Oil and Gas Exploration and Production.pdf

Nadine BRET-ROUZAUT and Jean-Pierre FAVENNEC

Oil and Gas Exploration and Production Reserves, costs, contracts Third edition revised and updated

With contributions by

D. Babusiaux (IFP Energies nouvelles) • S. Barreau (IFP Energies nouvelles) P.R. Bauquis (Total) • N. Bret-Rouzaut (IFP Energies nouvelles) • A. Chétrit (Total) P. Copinschi (IFP Energies nouvelles) • J.P. Favennec (IFP Energies nouvelles) R. Festor (Total) • E. Feuillet-Midrier (IFP Energies nouvelles) • M. Grossin (Total) D. Guirauden (Beicip) • V. Lepez (Total) • P. Sigonney (Total) • M. Valette (Total) The first edition of this book has been selected for inclusion in Choice’s annual Outstanding Academic titles list. It has been rewarded for its excellence in scholarship and presentation, the significance of its contribution to the field, and its value as important treatment of the subject.

Translated by Bowne Global Solutions Mr Jonathan PEARSE

2011

Editions TECHNIP

25 rue Ginoux, 75015 PARIS, FRANCE

FROM THE SAME PUBLISHER • The Geopolitics of Energy J.P. FAVENNEC • The Oil & Gas Engineering Guide H. BARON • Project Management Guide M. DUCROS, G. FERNET • Petroleum Refining. Vol. 5: Refinery Operation and Management J.P. FAVENNEC • Petroleum Economics J. MASSERON • Manual of Process Economic Evaluation A. CHAUVEL, G. FOURNIER, C. RAIMBAULT

Translation of Recherche et production du pétrole et du gaz. Réserves, coûts, contrats / 2e édition N. BRET-ROUZAUT, J.P. FAVENNEC © 2011, Éditions Technip, Paris for the second edition

All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopy, recording, or any information storage and retrieval system, without the prior written permission of the publisher.

© Editions Technip, Paris, 2011. ISBN 978-2-7108-0975-3

Printed in France

Foreword to the third edition

We first had the idea for this book in early 1999, when we considered writing about all the economic considerations associated with hydrocarbon exploration and production. It was then that we laid out its aims and devised the plan. The idea was consistent with one of the missions of the IFP School’s Centre for Economics and Management: to convey information about all aspects of the hydrocarbon economy. Thanks to encouragement from IFP Énergies nouvelles and friends in the sector, the project started to take shape and finally got under way. This book sets out to tackle all aspects of hydrocarbon research and production concisely, but also exhaustively. It does so by describing this activity – an activity that is often seen as somewhat mysterious – by looking at all the major themes involved. The first chapter contextualises the role played by oil in a world which is dependent on it, and which shall continue to be dependent on it for a number of years to come. It looks back over the history of this raw material, investigates the changes in its price over the years and the changes in the way in which the whole oil industry has been structured. The second chapter adopts a more technical approach and describes the expertise and technologies that are used both in the search for hydrocarbons and in their production. The third chapter looks at the concept of reserves and discusses it, along with the various classifications and modes of assessment involved. The fourth chapter puts forward a detailed analysis of the investments and costs involved in this highly capital-intensive industry. The fifth chapter deals with the legal, contractual and fiscal considerations which govern the ways in which income is shared among the various stakeholders involved. The sixth chapter looks at the economic criteria which are used when investment decisions are made in this sector. The seventh chapter looks at specific accounting features and other useful indicators that are used for analysing competition. The eighth and last chapter investigates problems to do with safety, the environment and ethics – problems which are fundamental nowadays. If this book succeeds in providing readers with a better overview of this industry of which Colonel Drake was the pioneer, then we will have succeeded in our aim. We would like to extend our warmest thanks to all the people who were involved in the first edition of this book. For the update, in addition to all those involved in the first edition (including Denis Guirauden who has been ever present by our side), we called upon a number of specialists who were tasked with looking out for errors and putting forward recommendations for changes and improvements. Among them are Alain Auriault, Antoine Couturier, Alain Doat, Jean-Luc Mari and Alain Mascle.

VII

Foreword

Finally, we would like to thank Total, Shell and BP who were kind enough to provide us with the photographs without which such a book would not have been possible. Nadine Bret-Rouzaut Director of the Centre for Economics and Management IFP School Jean-Pierre Favennec Consultant Professor IFP School September 2011

VIII

Preface to the first edition

It has been a long time since a reference book on the exploration and production of oil and gas was last published. This book therefore meets a genuine need: to explain to a wellinformed readership (teachers, students, researchers, journalists, engineers, industrial and political decision-makers) the key activities of this sector so vital to the world economy both now and in the future. It also provides essential information for the public at large on the relationships between energy and the environment, which involve many complex issues and stir public debate. This book stresses the economic aspect of petroleum activities and provides a solid understanding of the technical and contractual issues which underpin relations between the petroleum industry and the producing countries, a wise choice since the economics of the sector cannot be understood without a solid grounding in the technical, legal and political aspects. I should like to pay tribute to the IFP and the IFP School for having taken the initiative to compile this book, particularly valuable because of two features: it brought together, at both conception and realisation stages, authors from both the IFP and the Total group, thereby linking the visions of a large research institute and a commercial petroleum group, and it features authors of varied backgrounds and ages, including young engineers as well as recognised academic and industrial experts. The book therefore sets a fine example in our rapidly changing world, and should be instrumental in attracting new talents to a sector which will remain exciting and vital for at least the next 50 years and probably longer. I hope this book is rewarded with the success it deserves.

Thierry Desmarest Chairman Total

V

Table of contents

Preface to the first edition

...................................................................

Foreword to the third edition

1

...............................................................

Petroleum: a strategic product

V VII

...................................................

1

1.1 Uses, importance, future . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1.1 Uses of petroleum through the centuries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1.2 The importance of oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1 1 4

1.2 Historical background 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.1 The large oil companies up until the First World War, early competition . . . . . 1.2.2 Between the wars: the role of the state . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.3 Between the wars (2): cooperation and competition between oil

5 5 14

companies. The example of the Turkish Petroleum Company

..................

17

1.2.4 After WWII: increasing oil consumption, new oil companies, creation and 1.2.5 Weakening of OPEC and fall in prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.6 The 1990s: market forces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.7 The twenty first century: sustained high prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

20 31 36 37

1.3 The oil market and the oil price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3.1 Physical parameters which affect the price of crude oil . . . . . . . . . . . . . . . . . . . . . . . . 1.3.2 Mechanisms for setting the price of crude: history . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3.3 Economic analysis of price formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

44 44 45 51

1.4 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

60

Oil and gas exploration and production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

61

2.1 How 2.1.1 2.1.2 2.1.3

61 61 63 65

development of OPEC

2

............................................................

hydrocarbons are formed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sedimentary basins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Petroleum geology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Petroleum system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

IX

Table of contents

3

2.2 Exploration for hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.1 Prospecting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.2 Geology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.3 Geophysics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.4 Exploration drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.5 Appraisal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

65 65 67 68 71 75

2.3 Development and production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.1 Reservoir management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3.2 Reservoir simulation models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

78 78 83

2.4 Development drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.1 Directional drilling, horizontal drilling, multidrains . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.2 Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.3 Well productivity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4.4 Well interventions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

85 85 86 88 89

2.5 Processing of effluents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5.1 Separation process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5.2 Oil treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5.3 Water treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5.4 Gas treatment: sweetening and dehydration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

89 90 90 90 91

Hydrocarbon reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

93

3.1 Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1.1 Political and technico-economic constraints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1.2 Deterministic and probabilistic estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1.3 P90, P50, P10, etc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1.4 1P, 2P and 3P reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1.5 Proven, probable and possible reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1.6 Need for caution in using definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

95 95 95 97 97 98 98

3.2 Characteristics of reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.1 Conventional and non-conventional hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.2 Deep and ultra-deep offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.3 Heavy, extra-heavy oils and oil sands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.4 Oil shales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.5 Synthetic oils (Fig. 3.3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.6 Non-conventional gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.7 The polar zones . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.8 Other types of non-conventional hydrocarbons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

99 99 100 100 101 102 102 103 103

3.3 The production of reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.1 The decision to produce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.2 Production profiles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.3 Hubbert theory of decline (Fig. 3.6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.4 The impact of technical progress on the production profile . . . . . . . . . . . . . . . . . . . .

104 104 104 105 107

3.4 Optimists and pessimists . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.1 Two schools of thought . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.2 Naturalists or economists? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.3 Concluding remarks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

109 109 111 111

3.5 Geographical distribution of reserves and production . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.1 North America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.2 South America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

112 113 114

X

115 116 117 118 119

4

Investments and costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

121

4.1 Introduction

...........................................................................

121

4.2 Costs classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.1 Types of costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.2 Examples of cost breakdowns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

122 123 123

4.3 Exploration costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.1 Geophysics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.2 Exploration drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

125 125 128

4.4 Development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.1 The key stages prior to project authorisation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.2 Development drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.3 Production and transport installations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.4 Methodology for estimating development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4.5 Examples of developments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

131 131 134 137 142 146

4.5 Operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.1 Classification of operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5.2 Controlling operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

156 156 157

4.6 Mastering costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.6.1 Impact of technological progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.6.2 Impact of the economic cycle and the contractual strategy on project costs .

158 159 163

4.7 The petroleum services sector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.7.1 Historical background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.7.2 Investment in exploration and production: the market for petroleum services

167 167 167

5

Legal, fiscal and contractual framework . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

171

5.1 The key issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1.1 Ownership of hydrocarbons and the sovereignty of the State over natural

171

resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forms in which exploration and production can be undertaken . . . . . . . . . . . . . . . Regulatory options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . The content of petroleum legislation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . The objectives of the parties involved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reconciling objectives and sharing the economic rent . . . . . . . . . . . . . . . . . . . . . . . . . Types of contract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Breakdown of petroleum contracts by type . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

171 174 175 175 177 178 178 178

5.2 Main provisions of a petroleum exploration and production contract . . . . . . . 5.2.1 General structure of a contract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2.2 Technical, operational and administrative provisions . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2.3 Economic, fiscal, financial and commercial provisions . . . . . . . . . . . . . . . . . . . . . . . . . 5.2.4 Legal provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.2.5 Gas clause . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

178 178 182 188 191 192

5.1.2 5.1.3 5.1.4 5.1.5 5.1.6 5.1.7 5.1.8

XI

Table of contents

Europe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Africa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Middle East . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Former USSR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asia–Oceania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3.5.3 3.5.4 3.5.5 3.5.6 3.5.7

Table of contents

5.3 Concession regimes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.1 General framework . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3.2 The main features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

193 193 194

5.4 Production sharing contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.1 General framework . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4.2 The main components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

199 199 199

5.5 Other contractual forms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5.1 Service contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

202 202

5.6 Impact of the economic rent sharing on exploration and production

activities

6

5.6.1 Flexibility and investment incentives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.2 Comparison between systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6.3 Perspectives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

204 204 208 210

Decision-making on exploration and production . . . . . . . . . . . . . . . . . . . . . . . . . . . .

211

6.1 Strategic analysis and definition of the objectives of the company . . . . . . . . . . . 6.1.1 Understanding the environment in which the company is operating . . . . . . . . . . 6.1.2 Strengths and weaknesses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.3 The portfolio of activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.4 Alliances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1.5 Strategy Department: organisation and functions . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

211 211 212 212 213 213

6.2 Economic evaluation (deterministic) and short-term decision-making

.......

214

............................................................

216 217

...............................................................................

6.3 Decision-making in relation to development and the deterministic

calculation of the return

6.3.1 Discount rate and the cost of capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.2 Constructing a schedule of cash flows, operating cash flows, general remarks

..........................................................................

218

6.3.3 Evaluation criteria for investment projects: net present value (NPV) and rate of return . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equivalent cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Financing mix and the equity residual method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquiring participations, valuing a project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Another approach to calculating the return on exploration/production projects: the Arditti method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.8 A new approach: the generalized ATWACC method . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3.9 A first step in dealing with uncertainty: sensitivity analysis . . . . . . . . . . . . . . . . . . . . 6.3.10 An empirical criterion: payback period (duration of financial exposure) . . . . . .

219 221 222 223

6.4 The decision to explore: introduction to probability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.1 The “exploration” data sheet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.2 Expected value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.3 Sequential decisions and conditional values . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4.4 Limitations applying to the expected value of NPV . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

231 231 231 234 238

Information, accounting and competition analysis

........................

243

7.1 Accounting principles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.1.1 Capital and operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.1.2 Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.1.3 Depreciation and provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

245 245 248 250

6.3.4 6.3.5 6.3.6 6.3.7

7

XII

224 227 229 231

to the balance sheet

7.2.2 Indicators

.............................................................

........................................................................

Annexe to Chapter 7 Basic principles of financial accounting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7A.1 7A.2 7A.3 7A.4

The balance sheet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Profit and loss account . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash flow statement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . The consolidated accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Health, safety, the environment, ethics

254 254 258

265 266 268 271 272

........................................

277

8.1 Risk in the industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

277

8.2 Safety management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.1 The Piper Alpha accident . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.2 Reducing risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2.3 Safety management systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

278 278 278 279

8.3 Taking account of the environment

...............................................

280

8.4 The stages of environmental management: before – during – after . . . . . . . . . 8.4.1 “Before”: the preparatory phase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.2 “During”: the operating phase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4.3 “After”: the aftercare phase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

282 282 282 284

8.5 The integration of health, safety and the environment

........................

285

8.6 Oil and ethics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.6.1 Ethical issues within the oil community . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.6.2 Ethical issues involved in relations with host countries . . . . . . . . . . . . . . . . . . . . . . . . . 8.6.3 Major ethical issues: the environment and human rights . . . . . . . . . . . . . . . . . . . . . .

286 288 288 291

Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

295

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

299

Index

307

8

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XIII

Table of contents

7.2 Competition AnalysiS in the upstream petroleum sector . . . . . . . . . . . . . . . . . . . . . . . 7.2.1 Supplemental information on oil and gas producing activities appended

1

Petroleum: a strategic product

1.1 USES, IMPORTANCE, FUTURE 1.1.1

Uses of petroleum through the centuries

References to petroleum (literally oil from stone) or more precisely bitumen, asphalt or even pitch, can be found in writings going back to earliest antiquity. These texts effectively describe the heavy and viscous residue which remains when petroleum reaches the earth’s surface and loses its lighter fractions as a result of natural evaporation. This residue has many uses, in particular the caulking of ships. It is said that Moses’cradle may have been tarred to prevent it from sinking on its journey down the Nile. Over the centuries up until the dawn of the modern era petroleum was used for two other important purposes: as a medicine it was considered a panacea (see Box 1.1 and Fig. 1.1).

Figure 1.1 Oil, a universal remedy.

1

Chapter 1 Petroleum: a strategic product

Box 1.1 The balsam of the Senecas “He continued: – In those days, the sons of our warriors did not learn how to read. They did not go to school but they understood the language of the birds and of all the animals that the Great Spirit had created in the sky, the waters, the prairie and the forest. They learned without a teacher everything they needed to live. Often, in the forest or in the mountains, they came across black lakes, whose waters seemed to be poisonous. Yet, the hunters claimed that, in the evening, many animals would come to drink from these thick waters. It was as if they were attracted from afar by the smell which rose above these lakes and spread far away through the air.” “Our brothers, the Senecas, were the first to think: – Why not do like these birds and these mooses? The bears that want to live through the harsh winter without feeling the cold lick the grease from their paws; for us, if we drink these oily waters, we will gain much strength for walking, hunting, fighting and to combat the cold. The Great Spirit, who placed these waters in our path, did not do it just to tempt us.” “They drank and they found that indeed the water from the black lakes proved to be a powerful remedy against all the ailments which threaten a warrior during his lifetime. Those who drank from these waters no longer suffered headaches or stomach aches; they saw the worms which incessantly gnawed away at man’s liver and entrails leave their bodies. Those who poured it over their heads felt their hair grow longer; those who applied it to their wounds were cured more quickly than with the balsams of our medicine men. Those who rubbed it on their bodies were protected against snakebite; even the Iroquois claimed that if they mixed a little of the water from the black lakes with their tattoos, they would never again fear arrows. The Indians had repeated these wonderful tales from one side of the continent to the other. Now, they were fighting with each other over the black lakes. They dug holes in the ground where salt was plentiful, on the surface of the earth. They threw their woollen blankets in these holes. At sunset, they prayed to the Great Spirit for mercy. And often, in the morning, they would find their blankets soaked with miraculous oil. They would offer them to their friends. My father often told me that one of our ancestors had shown one of these black lakes to a paleface who came to this country, many years ago, when the Indians knew no other master than the Great Spirit, between earth and sky.” “The land of oil” Hugues Le Roux, Félix Juven Publishers, 1901.

The ailments which it was supposed to cure were numerous: scurvy, gout, toothache, rheumatism, even ingrowing toenails according to Morris and Goscinny, authors of the cartoon Lucky Luke. Petroleum is also combustible, and therefore an instrument of war: the Greeks knew it as “medical fire”, the Romans as “incendiary oil”, the Byzantines as “Greek fire”, all forerunners of modern-day napalm. But the modern development of petroleum is mainly attributable to the invention of the oil lamp (Fig. 1.2) by the physicist Argand, later improved by Quinquet, a Parisian pharmacist. This lamp provided exceptional lighting, and caught on very quickly. From our vantage point in the new millennium, these lamps, very varied in size and shape, testify vividly to the daily life of our forefathers. Originally they often used whale oil. But apart from endangering the survival of their prey, whalers were not able to meet the needs of consumers. It was replaced by paraffin, or “kerosene”, a petroleum product. However natural seepage rapidly became insufficient to meet growing demand, prompting subsurface exploration to increase production. On 27 August 1859 Colonel Drake carried out the first drilling 2

Figure 1.2 Oil lamp.

Figure 1.3 Delivery van in the 1920s (by kind permission of BP).

3

Chapter 1 Petroleum: a strategic product

at Titusville, Pennsylvania. This was successful. At a depth of 23 metres the bottom of the pit filled with precious petroleum (see Fig. 1.5, Section 1.2.1.1). The methods used to manufacture kerosene from crude oil were rudimentary. The distillation techniques practised at that time allowed the heavy fractions to be separated and used as lubricants, but part of the crude was deliberately discarded; environmental constraints were not yet what they were to become a century later! Increases in the consumption of kerosene led to a rapid growth in the demand for crude oil. By the turn of the century oil lamps were being progressively replaced by the electric light bulb, and the consumption of kerosene began to decline. But declining demand for kerosene was offset by growing demand for petrol for cars, and later diesel. This was of course the time when the automobile industry was expanding. Some time later the heavy fuel oil market became an important outlet for the refining industry. Winston Churchill, first Lord of the Admiralty 1911-1915, urged the adoption of this fuel by the British fleet whose eventual agreement made an important contribution to the development of petroleum.

