company of New York (Socony, later Mobil, also now part of ExxonMobil) and Texaco (later merged into Chevron). Prior to the 1973 oil crisis the “Seven Sisters” controlled 85 per cent of the oil reserves in the world. 7. For free on board pricing, the seller is responsible for delivering the oil (or any other commodity) to the ship while the buyer is responsible for shipping, freight and insurance. 8. Unless otherwise noted, the data used in this section is from BP, “Statistical review of world energy”; available at: www.bp.com/​statisticalreview. 9. The founding members of OPEC are Venezuela, Iran, Iraq, Kuwait and Saudi Arabia. Qatar joined in 1961, Libya and Indonesia in 1962, the United Arab Emirates in 1967, Algeria in 1969 and Nigeria in 1971 (Dahl 2014). 10. Nationalization started as early as 1951, when the Iranian government nationalized the Anglo-​Iranian Oil Company. This was undermined by a boycott of Anglo-​Iranian and intervention by the Western powers, leading to the overthrow of the Iranian prime minister, Mohammad Mossadegh (Stevens 2010a). 11. A contributory factor for the increase in non-​OPEC oil supply was advances in technology, such as advances in horizontal drilling, which greatly improved the efficiency of petroleum exploration and development. 12. Tight oil is crude oil produced from petroleum-​bearing formations of low permeability that have to be hydraulically fractured to produce at commercial rates. Shale oil is a subset of tight oil. 13. These should be considered the long-​run marginal costs, which include the amortized capital cost and, of course, the operating cost. In the short run, prices can deviate from marginal costs. See the following section about the two-​factor model. 14. Here the definition of “marginal oil field” is slightly different from the concept that is often used in the oil industry. In the oil industry, marginal oil fields typically refer to mature oil fields whose remaining reserves are not economical when produced by the major oil companies but might be profitable if explored by independent entrepreneurs due to their low overheads and operating costs. Note that, from the IOCs’ point of view, these oil fields are either economically marginal or have a cost higher than the long-​run marginal cost. 15. The example follows Dahl (2014). 16. In this case, the sum of QDF and QCF is slightly off QW, because of rounding.

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17. For example, Crémer and Salehi-​Isfahani (1980) suggest that some countries may have a revenue target that is determined by their domestic economy for balancing the budget. 18. The netback price for crude oil is the value of the oil at the wellhead after transportation and refining costs have been subtracted from the value of the refined products. 19. It is common in economics and finance to take logarithms of commodity prices, because commodity prices are usually found to be log-​normally distributed. A  log-​ normal distribution has a higher probability for high prices than low prices. If a variable has a log-​normal distribution, then the logarithm of this variable has a normal distribution, which gives some very nice mathematical properties. 20. The Kalman filter is an analytical tool that uses observed data, which is usually noisy, to learn about the underlying driving force. It typically uses a recursive data-​processing algorithm. As new information arrives, it updates predictions and generates optimal estimates of the underlying variable. 21. Although long-​maturity futures exist for oil, the market is illiquid and there is little information contained in futures prices beyond one year (Alquist & Kilian 2010). 22. The idea of a “no-​change” forecast is that, if the price is unpredictable (i.e. a random walk), then the best forecast is to assume the price will not change. 23 This section draws heavily on Fattouh (2011). 24. As a result of production declines, the commonly referenced “Dated Brent” actually includes four crude streams: Brent, Forties, Oseberg and Ekofisk (BFOE). It can also be called Dated North Sea Light, North Sea Dated or Dated BFOE. 25. The “depth” of the market refers to the number of open buy and sell orders at different prices. It provides an indication of the liquidity of a market. The higher the number of buy and sell orders at each price, the greater the depth of the market. 26. A clearinghouse is an institution affiliated with a futures exchange providing clearing and settlement services. The role of the clearinghouse is to match the buys and sells that take place during the day, and to keep track of the obligations and payments required of the members of the clearing house (McDonald 2002: 134). 27. These are together called the “basis difference”. Here we assume that the basis difference is constant between June and September. 28. If one borrows money to buy a barrel of oil at St, It would be the interest cost to the borrower. Alternatively, if one uses one’s own money, It is the opportunity cost or the interest to be earned for St. 29. US Central Standard Time. 30. Also see Fattouh (2009). 31 Fama and French (1987) note that the risk premium model and the cash-​and-​carry model are alternative but not competing views of commodity prices.