1.1.2

The importance of oil

Finland

Yves Lacoste claimed that “geography is used to make wars”. We could paraphrase him by adding that so does oil. It would be possible to do without metals or certain agricultural products for a fairly long period. It would be unthinkable to do without petroleum products. Indispensable in the transport sector, petrol is of vital national importance in times of peace, but also in times of war. During the Second World War the German army tried to take control of oilfields (Fig. 1.4). The purpose of the 1941 offensive on the Eastern front was to gain control of the Russian oilfields of the Volga. Berlin later directed its forces towards the Middle East where large deposits of oil had been discovered in Saudi Arabia and Kuwait just before the onset of war. Petroleum is therefore a strategic commodity, i.e. a commodity on which not only man’s prosperity but even his survival may depend. Georges Clemenceau declared at the end of

Nor way Swed en

Chapter 1 Petroleum: a strategic product

Until the Second World War, however, the consumption of petroleum remained limited (Fig. 1.3): outside of the United States the consumption was small, and worldwide, coal was still the dominant source of energy. It was only after the war ended in 1945 that oil was to become the energy of reference. Consumption rose from 350 Mt in 1945 to over 1 Gt in 1960, over 2 Gt in 1970 and over 3 Gt in 1990. Now at the beginning of the 21st century consumption is close to 3.5 Gt/y.

USSR

Moscow Soviet counter-offensive

Stalingrad

Turkey Iran Iraq

Morocco El Alamein

Algeria Libya

Egypt

British counter-offensive

Figure 1.4 German army advances towards the Volga and the Middle East.

4

1.2 HISTORICAL BACKGROUND 1 1.2.1

The large oil companies up until the First World War, early competition

1.2.1.1 Standard oil The history of petroleum from 1859 (see Fig. 1.5) up to about 1960 is inseparable from that of the big oil companies which formed and grew rapidly in order to seek, produce, transform, transport and sell this precious liquid. The first company to become very large in the oil sector belonged to John D. Rockefeller. He initially headed up a wholesale business, one of whose products was petroleum, and built the first refinery in Pennsylvania, then a second, progressively extending his activities to cover the entire range of activities of the burgeoning petroleum industry. He acted according to a number of simple but effective principles: control the various links in the petroleum chain (storage, refining, transport, distribution infrastructure) and ensure that they operate at minimum cost. Rockefeller eschewed production, which he considered anarchical, preferring to buy in his crude, which was then available on the market at a very competitive price. On 10 January 1870, he created Standard Oil together with his brother and some friends. The name “Standard” reflected the desire to sell a product of constant and high quality. After a decade of fierce struggle with his competitors Standard Oil achieved a dominant position in the market, controlling 80% of the distribution of the principal oil products, and in particular kerosene. But the success—and size—of Standard Oil provoked defiance and hostility not only amongst its competitors but also amongst some sections of the public and the authorities. In order to defuse these attacks the company formed itself into a trust in 1882. The shares in the various operating companies in the group were presented as being no longer the property of a single company but rather as being held in trust on behalf of their owners, the shareholders of the main company. The Standard Oil Trust issued 700 000 shares, distributed 1. This section was inspired particularly by Étienne Dalemont and Jean Carrié: Histoire du pétrole. Presses Universitaires de France, 1993.

5

Chapter 1 Petroleum: a strategic product

WW1 “Petroleum is as necessary to the economy as blood to the human body”. But the examples of Japanese and Korean industrialisation show that it is control over the supply of petrol rather than its possession as such which is really the issue. Oil is likely to maintain its vital role in the future, particularly in the transport sector, where its hegemony is virtually unchallenged. Alcohols and gas (LPG, compressed natural gas and LNG) may make some inroads into the market for auto fuels, but the only serious rival is electricity. However technological and economic problems mean that it is likely to be many years or even several decades before electricity begins to make major headway in the auto fuel market. It should also be noted that, even if electricity were to become a serious contender, it would probably still be necessary to have recourse to petroleum or gas as energy source in the fuel cells. For the moment there is no prospect of replacing oil products. Meanwhile another oil product is likely to continue to grow: the fractions which are used as feedstocks for petrochemicals. The demand for petroleum is likely to go on increasing in the coming years to attain a level in excess of 4 Gt/y.

Chapter 1 Petroleum: a strategic product

*

Figure 1.5 The first oil drilling, as seen by Morris. The cartoonist was carried away by his enthusiasm here, showing oil gushing forth from a drillhole, whereas the oil actually only flowed out slowly into the bottom of the hole drilled by Colonel Drake. (From: “À l’ombre des derricks”, © Lucky Comics, by Morris and Goscinny). * and on 27 August 1859, having drilled to a depth of 23 metres, Drake discovered oil, lots of it. This was the dawn of a new era for mankind…

amongst its members; it received, in trust, the shares of all the companies in the group (14 were totally controlled and 26 partially controlled). The group continued to be run by a small team led by Rockefeller. Against a background of rapid growth in the demand for lighting, heating, lubricants and greases, Standard Oil continued to grow, maintaining its firm grip on the refining, transport, distribution and retail of petroleum. After 1880 it felt the need to increase its presence in oil production in order to guarantee its supplies of crude. This strategy of developing its production capacity proved particularly judicious when in 1888 a chemist employed by Standard Oil perfected a refining process which permitted sulphur to be removed from oil products, particularly kerosene. Hitherto kerosene with a high sulphur content had been impossible to sell because of the odour produced when it burned. This invention meant that new high-sulphur crudes could be used. Having become a trust in 1882, Standard Oil was forced to transform itself after anti-trust legislation was enacted (Sherman Act, 1890). In 1899 a new holding company, the Standard Oil Company of New Jersey, was created, bringing under its umbrella all the companies then constituting the group. The new company continued to represent a great concentration of power, attracting hostility not only from the authorities, who sought to promote competition, but also from 6

Box 1.2 The companies which emerged from the break-up of Standard Oil. Of the 34 companies which made up the Standard Oil group, 5 ceased operations, 8 turned to other activities and 21 continued their development, in some cases buying out their competitors. Amongst the companies still recently in existence were: – Standard Oil of New Jersey (now Exxon); – Standard Oil of New York (Mobil, after merger with Vacuum and until its merger with Exxon); – Standard Oil of California (now Chevron); – Standard Oil of Indiana (Amoco until its merger with BP in 1998; – Atlantic Petroleum Company (Arco until its merger with BP); – Continental Oil Company (now Continental); – Ohio Oil Company (now Marathon Oil Company); – Standard Oil Company (Ohio) (bought by BP, and now BP USA); – Ashland Oil Company (now Ashland); – Pennzoil Company (now Pennzoil). It should be noted that the mergers between Exxon and Mobil, and between BP, Amoco and Arco further reduced by several companies the number of “offspring companies” of Standard Oil.

The strategy adopted by Standard Oil illustrates the constant concern of industry to control the entire chain of its activity. Furthermore this desire for control rapidly translated itself into a financial obligation, the demands of technological and industrial development imposing investments on companies which only the largest could bear. This was conducive to the emergence of a vertically integrated and oligopolistic industry. Although in the first twenty years of its existence the petroleum industry was American, and dominated by Standard Oil, it rapidly became an international industry, even though the U.S. continued to account for more than half of world production until 1950. The growth in the consumption of kerosene, followed by gasoline, diesel-oil, and fuel oil was a worldwide phenomenon. Not only Europe but also Russia and Asia became important markets. New oil companies were created (e.g. Shell, Royal Dutch, Texaco, Gulf, Anglo-Persian, later to become BP). Standard Oil of New Jersey (later Esso, then Exxon), Standard Oil of New York (Mobil), Standard Oil of California (now Chevron), Texaco, Gulf, Royal Dutch Shell and BP became the “majors” (also known as the seven sisters). 7

Chapter 1 Petroleum: a strategic product

some journalists and writers who probed the mechanisms used by the group in its operations, criticising its harmful aspects. A series of articles published at the turn of the century by the journalist Ida Tarbell, subsequently compiled into a book, “The history of Standard Oil”, had a tremendous impact. Eventually action was taken in the courts, and in 1909 the Federal Court ordered the break-up of Standard Oil. Despite delaying tactics employed by the company, the ruling was confirmed in 1911. The group divided up into 34 separate companies (see Box 1.2).

Chapter 1 Petroleum: a strategic product

1.2.1.2 The oil industry in Russia It had long been known that the Baku region was rich in oil. Travellers had been struck by the permanent fires fuelled by natural sources of petroleum. There was a thriving trade in “naphtha” (nefte is the Russian word for petroleum) between the shores of the Caspian and the Far East. It was transported by camel in goatskins. The early discoveries of oil in the U.S. rekindled interest in the Baku resources, and drilling commenced there in 1872 (Fig. 1.6). Oil production grew rapidly, attaining 1 Mt in 1889, 4 Mt in 1890 and 10 Mt in 1900. At that time this was half of world production, and exceeded U.S. production. Among the first to buy up land on the banks of the Caspian were Robert and Ludwig Nobel, brothers of Alfred, the inventor of nitroglycerine and dynamite, and creator of the prize which bears his name. They rapidly developed oilfields, refineries and transport facilities. They arranged for the bulk transport of oil across the Caspian Sea, launching the first oil tanker, the Zoroastra, in 1878, and became the largest producers in the region. Of course a problem which rapidly presented itself was how the oil was to be transported out of Azerbaijan, across Georgia to the Black Sea. The isolation of the oil resources in the Caspian, already a critical problem at the end of the nineteenth century, continues to be relevant to this day. In 1893 a railway was proposed to connect Baku to Batum on the Black Sea, and a French financier Alphonse de Rothschild was approached. The latter already had interests in the oil industry: the import of kerosene from the U.S. and a refinery on the Adriatic. He agreed to participate in financing the pipeline, and went on to establish a company, BNITO, which was to become one of the largest in the region.

Figure 1.6 Baku Oilfield (by kind permission of BP).

The Nobels and the Rothschilds rapidly sought to sell their product to external markets: Europe and the East. While the Nobel brothers controlled much of the Russian market, the Rothschilds were much more dependent on foreign markets. The latter therefore turned to Marcus Samuel (Fig. 1.7), a London businessman specialising in imports and exports, particularly the import of antiques and sea shells from the Far East, in regard to the transportation of their products. 8

Chapter 1 Petroleum: a strategic product Figure 1.7 Marcus Samuel, founder of Shell (by kind permission of Shell).

For many years there was fierce competition between Standard Oil and the Caspian producers. But there was a rapid deterioration in economic and social conditions in Russia, the Tsarist administration proving weak and inept. A revolution in 1905 failed, but in 1917 the Bolsheviks took power and overthrew the Tsar. During this whole period the Baku region was being shaken by a whole series of strikes and industrial unrest caused by the deplorable working conditions. One of the leaders of these actions was a certain Jossef Djugashvili, later to become the notorious Stalin. In the face of this situation, the Rothschilds decided in 1912 to sell most of their interests to Royal Dutch Shell, which had been set up in 1907. In 1918 the new Soviet regime nationalised the entire oil industry. Royal Dutch Shell lost 50% of its oil supplies at a stroke. The last remaining Nobel was stripped of all his assets, which Standard Oil of New Jersey nevertheless bought from him, doubtless convinced that it would one day be able to resume operations on Russian territory. This hope was dashed, because despite the adoption of a new and more liberal New Economic Policy in the 1920s, none of the companies which had been nationalised ever managed to resume any significant activity. Standard Oil of New York, on the other hand, was later to contract to purchase Russian products. By 1920, Russian oil production had fallen to 3 Mt/y, compared with 10 Mt/y at the turn of the century. By 1930, however, it had regained the level it had enjoyed before the outbreak of the 1914 – 1918 war, the government being in dire need of foreign currency earnings from oil exports. These exports benefited from a small discount relative to the international price.

1.2.1.3 Shell and Royal Dutch As already mentioned, competition on the oil products market was stiff at the end of the nineteenth century, and there was particularly fierce competition between Standard Oil, the Nobel brothers and the Rothschild family. 9

Chapter 1 Petroleum: a strategic product

In order to find new markets in the East the Rothschilds, seeking new transport possibilities, turned, as we saw, to Marcus Samuel. In 1892 Samuel turned his hand to the oil sector, providing bulk transport of kerosene bought from Rothschild in Batum on the Black Sea to Asia (Singapore and Bangkok via the Suez Canal (Fig. 1.8)). Marcus Samuel gradually built up his oil interests, and in 1897 he created the Shell Transport and Trading Company Limited to manage these activities. The company prospered, trading not only kerosene but also, after 1885 when Karl Benz invented the internal combustion engine, gasoline.

Figure 1.8 One of the first oil tankers, the Murex (by kind permission of Shell).

In order to diversify his sources of supply, Marcus Samuel acquired concessions in the Dutch East Indies (East of Borneo), where he produced crude which was refined in a factory in the Balikpapan region. He also acquired interests in oil produced in Texas from the Spindletop oilfield, discovered in 1901. Shell therefore became the first company with oil sources throughout the world. Aware of the threat posed by its competitor, Standard Oil attempted to buy Shell out, but was turned down by Marcus Samuel. The company Royal Dutch was developing at the same time. It was created in 1890 by Aeilko Gans Zijlker, a former head of the East Sumatra Tobacco Company who, on discovering traces of a paraffin-rich petroleum on the island, decided to throw himself into oil exploration. After first drilling a dry well (without oil), he was successful on his second drilling attempt. In June 1885 there was a gusher from the Telaga Tunggal 1 well in Sumatra, which had been drilled to a depth of 121 metres; the oilwell continued to produce oil for another 50 years. Supported by powerful allies (including the Dutch King Willem III, who granted him a royal seal), Zijlker founded the Royal Dutch Company. When he died, several years later, his mantle was taken on by Jean-Baptiste Auguste Kessler. A refinery with a capacity of 8000 bbl/d (400 000 t/y), about 50% of the production of which was kerosene, was commissioned in the vicinity of the well (Fig. 1.9). Part of the production was exported, putting Royal Dutch into direct competition with Standard Oil. From 1894, the latter made 10

Figure 1.9 Telaga Saïd oilfield, Netherlands East Indies (Indonesia), around 1900 (by kind permission of Shell).

Many attempts were made to combine Royal Dutch and Shell; and in 1902 a working relationship was established whereby. Marcus Samuel became the Chairman and Henry Deterding, who had taken over from Kessler on the latter’s death in 1899, became Managing Director. Deterding also took on the day-to-day management, which was his wish. The Rothschilds became associated with this new organisation when the Asiatic Petroleum Company was created also in 1902, bringing together these three interests who nevertheless retained their autonomy. It was not until 1907 that a more comprehensive agreement was signed between Royal Dutch and Shell. In fact this made Royal Dutch, based in the Netherlands, the senior partner, with 60% of the shares in the new company, Shell Transport and Trading, based in the UK owning 40%. The formation of this new Anglo-Dutch group ushered in a new chapter in the competition with Standard Oil. In order to avoid falling victim to the power of the American company, Henry Deterding decided to gain a foothold in the American market by buying the American Gasoline Company and the Roxane Petroleum Company. 11

Chapter 1 Petroleum: a strategic product

attempts to capture Asian markets. It introduced millions of oil lamps onto Asian markets (particularly China) at derisory prices, or even gave them away. Competition was also intense with Marcus Samuel who owned a refinery virtually next door to that of the Royal Dutch in Balikpapan.

Chapter 1 Petroleum: a strategic product

1.2.1.4 The other American oil companies: Gulf, Texaco Many companies were formed in the United States at the end of the 19th century. Two of them played a particularly important role: Gulf (which disappeared in 1984 when it was bought out by Chevron) and Texaco. Gulf was created by the Mellon family around 1890. From 1889 they began to buy up oilwells in the West of Pennsylvania, using these as the basis for an integrated operation. But in 1893 the family decided to sell all its installations to Standard Oil, which showed every sign of wishing to achieve an unchallenged position in the American oil industry. The Mellon family resumed its interest in oil when the first explorations were being conducted in Texas, financing a drilling operation. This was at Spindletop in 1900, and on 10 January 1901, when a depth of 300 metres had been reached, an oil gusher destroyed all the drilling equipment, hurling rocks, sand and earth into the air! The well produced several tens of thousands of barrels per day, and it took weeks to staunch the flow of hydrocarbons. This discovery had a number of consequences. First of all the resulting glut of oil led to a fall in prices. The large oil companies, including Standard Oil and Shell, bought oil from Texas in order to take advantage of the low prices. But after 18 months the flow from Spindletop collapsed. In 1902 the Mellons raised further capital and founded another integrated company, also called the Gulf Oil Corporation. Their efforts were rewarded, because Gulf went on to become one of the world’s largest oil companies. Another company, the Texas Company or Texaco, was formed in 1901, based on a production facility in Texas. Like its competitors, Texaco developed an integrated structure, with a refinery in Port Arthur, a number of sources of crude and a distribution network. The lone red star logo (the symbol of Texas) was increasingly seen throughout the U.S. before embarking on the conquest of the world.

1.2.1.5 The creation of Anglo-Persian: the role of the British government At the turn of the century oil production was dominated by three regions: the U.S., Russia and the Dutch East Indies. But there were many indications that the Middle East was potentially rich in hydrocarbons. Exploration started in Persia (now Iran), followed by Turkey. The Shah of Persia was very keen to develop his country’s hydrocarbon resources. At the beginning of the century, William d’Arcy negotiated the rights of exploration in Persia. The project got off to a bad start. The first four exploration wells all proved dry, also drying up the funds which had been made available by the promoters of the operation. A new capital injection by Burmah Oil, a company which developed in India, allowed work to continue. The fifth attempt, which lasted many months, was successful. In 1908, oil gushed forth from the exploration well (see Figs. 1.10 and 1.11). But in order to turn a discovery of oil into a commercial venture, major investments are needed for the production, transport and refining facilities. More capital was needed. In 1909 the Anglo-Persian Company was established to realise this objective. Burmah Oil remained a partner. The new company went on to become the Anglo-Iranian Company, and later, in 1951, the British Petroleum Company. The new company required considerable capital to finance its development in consumer markets. Ultimately the British government, finally responding to the campaign of the first Sea Lord, Admiral Sir John Fisher, (1904 – 1910) and subsequently, Churchill, to use fuel oil for the fleet, provided the necessary finance. The British government acquired a 51% participation in the company, and two government directors with the right of veto sat on the board of directors. 12

Chapter 1 Petroleum: a strategic product Figure 1.10 First oil discovery in Persia (Iran) at Masjid-I-Suleiman (by kind permission of BP).

Figure 1.11 Steam production at Masjid-I-Suleiman (by kind permission of BP).

1.2.1.6 The development of production in Mexico and Venezuela Oil production in Latin America followed rapidly in the footsteps of the U.S., Russia, the Dutch East Indies and Persia. Oil was first discovered in Mexico in 1901, and in 1908 there was a spectacular gusher in the Dos Bocas oilfield. Royal Dutch Shell, Standard Oil of New Jersey and Gulf successively developed oilfields in Mexico, leading to a production which exceeded that of Russia: Mexico became the world’s second largest producer. But in the 1930s a number of conflicts between the Mexican government and the oil companies set back production. In 1938 the oil industry was nationalised. Pemex (Petroleos Mexicanos) was created and took control of all oil-related activities in Mexico. However 13

Chapter 1 Petroleum: a strategic product

production fell to a very low level (6 Mt/y) and never really recovered until the 1970s. It was at that time that large new discoveries allowed Mexico to become one of the world’s leading exporters. Venezuela followed close behind Mexico, and in the 1920s became the second oil producer in Latin America. The first discovery was made in 1914, in Mene Grande. Venezuela rapidly became the world’s second largest oil producer, in front of the USSR, retaining this ranking until 1961. At the beginning, Royal Dutch, Shell, Gulf and a small company, Pan American, were the main producers. After various incidents, Pan American was bought out by Standard Oil of Indiana, and later by Standard Oil of New Jersey.

1.2.2

Between the wars: the role of the state

1.2.2.1 Oil, a strategic product The links between Anglo-Persian and the UK government were established in order to safeguard the regular supply of heavy fuel oil to the British fleet. It also served as a clear reminder of the strategic importance of oil (another example is the support given to Royal Dutch by the Netherlands government when it was created). For consumer countries the problem is to secure reliable supplies of a vital product. France is another good illustration of the concern and the energy which a major industrial country largely devoid of hydrocarbons will mobilise in developing and protecting an industry capable of ensuring its national independence. During the first world war there was a rapid motorisation of the troops, mainly unmotorised at the outset of the war. Motor-driven vehicles replaced the horse for transport, assault tanks appeared in 1916 and aviation began to show its military potential. The battle of the Marne was a decisive episode which revealed how important motorised vehicles could be (Fig. 1.12). It was only by mobilising the famous Marne taxis that the troops could be conducted to the front, thereby avoiding a German breakthrough which could have endangered Paris. The importance which oil assumed in the first world war is encapsulated in two quotations. Lord Curzon, President of the Inter-Allied Petroleum Conference, declared: “The allied cause floated to victory on a sea of oil”. Senator Henry Béranger, who controlled the import and distribution of oil in France during the war, concluded a speech with a phrase which continues to resonate: “The blood of the earth was the blood of victory”.

Figure 1.12 The taxis of the Marne (Photo Monde et Caméra).

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1.2.2.2 Creation of the CFP (Fig. 1.13) France secured its supplies of crude by creating the CFP (Compagnie Française des Pétroles, later to become Total) which later acquired the Germans shares in the Turkish Petroleum Company (see Section 1.2.3). In 1923, at the request of the French government, Ernest Mercier set up a private, independent company, funded mainly by French capital. This company, with a capital of 25 million francs, was founded on 28 March 1924, the main shareholders being a number of large banks and the main French petroleum distributors, of which Desmarais was the most important. The state had a 25% stake. The CFP also received the shares in the TPC. Despite the scepticism of the industrial community about the financial viability of enterprises of this kind, the direct involvement of the government considerably modified the nature of the market. The French state became a participant in a market expanding rapidly in response to the rise of the automobile, but which was largely being driven by developments beyond France’s national frontiers. After the Second World War there was a tendency for the state to continue its support, direct or indirect, for the national oil industry in importing countries, both in Europe (with the creation of ENI in Italy (1953) and Elf Aquitaine in France (1976)) and in the U.S. 15

Chapter 1 Petroleum: a strategic product

Until the Great War, French oil supplies depended on private, independent companies linked to the major American, British, Russian and Romanian producers. Before the war, France was one of the largest oil consumers in Europe. But the onset of war caught the government by surprise. On the one hand the oil companies sought to maintain the regime of competition characteristic of the sector. On the other hand, the international situation meant that French supplies of Russian and Romanian oil were interrupted. The only source was therefore American. Furthermore the attacks by the German navy on oil tankers in the Atlantic were interfering with fuel supplies, to the point that in 1917 the private companies were not able to meet French needs. Clemenceau had to make an appeal directly to Wilson for the necessary shipments to be increased. The war therefore demonstrated to France that the outcome of the war depended on the large oil companies, mainly American and British: Standard Oil, Anglo-Persian, Royal Dutch Shell. The French government realised that it was crucial to increase French independence in relation to energy supplies, in particular by ensuring that it participated in international oil concessions such as those in Mesopotamia, where the British were very active and the Germans also had active interests. Following new negotiations between Clemenceau and Lloyd George in December 1918, agreement was reached about the transfer to France of the shares of the Deutsche Bank in the Turkish Petroleum Company – TPC (see Section 1.2.3.1). The British were fairly favourably disposed to France participating in the TPC, as this would act as a counterbalance to the influence of the American companies. This agreement proved particularly useful to Paris since the American companies decided after the war to stop supplying France, based on the decision of the authorities to maintain control over oil activities after the end of hostilities. During the war the efforts of these same companies, as members of the Petroleum War Service Committee, had allowed France to satisfy its needs. But once the war ended, the French government concentrated on trying to eliminate this dependence. Apart from its efforts to gain direct access to crude oil, the French government took other measures relating to the transport, refining and sale of products. Important decisions were also taken with regard to scientific research and training.

Chapter 1 Petroleum: a strategic product

Figure 1.13 The Compagnie Française des Pétroles was created in 1924 (by kind permission of Total).

1.2.2.3 The protection of the French petroleum industry As well as setting up the CFP, France protected its domestic petroleum industry with the help of various laws designed to foster petroleum refining and distribution. The National Office for Liquid Fuels, set up by an Act of Parliament of 10 January 1925, sought to regulate the industry without actually nationalising it. Its aim was not only to promote oil exploration in other countries by French companies, but also to encourage exploration in France. At the same time the Act encouraged the development of the French refining industry and allowed the expansion of a fleet of tankers which would guarantee national supplies in the event of war.

Figure 1.14 The Gonfreville (Normandy) refinery around 1930.

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Chapter 1 Petroleum: a strategic product Figure 1.15 The same refinery today (by kind permission of Total).

Laws enacted in 1928 provided for monopolies on refining and distribution to be granted by the state. The state authorised companies, either private or public, French or foreign, to import and refine crude for a term of ten years, and to import and distribute oil products for a period of three years. “Protected” in this way, the CFP created, in 1929, the Compagnie Française de Raffinage, which built its first two refineries in Gonfreville, near Le Havre, in 1933 (Figs. 1.14 and 1.15) and in La Mède, close to Marseilles, in 1935. These two refineries, with a combined capacity of 2 Mt/y, represented one-quarter of the total refining capacity in France at that time. Other refineries were also built, in Port-Jérôme by Esso, in Petit-Couronne by Shell, in Lavéra by BP and in Donges by Antar.

1.2.3

Between the wars (2): cooperation and competition between oil companies. The example of the Turkish Petroleum Company

1.2.3.1 The Turkish Petroleum Company The Turkish Petroleum Company (TPC) was established around 1910, with three shareholders: a subsidiary of the Anglo-Persian Company, a subsidiary of Royal Dutch Shell and Deutsche Bank. Amongst its concessions, those for the regions of Mosul and Baghdad were the most promising. During the 1914 – 1918 war the Deutsche Bank shares were frozen by the British government and at the same time discussions started between the British and French governments. These negotiations resulted in the French acquiring the Deutsche Bank shares in 1920. Moreover the United States, desirous of gaining access to oil resources outside its own territory acquired, by invoking the “open doors” policy (oil concessions throughout the world must be open to all the allies), shares for Standard Oil of New Jersey and Standard Oil of New York in the TPC. The shareholdings were then distributed as follows: – Compagnie Française des Pétroles: 23.75%; – D’Arcy Exploration Company (Anglo-Persian): 23.75%; – Anglo-Saxon (Royal Dutch Shell): 23.75%; 17

Chapter 1 Petroleum: a strategic product

– Near East Development Corporation (50% Standard Oil of New York, 50% Standard Oil of New Jersey): 23.75%; – Participation and Investment (C. Gulbenkian): 5%. Exploration got underway rapidly, and led to the discovery at Bala Gurgur, on 14 October 1927, of the very large Kirkuk oilfield (Fig. 1.16). In 1928 the Turkish Petroleum Company became the Iraq Petroleum Company (IPC), underlining its association with the newly created independent kingdom of Iraq, which included the former Mesopotamia. The Company ran rapidly into serious difficulties. There proved to be a divergence of interests between the CFP (for which the IPC was the only source of crude) and its American partners in particular. The so-called “Red Line” agreement, which stipulated that the partners in the IPC should act in concert in all the former Ottoman Empire territories, resolved these difficulties in 19282. However the problem resurfaced in 1948.

1.2.3.2 The Achnacarry Agreement The Achnacarry Agreement was signed in 1928, the same year as the Red Line agreement. It reflected the desire of the oil companies to avoid competing so fiercely that their interests would be harmed, and established a form of cooperation between them. We will consider this agreement in greater detail in Section 1.3.

Figure 1.16 The discovery of oil at Kirkuk (Iraq) in 1927 (by kind permission of Total).

2. The agreement is so named because, after long discussions, C.S. Gulbenkian grabbed a map and drew a red line around the territories within which the partners in the TPC (later the IPC) would be obliged to act in concert.

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Around 1920 the geologist Frank Holmes published evidence pointing to the presence of oil in the Bahrain region, and obtained concessions in that Emirate, as well as in Kuwait and Saudi Arabia. However, short of money, he sold all these concessions to Gulf in 1927. In Bahrain, Gulf sold these interests on to Standard Oil of California (Socal). The first discovery was made in 1932. This was fairly modest in size, and the production of the Emirate did not exceed several million tonnes per year, but it confirmed the promise of this zone. Kuwait was the only country situated outside the Red Line. Gulf and Anglo-Persian jointly obtained a concession for 75 years. In 1938 the Burgan oilfield was discovered. Its initial reserves were estimated at 10 billion tonnes, making it at the time by far the largest oilfield yet discovered. In Saudi Arabia IPC was competing with Socal. The new king, Sultan Ibn Saud preferred to negotiate with the Americans and granted Socal a 60-year concession in 1933. In 1948 the Ghawar oilfield was discovered, still the largest ever discovered. At an early stage Socal formed a joint venture with Texaco in order to develop its resources in Bahrain. The latter controlled major outlets in Europe and Asia, whereas Socal

Black Sea USSR

ian sp Ca a Se

Turkey

Syria Mediterranean Sea Palestine Suez Canal

Iraq

Iran

Transjordan Kuwait

Egypt Neutral Zone

Persian Bahrain Gulf Qatar

Red Sea

Saudi Arabia

Trucial States

Oman

Figure 1.17 The Middle East in the 1930s. This region accounts for twothirds of the world’s oil reserves.

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Chapter 1 Petroleum: a strategic product

1.2.3.3 Oil in the Arabian peninsula (Fig. 1.17)

Chapter 1 Petroleum: a strategic product

had an excess of crude. Socal and Texaco established two new companies: Casoc (California Arabian Standard Oil Company), which looked after Socal’s production interests in Bahrain and Saudi Arabia, and Caltex (California Texas Oil Company), which looked after the Texaco distribution networks in Europe and the East. The 1939-1945 war interrupted oil extraction activities in Saudi Arabia. The full potential of the Arabian peninsula only became fully apparent after the war. But the investments needed to develop the resources of the Wahhabite kingdom were considerable. Socal and Texaco sought partners. After lengthy discussions, Esso and Mobil joined Socal and Texaco to form Aramco (Arabian American Oil Company). The other IPC partners, who could have demanded to participate in Aramco, obtained increased interests in Iraqi production.

1.2.4

After WWII: increasing oil consumption, new oil companies, creation and development of OPEC

After the Second World War, and particularly in the 1950s, oil consumption grew at a rate of about 7% per year. Automobile transport was developing rapidly, and demand for domestic and heavy fuel oil was increasing steeply. These two fuels were making major inroads into the traditional markets of coal. Supply remained abundant, however, thanks to large discoveries not only in the Middle East (Fig. 1.18) but also in Africa (Algeria, Libya and Nigeria) and in Venezuela. Russian exports were also increasing. However the entry of new producers—the American independents—onto a market hitherto controlled by the “majors” (current term used to designate the large oil companies) increased and modified the nature of the competition. These new companies sought to counter the declining profitability of American operations by internationalising their operations and gaining a foothold in Libya, in particular. European governments were also taking an increasing stake in oil and creating national companies such as ENI (Ente Nazionale Idrocarburi), Elf and Fina, intended to increase national energy-independence. These companies grew rapidly.

Figure 1.18 Another major Middle East producer: Abu Dhabi.

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The Second World War changed the nature of the relationship between the producers and the international oil companies: the producing countries were no longer content to grant concessions in the traditional way. They wanted a greater share of the rewards arising from the extraction of their oil wealth. Negotiations in Iran in 1949 to revise the terms of the Anglo-Iranian concession got off to a difficult start. The young Shah had to contend simultaneously with the very influential religious community and a powerful communist party. The first proposals for modifying the concession were rejected by the Iranian parliament, which demanded nationalisation. The then Prime Minister announced to parliament that he rejected nationalisation, and urged instead modification of the concession. He was assassinated several days later. The new Prime Minister, Muhammad Mossadegh, had Parliament confirm nationalisation. After many troubled months the Iranian authorities negotiated an agreement with the oil companies (led by the American companies): the oil companies recognised the ownership by the Iranian state of the Iranian land and mineral resources. The National Iranian Oil Company (NIOC) was formed. It became the owner of the resources, with production being entrusted to a consortium in which Anglo-Iranian would hold 40% of the shares, the five American majors (Standard Oil of New Jersey, Mobil, Standard Oil of California, Gulf and Texaco) 7% each, Shell 14%, a group of American independents 5% and CFP 6%. Production, rose rapidly to achieve 300 Mt in 1973.

Figure 1.19 Lacq: the major French gasfield (by kind permission of Total).

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Chapter 1 Petroleum: a strategic product

1.2.4.1 After 1945: a new relationship

Chapter 1 Petroleum: a strategic product

Figure 1.20 The gas treatment plant at Lacq (© Roux, Total).

Figure 1.21 1956: the discovery of oil in Algeria (© Dumas, Total).

22

A. The creation of ENI by Enrico Mattei In the 1920s, Italy formed a national refining company, the AGIP (Azienda Generali Italiana Petroli) based on the model adopted in other countries. By the outbreak of war, this company was of comparable size to the local subsidiaries of foreign companies operating in Italy. At the end of the war Enrico Mattei, an industrialist who had fought with the Resistance, was appointed to head up AGIP, whose installations had suffered severe war damage. Dynamic and ambitious, Mattei sought to develop AGIP and allow it to play a major role in guaranteeing Italy’s oil supply. However capital was needed. The discovery of major reserves of natural gas in the Po valley met this need. SNAM (Societa Nazionale Metanodotti), the company formed to produce this gas, would generate the necessary capital. The ENI was formed in 1953, bringing together various companies in the hydrocarbons sector, most of which were run by Mattei. In order to guarantee access to petroleum resources, Mattei pursued a policy of maintaining active contacts with producing countries. Failing to secure an interest in the major oilfields of the Middle East from the “seven sisters” (Mattei is reputed to have coined this sobriquet himself) he negotiated an agreement with Iran. Although Mossadegh had partially failed, several years earlier, in his assault against the oil companies, the oilfields had still been nationalised, and the state had more flexibility in its negotiations with foreign companies. Mattei signed an agreement with the Shah which envisaged a 75% share of the profits for the state and 25% for ENI. This was a first in the oil sector. Until his death in 1962 in an aircraft accident, Mattei sought to diversify his company’s supply sources. B. The creation of ELF, a second national French oil company In addition to supporting the CFP the French government was anxious, particularly after 1945, to promote exploration and production in France and other territories under its sovereignty. Several companies were created and oil and gas discoveries were made in the south of France, in Gabon and in Algeria. These companies progressively merged into the Elf group (today part of Total). C. The Institut Français du Pétrole (now IFP Energies nouvelles) Although not an oil company, the formation of the Institut Français du Pétrole (IFP) in 1944 should be mentioned here (Fig. 1.22). The IFP arose out of the desire of the French government to support its national petroleum industry and to limit its dependence on imported processes, equipment and technology, particularly from the U.S. The brief of the IFP is to foster scientific and technical research into all aspects of exploration, production, transformation (refining and petrochemicals), applications (e.g. engines), including training and documentation. The IFP developed rapidly, reaching something like its present size in the early 1980s. Its success in realising its objectives can be measured in terms of the number of its proprietary refining and petrochemical processes it has sold. In 2003 more than 1500 process units in many countries including Japan and the U.S. were using IFP processes, making it the second largest licenser in the world in this field. The influence enjoyed by the IFP School, half of whose students are non-French, testifies further to the success of the IFP. The IFP has also played a major part in the creation of a world-class petroleum services industry in France. Technip and Coflexip, for example, originally set up by the IFP, and which recently merged, are amongst the world’s leaders in their respective fields. 23

Chapter 1 Petroleum: a strategic product

1.2.4.2 New entrants into the oil sector

Chapter 1 Petroleum: a strategic product

Figure 1.22 The first offices of the IFP (now IFP Energies nouvelles).

1.2.4.3 Developments in the U.S.: quotas, isolation of U.S. market The U.S. has always played a key role in the oil industry. Until 1950 it accounted for half the world’s crude production. But consumption grew much faster than production. The U.S. began to import oil in 1948, and by 1962 annual imports had reached 100 Mt. By 1971 this figure had doubled. These imports were attractive because the price of Middle Eastern oil in New York was lower than that of American oil. The American authorities, worried about this competition, started by calling for voluntary restrictions, and in 1959 imposed compulsory restrictions: import quotas. The American market was therefore partially protected from the world market, leading to price rises. Prices outside the U.S., on the other hand, were falling because of the abundance of crude oil.

1.2.4.4 Falling prices and the creation of OPEC The isolation of the American market led to increased competition on other markets, notably the European and Japanese markets. In order to increase their crude sales, oil companies widely adopted the practice of discounting the posted prices, which continued to be the reference price for the calculation of royalties and taxes. But competition also led to companies seeking to reduce the posted prices. Two reductions were made, by 18 ct/bbl in February 1959 and 10 ct/bbl in August 1960. These reductions produced an automatic reduction in the incomes of producing countries per barrel sold. Unhappy with this development, the main producing countries (Venezuela, Saudi Arabia, Iran, Iraq, Kuwait) met in Baghdad in September 1960 and agreed to form the Organisation of Petroleum Exporting Countries (OPEC). The main objective of this new organisation was successfully achieved: posted prices remained stable for 10 years, until the increases of the 1970s.