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LIST OF FIGURES AND TABLES

Figures 1.1 1.2 1.3 1.4 1.5 1.6a 1.6b

World total primary energy supply by fuel (Mtoe), 1990–​2016  Share of households’ energy consumption (United States), 2015  Energy use per capita versus GDP per capita, 2013  World oil consumption by sector (Mtoe), 1973 & 2016  Comparison of unit storage costs between a big tank and a small tank  Heat content of oil and different types of coal by weight  Heat content of oil and gas by volume (at standard temperature and pressure)  1.7 World crude oil prices, 1992–​2016  1.8 Energy consumption in US transportation sector by sources, 2017  1.9 The Netherlands’ exports as a percentage of GDP, 1960–​2000  1.10 Monthly average of WTI prices ($/​bbl), January 2000–​January 2018  2.1 Exploration: finding the field  2.2 Average drilling costs per well in the United States (2000 real dollars), 1980–​2005  2.3 Production phases  2.4 Actual production profiles of the North Sea oilfields (bbl/​d), 1975–​2011  2.5 A decision tree for acquiring a lease  2.6 The relationship between initial production and recoverable reserves  2.7 The common pool problem in the oil industry  2.8 Hyperbolic decline curves  2.9 Exponential decline curves  2.10 Cost shares of US onshore oil and gas drilling and well completion  2.11 Growth in the three-​year moving average of the real oil price and drilling costs (in percentage terms), 2005–​2012  3.1 Economic rent in the petroleum industry 

3 3 4 5 7 7 8 8 9 14 16 20 21 24 26 31 39 41 44 45 46 47 62

253

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2

List of figures and tables

3.2 3.3 3.4 3.5 4.1 4.2 4.3a 4.3b 4.3c 4.4 4.5 4.6 4.7 5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8 5.9 5.10 5.11 5.12 6.1 6.2 6.3 6.4 6.5 6.6 6.7 6.8 6.9 6.10 6.11 6.12 6.13 6.14 6.15 6.16

254

The size distribution of a drilling prospect  Typical revenue distribution under the royalty/​tax system  A flowchart of a stylized production-​sharing contract  Revenue allocation under a PSC with royalties and taxes  Size of oil tankers  Baltic Exchange tanker indices, August 2002–​December 2017  Average tanker construction costs  Average tanker operating costs, daily  Average total costs, daily  Crude oil transportation cost of major routes ($/​bbl), 2010–​2017  Major seaborne oil transportation routes and transit volumes  Pipeline maximum throughput and average transportation cost assuming 100% utilization  Trans-​boundary pipelines  Simple refinery flow: primary distillation  Flow diagram of a moderately complex refinery  Fractions of products from refining different crudes  Average costs of selected refining processes  3:2:1 crack spread, 2010–​2018  Refinery location  World refining capacity by region, 1995–​2015  Distribution channels  Refiner motor gasoline sales volume in the United States, 1994–​2017  Gasoline prices in selected countries ($ per gallon), 16 April 2018  Breakdown of retail gasoline price in the United Kingdom, week commencing 12 November 2018  The welfare effect of subsidizing petroleum products  Schematic view of natural gas formation  Natural gas consumption in OECD countries, 1980–​2015  Natural gas delivered to consumers in the United States  Types of natural gas underground storage facilities  Fuel shares of world primary energy supply, 1973 & 2016  The LNG supply chain  Capital cost breakdown for a “typical” LNG project  An example of an S-​curve  World LNG imports, 2017  The share of short-​term contracts in world LNG trade, 2000–​2017  The Fischer–​Tropsch gas-​to-​liquids process  Comparison of energy balance between GTL and LNG  Natural gas prices, 1990–​2017  Change in natural gas industry structure in the United States  Natural gas hubs in North America  US natural gas production, 2007–​2017 

64 71 72 73 85 88 91 92 92 93 95 100 103 114 115 118 123 126 127 129 134 135 136 138 140 148 150 151 153 154 156 159 161 164 166 167 170 172 177 178 186

255

List of figures and tables

6.17 6.18 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 7.9 7.10 7.11 7.12 7.13 7.14 7.15

US natural gas imports and exports, 1973–​2017  US natural gas wellhead prices, 1980–​2012  History of oil prices, 1860–​2017  OPEC’s share of oil production, 1960–​2016  OPEC’s crude oil spare production capacity, 2003–​2011  Spot crude oil prices (monthly), 1987–​2017  Oil supply disruptions, 2011–​2015  Total US consumption of finished petroleum products, 1981–​2017  Monthly averages of US crude oil production, 1981–​2017  Oil price determination in competitive markets  World proven crude oil reserve, end of 2016  The effect of an oil production cut by OPEC  The dominant firm model and the oil market  A two-​factor commodity pricing model  The decomposition of the oil price trend and cycles, 1861–​2010  Differences in spot prices of WTI and Brent (WTI –​Brent), 2000–​2018  Saudi Arabian crude oil price differentials vis-​à-​vis the OPEC reference price ($/​bbl), 2000–​2018  7.16 Spot price differential between Arab Light and Iranian Light, 1990–​2017  7.17 WTI one-​and four-​month futures prices, 2000–​2018 