1.2.4.5 Early signs of the oil shocks From the late 1950s there were a number of political and economic events which were to transform the oil industry hitherto dominated by the international oil companies and, more discretely, a certain number of consuming countries, above all the U.S. 24

In 1956 the nationalisation of the Suez Canal resulted in its closure. As a gesture of support for Egypt, Syria interrupted the shipment of IPC oil. While everything was restored to normal within several months, and good cooperation between the consuming countries limited the effects of the crisis, these events marked the emergence of third world countries as a political force. Two years later, in 1958, a military coup d’état in Iraq swept General Kassem to power. In 1961 the new government decided to withdraw IPC’s concessions except where there were already productive wells. The following year the Iraqi government created the INOC (Iraq National Oil Company) which replaced the IPC. In 1967, during the Six Day War, the Arab countries imposed an embargo on oil deliveries to the U.S., the UK and Western Germany. While this embargo only lasted a few weeks, it marked a new stage in the use by producing countries of oil as a weapon. Furthermore the reclosure of the Suez Canal (see Fig. 1.27 and Section 1.2.4.10) led to an explosive growth in the demand for transport, i.e. tankers, because Middle Eastern oil destined for Europe and the U.S. henceforth had to be routed via the Cape of Good Hope. North African oil was therefore at a premium because of its transport advantage, a factor which would become significant in the following years. During the 1960s Algeria and Libya became important oil producers. In Libya, where not only the majors (Exxon, Mobil, Gulf, BP, Shell) but also several independents (Occidental, Oasis, etc.) were active, production reached almost 60 Mt in 1965 and almost 160 Mt in 1970. But in 1969 King Idris of Libya was replaced by Colonel Gaddafi, who became the first leader of a producing country to seek to cut production in order to conserve resources. B. Economic climate Oil consumption had increased (Figs. 1.23 and 1.24) to the point where liquid hydrocarbons accounted for half the energy needs of Europe and three-quarters of those of Japan, two regions virtually devoid of their own oil. There was another cause for disquiet: the world’s oil reserves were equivalent to only 30 years production at current levels in 1970, compared with 140 years production 20 years earlier (Fig. 1.25) 3. It was feared that oil resources might be largely exhausted by 2000. This was the backdrop against which the famous report of the Club of Rome entitled “Limits to Growth” was published in 1972. This report warned of the dangers of the depletion of natural, non-renewable resources, as a result of economic development. The report called for economic growth to be slowed so as to save raw materials and protect the environment. Of course there was no simpler way to limit consumption than to increase prices. At the same time, new air quality legislation in the U.S. made it more difficult to burn coal, and encouraged the use of oil. But initiatives to open up new resources situated in ecologically fragile areas (Alaska, California coast, Gulf of Mexico) were delayed following actions taken by environmental protection groups. This led to a somewhat paradoxical situation, since it made the U.S. dependent on foreign oil. In order to protect the interests of domestic producers, who were at a cost disadvantage compared with their foreign competitors, quotas were introduced. But these proved difficult to administer. In 1969 President Johnson, who had been very close to Texan oil interests, was replaced by the Nixon 3. By 2000 the R/P ratio (reserves to annual production) was back to over 40, for “conventional” oil alone.

25

Chapter 1 Petroleum: a strategic product

A. Political events

Chapter 1 Petroleum: a strategic product

Figure 1.23 Service station in Senegal in the 1950s. Sales were increasing and equipment was being modernised all over the world (by kind permission of BP).

4 000 3 500

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Figure 1.24 Production and consumption of oil, showing the steep increase in the 1960’s.

26

Chapter 1 Petroleum: a strategic product

Oil reserves / Annual production (years)

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Figure 1.25 Ratio of reserves to production, illustrating the sharp drop from 1950 to 1980 and then the stabilization.

Administration, which decided to change course. American producers would be protected by raising prices; this would not only allow quotas to be abolished because it would make American producers profitable, but it would also guarantee adequate revenues to the producing countries (Venezuela, Gulf states), thereby stabilising the existing regimes, which were necessary partners of the U.S. By 1970, the politico-economic climate was at last turning favourable to an increase in oil prices. The main actors (with the important exception of the major consuming countries without oil resources) saw nothing but benefit from such a development. The event which actually triggered the price rise was the decision by Libya, which demanded that the oil companies reduce production by more than one million barrels per day. At the same time, Algeria nationalised the six oil companies and unilaterally set the price of its oil. Libya obtained higher tax rates and an increase in the posted prices from the oil companies. And Venezuela decided to increase its tax rate to 60% and enacted a law allowing the posted price of oil to be set unilaterally. But most was still to come.

1.2.4.6 The first oil shock The oil companies, concerned at the course of events, invited OPEC to enter into negotiations. In practice, two separate negotiations led to significant price increases, which in turn produced an increase in the income—per barrel—for producing countries. The Teheran Agreement (February 1971) related to the Gulf countries. The Tripoli Agreement (April 1971) related to Algeria and Libya, but also to that part of the production of Saudi Arabia and Iraq output into the Mediterranean. Finally, following the devaluation of the dollar in August 1971, two successive conferences in Geneva in 1972 and 1973, led to increases in posted prices to compensate for the loss in value of the American currency. Even more importantly, a fourth conflict broke out between Israel and the Arab countries. This time the war was started by Egypt and Syria, who attacked Israel during the festival of Yom Kippur, on 6 October. Initially events moved against Israel before reaching a balance of force. The war ended on 25 October 1973 without a victor. 27

Chapter 1 Petroleum: a strategic product

$/b 140

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Hurricanes Katrina and Rita Attack on personnel in Saudi Arabia, trouble in Iraq and Nigeria

120 110 100 90 80

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30 20 10 0 1970

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Figure 1.26 The oil shocks.

This war nonetheless had a considerable impact on the oil industry: • On 16 October 1973 the six Gulf states decided on an enormous increase in the posted

prices. The price of Arab light, the reference crude, rose from $2.989 to $5.119/bbl (Fig. 1.26). • On 17 October all the member states of the OAPEC (Organisation of Arab Petroleum Exporting Countries: Abu Dhabi, Algeria, Saudi Arabia, Bahrain, Dubai, Egypt, Iraq, Libya, Kuwait, Qatar) except Iraq decided to reduce their exports by 5% per month until Israel withdrew completely from occupied territories and the rights of the Palestinian people had been restored. On 4 November this reduction was increased to 25%. • On 25 October the same OAPEC members imposed an embargo on the deliveries of oil to the U.S., Portugal, the Netherlands, South Africa and Rhodesia, which were accused of favouring Israel. The spectacle of Dutch motorways closed to traffic at weekends to save fuel was a powerful image which remained engraved on European imaginations for long thereafter. Finally at a meeting in Teheran in December, OPEC took advantage of the turbulence to again raise posted prices. The posted price of Arab Light rose to $11.651/bbl, the real price was of the order of $7.

1.2.4.7 Nationalisations Another consequence of the increasing power of OPEC, perhaps even more important than the price rises, rock the oil world to its core: the main producing countries decided, one after the other, to nationalise their oilfields (see Box 1.3). During the 1970s a wave of nationalisations by OPEC member countries gathered momentum. Over a few years most of these countries nationalised the assets of foreign companies, and in most cases declared a state monopoly on all activities related to petroleum. OPEC, by providing its members with the opportunity to take concerted action to strengthen their negotiating position, acted as a catalyst to a movement which arose from age-old demands. 28

In producing countries petroleum has often been considered a natural resource which belongs to the people, and must be used in their interests. This is sometimes actually written into the national constitution. During the period between the Second World War and 1970 this concept reached its climax. Many countries became independent either after the war or during the 1960s, and acquiring control over their natural resources, particularly oil, symbolised national sovereignty. Although several countries—: Russia (1918), Mexico (1938), Iran (1952), India (1958)— nationalised their oil industry earlier, the great wave of nationalisations occurred between 1970 and 1980. In the Mediterranean countries nationalisations often occurred on a company-bycompany basis: in 1971 Algeria took control of 51% of the concessions of the French companies. Starting in 1971 Libya successively nationalised BP and then ENI (50%) and the other companies (51%), and Iraq nationalised the last IPC concessions. In 1972 negotiations between the oil companies and OPEC led to the “participation” agreements (New York Agreements), which envisaged the progressive acquisition of concessions by producing countries. The participation percentage, initially fixed at 25%, was supposed to be increased to 51% in 1983. Only some of the Gulf States signed this agreement, and the nationalisations in fact occurred much faster than envisaged in the agreement: Kuwait and Qatar in 1975, Venezuela in 1976 and Saudi Arabia in stages between 1974 and 1980. One clear consequence of the concept of petroleum as “the property of the people” is that the national public should have access to oil products at as low a price as possible. In Venezuela, Nigeria and Saudi Arabia petrol prices are very low, often below the international price excluding taxes and distribution costs. This encourages very high consumption, to the detriment of exports, and therefore of vital foreign currency earnings. These concepts only changed at the end of the 1980s, with the fall of the Berlin Wall and the collapse of communism.

The oil shock of 1973 marked the start of an economic crisis in Western countries as well as a major turning-point in the development of the petroleum market. Firstly, a new type of actor in the oil market began to emerge beside the Western oil companies and the major importing countries: the producing, exporting countries themselves. These countries acted either individually or in some cases through OPEC. In 1973 these countries controlled over 50% of the world’s production of crude and more than 80% of its reserves. Secondly, a split developed in the oil industry at the global level, with oil production, now under the control of state companies, remaining separate from refining and distribution, most of which was still in the hands of the Western oil companies.

1.2.4.8 The creation of the IEA After the first oil shock, which led to real shortages in the countries subject to the embargo, the industrialised countries founded the International Energy Agency (IEA) in 1974. This Agency was set up within the OECD (Organisation for Economic Cooperation and Development), with just over 20 members, including the U.S. and Canada, Western Europe (with the exception of France, which did not join until 1992) and Japan, to mention the largest oilconsuming countries. The objectives of the IEA were: • To promote cooperation between participating countries in reducing their excessive dependence on oil through energy conservation, the development of substitute energy sources and relevant R&D. 29

Chapter 1 Petroleum: a strategic product

Box 1.3 Nationalisations.

Chapter 1 Petroleum: a strategic product

Next Page • •

•

To set up an information system on the international oil market, as well as consultations with the oil companies. To cooperate with producing countries and other oil-consuming countries in stabilising international energy markets to ensure that the world’s energy resources are managed and used rationally, in the interests of all countries. To create a plan which would prepare countries for a possible major disruption of supplies and for sharing the available oil in the event of a crisis. The IEA is also an important centre for publications on the energy sector

1.2.4.9 Price stability 1974 to 1978 During the period 1974-1978 the price of petroleum rose only slightly (from $11.65/bbl in December 1973 to $12.70 in December 1978 for Arab Light, then the reference for pricing all crudes). Prices were fixed by OPEC at periodical meetings. The prices of other crudes were derived from that for Arab light as a function of their quality (°API, sulphur content) and location.

Figure 1.27 The Suez Canal was closed from 1967 to 1974, following the Six Day War (© René Burri/Magnum photos).

1.2.4.10 Second oil shock 1979-1981 The second large price rise, or second oil shock, was associated with the Iranian crisis. At the end of 1978 political and social discontent in Iran (Fig. 1.28) led to strikes in most sectors of the economy and particularly in the oil sector. Iranian production fell from 6 Mbbl/d in September 1978 to 2.4 Mbbl/d in December and to 0.4 Mbbl/d in January 1979 when the Shah departed, to be replaced by the Ayatollah Khomeini. At first other counties increased their production to make good the Iranian shortfall. But Saudi Arabia subsequently decided to place a ceiling on its production significantly lower than its level of December 1978. The free market, still relatively undeveloped, spiralled out of control. Demand far exceeded supply, exacerbated by the scramble by operators to 30

Chapter 1 Petroleum: a strategic product

Previous Page

Figure 1.28 The Iranian crisis (© Abbas/Magnum photos).

maximise their stocks. By the end of 1979 spot prices (see Section 1.3.2.5) had risen above $38/bbl. At the same time the OPEC countries began to pursue a policy of setting the official price close to the spot price. In October 1980 the commencement of hostilities between Iraq and Iran led to a large reduction in the output of these two countries, provoking a new, although brief, upsurge in prices. In fact energy conservation measures taken by consumer countries were beginning to show their effectiveness: world consumption fell from 3.1 Gt in 1979 to about 2.8 Gt a few years later.

1.2.5

Weakening of OPEC and fall in prices

1.2.5.1 The oil supply situation in the early 1980s While consumption was falling off, production was increasing rapidly in Northern Europe— following the discovery of oil in the North Sea—, Alaska and West Africa (Figs. 1.29 and 1.30) in the region of the Gulf of Guinea. Other zones were also the object of extensive development, for example in the republics of Central Asia around the Caspian Sea. Before the oil shock of 1973 and the wave of nationalisations, the large western oil companies had chosen their supply sources essentially on commercial considerations. The expectations of governments played little part. The world was one in which crude oil was cheap and abundant, rarely costing more than $1.50/bbl to produce. Outside of the communist block the growth in production, which extended from 1950 to 1970, therefore took place in zones with low production costs, that is basically the countries which founded OPEC in 1960 or which joined subsequently. Even countries such as India and Brazil, which were actively committed to an independent, state-controlled approach to development, preferred to import growing quantities of petroleum products produced cheaply by the multinationals rather than develop their own production. It was regarded there as elsewhere as the antithesis of sound economics to use scarce financial resources to encourage an uncompetitive national production. 31

Chapter 1 Petroleum: a strategic product

Figure 1.29 Development of production in Nigeria (© Tainturier, Total).

Figure 1.30 Production in Angola – FPSO Dahlia (© Technip et Total).

The attractiveness of OPEC oil (and particularly that from the Gulf states) was considerably reduced as a result of its policy of high prices. There were also doubts as to the reliability of OPEC supplies. Political instability in the region made Western countries increasingly wary of Middle Eastern oil. Most oil-importing countries were pursuing a policy of diversifying supplies. The sharp oil price rises greatly facilitated the emergence of new producing regions. An oil price of $30/bbl enhanced petroleum-producing potential throughout the world, benefiting new producing countries, Western oil companies and governments of importing countries. For new producers, any domestic production which 32

Chapter 1 Petroleum: a strategic product Figure 1.31 Production in Azerbaïdjan – Shah Deniz field platform (© Total).

Figure 1.32 Production in a harsh environment (© Gstaler, Total).

substituted (costly) foreign imports or could be exported (lucratively) handsomely justified the attraction of foreign capital. Nationalisation’s in OPEC countries led to a split between the upstream and downstream activities of the international oil companies, which had lost most of the reserves which they managed. Their primary commercial motive was therefore to replace these reserves elsewhere so as not to be unduly dependent for the crude purchases 33

Chapter 1 Petroleum: a strategic product

so vital to their refining activities on any single producer. They also sought to avoid losing the benefit of their production know-how, even though this meant redirecting investment towards regions where production costs were higher than in the Arabian-Persian gulf. Western states found in these developments a very effective means of revitalising competition between producers, thus exercising a downward pressure on prices and restoring a balance of advantage in their dealings with exporting countries. High prices and the fear of scarcity led to increased R&D efforts which allowed production from fields with high exploitation costs, especially offshore. New production facilities were established not only in Europe (the North Sea, see Fig. 1.31) but also in North America (Fig. 1.32) and developing countries: Argentina, Brazil, Colombia, Ecuador, Angola, Egypt, Gabon, Syria, India, Malaysia. All of these countries became middle-ranking producers, between 20th and 30th in the world rankings. Only Mexico, Norway and the United Kingdom joined the ranks of the major producers. During this time there was a significant fall-off in the production of the OPEC countries.

1.2.5.2 Oil quotas With effect from 1981 petroleum markets began to undergo major changes. As already mentioned, between 1979 and 1985 total world demand for oil fell by about 300 Mt each year. The price increases led to fuel substitution (a return to coal in some industries, the use of nuclear energy for power generation, etc.) and energy conservation measures (insulation of buildings, more efficient engines, etc.). Since there was also a rapid increase in non-OPEC production, that part of total demand met by OPEC (Fig. 1.33) fell by almost 50%, from 1500 Mt at the end of the 1970s to less than 850 Mt in 1985. The fall in production was no greater than 30 – 40% in most OPEC countries. It was Saudi Arabia which experienced the greatest difficulty: having accepted the role of swing producer, it saw its production fall from 510 Mt in 1980 to 185 Mt in 1985.

60% First oil shock 1973 50%

Second oil shock 1979

40%

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1965

1970

1975

1980

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Figure 1.33 Reduction and recovery in OPEC share of world production.

34

2000

2005

1.2.5.3 The oil counter-shock 1986 At the end of 1985 OPEC as a whole and Saudi Arabia in particular found themselves in a desperate plight. The revenues of the latter had fallen by 75% in five years. For the first time in history Saudi Arabia abandoned its defence of oil prices and sought to recapture “its fair market share”. In order to do this it established a new type of contract for the sale of crude, the “netback” contract. For several years the profit margin on refining activities had been very low. Riyadh therefore made the following proposal to the purchasers of crude: the refiner would take delivery of the crude, would transport it and transform it into finished products which he would sell at the current price on the international market. The proceeds would then be returned to the producer of the crude after deducting refining and transport costs. The price of the crude would therefore be equal to the value of the products obtained from its processing after deduction of the costs of processing and transport. This was referred to as the netback contract. This arrangement certainly allowed Saudi Arabia to regain market share, but it led to a collapse in the oil price. Refiners were encouraged to maximise their throughput, since their margin per barrel was guaranteed. This resulted in a glut of products on the market, and prices fell. In consequence the price of crude fell also. In January 1986 the price of Arab Light was $25/bbl. By July the price had fallen to $8/bbl. The OPEC countries therefore decided to put an end to the netback contract and to return to a system of official prices. They set a target (desired) price for Arab Light of $18/bbl. But in practice the price of crude fluctuated widely, depending on variations in supply and demand. Producing countries paid a heavy price in terms of their oil revenues. These fell from their 1981 peak of $261 billion to $77 billion in 1986, recovering to $180 billion in 2002.

1.2.5.4 The situation in the late 1980s The reason behind the desire of importing countries to increase the production of nonOPEC oil was less the supposed instability of the OPEC members than the political weight which this cartel was able to wield. Experience in countries such as Angola, Algeria and Nigeria shows that internal political instability and even civil war rarely interferes with oil production. Both sides are usually careful to ensure that the petroleum infrastructure, the source of great wealth and sometimes even the object of the conflict, is not damaged. The same does not apply to confrontations between different states, when the oil infrastructure becomes a military target and may suffer, as was the case in the Iran-Iraq war and the Gulf war. The diversification of supply was achieved not only because of the voluntary policy put in place but also because, as we saw, higher prices drove the international companies to develop their activities in non-OPEC countries. By the end of the 1980s, the industrialised countries were less dependent on oil than they had been at the time of the first oil shock in 1973. Only the transport sector remained a captive market for oil products. 35

Chapter 1 Petroleum: a strategic product

To cope with this weakness in demand, the OPEC countries decided to place limits, or quotas, on their production. These quotas totalled 17.5 Mbbl/d (compared with a production of 30 Mbbl/d two years earlier). They were only able to retard the fall in oil prices, which fell from $34/bbl in 1981 to $29 in 1983 and $28 in 1985.

Chapter 1 Petroleum: a strategic product

1.2.6

The 1990s: market forces

Since 1986 oil prices have been subject to rapid and large fluctuations. Over the next 15 years it fell on several occasions to around $10/bbl, and rallied at other times to a maximum of about $40. Remarkably small variations in the supply/demand balance can produce very large price swings. Between mid-1986 and mid-1991 prices remained within the range $10-20/bbl, depending on the production quotas agreed by OPEC. The Iraqi invasion of Kuwait in 1990 resulted in a sharp rise in prices. Supply was reduced by 4 Mbbl/d, and prices doubled in a few weeks. Real shortages did not occur, however, as Saudi Arabia, Venezuela and the United Arab Emirates were rapidly able to increase production to make good the shortfall in production by Iraq and Kuwait. Even more interesting is that throughout the occupation of Kuwait by the Iraqi forces, the futures markets indicated a return to normal prices (i.e. around $20/bbl) within several months. In fact, most observers were betting on the rapid intervention of the U.S. and her allies and a normalisation of the situation within a reasonable period. Another lesson learned in the Gulf was that when hostilities commenced on 17 January 1991 (Fig. 1.34), although the experts expected a brief upsurge in the price of crude, it actually fell: the markets were discounting a short, sharp military action, and the actual price aligned itself with price on the futures market.

Figure 1.34 Blazing oilwells after the Gulf War (© Bruno Barbey/Magnum photos).

The oil price subsequently stabilised within the range $15 – 20/bbl. This was the result either of modifications in OPEC production levels or by actions such as that of American pension funds in the spring of 1994: taking the view that the oil price was abnormally low they purchased oil on the forward market. The end of the century was marked by a further demonstration of the sensitivity of prices to fluctuations in the equilibrium between supply and demand and the importance of the role of OPEC. Over the period 1995 to 1997 there was a significant hardening of the oil price, caused particularly by a series of cold winters in both the U.S. and Europe. On occasion, stocks of oil products reached rock bottom levels, leading to spectacular price rises. It became increasingly clear that the volumes of stocks of crude and of oil products were key 36

The other key factor is the volume of OPEC production. At the end of 1997 OPEC, assuming continued economic growth in Asia, announced a 10% rise in its production quotas (from 25 to 27.5 million barrels per day). This was equivalent to less than 4% of total world production. Yet the Asian crisis of 1997, followed by a Russian crisis in 1998 and subsequent problems in Latin America, dampened the increase in demand, so that the price of crude fell to about $10/bbl, notwithstanding a progressive reduction in the OPEC quotas which effectively wiped out the increase at the end of 1997.

1.2.7

The twenty first century: sustained high prices

1.2.7.1 Over the period 1999 to 2003 OPEC’s unity was re-established A price of $10/bbl was a catastrophe for the oil-producing countries and it meant that they could no longer meet their financial needs. OPEC countries’ debt was growing. A return to discipline among the OPEC countries was needed to increase prices. How could it be achieved? The election of Hugo Chavez as President of Venezuela at the end of 1998 was the first sign of change. While the previous governmental had favored maximizing production, the new President favored a policy of solidarity with third-world countries in general and with other oil-producing countries in particular. Aware of the importance of increasing oil prices, he argued for an agreement between Venezuela, Saudi Arabia and Mexico (a non-OPEC country) to limit production. This agreement would be strengthened by an improvement in relations between Saudi Arabia and Iran, the main Arabian Gulf producing-countries. The commitments to reduce OPEC production, supported by clear signs of solidarity from the main non-OPEC producers, finally appeared credible to operators. In March 1999, the price of oil started an upward trend that would lead it to a peak level in 2000. The OPEC countries then decided to set an objective for the average price of a basket of crude oil of $25 per barrel, and a range of $22 – $28 within which the price should remain: if the price went above $28, production would be increased by 0.5 Mb/d, and if the price fell below $22, production would be decreased by 0.5 Mb/d. This objective was largely achieved: during the first six months of 2001, the price of a barrel (OPEC basket) was $21. The terrorist attacks of September 11, 2001 caused a collapse in prices, with Americans greatly reducing their personal travel. But prices gradually recovered. Until 2003, $25/bbl was generally agreed to be the “normal” price of crude oil, and this was OPEC’s objective. But the threat of American intervention in Iraq caused uncertainty in the market and the addition of a “risk premium”, which different experts estimated at $5, $10 or $15/bbl. This theory was confirmed by the fall in the price of oil on March 20, 2003, the day on which President George W. Bush announced that the US rejected Saddam Hussein’s response to the US ultimatum, and that the US-led coalition would attack Iraq. In London, the price of Brent crude fell from $35 to $25. Operators were not worried about the immediate consequences of the US action. Surplus capacity from countries neighboring Iraq (Saudi Arabia, UAE, etc.) meant that lost Iraqi production could be made up and it was considered that, with surplus production capacity at 5 to 10% of total capacity, there would be a return to “normal” market supply within a few months. It was also expected that investment in Iraq would once again become possible (plans were made to raise production capacity from 3 to 6 Mb/d), so a return to “normal” oil prices therefore seemed probable. 37

Chapter 1 Petroleum: a strategic product

parameters determining short-term price movements. Most observers therefore attached considerable importance to the regular publication of data on stocks.

Chapter 1 Petroleum: a strategic product

$/b 150 140 Weekly average 130 Annual average 120 110 100 90 80 65.1 70 60 50 54.5 40 28.4 24.5 38.1 30 19.1 17.7 28.8 20 24.5 10 20.7 12.7 0 1996 1999 2002 2005

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2011

Figure 1.35 Brent Oil Spot fob Price – January 1996 to July 2011 (Source: US DOE, BP Statistical Review).

1.2.7.2 From March 20, 2003 to July 11, 2008, pressure on the market grew The price of oil continued to increase, reaching $60 per barrel in 2005, and $75 in May 2006. After a fall in the last months of 2006, it shot from $50 per barrel in January 2007 to $147 per barrel (Brent price) on July 11, 2008. There were many reasons for this. The situation in Iraq – and the Middle East – was not as had been expected. Iraqi production remained far below its level under Saddam Hussein. Attacks in Saudi Arabia were worrying. Some countries could not stop their production declining. Oil consumption rose strongly while the surplus production capacity that had resulted from the fall in demand and increased non-OPEC production after the second oil shock, had disappeared. There was no shortage of oil on the markets, but the balance of supply and demand was precarious. Costs – particularly capital costs – were rising steeply. Arguments regarding levels of oil reserves added to the concern. These arguments were misdirected since the immediate problem was not the reserves underground, these were still sufficient for several years. It was rather above the ground, particularly the lack of sufficient capital investment for geopolitical reasons: producing-countries were reluctant to invest massively to produce more oil for a market that did not seem guaranteed. Why invest to supply Western consuming countries who wanted to reduce their oil consumption because of their supply security concerns and to reduce greenhouse gas emissions? There was great concern about forecasts of an oil production ceiling of 95-100 Mb/d, while the needs of China and other emerging countries seemed unlimited. The market was preoccupied by its desperate attempts to balance future supply and demand. Many specialists did not understand why the price increases did not reduce the increase in demand. The explanation is simple. The income effect – when revenues double, gasoline consumption increases by 70% – is more important than the price effect – when prices increase by 100%, gasoline consumption only decreases by 7%. Economic growth was 38

Although supply and demand has had a basic role in the oil price setting mechanism since 1986, at least until 2003 it was OPEC’s position that was decisive. Without OPEC, oil prices would have been much lower – probably of the order of $10 to $15 per barrel – over the period 1986-2003. However, in periods of significant potential oversupply, OPEC cannot – and does not wish to – assume the sole responsibility for supporting prices. Thus in 2001, OPEC reduced its production by 5 million barrels per day, i.e. by nearly 20%, to prevent a sudden price fall. But, at the end of 2001, the organization was faced with a dilemma: it could reduce its production further and see its market share decline dramatically and non-OPEC producers profit from higher prices without participating in the loss of production, or maintain its export volume and inevitably experience a fall in the crude oil price. In fact, at the start of 2002, the major non-OPEC producers (Mexico, Norway, and most importantly Russia) joined OPEC in their efforts to maintain prices. Between 2003 to mid-2006, there was no longer any need for this debate. Globally production capacity was saturated and OPEC no longer needed to consider reducing its quotas. In the autumn of 2006, with the commissioning of new production capacity, a quiet political situation and mild weather, a tighter quota policy once again made sense. OPEC instigated massive production cuts in reaction to prices collapsing by a third, which stopped the decrease in prices and restored the organization’s credibility. Angola and Ecuador joined OPEC in 2007 and, despite Indonesia leaving in 2008 (which was logical as Indonesia had become an oil importer) OPEC increased its share of worldwide production to 44.8% in that year. At the end of 2008, the worldwide recession and a further collapse in oil prices once again made the cartel’s pricing policy a central issue. OPEC decided to reduce its quotas by 4 Mb/d over several stages, starting in September. It also tried to persuade other producing-countries (Russia, Mexico, Norway, etc.) to join in. Russia grudgingly agreed to a symbolic reduction since, during winter, Russian exports are reduced anyway because weather conditions limit tanker loading at the Novorossiysk and Primorsk terminals. OPEC may decide to invite new members to join. Although countries like Brazil and Kazakhstan have envisaged joining, there are no guarantees that a larger OPEC could maintain its unity. Would Brazil with its bio-fuels really be welcomed within the cartel? Would the complexity of relationships between the states surrounding the Caspian Sea allow countries such as Kazakhstan or Azerbaijan to join the cartel, without adversely affecting OPEC’s relationship with Russia? Would Russia be ready to compromise its foreign policy goals, particularly with respect to Iran, by participating in OPEC? Given their relations with Europe and the US, is it conceivable that Norway and Mexico could join OPEC? Wouldn’t the integration of Sudan within OPEC carry the risk of dragging the organization into regional African conflicts? A more reasonable solution to a massive and continuing fall in demand seems to be OPEC working with “associate” members.

extremely strong (4% per year from 2003 to 2007), while the fuel price increases seen by consumers were “tempered” by the significance of taxes in consuming countries and by price controls in emerging countries. A comment should be made on the impact of speculation. When it seems probable that economic growth will continue and the needs of emerging countries will rapidly increase – e.g. automobiles in China – an increase in oil prices appears inevitable. Commercial “funds” will therefore invest in oil – and other raw materials – thinking that prices will continue to increase. They of course make the trend in price increases more pronounced, but they do not create the increase, they follow it. 39

Chapter 1 Petroleum: a strategic product

Box 1.4 The Role of OPEC.

Chapter 1 Petroleum: a strategic product

1.2.7.3 The fall in demand and collapse in prices, from $147/barrel on July 11, 2008 to $40 at the end of 2008 Economic growth tumbled while oil production remained strong. Even the conflict in Georgia in August 2008 failed to slow the fall (however, the Russians bombed both sides of the BakuTbilisi-Ceyhan pipeline, the only outlet route outside the control of Moscow, to show that if they wished, they could stop exports from the Caspian). The fact that oil was abundant and consumption was stagnant or even declining, was finally recognized. OPEC reduced its production quotas by 0.5 Mb/d in September, 1.5 in October, and 2 in December. This stabilized prices in the $40-$50 range. Investment funds withdrew from the oil markets (and those for other raw materials) en masse. This seemed logical considering the price forecasts, but only strengthened the trend to lower prices. The fall in prices from $147 to less than $40 between July and December 2008 is in every respect similar to what occurred in 1986 at the time of the oil counter shock, when Saudi Arabia launched a price war to recover market share and prices fell from $28 to $8 between January and July. The reasons in both cases were the same: an oversupply of crude oil. The market forgets long-term considerations (anticipation of increasing and strong demand confronting limited future production) and focuses on short-term fundamentals.

1.2.7.4 The situation in 2011 After the price collapse at the end of 2008, and partly because of the reduction of OPEC quotas, the price of oil started to increase again and rose to $70 per barrel in mid-2009. This was close to $75 considered at this moment by King Abdullah of Saudi Arabia to be the right price for oil and the price needed to ensure the production of marginal supplies, i.e. synthetic oil from Canadian oil sands, the most costly liquid (obtained from non conventional oil) over the next few years. Economists were satisfied: the price of oil was close to the “long term marginal cost of production” or the cost of the most expensive barrel to produce in a few years to meet demand. This situation did not last and quickly the price increased again, flirting with $100/b at the beginning of 2011. Of course the revolutions in some MENA countries played a role. However it should be noticed that: • Prices over passed the “long term marginal cost of production” before the beginning of the movements in Tunisia and Egypt. • These revolutions had a limited direct effect on the oil production. Only in Libya oil production fell from 1,8 Mb/d to a very small quantity. Other OPEC countries had large excess capacities and could meet the lack of Libyan production, even if the quality of the crude was a problem (most of the excess capacity was for medium, sour crude, while the Libyan one is light, low sulfur). By mid 2011 the oil price remains “high” and the short term direction is difficult to predict. A price close to $100/b is the most likely forecast even if geopolitical events can provoke strong variations.

1.2.7.5 High oil prices – how do they affect demand? Although the two oil shocks of 1973 and 1979 resulted in demand falling by 15%, the increase in the price of a barrel from $10 to more than $100 between 1999 and 2008 had effects on demand that were slower and more limited. Several explanations for this have been advanced: 40

of the energy bill is also less. France spent nearly 6% of its GDP on its oil at the beginning of the 1980s but only slightly above 3% in 2007. More efficient use of oil, and an increase in the service sector’s share in the economy (services consume little energy) explain this. However, although oil has less weight in developed economies, it remains very significant for the poorest developing countries: in 2007 Senegal spent more than 8% of its GDP to purchase the oil it needed. • The proportion of taxes in the price of gasoline and diesel fuel lessens the impact of crude oil price variations in a number of countries. Generally in Europe, if the price of crude oil quadruples from $25 to $100 per barrel, the price of fuel at a service station only increases by around F0.50 per liter, which is 30% of the consumer price. • The price of a liter of gasoline represented half an hour’s earnings at the French minimum wage in 1981, but only less than 15 minutes in 2011 (when the price of oil is $100/b).

Box 1.5 What is the “Right Price” for Oil? While it is difficult to answer this question, there are several possible benchmarks that can be considered: – Production costs (excluding costs of capital) are less than about $5/barrel in the Middle East, and $10 to $15 in other producing countries. However they are $60 or more for the highest cost oil from difficult zones of the North Sea and synthetic oil obtained from the very heavy crude oil of Orinoco or oil sands (also called tar sands or crude bitumen) from Athabasca. – Most oil-producing countries who are members of OPEC depend on oil for 80% to 90% of their national revenue. Until roughly 2005, they prepared their budgets assuming an oil price of $20-$25/bbl. For example Algeria used $19/bbl for many years. Any revenue from higher prices was then used for exceptional expenditure (debt repayment, new equipment projects, etc.). This situation has changed and many producing countries now “need” a much higher price to balance their budgets. The price “needed” varies considerably from one producing country to another, but often exceeds $50/bbl. A new factor that must now be taken into account is the considerable increase that will apply to future total production costs arising from the substantial increase in capital costs. In recent years, these costs have increased by a factor of 2 or 3. Taking this increase into account, experts agree on a total production cost (including capital costs) of $60 to $80 for the most expensive oil. The price of oil is mainly determined by the balance of supply and demand. “Speculation” increases the volatility of price but does not affect the price level. Other factors: stock levels of crude oil and products, geopolitical events can at some time play an important role.

1.2.7.6 High oil prices – how do they affect supply? Non-OPEC production seems to be reaching its ceiling in many countries except for the CIS (in both Russia and countries of the Caspian region – Kazakhstan and Azerbaijan in particular) and West Africa. Only OPEC countries - and in particular the countries of the Middle East – seem to be able to increase their production significantly. Saudi Arabia has an actual production capacity of more than 12 Mb/d. Who will make the necessary investments in exploration and production? The five largest international oil companies (Exxon Mobil, Shell, BP, Chevron and Total) have jointly earned 41

Chapter 1 Petroleum: a strategic product

• The weight of oil in the economy is less than it was 20 years ago and so the importance

Chapter 1 Petroleum: a strategic product

more than $110 billion in profits every year from 2005 until 2008. In 2009 that total fell to under $70 billion. Results in 2010 were distorted by BP taking a pre-tax charge of $32 billion in relation to their Deep Water Horizon disaster, had it not been for that the total profit would have shown a substantial increase over 2009. Over the total period some of these profits were used to reduce their debt, which is now very low, and to reward shareholders. These companies have announced significantly increased capital expenditure. But prudence is still necessary: • The most promising basins are often not accessible to major international companies. OPEC member countries control 80% of reserves, and they are the lowest cost reserves to exploit. However, since the nationalizations of the 1970s, and notwithstanding the few exceptions which are discussed later, these countries overall remain reluctant to re-open their oil and gas industries to major international companies. Saudi Arabia and Kuwait are completely closed. Iran has opened itself to only a limited extent. Outside the Middle East, Venezuela has only opened marginal fields and reserves of extra-heavy crude oil to foreign companies. Outside OPEC, Mexico remains totally closed to non-Mexican companies and Russia has shown that it wishes to keep tight control over its reserves. This leads to the repeated refrain of international companies: “We lack profitable projects”. • Producing states adapt oil taxation levels to increase their share of the revenue when prices increase, leaving the foreign companies’ portion broadly constant (in dollars per barrel). This policy is consistent with a dominating political approach which sees mineral resources as an asset belonging to the nation and its people whose benefits (and sometimes the exploitation – see the case of Mexico in particular) must be reserved for nationals. State-owned companies (Saudi Aramco – Saudi Arabia, NIOC – Iran, PDVSA – Venezuela, Pemex – Mexico, Sonatrach – Algeria, NNPC – Nigeria, etc.) have not had the full benefit of the increase in crude oil prices. Their government only returns a portion of the oil revenues to them and retains the rest to finance their budgets. Of course, the high revenues of recent years have allowed major producing states to balance their budgets - or even achieve surpluses – in contrast to the difficult years of the 1990s. Nonetheless, in many cases the amounts left for the national oil companies have been insufficient for them to maintain and develop their oil production capacities. Since mid-2008, this position has been even more pronounced.

1.2.7.7 New oil nationalism The high oil prices of the period up to 2008 had important consequences for the principal oil producing countries’ policies. Their revenues have given them (temporarily?) far more independence from the major International Oil Companies (IOCs). Of course, for more than 30 years now, some countries – Saudi Arabia, Kuwait and Mexico – have operated a system in which their National Oil Company (NOC) holds a monopoly. Other countries (e.g. Venezuela), in which the presence of oil companies was limited, have recently reduced this presence even further through nationalization by legislation (Bolivia) or de facto nationalization (Venezuela decided to increase the national oil company PDVSA’s share in the project for exploitation of the extra-heavy oils of Orinoco, to 60%, leading to the withdrawal of Exxon Mobil and Conoco-Phillips from these projects in which they were the leaders). As well as their higher petrodollar revenues, continuing concern that major consuming countries will drastically decrease their oil consumption has made producing countries very prudent when considering any increase in production. Producing countries have blamed speculation for much of the increase in prices, have always insisted that the markets are wellsupplied and that they need security of demand in response to the security of supply called for by consuming countries. Why should they invest tens of billions of dollars in new 42

A few figures will help put the significance of oil price movements into context. If the price of oil were to remain at $75 for one year, the value of oil traded internationally would be greater than $2 trillion. This is approximately the value of French GDP. It is significant, but small when compared with 2007-2009 stock market “losses” amounting to $25 trillion, or the amounts available in investment funds (these funds include in particular the pension funds which receive contributions from American employees to fund their retirement), which amount to tens of trillions of dollars. Variations in the price of oil result in a significant shifts of resources from producing countries to consuming countries. Impact of prices for the major consuming-countries: the price of oil was only $61/bbl in 2009 compared with an average of about $100 in 2008 ($97 to be precise). France’s oil bill therefore fell from roughly $70 to $40 billion p.a. This decrease represented more than 1% of GDP. The gas bill was also lower because gas prices are still linked to the price of oil. The impact on inflation is also significant. The increase in oil prices was of great concern to European authorities since it brought inflation to a level of nearly 4% While this was still reasonable compared with the level of the 1980s (more than 10%), it was far above that of more recent years. The decrease in the price of oil – and of many raw materials at the end of 2008 – decreased inflation to a level of nearly zero. Impact of prices for poor countries: although emerging countries found it relatively easy to tolerate a significantly higher energy bill, the same was not true for less-advanced countries for whom the increase in prices was stifling. Their oil bill, for example in West African countries, frequently exceeded 10% of GDP, a level far greater than the few percentage points of GDP covered by governmental and privately funded aid. The bill remains high with current prices. Impact of prices for producing-countries: a high price is desirable for producing countries, since most depend almost exclusively on their oil and gas revenues to balance their budgets, and the minimum oil price needed to achieve this varies considerably from one country to another. It is the relatively low population Gulf countries that have accumulated significant financial reserves and whose sovereign funds have access to hundreds of billions of dollars: $40 per barrel is sufficient for the UAE, Kuwait, etc. It is much higher in countries like Iran and Venezuela, which have difficulties when the price drops below $80. Russia also depends significantly on its exports of oil and gas, since the price of gas is indexed to the price of oil. The fall in the value of the ruble at the beginning of 2009 reflected the importance of oil for Russia.

capacity, which will probably result in a decrease – or even collapse – in prices, if demand falls in several years time?