187 187 196 204 206 206 207 208 209 210 211 212 214 219 223 228 230 231 241

Tables 2.1 3.1 3.2 3.3 4.1 4.2 4.3 4.4 5.1 5.2 5.3 5.4 5.5 5.6 6.1

Norwegian share of North Sea oil fields, 1985 & 1995  A sliding-​scale royalty  A sample PSC cash flow projection  Take calculation with varying costs  Oil tanker size categories  Leading flags of registration oil tankers, 2017  Oil tanker costs  Volume of crude oil and petroleum products transited through world chokepoints (million barrels per day), 2011–​2016  Boiling ranges for petroleum products  Complexity factors, main processing unit  Maximum sulphur content of gasoline and diesel for selected countries, 2004–​2017  API and sulphur content of selected crudes  Process cost functions (cost in $ million = α∙capacityβ)  Gasoline and diesel end-​use prices for selected countries, July 2017  Emissions levels of gas, oil and coal (pounds per million BTU of energy input) 

42 66 75 77 84 89 90 94 113 113 117 118 122 137 149

255

256

1

List of figures and tables

6.2 6.3 6.4 6.5 6.6 7.1 7.2 7.3 7.4

256

Comparison of pipeline transportation costs between oil and gas  Comparison of product slate (GTL versus traditional refinery)  Comparison of GTL diesel versus refinery diesel  British Gas’s declining market share (%), October 1991–​January 1996  Worldwide count of rigs, 2010–​2018  Main benchmarks used in formula pricing  Key specifications of WTI crude oil futures contracts traded at NYMEX  Comparison of forwards and futures  WTI futures prices observed at different times 

155 168 169 182 191 226 235 237 240

257

INDEX

Page numbers in italics and bold denote figures and tables, respectively. additional profits tax (APT), 68 ad valorem royalty, 65 Afghanistan, 65 Aframax, 84 agglomeration, 128 alkylation, 111 Anglo-Iranian Oil Company, 242n6 Anglo-Persian Oil Company, 198 Appalachia, 197 appraisal, in exploration activities of phases, 20–1 aims of, 20 aquifer, 152 Arab Light, 227, 231, 231 Arab Spring, 207 arbitrage, 8, 17n6 Argus Sour Crude Index (ASCI), 227 aromatics, crudes in, 145n8 Asian premium, 232 As-Is Agreement, 198–9 and basing point system, 199–200 principles of, 199 Atlantic Basin, 163 atmospheric distillation unit (ADU), 110 average freight rate assessment (AFRA) system, 83–4, 106n3 Baku, 197 balance of payments, 10

Baltic Exchange, tanker indices of, 87, 88 bareboat charter, 86 bargaining power, 28–9 barges, 82 Barnett Shale, 188, 189 barrels per calendar day (b/cd), 145n6 basin, definition of, 27 basing point system, 199–200 BG Storage Ltd, 182 bid week, 178 bilateral monopoly (BIM), 173 blowout accidents, 52n2 boiler fuel, in industry, 6 bonus pre-discovery signature bonus, 64–5 production bonus, 66 Brazil, 61 Brent pipeline, 102 Brent price, 205 British Gas (BG), 153, 181 British Petroleum, 197, 198 British thermal units (BTU), 148 Brownian motion process, 220 call option contracts, 233 Calouste Gulbenkian, 198 capacity release programmes, 176 cash-and-carry model, 238–41 catalysts, costs of, 119

257

258

2

Index

catalytic cracking, 111 catalytic reforming, 111 Centrica, 182 cetane number, 112, 194n9 chartering, tankers, 85–9 agreements, 86 rates, 86–8 and slack capacity, 87 chemical enhanced oil recovery, 24 chemical tankers, 83 China, 174 Christmas tree valves, 22, 35, 52n3 clean tankers, 87, 88, 106n2 clearinghouses, 236, 243n25 coalbed methane, 147 Colombia, 16 combined-cycle gas turbines (CCGTs), 150 combined heat and power (CHP) plants, 151 commercial risk, in petroleum exploration, 29 commodity exchange, 234 commodity prices, 219 fluctuations, 15 two-factor model, 218–21, 219 common pool problem, 40–2, 41 Compagnie française des pétroles (CFP), 198 company-operated outlets, 132 compressed natural gas (CNG), 151 concession agreements, 56, 57–8, 60–1 conflict resolution, and trans-boundary pipelines, 104 constrained fuel, gas as, 152–5 consumer surplus, 141, 146n19 contractor take, 70–1, 73, 74, 77–78 contract risk, in petroleum exploration, 27–9 convenience yield, 238, 239 conversion efficiency, 150, 193n2 Cooperation Council for the Arab States of the Gulf, 207 corporate income tax (CIT), 67–8, 73, 74 and bonus payments, 65 for natural gas, 69 cost of carry model see cash-and-carry model