1.2.7.8 What price in future years? The process of experts forecasting crude oil prices has proved to be self-defeating. The forecast in the early 1980s that the price would exceed $100/bbl before 2000, promoted a fall in demand and an increase in supply. Similarly, the low prices of the 1990s discouraged investment and so were indirectly responsible for the increases of 2003-2008. Nobody expects the oil price to fall back to levels of below $60/bbl. The potential for increased demand remains very significant. If we want to “put China on four wheels”, i.e. allow Chinese citizens access to the same number of vehicles per inhabitant as the US, China will need the equivalent of the current worldwide consumption of oil, for “only” one-fifth 43

Chapter 1 Petroleum: a strategic product

Box 1.6 The Impact of Oil Prices on the World Economy

Chapter 1 Petroleum: a strategic product

of the world’s population. In addition, reserves of oil – although very large– currently show constraints that were not apparent in 1970 or 1980. The oil market remains subject to basic economic laws: all periods of high prices carry the potential for future prices to fall, since they tend to stimulate supply and moderate demand. Nonetheless, it seems probable that future price movements will continue to be both significant and unpredictable, while prices themselves will stay at a considerably higher level than in the 1990s.

1.3 THE OIL MARKET AND THE OIL PRICE The oil shocks gave a sharp impulse to inflation in Western countries. The events of 1973 were followed by a worldwide economic recession. Seen from our perspective at the beginning of the 21st century, movements in the oil price are likely to have less impact on economic growth. But the strategic nature of oil remains, even if less pronounced than in the past. This makes a good understanding of the mechanisms which determine price crucial. This is the subject of the present section.

1.3.1

Physical parameters which affect the price of crude oil

1.3.1.1 The quality of crude oil There are probably over 400 different qualities of crude oil. A specified quality may relate to a single oilfield for example the Ghawar (Arab Light) or Ekofisk (crude of same name) oilfields, or to blends from different oilfields: Brent blend, Nigerian crudes obtained by blending the outputs of numerous small deposits (sand lenses). In the latter case the blend must of course be adjusted to guarantee a constant quality. The value of a crude depends on the products which may be obtained from it. A light crude will yield a lot of gasoline, jet-fuel and diesel oil, while a heavy crude will yield more fuel oil, particularly heavy fuel oil. The prices of gasoline and diesel oil are considerably higher than that of fuel oil. The most commonly used unit for indicating the specific gravity of a crude oil is degrees API. This is a unit adopted by the American Petroleum Institute, and defined as follows: °API = 141.5/sg – 131.5 where sg is its specific gravity. Crude oils can be classified as follows: – Extra-light crudes (condensates): greater than 45 °API; – Light crudes: between 33 and 45 °API; – Medium crudes: between 22 and 33 °API; – Heavy crudes: between 10 and 22 °API; – Extra-heavy crudes: less than 10 °API. The value of a crude also depends on its sulphur content. The higher the sulphur content the more costly it is to process because the sulphur content of the different products is limited by their quality specifications. The latter are become increasingly severe due to environmental concerns. Generally speaking, light crudes have a low sulphur content while some heavy crudes may contain up to 5 or 6% sulphur, or even more. This is not a hard and fast rule however. 44

The most commonly quoted price for crude is the FOB (free on board) price. This is the price of the crude on board the vessel which will transport it at the port of origin (Ras Tanura in Saudi Arabia for Arab Light, Sullom Voe in the Shetland Islands for Brent, etc.). Prices are also quoted as CIF (cost, insurance and freight) which is the price at the destination port (New York, Rotterdam, Yokohama,…). In principle there is only one FOB price for a given crude at a particular time, but as many CIF prices as there are destination ports. Two crudes of the same quality should have the same price when delivered to the refiner, otherwise the refiner would choose the cheaper of the two. If two crudes of the same quality are produced from different oil fields, the price differential between them should represent the difference in transport costs. Suppose that two crude oils with the same characteristics are produced, the first in the North Sea (loading port: Sullom Voe), the second in Nigeria (loading port Bonny). Assuming that the transport cost between Sullom Voe (North Sea) and Rotterdam is $0.50/bbl, and that between Bonny (West Africa) and Rotterdam is $1.00/bbl, then if the North Sea crude sells at $25/bbl FOB the West African crude would have to sell at $24.50/bbl to compete.

1.3.2

Mechanisms for setting the price of crude: history

1.3.2.1 Initial approach: posted prices Between 1859 and 1870 the price of crude oil varied considerably. Demand was growing rapidly while supply fluctuated depending on discoveries made: the arrival of substantial volumes of new oil on the market could result in a collapse in prices. Prices fluctuated between up to about $20 and several tens of cents per barrel. In the very early years exchanges were set up in which oil was freely traded. The Rockefeller era saw greater stability in prices. Standard Oil controlled most of the refining capacity and distribution infrastructure in the United States, and sought to prevent large variations in price so as to foster demand. This was the time when the system of “posted prices” was developed. Faced with a very wide range of different crudes, the refiners, and specifically John Rockefeller’s Standard Oil, posted the price at which they were willing to purchase crude at the refinery gate. Posted prices were introduced in other areas by the oil companies, after World War II as the price at which they were prepared to sell the crude. Posted prices were used as a reference for taxes calculation. They were abandoned in the 70’s as a result of fields nationalisation.

1.3.2.2 The inter-war period in the U.S.: the system of pro-rating The break-up of Standard Oil, on the other hand, tended to increase competition, since the number of oil companies suddenly rose sharply. During and immediately after the war the price of crude climbed (from $1.20/bbl in 1916 to $8/bbl in 1920). However the nature of the American market was significantly modified by a large number of discoveries of oil, in California (Signal Hill oilfield), Oklahoma (Greater Seminole in 1926) and Texas (East Texas in 1931). Piecemeal and chaotic oil extraction also contributed to a collapse in the oil price. The fact that in the U.S. landowners also own the mineral rights means that when oil is discovered on someone’s land, all his neighbours will have an incentive to also drill and produce oil themselves. This fact can result in gluts of oil on the market, and also to the inefficient exploitation of oilfields, which are rapidly depleted (Fig. 1.36). 45

Chapter 1 Petroleum: a strategic product

1.3.1.2 Location

Chapter 1 Petroleum: a strategic product

1 2 3

Figure 1.36 Cut-throat competition led to the rapid exhaustion of oilwells (From Lucky Luke comic book “À l’ombre des derricks”, © Lucky Comics, by Morris and Goscinny). 1. Your well is running mine dry. 2. I got here first. 3. As soon as an oilwell starts producing, other people start drilling next door to benefit from the oil field! When wells start interfering with each other’s production, litigation follows.

The fall in prices in the early 1930s provoked social unrest and riots. The authorities were forced to intervene to control production. This meant putting a stop to anarchical oil extraction activities, which proved to be hugely wasteful, and matching production to demand. An inter-state committee was set up to distribute production quotas set by the Bureau of Mines between the various states, and to set prices. This system of “pro-rating” was established in Texas by the famous Texas Railroad Commission.

1.3.2.3 From Achnacarry (1928) through to the post-war years The system of pro-rating resulted in the isolation of the American market (which at that time absorbed almost half the world’s production of crude) from the rest of the world, where the majors were in cut-throat competition with each other. When prices again fell, in 1928, the main leaders of the oil industry (in particular Henry Deterding, Chairman of Royal Dutch Shell, Walter Teagle, President of Standard Oil of New Jersey and John Cadman, President of Anglo-Persian) got together in a castle in Achnacarry in Scotland. The objective, apart from shooting grouse, was to coordinate the actions of the main oil groups so as to curtail the impact of this disastrous competition. The participants reached an agreement which advocated action to prevent surplus capacity, allocated a market share to each group in each of a number of zones and limited competition in acquiring new markets. As far as prices outside the U.S. were concerned, the rule since the end of the nineteenth century had been: any product, whatever its origin, is sold throughout the world as if it had originated from New York. This practice was justified by the American dominance, and in particular the dominant position of the East coast. The Achnacarry agreement perpetuated this principle in a slightly modified form: since Texas had now become the centre of world 46

This formula was first challenged during the war. The American and British navies discovered that it increased their refuelling costs considerably. The oil companies therefore accepted that a second point of reference for pricing should be established in the Arabian Gulf. The FOB price there was aligned with the price in the Gulf of Mexico. After the war the situation changed further. Europe was importing more and more crude from the Middle East. The European Cooperation Administration (ECA), whose job it was to manage the aid provided by the U.S. under the Marshall Plan, sought to reduce the cost of oil imports, which was absorbing a large part of the American aid. Furthermore it was in the interests of the oil companies to develop their production in the Middle East: per barrel costs were low there and could be reduced even further if the volumes produced and exported could be increased. After the war there was a growth in oil imports to the East coast of the U.S. which involved the adoption of a new system of so-called “posted” prices (1949): the FOB price of a crude was set at a level such that its price in New York would be the same as a crude from Texas.

1.3.2.4 Taxing revenues; the generalisation of posted prices During the 1940s the idea gradually took root in Venezuela that the wealth generated by oil should be shared equally between the producing country and the oil companies (see Box 1.8). In 1948 a 50/50 scheme was adopted: half of the profits from the production of oil would accrue to the company and half to the producing country. This principle spread to other countries, particularly in the Middle East. It should be noted that if the international and particularly the American companies accepted this regime relatively easily, this was because their costs were fairly limited: taxes paid to the local authorities would be deductible from the taxes paid in the United States. And if the U.S. government did not object, this was because the U.S. had become an importer and because production costs in the U.S. were very high. An indirect consequence of the imposition of a tax on revenues was that the posted prices system spread to all large producing countries. Before then the prices of crudes at the wellhead or at ports were book prices set by different operating companies within a group. Posted prices were, initially, real selling prices. But as production expanded, significant reductions in costs were possible. It became general practice to apply reductions, and the posted prices were periodically revised downwards. There were other changes: royalties began to be regarded as a cost rather than as an advance on tax. This amounted to increasing the taxation of companies by one-half of the royalties. After the large price increases of 1973, producing countries replaced the posted price by the Government Official Selling Price, which was taken as the basis for the calculation of the royalties and taxes, in the countries which had not fully nationalised their fields. The rates were increased sharply. Royalties rose to 20% and more, the tax rate to 55%, and later 80 or 85%. The objective of producing countries was clear: to retain for themselves the lion’s share of the profits, leaving the oil companies a more or less stable income per barrel. After the oil counter-shock (1986) however, the converse happened: royalty and tax rates fell to ensure that the operating companies still had a financial incentive to explore and produce. 47

Chapter 1 Petroleum: a strategic product

production, the system was based on the “Gulf plus” pricing agreement. All oil products would be sold anywhere in the world at a price equivalent to the Gulf of Mexico FOB price, to which would be added the transport cost from the Gulf of Mexico to the country of destination. After the major discoveries at the end of the 1930s, this system favoured and continued to favour Middle Eastern oil because of the low production costs applying there.

Chapter 1 Petroleum: a strategic product

Box 1.7 The legal and regulatory framework for oil production: the concession. Mineral rights are the property of the state, except in the US where they belong to landowners. An operator who suspects there is a deposit of oil on his land must seek permission from the state, which owns the rights, to explore and if successful, produce. There are several different types of contract (see chapter 5). The concession has long been the most common. In exchange for the payment of a sum of money known as a bonus and the acceptance of a number of obligations, the operator obtains the right to explore for a certain number of years and, if he makes a discovery, to extract the hydrocarbons. A company holding a concession must pay a royalty to the state (the owner of the mineral rights) for each barrel produced. This royalty compensates the state for the removal of a non-renewable resource. The amount varies considerably, but is frequently of the order of 10-15% of the price of the crude. In addition, producing companies pay a tax on their profits to the state. The cost of obtaining the crude is therefore the production costs plus the royalty plus the tax. For example: Example of cost of obtaining crude, Middle East, 1960s Posted Price: $1.80/bbl Production cost: $0.20/bbl Royalty (12.5% of posted price): $0.225/bbl Gross profit: $1.375/bbl Tax (50%): $0.6875/bbl Total cost of obtaining crude: $0.20 + 0.225 + 0.6875 = $1.1125/bbl Receipts of the state: $0.225 + 0.6875 = $0.9125/bbl Company’s net profit: $0.6875/bbl

1.3.2.5 After the counter-shock: spot markets, futures markets From the Second World War until the second oil shock, there were shorter and longer periods of price stability. These were the prices posted by the majors from the end of the war until 1973, or the official prices set by governments between 1973 and 1985. Before 1985, free market mechanisms, where cargoes of crude or of products were traded outside the control of the major producers played very little part. The second oil shock transformed this situation. At the end of 1978 and for many months thereafter the prices on the free market were in excess of the official prices. This led to an understandable tendency on the part of certain producers to dispose of increasing volumes of crude on these markets. But on these free markets, the prices are also free, being fixed on a day-to-day basis, cargo by cargo. This is the “spot” market. It should be mentioned that after 1981 the reverse situation applied, with the spot prices being lower than the official prices, a situation which led to the lowering and eventually the disappearance of the official prices. In practice, only a small number of crudes were traded very actively, thereby supporting a spot market. The prices set in a market can only be accepted by the parties concerned if there are many buyers and sellers. In most of the large exporting countries the number of sellers remains very small. This is why the spot markets concentrate particularly on several North Sea crudes (Brent in particular), on West Texas Intermediate in the U.S. and on Dubai in the Middle East. From that time on, spot prices began to drive the physical markets. The major exporters began to fix the FOB price of their crude by reference to the spot price of Brent (for crudes 48

Box 1.8 Futures and derivatives markets. Futures (contracts) Because spot prices are very volatile, the need arose for an effective means of hedging against loss due to unfavourable price movements. Various exchanges have opened up markets for futures contracts in crude oil and refined products. These are financial markets. They do not involve exchanges of physical goods, but are standardised contracts (futures) of a financial nature. The physical exchange, takes place, if at all, when the contract expires in the future (whence the name of the contract) in month m + 1, m + 2,….., the term being stipulated in the contract. The price is determined at the time the contract is made. In most cases operators never actually get as far as a physical exchange, but sell their contract before it matures (close their position). Derivatives These are a range of financial products of varying degrees of sophistication associated with other types of asset or commodity, also suited for use with crude oil and petroleum products. The most common derivatives are options and swaps. Options The purchase of an option gives the holder the right (but not an obligation, as in the case of a futures contract) to buy or sell a standard quantity at a given fixed price. A right to buy is referred to as a call option and the right to sell is a put option. An option is characterised by: – the underlying asset: the asset which can be bought or sold; – the exercise price: the fixed price at which the buy or sell can be effected; – the premium (option price): the sum paid to the seller of the option; – the maturity date: the date at which the option can be exercised. Swaps These are financial contracts which allow an operator to swap a variable price for a fixed price. An airline wishing to know what it will pay for kerosene can effect a swap contract with a trading company. The airline will buy the kerosene at the price applying on the day of purchase, but will receive the difference between that price and the reference price if this difference is positive, or will pay this difference if it is negative.

49

Chapter 1 Petroleum: a strategic product

sold in Europe), WTI (for crudes sold in the U.S.) or Dubai (for crudes sold in the Far East). Thus, the FOB price of Arab Light sold in Europe is indexed on the price of Brent, i.e. equal to the price of Brent less a differential reflecting both the difference in quality and the difference in transport costs. Spot markets developed relatively rapidly. Before 1973 when the producing countries took control of their petroleum resources the international companies were highly integrated and almost all trade took place within the framework of long-term contracts. Spot markets were almost non-existent. In 1973 only 1% of transactions were effected on the spot markets, but by 1980 spot transactions accounted for 20% and by the end of the 1990s the proportion was about one-third. In most contracts for the delivery of crude oil or refined products, whether short or long term, the prices are now indexed to spot prices or quotations on the futures markets. Around 1980 forward and futures markets began to develop for some crudes and refined products (see Box 1.8) to deal with the financial risks associated with the volatility of prices resulting from the development of spot prices. The new markets had a considerable impact

Chapter 1 Petroleum: a strategic product

in making for a more flexible market. The relatively low transport costs and the differences in price between crudes of similar quality led traders to deal very rapidly for arbitrage4, because market information is available in real time on computer terminals worldwide. Many analysts ascribe the relative stability of prices (or more precisely the speed with which prices regained their pre-war levels) at the outbreak of the Gulf war in 1990-1991 to the existence of futures markets rather than the announcement by the IEA that strategic stocks would be used. The ability to purchase oil forward has effectively made it pointless to accumulate stocks speculatively, a practice which is thought to have contributed to the second oil shock. But speculative behaviour on these “paper” markets can also amplify the price movements caused by uncertainties related to the weather, stock levels, etc. In general, a small mismatch between supply and demand can strongly influence price. The influence which market developments have on price volatility remains a matter of debate. Box 1.9 The futures markets. Spot and future price of gas oil in London a. Spot price (in red) and future price (in blue) up to July 2008 $/b 140 120 100 80 60 40 20 0 1995

1997

1999

2001

2003

2005

2007

2009

2011

2013

2015

2013

2015

b. Spot price (in red) and future price (in blue) from July 2008 $/b 140 120 100 80 60 40 20

0 1995

1997

1999

2001

2003

2005

2007

2009

2011

Source: Total. 4. Arbitrage consists of exploiting differences between two markets for a given product. If, for example, the price difference is greater than the transport and transaction costs then arbitrage consists of buying the product at the lower price and selling it at the higher price.

50

Economic analysis of price formation

1.3.3.1 Long-term price formation. Oil as an exhaustible resource. The first oil crisis revealed the exhaustibility of oil resources, something that had been overlooked during the previous decades, when large discoveries were being made in the Middle East and production increased rapidly. In 1974, economists, following R. Solow [1974], rediscovered Hotelling’s Rule (see Box 1.10), according to which the price of a nonrenewable resource increases at a rate equal to the discount rate (when operating costs are negligible). Consequently, crude oil prices reflect its scarcity rather than production costs. Prices observed after 1973, but also after the second oil crisis, have been felt to be consistent with a model based on Hotelling’s rule that incorporates the latest assumptions for each period for reserve volumes, the price of alternative energy sources, and demand elasticity. This law is still referred to, explicitly or implicitly, by a number of economists5. The theory is based on the premise6 that resources exist in limited quantities and will have to be replaced when they are exhausted either by some other good or by an alternative technology (backstop technology) at a higher cost. Until the mid-1980s, the resource in question could be considered to correspond to “conventional” oil. Available backstop technologies (non-conventional hydrocarbons, biomass and other renewable energy sources, nuclear energy, liquid fuels obtained from coal) appeared to be accessible only at a cost that was considerably greater than oil prices could support. At least this was the case for “white” products, fuels and petrochemical feedstock.