258

cost of service regulation, 102, 107n18 cost petroleum, 59 cost recovery limit, 59, 68–9, 71, 72–3, 76–8 cracking unit, 109, 110 crack spread, and refinery profitability, 124–7 cross-border pipelines see trans-boundary pipelines crude oil density of, 116 export, 128–9 mixed base, 116 naphthene base, 116 netback price for, 243n18 OPEC’s spare production capacity, 206 paraffin-base, 116 physical trading of, 224 quality and product standard, 114–18 refining see refinery costs; refining process reserve, world proven, 211 sulphur content, 116–17, 117, 118, 145n10 tankers, 83, 92, 93 crypto fees, 66–7 cut point, 110, 145n2 cyclical behaviour modelling of oil prices, 221–3 Dated Brent/BFOE, 225, 243n23 Dated North Sea Light, 243n23 deadweight loss, 141, 146n20 dealer-operated outlets, 132–3 decision tree analysis, for exploration, 30–2, 31 advantage and disadvantage of, 33–4 backward induction, 32–3 and probabilistic assessment of possible outcomes, 35 decline curve analysis, of production exponential curves, 44, 45–6 harmonic curves, 44 hyperbolic curves, 44, 46 delayed coking, 111 delivered ex ship (DES) contracts, 162

259

Index

demand derived demand, 130–1, 146n16 elastic demand, 132 inelastic demand, 17n7 deregulation process, 175–6, 181 desulphurization, 117, 145n10 development plan, 35–8 development wells, 35 Devon Energy, 193 dirty tankers, 87, 88, 106n2 discovery probability, 34 dissolved gas drive, 22 distribution channels, 131, 134 company-operated outlets, 132 dealer-operated outlets, 132–3 hypermarkets, 133–4 wholesalers, 133 dominant firm model, 212–17, 214 DOT-111 car, 81 downstream petroleum products, tax regime for, 69 Drake, Edwin, 195 drilling, 21–2 horizontal drilling, 37, 188 precautionary measures, 22 driving mechanisms, in oil and gas recovery, 22–3 gas cap drive, 22–3 water drive, 23 Dutch Disease, meaning of, 13 Dynegy, 182 East Texas Oil Field, 198 economic rent, 61, 62, 62 Ecuador, 61 electric power sector, 149 emissions levels of gas, oil and coal, 149 energy derivatives, 232 cash-and-carry model for futures prices, 238–41 energy futures, 234–7 energy-saving technologies, 203 energy use of oil and gas, 2 in business, 4–6 in industry, 6 in residence, 2–3 in transportation, 6

enhanced oil recovery (EOR), 23, 24 equity oil, 72, 73 equivalence to the buyer principle, 231–2 Europe, 125 exercise, and options contracts, 233 expected monetary value (EMV) approach, 29–30 exploration costs of, 21–2 drilling, 21–2 horizontal drilling, 37, 188 licence, 56 reservoirs, 19 risks see exploration risks surveys required for, 19–20 three-dimensional seismic surveying, 37 wells, 21 wildcat wells, 21, 25, 34 exploration and development productionsharing agreements (EDPSAs) see production-sharing contracts (PSCs) exploration and production (E&P) contract see upstream licensing arrangements exploration production-sharing agreements (EPSAs) see productionsharing contracts (PSCs) exploration risks, 21 commercial risk, 29 contract risk, 27–9 decision tree analysis, 30–4, 31 expected monetary value (EMV) approach, 29–30 probabilities approach, 34 prospect risk, 25–7 simulation analysis, 34–5 Exxon Mobil, 65, 198 Federal Energy Regulatory Commission (FERC), 102, 175 financial institutions, involvement in natural gas market, 185 fiscal instruments, 64 post-discovery royalties, 65–6 production-based instruments, 66–7 profit-based instruments, 67–9

259

260

2

Index

fiscal systems economic basis of, 61–4 financial modelling of royalty/ tax system and PSCs, 70–8 fiscal instruments see fiscal instruments neutral, 62 progressive, 62 and prospectivity of projects, 62–3 regressive, 62, 66 and size distribution of drilling prospect, 64 and success ratios of exploration efforts, 63–4 Fischer–Tropsch (F-T) process, 167 fixed operational and maintenance (fixed O&M) costs, in refineries, 119–20 flags of convenience, 88–9 flexible market scale, 84, 85 Flotta pipeline, 102 foreign direct investment (FDI), 28, 61–2 formula pricing, 224–30, 226 Forties pipeline, 102 forward contracts, 232–3 fracking, 47, 186, 194n18 free on board (FOB) prices, 199 frontier exploration wells, risks, 25–7 fuel price regulation, 139 to control inflation and avoid volatility, 139 and lack of competition, 139 redistribute revenue, 139; see also subsidies fuel shares of world primary energy supply, 154 fuel taxation, 134–8 futures (contracts), 233 Gas Acts, UK, 181 gas cap drive, 22–3 gas flaring, 53n13 gas-on-gas (GOG) competition, 172, 179 gas pipelines, 81, 98, 100–1; see also pipelines gas to liquids (GTL), 166 commercial plants, 169–71 energy balance with liquefied natural gas (LNG), 170

260

technical background, 167–9 geological change, and commercial risk, 29 geological surveys, 19 geophysical surveys, 19–20 geopolitics, and Suez Canal, 97 government selling price (GSP), 201 government take, 71, 77–78 Great Depression, 197, 198 Groningen gas field, 13 Gulf of Mexico, 200 Gulf Plus basing point system, 199 Henry Hub, 161, 176, 180, 185 horizontal drilling, 37, 188 Hoteling model, production allocation, 50–2 Hussein, Saddam, 16 hydraulic fracturing, 47, 186, 188, 190, 194n8 hydrocracking, 111 hydrotreating, 111, 117 hypermarkets, 133–4 Indonesia oil discoveries in, 197 terms for profit gas in, 69 injection wells, 23 institutional control, 42 Intercontinental Exchange (ICE), 1 weighted Brent futures price (BWAVE), 225 international arbitration, for transboundary pipeline conflicts, 104 International Energy Agency, 193n1 International Gas Union (IGU), 172 international oil transport, 93–4, 94 Panama Canal, 97–8 Strait of Hormuz, 94–5, 107n12 Strait of Malacca, 95–6 Suez Canal, 96–7 inventory costs, in refinery, 119 investment costs and capacity for refinery, 121–4, 122 labour cost, 120 and location, 120, 127 off-site facilities, 120–1 and profit see refinery profitability

261

Index

investment decision, factors of, 36 Iranian Light, 231 Iranian Revolution, 202 oil prices in the aftermath of, 203 Iran–Iraq war, 202 Iraq, 61, 202 isobutane, 145n4 isomerization, 111 Japan, 171 jobber, 133 Kalman filter, 221, 243n20 Kaufman, Gerald, 16 kerosene, 196, 197 Kuwait oil production in, 202 resource curse, 16 land and mineral rights ownership, 189–90 law of one price (LOOP), 8, 194n12 Liberian National Oil Company, 65 Libya civil war, 206–7 licensing exploration licence, 56 production licence, 56 upstream licensing see upstream licensing arrangements lifting cost, 53n15 line packing, pipelines, 100, 101 liquefaction, 157 liquefied natural gas (LNG), 151, 155 carriers, 156 contracts and pricing, 158–63 energy balance with gas to liquids (GTL), 170 evolution of LNG markets, 163–6 history of, 157 imports, 164 measurement and density, 158 supply chain and cost structure, 156–8 tankers, 83 London Tanker Brokers’ Panel (LTBP), 89, 106n3 long-run equilibrium price, 219

maintenance margin, 236 Malaysia, 63 marginal oil field, 242n14 margin requirement, 234–6 market conditions, and commercial risk, 29 market depth, 243n24 market hubs, 176 marketing and distribution derived demand, 130–1 distribution channels, 131–4 fuel price regulation, 139 fuel taxation, 134–8 subsidy, 139–45 market liberalization, 182 market share strategy, 209, 218, 231 market structure of oil industry, 190 Marlow, Tony, 16 maximum efficient rate (MER), 39, 52n10 methane, 147 Mexico, 61 Middle East, 211 midstream liquefaction plant, 157 miscible gas flooding, 24 Mitchell Energy, 188, 189, 190, 192–3 Myanmar–China pipeline, 96 National Balancing Point (NBP), 160, 164, 182, 185, 193n7 National Grid, 182–3 nationalization, of oil, 201 national oil company (NOC) and production-sharing contracts, 58, 59 and risk service contracts, 60 natural gas associated, 147 basics, 147–9 constrained fuel, gas as, 152–5 consumption, in OECD countries, 150 conventional, 147 demand, 149–52 fiscal terms for, 69–70 formation, 148 gas to liquids see gas to liquids (GTL) general flow equation of, 99