Box 1.10 Hotelling’s Rule of exhaustible resources. Harold Hotelling, a prolific economist active in the nineteen twenties and thirties, is generally considered to be the founder of the theory of exhaustible resources, following a pioneer article by L. C. Gray (1914). His work was rediscovered in the 1970s and brought to attention by a no less famous article by R. M. Solow (1974). We note, however, that Edmond Malinvaud (1972), even though his article is less cited than Solow’s, had discovered “Hotelling’s Rule” a short time earlier using a different approach. This rule, for the case where the cost of production is negligible, states that the price of an exhaustible resource increases at a rate equal to the real rate of interest (or, using a more contemporary approach, to the discount rate). If the cost of production is not negligible, it is the rent (marginal cost price) that must increase at the discount rate. The theory is rigorously developed (calculus of variation or control theory) but can be explained very simply. If the price of the resource is stable (or increases at a rate less than the discount rate), it would be in the interest of producers to produce goods as quickly as possible, which would cause the price to drop. If it were to increase at a higher rate, producers would delay production to take advantage of a higher discounted value. The only change that would allow for market equilibrium is, therefore, the one that makes the discounted value of future unit revenues stable, thus an increase at a rate equal to the discount rate.

5. For example, see P. Artus (2005). 6. It is also based on different assumptions of the rationality of supply and demand behavior, and, at least in its initial version, perfect information.

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Chapter 1 Petroleum: a strategic product

1.3.3

0 200

Gulf of Mexico

USA

400 600 800 Water depth (m)

Chapter 1 Petroleum: a strategic product

The situation has changed since then. The belief, up until 1985, in an ineluctable growth in prices stimulated significant research and development efforts. The resulting technological progress has led to the discovery of hard-to-find deposits, to noticeable improvements in rates of recovery, and to the development of “non-OPEC” oil, especially offshore. After the 1986 price drop, these efforts were continued and led to a sharp decrease in exploration and production costs in non-OPEC countries, especially for deep-sea oil. The frontier between conventional and non-conventional oil (deep-sea oil, extra-heavy oil, tar sand) is regularly being pushed back. Producers can now access offshore deposits at increasingly greater depths using technologies that are constantly being improved. Figure 1.37 illustrates the progress made in this field. The difference between the production costs of offshore and on-shore oil is decreasing. As indicated above, the extra-heavy oil in the Orinoco Basin in Venezuela was, until the 1990s, considered to be practical to produce only at a relatively high price per barrel of crude (at the time, $40 or more). This oil is now produced for a relatively low price, and large-scale production has begun. We’ll discuss the technological costs in the following section. In fact, there is a continuum of hydrocarbon resources: deposits that are difficult to access, traps that are more complex and harder to detect, deep and very-deep offshore sources, extraheavy oil, tar sand, oil shale, and so on. The traditional distinction between conventional and non-conventional oil makes little sense today. Moreover, this continuum is not limited to oilbased hydrocarbons. Considerable research has been done on the development of technologies for producing liquid fuel from natural gas (gas-to-liquid, or GTL, technologies using the Fischer-Tropsch process) and coal (coal-to-liquid, or CTL, technologies using direct liquefaction or indirect liquefaction after gasification). These technologies will be discussed below. This continuum extends to biomass fuels that make use of available products or processes (ethanol, ETBE, vegetable oils, methyl esters of vegetable oils) or those that are currently being researched (ligno-cellulose or biomass-to-liquid, BTL). In the more distant future, we may be able to develop technologies for the “carbonation” of hydrogen produced

1000

Brazil (Petrobras) Adriatic (Agip) Brazil (Petrobras) 1027 m

Gabon

1200 1400

Congo Brazil (Petrobras) 1709 m

1600 1800

Brazil (Petrobras) 1852 m

Mediterranea sea

2000

Gulf of Mexico (Total) 2197 m

2200 2400

Gulf of Mexico Texas 2370 m

2600

Gulf of Mexico (Shell) 2307 m

Gulf of Mexico Norway (Chevron) 2400 m (Statoilhydro) 2430 m Gulf of Mexico Gulf of Mexico (ChevronTexaco) 3051 m (Unocal) 2955 m

Brazil (Petrobras) 2777 m

2800

3000 1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 2012

Figure 1.37 Records for offshore drilling.

52

1.3.3.2 Production costs The average and marginal costs of production are the first elements used to analyze price formations. Average production costs, for conventional crude oils, are between a few dollars per barrel for the largest and easiest fields to develop (Middle East), up to $60/b in the most difficult areas. To complete this study, we need to provide some idea of the costs of non-conventional oil, synthetic hydrocarbons, and alternative fuels. A. Extra-heavy oil and tar sand The average cost of production of Venezuelan extra-heavy oil is on the order of $20-30 a barrel, with variable costs on the order of $10-15 a barrel. Average costs could be around $20 a barrel for new projects. These are costs associated with so-called “cold” production, that is, using natural drainage in horizontal wells, a technology that leads to rather low rates of recovery (8 – 10%). The injection of steam would increase costs but would result in appreciably better rates of recovery. The cost of oil extracted from the Athabasca tar sands —oil sands— fell to low levels before the rise in gas prices, to which production costs are highly sensitive. Production can

Production costs (2008 dollars)

140 Enhanced recovery

120 100

Ultra deepwater

Artic

CO2 injection

Coal to liquids

80 Gas to liquids

Other conventional oil

60 40

Oil shales Already

20 produced MENA* 0 0

1000

2000

Oil Sands

3000

4000 5000 6000 7000 Resources (billion barrels)

8000

9000 10 000

* MENA : Middle East and North Africa

Figure 1.38 Oil cost curve, including technological progress: availability of oil resources as a function of economic price (Source: IEA).

53

Chapter 1 Petroleum: a strategic product

from nuclear or renewable energy sources (Bauquis, 2004) or, to put it somewhat differently, carbon hydrogenation (hydrogen-to-liquid, or HTL, technology). Within several decades there will be no hydrocarbon (natural plus synthetic) resource limitation, but there is and will be a need to make use of more complex and more costly technologies (as currently perceived) as conventional deposits are exhausted.

Chapter 1 Petroleum: a strategic product

be made by use of mining technologies or petroleum technologies with steam injection (steam assisted gravity drainage, SAGD). The latter technologies consume natural gas for the production of heat at a rate that is at least twice as great as that for mining technologies. (The steam injected into horizontal wells fluidizes the crude, which is collected in other horizontal wells situated at a lower level). In addition to extraction costs, we should take into account so-called “upgrading” facilities, which convert ultra-heavy crude with an API gravity of 9 to 11 degrees into lighter, “synthetic” crude of 25 to 35 degrees API. While the use of oil shale has been around for a very long time, the process requires very high energy consumption. Research is being done in this area, especially by Shell in Colorado, using techniques for the transformation of kerogen by in situ heating. However, it is unlikely that this research will lead to any significant commercial production before 2020. “Oil shale” (a very thick product squeezed in rock) should not be confused with “shale oil”, a good quality oil located in the source rock and which can be produced by fracturing techniques. B. Synthetic hydrocarbons obtained from coal and gas There are two methods for producing synthetic hydrocarbons from coal (coal-to-liquid). One entails direct conversion through the hydrogenation of coal, the other makes use of indirect conversion, coal gasification initially producing a synthesis gas (CO + H2), which is then transformed into liquid hydrocarbons by the Fisher-Tropsch process. The products obtained, primarily diesel fuels, are of excellent quality (free of sulfur and with a very high cetane number). During World War II, Germany made use of both types of processes. Currently the only factory of industrial capacity still using the Fischer-Tropsch process is the Sasol plant in Segunda in South Africa. Several facilities are currently under project in China. As for the direct hydrogenation process, a large-scale project is currently underway in China, with the participation of the IFP Energies nouvelles-Axens group (providing technology and engineering). Prior to the recent rise in the price of steel, raw materials, and services, CTL technologies were considered profitable for per-barrel prices of $50 and above (excluding costs associated with CO2 emissions) for production units located near low-cost mines. Since then, estimates of breakeven points have been revised upwards to around $70 – 80 a barrel. Recall that coal reserves represent on the order of 100 years of production at the current rate (with considerable uncertainty however). The limitations of CTL will most likely arise not from constraints on raw materials but from the costs associated with CO2 emissions. The production of liquid hydrocarbons from natural gas (gas-to-liquid) also makes use of the Fischer-Tropsch process. The first plant of this type was built in 1991 by Mossgas (now Petro SA) in South Africa. Shell then brought on line a 14,500 barrels-per-day (b/d) facility in Malaysia. The rise in oil prices that began in 2000 has promoted studies for several new projects. Two of them have been built in Qatar, the first with a capacity of 34,000 b/d by Sasol, the second by Shell (70,000 b/d in the first phase and 70,000 b/d in the second phase, for a total capacity of 140,000 b/d). The first started operation in 2007, the second in 2011. The announced costs should be on the order of $25 per barrel when the gas is produced at low cost and supplied at low price ($0.5 – 1/MBTU) to produce high-quality diesel fuel. The higher cost of raw materials and services seen since 2004 has raised the stakes. With unit investment costs that are three times greater and a higher gas price, the Shell project would only be profitable with high crude prices. The success of these initial projects will have a 54

C. Biofuels The biofuels used today, so-called first-generation fuels, consist primarily of ethanol for gasoline engines and the methyl esters of vegetable oils for diesel engines. In 2010 worldwide production of ethanol fuel was 70 million tons compared to 7 million tons for biodiesel. Brazilian ethanol is produced from cane sugar at costs similar to, if not less than, those for traditional gasoline. Outside Brazil, the cost of biofuels is higher than that (excluding taxes) of oil-based fuels. Their contribution to the reduction of CO2 emissions is controversial. Their substitution potential for oil-based fuels is limited to a few percent because of competition with food production. To go further it will be necessary to develop second-generation systems, which make use of ligno-cellulose biomass (wood and straw). Optimistic estimates indicate a substitution potential of 30% by 2030. Biomass-to-liquid (BTL) systems involve gasification of the biomass followed by the production of kerosene and diesel fuel using the Fisher-Tropsch process. The second method is comparable to the production of ethanol by fermentation. These approaches are subject to considerable research in an attempt to reduce production costs, which would be on the order of a euro per liter of oil equivalent at the present time. D. The role of technological progress What about future developments? The hydrocarbon resources constituting the continuum mentioned above could be classified today by increasing cost. It is therefore likely that with the exhaustion of deposits that are easy to access, costs and prices will increase. This is not certain, however. Recall that in the early 1980s all the published scenarios for the development of oil prices pointed upward and technological progress played a determining role in proving those assumptions wrong. But if there is one field in which forecasting is an especially difficult art, it is that of technological change. There are many examples of this. In the energy sector, aside from the spectacular drop in production costs for extra-heavy oil already discussed, there have been improvements in the yield of combined cycle electrical production plants. Progress is often faster than anticipated, although it does not always occur when we expect it, as the case of nuclear fusion illustrates. Fifty years ago, it was believed that it could be controlled for applications to produce electricity within 35 to 50 years. We are still talking about a fifty-year horizon today, with little certainty about commercial prospects.

7. “Les pics mondiaux du pétrole et du gaz” [Global Peaks in Oil and Gas], presentation to the Conseil d’Analyse Stratégique, Paris, Oct. 28, 2006.

55

Chapter 1 Petroleum: a strategic product

decisive effect on developments in this field. Different projects are being studied but developments will probably remain limited to niche production activities. Another drawback: costs do not include the cost of CO2 emissions, and GTL like CTL involves a significant consumption of energy. Additionally, opportunities could be limited by the appearance of the global production “peak” for gas, which could follow the oil “peak” by ten to fifteen years, based on estimates by P. R. Bauquis7. Note, however, that according to other authors, the uncertainties concerning peak gas are stronger than those for peak oil. In particular, in the distant future shale gas reserves are large and we cannot exclude the development of production technologies that make use of methane hydrates (clathrates). These resources are poorly understood at present but could become highly significant.

Chapter 1 Petroleum: a strategic product

1.3.3.3 External costs and greenhouse gases Available options in the energy sector must take into account concerns about climate change. Greenhouse gas emissions, associated with the use of fossil fuels, increase the temperature of our atmosphere. By the end of the century, the change could amount to as much as 1.5 to 6 degrees Celsius on average, according to experts from the Intergovernmental Panel on Climate Change (IPCC). Although there are considerable uncertainties about the scope and consequences of such emissions, there appears to be little doubt that it will lead to an increase in the frequency of “extreme events,” including violent storms, floods, and heat waves. In spite of the United States’failure to ratify the Kyoto Protocol, European Union directives adhere to the logic of the commitments made in Kyoto, and a European market for CO2 emissions permits has been in place since January 1, 2005. The different steps that will need to be taken to limit emissions will entail costs that will have to be tied to hydrocarbon use. Many analysts feel that constraints on greenhouse gases will have a greater effect on limiting the use of fossil fuels, and oil in particular, than resource scarcity. Steam-assisted recovery, the processing of extra-heavy fuel, the use of tar sand or oil shale, and the conversion of gas or coal into liquid hydrocarbons all require high energy consumption and result in significant CO2 emissions. The internalization of the corresponding external costs or the use of Carbon Capture and Storage (CCS) can modify the hierarchy of direct costs. This may restrain the development of non-conventional oil and assisted recovery processes intended to increase recovery rates. In this area technological progress plays a key role. To limit CO2 emissions, the heat needed for assisted recovery projects and the production of non-conventional oil can be provided by nuclear reactors. The carbon capture and storage provide a number of alternatives, but the development of the corresponding costs is difficult to predict. Reduced CCS costs could promote new developments in the coal industry.

1.3.3.4 Geopolitical factors and short- and medium-term price formation Oil is a strategic asset for producing and consuming countries alike. Two-thirds of global reserves of conventional crude are located in the Middle East and 80% of proven global reserves are owned by national companies. We all know how oil has influenced political events and the repercussions political events have had on the oil market. Oil market is a global market to the extent that transport costs are low and much lower than those associated with other energy sources. Geopolitical issues, therefore, are considerably different for oil and natural gas, which are related energy sources. Events that have had a major impact include the Six-Day war and Arab embargo, the Yom Kippur war, the Iranian Revolution, the Iran-Iraq war, and the two so-called “Gulf” wars. Figure 1.26 presents a summary of the history of the price of crude in relation to some of these events. Although of more limited impact, the uncertainty in Venezuela concerning the policies of President Chavez, or Europe’s fears concerning Russian supplies, in particular issues related to energy transport through gas and oil pipelines, are important. OPEC’s decisions also play a significant role in geopolitical events. However, although the 1973 conflict was a factor in triggering the first oil crisis, the price rise was inevitable given the increased demand (7 – 8% annually), which rose at a considerably faster pace than the increase in production capacity. Finally, in the producing countries the willingness to allow international companies to exploit natural resources is the result of political decisions. In Mexico and Saudi Arabia, for example, oil exploration and production are a monopoly of PEMEX and ARAMCO 56

A. The cartel Ever since the first oil crisis, increases in crude oil prices have been considered the result of behavior by the OPEC cartel8, with Saudi Arabia playing a dominant role. Outside periods of sharply rising and falling prices, it has served as a price regulator, by agreeing to be the (or the principal) swing producer. To meet demand, the country increased sales in 1977 – 78. In 1979 – 80, limited by its production capacity, it was unable to meet the increased demand that was partly the result of speculative behavior (following the Iranian revolution) and allowed prices to “float.” To maintain them at their new level, it reduced production from 1981 to 1985. This situation is atypical, however. The Persian Gulf reserves, which are very inexpensive, should be sold before those with a higher marginal cost, assuming the existence of centralized global economic management or the presence of a competitive environment. The result was just the opposite, however. When demand contracted following the introduction of alternative energy sources and energy saving policies, non-OPEC production, as a result of the technological progress mentioned above, continued to grow while OPEC production fell, especially in Saudi Arabia. In 1985 it hit bottom (2.5 mb/d compared with 11 in 1980). The decline in revenues led to tensions within the organization. Saudi Arabia decided to regain its market share. This was the start of the “counter shock” and the drop in oil prices (figure 1.26). What is the role of the market when Saudi Arabia has the will and ability to regulate activity? R. Mabro once quipped that Saudi Arabia and the market divide the work of determining crude oil prices: Saudi Arabia gets to determine the first two figures before the decimal point, while the market gets to determine the two figures following the decimal. Note that Saudi Arabia assumed the bulk of production reduction efforts between 1980 and 1985, but it refused to act alone in this role in 1998 – 99. The time needed to rally its OPEC partners as well as non-OPEC producers (Norway, Mexico, Russia) explains the lag before prices found a level that was considered satisfactory by the producing countries. In the interval, the low price levels led some analysts to speak of a loss of power on the part of OPEC. However, between 2000 and 2003, including during the American intervention in Iraq, OPEC demonstrated that it could exercise close control over the situation to hold prices within the range ($22 – 28 a barrel) it had established in March 2000, or at least could maintain the lower limit. The possibilities for regulation disappear, however, when excess production capacity is inadequate, as was the case in 1979 and from 2004 to 2009.

8. More specifically, it is a dominant oligopoly with a competing fringe. The Arab countries with small populations and extensive reserves (Saudi Arabia, Kuwait, the Emirates), whose cash flow needs are less pressing and can more easily limit production, constitute the core of the oligopoly (see, for example, P. N. Giraud [1995]).

57

Chapter 1 Petroleum: a strategic product

respectively, which are national companies. In Iran, foreign companies have limited access to the market. The country has created an original type of contract known as the “buy back” contract, which is a short-term risk-service contract. It is designed to adhere to the principles embodied in the Iranian constitution, according to which the state has a monopoly on the development of petroleum resources. Such complex contractual arrangements represent a significant limitation for the host country and for international firms. For the past several years, we have seen how the Russian government has reasserted control over the oil and gas sectors; and more recently Latin America (Venezuela, Bolivia) has followed suit.