261

262

2

Index

natural gas (cont.) liquefied natural gas see liquefied natural gas (LNG) market see natural gas market, functioning pipelines, 100, 101 pricing in Europe, 179–80 shale gas see shale gas spot market development in the United Kingdom, 181–3 transportation problem, 152 unconventional, 147 underground storage facilities, 153 in the United States, 177, 186–7 natural gas liquids (NGLs), 147 natural gas market, functioning, 183 competitive number of market participants, 185 financial institutions, involvement of, 185 government approach, 183–4 networks, 184–5 transport and commercial activities, separation of, 184 wholesale price deregulation, 184 Natural Gas Pipeline Company of America (NGPL), 192 Natural Gas Policy Act (NGPA), 175 natural gas pricing, 171–2, 172 bilateral monopoly (BIM), 173 deregulation process, 175–6 gas-on-gas (GOG) competition, 172 increase in the 2000s, 189 netback from final product/competing fuels (NET), 173 no price (NP), 173 oil price escalation (OPE), 173 regulation: below cost (RBC), 173 regulation: cost of service (RCS), 173 regulation: social and political (RSP), 173 through trading, 176–9 Natural Gas Wellhead Decontrol Act (NGWDA), 175 natural monopoly, pipelines as, 101–2 Nelson complexity index (NCI), 111–14 Neopanamax (or New Panamax), 84, 98

262

netback from final product or competing fuels (NET), 173 netback pricing, 174, 243n18 Netherlands, the, 13 net present values (NPVs), 29, 52n5 Network Code, 182 networks, in natural gas market, 184–5 neutral fiscal system, 62 New York Mercantile Exchange (NYMEX), 1, 17n3, 126 Nigeria, 66–7 Ninian pipeline, 102 Nobel brothers, 197 no-change forecasts, 222, 243n22 non-energy use of oil and gas, 2 non-oil industrial commodities prices, in 1970s, 202 non-specific asset, 159 no price (NP), 173 North America, natural gas hubs in, 178 North Sea pipeline systems in, 102 rule of capture, 41–2 North Sea Dated, 243n23 Norway ring-fencing of tax in, 67, 79n11 wildcat wells in, 26 obsolescing bargaining model, 28–9 octane, 112 official selling price (OSP), 201 oil convenience in use, 9 energy density, 7–8 exporters, resource curse see resource curse fluidity, 6, 7–8 importers, impact of oil price shocks, 10–12 indexation, 179 transportation and storage of, 7–8 oil demand, 203 during the 1960s, 201 after First World War, 197 destruction, 207 residual demand, 213 during Second World War, 198, 200

263

Index

oil-indexed gas supply, 179 oil originally in place (OOIP), 23, 38, 52n8 oil price determination, 209 in competitive market, 210–11 in competitive markets, 210 dominant firm model, 212–17 OPEC as a cartel, 217–18 OPEC production cut, impact of, 211–12, 212 oil price escalation (OPE), 173 oil prices during 1860–2017, 196 from 1861 up to the Second World War, 195–8 after 1980s, 202–9 As-Is Agreement, 198–9 basing point system, 199–200 indexation, formula for, 160 modelling the cyclical behaviour of, 221–3 in physical markets, 224–32 postwar to 1970s, 200–2 two-factor model of commodity prices, 218–21 oil price shocks, and economies of oil importers demand shift, 11 demand side channel, 10–11 macroeconomic indicators, 11–12 supply side channel, 11 oil recovery see recovery methods oil supply disruptions, 207 oil transportation, 81 chokepoints, 93–8, 94 major routes and transit volumes, 95 pipelines, 100–1 see also pipelines; tankers on-system market, 182 option premium, 233 options (contracts), 233 Organization of Arab Oil Producing Countries, 201 Organization of Petroleum Exporting Countries (OPEC), 195, 201, 202–3, 213, 215 after the 1980s, 202–9 as a cartel, 217–18

crude oil spare production capacity, 206 demand elasticity for oil of, 216–17 founding members of, 242n9 postwar to the 1970s, 201–2 production cut by, 211–12, 212 over-the-counter (OTC) transactions, 178 Pacific Basin, 163, 165 Panama Canal, 84, 93, 97–8 Panamax, 84 Persian Gulf, 200 petroleum definition of, 2 exploration see exploration policy, 55, 61 refining process see refining process reservoirs see reservoirs significance of, 1–6 physical markets, pricing mechanisms in benchmarks in formula pricing, 224–30 price formulae in physical trading, 224 setting the price differential, 230–2 Pindyck’s theory, 222 pipelines, 81 capacity of, 98 cost of, 98, 99, 100 diameter of, 98, 99 economic characteristics, 98–100 general flow equation of natural gas, 99 leakage, 101 as natural monopoly, 101–2 oil versus gas, 100–1 operating pressure of, 99, 100–1 safety hazard of, 101 and supply disruption, 101 throughput of, 98–9, 100 trans-boundary pipeline issues, 102–5 transportation costs, 155 play, definition of, 27 post-discovery royalties, 65–6 power-generating technologies, 149 pre-discovery payments, 65 pre-discovery signature bonus, 64–5 premium fuel, 153 present value (PV), 52n5 price-reporting agencies (PRAs), 224, 227 prices, of oil see oil prices

263

264

2

Index

primary energy, 17n4 process heating, in industry, 6 production, 43 allocation over time, 49–52, 52n11 cost structure of see production costs decline rate, 43–6 licence, 56 production-based fiscal instruments, 66–7 production bonus, 66 production costs, 46 change with technology and market conditions, 47–8 and depletion, 52 development cost, 46–8 direct production cost, 46 exploration cost, 46–8 fixed costs, 48–9, 53n18 impact of technology on, 52 and locations, 48 variable costs, 48–9 production-sharing contracts (PSCs), 57, 58–60, 61, 69 cash flow model, 73–4, 75–6, 77 financial modelling of, 71–8 for natural gas, 69 with royalties and taxes, 70, 72–3, 73 stylized, flowchart of, 72 with varying costs and profits, 76–8, 77 product tankers, 83 profitability see refinery profitability profit-based fiscal instruments, 67–9 profit petroleum, 59, 68–9, 71–2, 73, 74, 77–8 cumulative production from a project, 69 daily production-based, 69 rate of return, 69 R-factor, 69 profit sharing agreements, 28 progressive fiscal system, 62 proppant, 47, 53n17 prorationing, 42, 52–3n11 prospect, definition of, 27 prospectivity of projects, 62–3 prospect risk, in petroleum exploration, 26–7 put option contacts, 233

264

Qatar, LNG export by, 164–5 railways, 81 rate of return regulation see cost of service regulation rate sensitivity, 38–40 real prices, 146n17 recovery methods driving mechanisms, in oil recovery, 22–3 phases, 22–6, 24 precautionary measures, 22 primary recovery, 22–3, 26 production decline phase, 23–4, 26 secondary recovery, 23, 26 tertiary recovery, 23, 26 time profile of reservoirs, 26 Red Line Agreement, 198 refinery costs, 118, 118–19 capital costs, 120–4 fixed operational and maintenance (fixed O&M) costs, 119–20 inventory costs, 119 and profit see refinery profitability variable operational and maintenance (VOM) costs, 119 refinery location, 120, 127, 127–8, 129 agglomeration, 128 economic considerations, 128–9 and industrialization, 129–30 security considerations, 129 refinery profitability and crack spread, 124–7 and refinery margin, 145n15 refining process alkylation, 109, 111 atmospheric distillation unit (ADU), 110 catalytic reforming, 111 chemical and physical processes, 109, 145n1 complexity level, 111–14, 115 conversion, 109 costs see refinery costs cracking unit, 109, 110 delayed coking, 111 distillation, 109 flow diagram, 114, 115

265

Index

hydrotreating, 111, 117 isomerization, 111 secondary processing units, 109–10 separation, 109 treatment, 109 vacuum distillation unit (VDU), 110 regressive fiscal system, 62, 66 regulation: below cost (RBC), 173 regulation: cost of service (RCS), 173 regulation: social and political (RSP), 173 reserves, 36 classification of, 36, 38 recoverable reserves, 38–40 technically recoverable reserves, 38 reservoirs, 19 depletion, 152 recoverable reserve and the number of wells drilled, 39, 39–40 rule of capture, 40–2 time profile of, 26 resource curse, 12–13 domestic and international conflicts, 15–16 Dutch Disease, 13 origin and meaning of, 13 revenue volatility, 15 weak institutions and windfall revenues, 14–15 resource rent tax (RRT) see additional profits tax (APT) ring-fencing provisions, and tax calculation, 67 risks, in exploration see exploration risks risk service contracts (RSCs), 57, 60, 61 Rothschilds, 197 Royal Dutch Shell, 197, 198, 242n3 royalties advantages of, 65–6 drawbacks of, 66 financial modelling of, 69–70, 71 for natural gas, 69 post-discovery, 65–6 production-sharing contracts with, 72–3, 73, 76–8 rate, 65 sliding-scale, 65, 66 rule of capture, 40–2, 41

salt caverns, 152 SASOL, 168 Saudi Arabia market share strategy, 209 oil production in, 202, 203 as the swing producer, 205 secondary energy, 17n4 seismic surveys, 19–20 service fee, 60 Seven Sisters, 199, 242n6 shale gas, 147, 186–8 dynamic and competitive service industry, 190 land and mineral rights ownership, 189–90 market structure of oil industry, 190 Mitchell Energy and shale gas development, 192–3 natural gas prices increase in the 2000s, 189 pipeline infrastructure, 190–1 water availability, 190 shale gas revolution, 171, 189, 192, 193n6, 208 shale oil, 242n12 short-term deviation, 219, 220 signature bonuses, 63, 64–5 simulation analysis, 34–5 Sinai Peninsula, Israeli occupation of, 97 Six-Day War, 97 sliding-scale royalty, 65, 66 space heating, in residence, 3 specific asset, 159 spot crude oil prices, 206 spot market, 179 in the United Kingdom, 181–3 Standard Oil, 196 Standard Oil of New Jersey, 198 Standard Oil of New York, 198 Standard Oil of Ohio (Amoco), 198 Standard Oil Trust, 102 Stanley, North Dakota, Dutch disease, 13–14 straight line depreciation method, 91 Strait of Hormuz, 94–5, 107n12 Strait of Malacca, 94, 95–6 strike price, 233

265

266

2

Index

subsea completion, 37 subsidies, 139, 146n22 cost of, 141, 146n23 measurement of, 143–4 removal of, 142, 144–5 welfare effect of, 140, 141 Suez Canal, 84, 93, 96–7 Suezmax, 84, 85 Sumed pipeline, 97 syngas, 167 take-or-pay clause, 162–3, 165 tankers, 81–3 chartering, 85–9 chokepoints see international oil transport construction costs, 89, 91, 91 costs, 89, 90, 91 crude oil transportation cost, 92, 93 economies of scale, 89, 91–3 flags of convenience, 88–9, 89 history of, 82 operating costs, 91, 92 size, and port size/routes, 93 size-based classification, 83–5, 84, 85 total costs, 91, 92 usage-based classification, 83 see also oil transportation Tanker War, 106n12 tax additional profits tax (APT), 68 and concession agreements, 57, 58 corporate income tax (CIT), 65, 67–8, 69, 73, 74 for downstream petroleum products, 69 fuel taxation, 134–8 for natural gas, 69 neutral, 62 in Norway, 67, 79n11 production-sharing contracts (PSCs) with, 59–60, 70, 72–3, 73 progressive, 79n10 regressive, 79n10 ring-fencing provisions, 67 risk service contracts, 60 systems, financial modelling of, 69–70, 71 in Trinidad and Tobago, 69 in United Kingdom, 63, 67 266

see also fiscal instruments tax and royalty agreement, 57; see also concession agreements Texas Railroad Commission, 42, 198 thermal cracking, 111 thermal enhanced oil recovery, 24 three-dimensional seismic surveying, 37 tight gas, 147 tight oil, 242n12 time charter, 86 time-series model of the global oil market, 222 total primary energy supply (TPES), 2 trading, natural gas price formation through, 176–9 trans-boundary pipelines, 102–3, 103 agreement on, 103–4 asset specificity of, 103 competition for gas market/gas resources, 104 conflict of interest, 104 and conflict resolution, 104 increase in, 103 opportunity cost, 106 security of supply and demand concerns, 104 transit fees, 105–6 transit pipeline, 102–3, 105 Transco, 182 transmission system operator (TSO), 185 transportation, petroleum, 81–2 cost, and computation of royalties, 70 pipelines see pipelines tankers see tankers trap, definition of, 27 trend-cycle models, 222 Trinidad and Tobago, 69 trucks, 82 Turkish Petroleum Company, 198 two-factor model, 218–21, 219 two-period production allocation model, 49–50 ultra-large crude carriers (ULCCs), 84 ultra-low-sulphur diesel (ULSD), 168 United Kingdom breakdown of retail gasoline price in, 138 corporate income tax in, 67

267

Index

development of a spot market in, 181–3 oil industry in, 196 ring-fencing of tax in, 67 tax profits in, 63 view on Iraqi invasion of Kuwait, 16 work programme commitment in, 63 United Nations Conference on Trade and Development (UNCTAD), 88 United States natural gas, 177, 186–7 oil industry in, 196, 197 onshore wells, 53n16 rule of capture, 40–1 shale gas revolution, 165, 171 unitization, 42 unit royalty, 65 upstream licensing arrangements, 56–7 concession agreements, 57–8, 60–1 production-sharing contracts (PSCs), 58–60, 61 risk service contracts (RSCs), 60, 61 vacuum distillation unit (VDU), 110 variable operational and maintenance (VOM) costs, in refineries, 119

very large crude carriers (VLCCs), 84–5, 93, 97 visbreaking, 145n11 volumetric measures, 147 voyage charter, 86 water drive, 23 West African Gas Pipeline, 103, 104 wholesale price, 194n14 wholesale price deregulation, in natural gas market, 184 wholesalers, 133 wildcat wells, 26, 52n1 discovery probability, 34 in exploration, 21 success rates, 26 windfall profit, 68 work programme commitment, 63 world oil consumption, 203 Worldscale, 86, 87 WTI/Brent price differential, 227 WTI crude oil futures contracts traded at NYMEX, 235 Yom Kippur War, 97, 201

267

268

1