Chapter 1 Petroleum: a strategic product

B. The restoring force of the market Along with P. N. Giraud [1995], we can consider that there isn’t a single equilibrium price (or a single pathway for equilibrium prices) but a range or spread whose limits are difficult to quantify. Within this range, Saudi Arabia and its partners can maintain a consistent price. But if the price is too high (the 1980 – 85 period), the market’s restoring forces, notwithstanding inertia, become effective: alternative sources, energy savings, investment in nonOPEC regions. Moreover, among the members of the cartel, the temptation to ignore quotas increases whenever prices are high. As Sadek Boussena9 remarked, “OPEC is strong when prices are weak, but weak when prices are strong.” The temptation becomes even greater when there is significant overcapacity. Thus, it is even more difficult to conclude agreements designed to distribute additional limits on capacity among the members of the oligopoly. On the other hand, when prices are low, investments by exploration and production companies are scaled back because of the reduced profit potential of new projects as well as a limitation on financing ability. Low prices also promote increased consumption, which can increase more rapidly than the growth in production capacity. This was the situation observed between 1998 and 2000. Moreover, considerable degradation in revenue could, in some countries, result in the growth of social movements and political instability that all participants seek to avoid. We could summarize this by noting that in the petroleum industry, as in the majority of other industries, production capacities are sometimes excessive, sometimes saturated. When there is excess capacity, as always prices trend downward. It is primarily in such circumstances that OPEC can intervene. When production capacities are saturated, the price increases until capacities are restored. Since 2004 not only has excess production capacity been strongly reduced but refinery processing capacity has been saturated. The initial question was whether, following a transitional “squeeze” between supply and demand, prices could return to an equilibrium not very different from that of the 1990s, or if the rise seen in recent years reflects a structural modification, the increase in demand necessitating the search for production sources at higher marginal cost. Since 2005 many economists and politicians have come to believe that the latter is the correct view, and speak of a “paradigm shift” in the price of oil and other energy sources. For the restoring force to be effective, several conditions are needed. For decisions to be made, actions to be taken, and investments made, it is not enough for prices to be high, one must assume they will remain high. C. Expectations Investment decisions are naturally based on assumptions about demand and medium- and long-term prices. But price forecasts are always difficult and, it is worth pointing out, in the petroleum market, often self-destructive. One especially relevant example relates to the 1985 price drop. Until then, all oil price forecasts pointed upward, as shown in figure 1.39, and this was true for several different scenarios. For example, in 1980 the French Commissariat Général du Plan had defined three scenarios that revealed increases, in constant money, of 2, 7, and 14% annually. Naturally, political decisions, such as those involving the French nuclear program, were made for reasons of energy independence ––these immediately

9. Associate professor at the University of Grenoble, former Algerian Energy Minister, former president of OPEC.

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Chapter 1 Petroleum: a strategic product

100 90 80

1980-1981*

Constants $

70 60 50

1982* 1983*

40

1984*

30

Real

20 10 0 1972

1976

1980

1984

1988

1992

1996

2000

2004

2008

* Price forecast of the year shown

Figure 1.39 Changes in crude oil price forecasts.

followed the first oil crisis. But significant energy savings, the use of alternative energy sources, research and development, and investments in the exploration and production of “difficult” oil in non-OPEC regions occurred not simply because the price of crude was high but because it was considered unlikely that prices would not continue their rise. Expectation certainly played a role in the sequence of events leading to the saturation of production and refining capacity in 2004. The rate of growth of demand, especially in China since 2003, had not been anticipated. And, until the summer of 2003, nearly all analysts assumed Iraq would again participate in the market, with the development of new production capacities in the country, which would have resulted in significant overcapacity for OPEC. Increased Iraqi exports would have led to a necessary reduction in production from other OPEC countries, primarily Saudi Arabia. Such a consensus was obviously unfavorable to investment in those countries. Coupled with the slowdown in demand observed after the events of September 11, 2001, this led to a reduction in worldwide exploration and development expenditures in 2002 and 2003, on top of that of 1998 – 1999. In short, the prevailing consensus until mid-2003 on the existence of excess capacity contributed to the disappearance of that excess. Following IFP Energies nouvelles studies on investments projects and production potential region by region, Y. Mathieu proposed two scenarios regarding oil production (Fig. 1.40). It is clear that hydrocarbon reserves are finite and therefore exhaustible. But little is known regarding the level of ultimate (i.e. total existing) reserves. The Association for the Study of Peak Oil represents a pessimistic view of the future production. However: • The work of ASPO mainly focuses on conventional crude oils, and does not sufficiently take into account so-called “unconventional” reserves. • An increasing number of specialists put maximum production at less than 100 Mb/d (some even speak of 95 Mb/d or less), more for geopolitical than physical reasons. 59

Production (Mb/d)

100

Conventional oil Non-conventional oil

80 60 40 20

1260 Gb Cumulated production end 2010

1476 Gb Proven reserves*

0 1950 1960 1970 1980 1990 2000 2010 2020 2030 2040 2050 Scenario 2: possible 120 Production (Mb/d)

Chapter 1 Petroleum: a strategic product

Scenario 1: probable 120

100

Conventional oil Non-conventional oil

80 60 40 20

1260 Gb Cumulated production end 2010

1476 Gb Proven reserves*

0 1950 1960 1970 1980 1990 2000 2010 2020 2030 2040 2050 * including part of the oil sands of Canada and extra heavy oils of Venezuela

Figure 1.40 Production scenarios (Source: Yves Mathieu (2006)).

1.4 CONCLUSION A future without oil crises is quite unlikely, even if we retain optimistic hypotheses of technological progress in the exploration and production sector, in the use of petroleum products, and in the field of alternative technologies. It is not enough that resources and technologies are available, timely investments must be made in energy management and alternative fuel technologies, and in the development of oil production capacity. This last point would assume a continuous pro-active effort on the part of OPEC countries to make investments with a certain amount of foresight. The investments in question are often considerable and just-in-time management is not favorable to the existence of excess capacity. Moreover, it is not clear that such behavior is in OPEC’s interest. Finally, we must not forget that the question of the future of oil is only one of the elements of a much larger problem ––the ability to ensure the sustainable development of human societies. Water and agriculture are the major factors, along with health, and will require increasingly greater amounts of energy. The real question is not about hydrocarbons but about all energy sources. The twenty-first century will only be able to resolve these problems if we make a concerted effort to rid ourselves of our addiction to the use of energy. We will also need to make use of synergistic effects in promoting the use of different forms of energy: upstream and downstream cooperation between oil and nuclear energy, cooperation between renewable energy and nuclear energy. 60

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Oil and gas exploration and production

2.1 HOW HYDROCARBONS ARE FORMED 2.1.1

Sedimentary basins

A hydrocarbon deposit consists of an accumulation of oil or gas in the pores of a sedimentary rock, which forms the reservoir. They therefore occur in sedimentary basins, that is, in depressions which were filled with sediments millions of years ago (Fig. 2.1). These sediments were produced either by the erosion and weathering of rock close to these depressions (clays, sands), by bio-chemical activity (calcareous rock) or by evaporation from lagoons (salt, gypsum). These sediments formed in successive layers, millions of years ago, older layers being buried by more recent layers. Once buried, these layers became compressed, the water was driven out and the density increased according to the phenomenon of compaction. A process of subsidence then occurs in which the thickness of the layers decreases over time and there is a natural packing of the rock. Furthermore variations in pressure, temperature and the ionic balance due to the process of sedimentation cause the mineral salts dissolved in the interstitial water to precipitate, leading to the formation of cement. The cumulative effect of compaction and cementation eventually results in a transformation in which the sediments, initially loose, become solid rock. Sedimentary rocks settle first into horizontal layers known as strata, but can be deformed by geological processes related to tectonics, that is, movements in the earth’s crust. The largest such movement of this type is continental drift, known as plate tectonics. The sliding motion of oceanic and continental plates produces folding which can lead to the formation of mountain ranges and the major ocean trenches (Fig. 2.2). They lead to the formation of anticlines (folds), synclines (basins) and faults (fractures) if the strata are brittle. When these structures undergo erosion for thousands of years and are then covered by more recent layers the process is known as discordance.

61

180

UPPER (MALM) JURASSIC

154

MESOZOIC

LOWER 135

TRIAS

205

245

MIDDLE (DOGGER)

HADRYNIAN

Birds;

Breakup of Pangea;

MIDDLE LOWER

First dinausaurs

O2

First microscopic algae

N2

Macroscopic eukaryotes

Glaciation

Origin of eukaryotes Diversification des prokaryotes

1,7

Glaciation

Conifers

295

21 %

Development of sexual reproduction

Formation of South Atlantic;

UPPER

PERMIAN

1,0

Flowering plants;

First mammals;

Primates Mammals

Fish

Disappearance of dinausaurus and ammonites; Primate; Formation of North Atlantic,

LOWER (LIAS)

Atmo -sphere

PALEOZOIC 0,6

HELIKIAN

UPPER

Main events

Reptiles

0,20

APHEBIAN

96

PALEOCENE

MESOZOIC

ALGONKIAN

IVre CRETACEOUS

65

EOCENE

CENOZOIC 0,06

PRECAMBIAN

53

OLIGOCENE

Period

PROTEROZOIC

34

MIOCENE

Homo sapiens; Glaciations; Proto-hominoids; Formation of the Red Sea; Subduction of India under Asia; Anthropoids; Separation of Australia from Antarctica; Emergence of mammals;

ARCHEOZOIC

23,5

CENOZOIC

5,3

PLIOCENE

PALEOGENE

0,01 1,65

Billions years

PERIOD HOLOCENE PLEISTOCENE

NEOGENE

ERA

Aerobic respiration

couche O3

oxygenated atmosphere

O2

Development of aerobic photosynthesis

CO2

Reptiles N2

2,6

CARBONIFEROUS

LAURENTIAN

Insects

410

3,2

Bony fish

SILURIAN

Terrestrial flora

Firts stromatolites

H 2O

Anaerobic bacteria

NH3 CH4

HCN

KEEWATINIAN

fems

ARCHEAN

Amphibians DEVONIAN

KATARCHEOZOIC

360 PALEOZOIC

Chapter 2 Oil and gas exploration and production

My

First sedimentary rocks

435 Glaciation

First known igneous rocks

3,9

ORDOVICIAN Armour-plated fish

Formation of oceans and continents

500 4,6

H2

Formation of the Earth He

CAMBRIAN molluscs

4,7

Formation of the Sun

15

Formation of the Universe

540

Figure 2.1 Stratigraphic scale.

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Chapter 2 Oil and gas exploration and production Figure 2.2 Mountain folds and faults.

2.1.2

Petroleum geology

When animals and plants die, they leave an organic residue composed of carbon, hydrogen, nitrogen and oxygen. Most of this material is broken down by bacteria. Some, however, is deposited in aquatic environments low in oxygen —on the beds of inland seas, lagoons, lakes or deltas— and is therefore protected from the action of aerobic bacteria. These residues are mixed with sediments (sand, clay, salt, etc.), accumulate, are compressed, and undergo a first transformation under the action of anaerobic micro-organisms. This first stage in the decomposition of the organic matter gives rise to kerogen, solid organic molecules entrapped within a rock known as the source rock. The mechanism of subsidence causes sediments to be entrained to great depths, where they are exposed to high temperatures and pressures. The kerogen is then transformed into hydrocarbons by thermal cracking: the long molecular chains are broken down, expelling the oxygen and nitrogen, leaving molecules made up only of carbon and hydrogen. When temperatures exceed around 60°C (140°F), kerogen is transformed into petroleum (also referred to as oil). From 90°C (194°F) the oil is itself subjected to cracking, to give wet gas, then dry gas, as indicated in Fig. 2.3. The higher the temperature and the longer it is maintained, the shorter are the resulting molecules, and therefore the lighter the hydrocarbons. In some cases, all the hydrocarbons are broken down into the lightest hydrocarbon component, methane (CH4). During their primary migration, due mainly to the effect of pressure, the oil and gas generated from the kerogen are expelled from the fine-grained source rock in which they formed. Lighter than water, they tend to rise towards the earth’s surface, making their way upwards along permeable conduits and fractures during secondary migration. Unless stopped they escape and seep away at the surface or lose their volatile components and solidify into bitumen. If on their path they encounter an impermeable layer, referred to as a seal, they cannot migrate further. In order for a deposit to form, the hydrocarbons also need to be trapped under this seal, in the pores and fissures of a rock reservoir where they can accumulate. 63

Immature zone Depth (km)

1

2 Oil 3

Wet gas

Oil

Biochemical CH4

Gas Dry gas

Chapter 2 Oil and gas exploration and production

Hydrocarbons formed 0

4

Figure 2.3 Formation of hydrocarbons. Oil window, gas window.

A

B

C

D

Figure 2.4 Structural (A, B) and stratigraphic (C, D) traps. A. Anticlinal trap. B. Fault trap. C. Sand lens and wedge deposit under discordance. D. Reef.

There are two main types of trap: structural traps and stratigraphic traps (Fig. 2.4). Structural traps are created by folds and fractures in the earth’s crust. The most common are anticlinal traps, which contain two-thirds of the world’s hydrocarbon reserves, and fault traps, in which the accumulated hydrocarbons are retained by an impermeable rock formation lying adjacent to the reservoir rock. A trap is referred to as stratigraphic, on the other hand, if at least one of its boundaries comprises a change of physical properties, i.e. a significant change in porosity or permeability within the rock. 64

2.1.3

Petroleum system

The term petroleum system refers to the combination of the main geological attributes which have led to the accumulation of hydrocarbons (Fig. 2.5). Firstly, there has to be a source rock for hydrocarbons to be generated. A porous and permeable reservoir rock is needed to contain the hydrocarbons and allow them to accumulate. The reservoir must be surmounted by an impermeable cap which acts as a barrier to the natural upward movement of fluids. The system must be sealed by a trap in order to permit the hydrocarbons to accumulate. And finally, the succession of geological events, referred to as the timing, must be favourable and, in particular, it is crucial that the trap forms before the hydrocarbons migrate. During the so-called phase of hydrocarbon exploration, prospectors try to assess the likelihood of occurrence of each of these events in order to estimate the chance of finding an accumulation of hydrocarbons at a given subsurface location.

2.2 EXPLORATION FOR HYDROCARBONS The first stage in the exploration-production cycle is of course to look for deposits of hydrocarbons, which will then be produced if the technico-economic conditions permit.

2.2.1

Prospecting

The exploration phase is subject to uncertainties more or less great according to the regions. The purpose of exploration is to discover accumulations of hydrocarbons situated thousands of metres below ground, so quite indiscernible visually or otherwise. Furthermore, these accumulations themselves only occur under very precise and restrictive conjunctions of geological circumstances. An exploration programme involves formulating a certain number of hypotheses which are either more or less rapidly confirmed or have to be rejected given the indicators commonly adopted. Chance plays a non-negligible role, even though spectacular advances in prospecting methodology have taken place since oil exploration began 150 years ago. At one time the most effective method of finding oil consisted of drilling close to surface indicators. Hydrocarbon resources are now becoming increasingly difficult to discover because they are found at depths of up to 5 000 or even 6 000 m (16 000–20 000 ft), increasingly frequently offshore, so that sophisticated tools are needed to locate them. Even today, however, drilling is still the only way of definitely establishing the presence or absence of hydrocarbons in a given subsurface formation. Furthermore it allows the pressure of a reservoir to be measured and allows samples of rock to be brought to the surface 65

Chapter 2 Oil and gas exploration and production

The capacity of the reservoir rock to contain hydrocarbons is determined by its porosity, that is the ratio of the pore volume in a sample of the rock to its total volume. A reservoir of fair quality has a porosity in the range 10–20%. Moreover, it must be permeable, i.e. the pores must be connected in such a manner that the fluids can flow through the pores, so that they can be extracted. Most reservoir rocks are composed of sandstone or carbonates. Sandstone reservoirs account for some 80% of all reservoirs and 60% of oil reserves. Within the reservoirs the fluids arrange themselves in layers from the lightest to the heaviest, the gas lying above the oil, which itself lies above the water. A field comprises one or more reservoirs superposed over one another or in close lateral proximity. Some formations may contain many tens or hundreds of reservoirs: they are then described as being multilayered.

Chapter 2 Oil and gas exploration and production

10 km

50-100 m

3 3

1 1 2 2

1

1

2

50-100 μm Rock pores

Oil

Salt water

Figure 2.5 Petroleum system.

for analysis. Because drilling is costly, however, it is essential that geological, geochemical and geophysical studies are carried out beforehand. In the first place it is up to the geologists to identify general areas which, on the basis of geological criteria, are likely to conceal accumulations of hydrocarbons. They work with geophysicists who study the physical properties of the subsoil, in particular with the help of seismic reflection. For offshore exploration since general ground reconnaissance is simply not feasible, seismic methods are used right from the outset. At this stage the presence of a deposit is still uncertain, and the term “prospect” is used. Using the first set of data collected, a prospect is evaluated, and if appropriate, a decision is 66

If exploration drilling produces positive results, the next task is to delineate the reservoir discovered and appraise it by drilling additional wells and making further measurements. At this point, we can estimate the volumes of oil and gas in place, then the recoverable reserves.

2.2.2

Geology

There are four main branches of geology relevant in exploring for hydrocarbons: – Sedimentology, i.e. the study of sedimentary rocks; – Stratigraphy, i.e. the organisation in time and space of sedimentary rocks; – Structural geology, i.e. the study of deformations and fractures; – Organic geochemistry, i.e. the study of the potential of rocks to produce hydrocarbons. The approach taken to prospecting in a particular sedimentary basin will depend on how much is already known about the area. In hitherto unexplored territory the first stage is to narrow down the area of study and identify zones where more detailed exploration is appropriate. For onshore zones this involves studying satellite images, aerial photographs and radar imagery in order to determine the main features of the sedimentary basin concerned. The next stage is to conduct geographical studies of the surface in order to verify that the three necessary components, i.e. source rock, reservoir rock and impermeable seal are present. If they are, the next stage will be to try to identify possible traps. Traces of hydrocarbons at the surface or in the subsoil can be a good indication of the proximity of an accumulation. Geologists drill small boreholes which allow them to take core samples for chemical analysis by a laboratory. The results provide useful information on whether there are traces of hydrocarbons present. In a mature, more familiar region, existing sources of information in libraries and company databases, public agencies, etc. can be consulted. Particular efforts are made to gain a better understanding of the porosity and permeability of potential reservoirs. Most large traps have already been discovered, so that less obvious traps need to be identified. Geologists synthesise the information obtained into subsurface maps on different scales, which may be extended over an entire basin or represent just a single field. The most common geological maps comprise: – Contours of equal thickness (isopachs); – Contours of equal depths (isobaths); – Physical properties of rocks (lithofacies). Every time a new well is drilled, additional data are obtained and added to the subsurface maps. These successive elaborations require a stratigraphic correlation which involves identifying rocks of a similar age by comparing fossils and the electrical analysis from an exploration well or from an outcrop with the data from another well or outcrop in the light of the seismic results. A major variation in thickness or in the type of rock may provide an interesting geological clue.

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Chapter 2 Oil and gas exploration and production

taken to drill an exploration well. Whether or not the drilling is successful, it provides the geologist with valuable information in the form of core samples, cuttings and electrical records from the wellbore. By examining, cross-correlating and interpreting these data, prospectors are able to pinpoint subsurface structures which could contain economically viable quantities of hydrocarbons. Exploration is an iterative process, each round of results obtained permitting more targeted exploration to be conducted.

Chapter 2 Oil and gas exploration and production

2.2.3

Geophysics

It is not possible to obtain an adequate picture of the subsurface properties by extrapolating from surface characteristics. And the underground formations are not visible. It is therefore necessary to resort to geophysical exploration methods. These consist of making measurements of fundamental physical data —the gravitational field, magnetic fields, electrical resistance— in function of depth, and interpreting these results in geological terms.

Gault clays AlboAptian Barremian Wealdean Portlandian Kimmeridgian Sequanian

Rauracian

A B

C

Figure 2.6 Principle of seismic exploration (A), 2D seismic image (B). 3D seismic image (C).

68

•

Magnetometry, which involves measuring, usually from an aircraft, variations in the earth’s magnetic field. This provides an indication of the subsurface distribution of crystalline formations, which have no chance of containing oil, and more promising sedimentary formations.

•

Gravimetry, which involves measuring variations in gravitational fields which occur as a result of the different densities of rock close to the surface, and gives indications of the nature and depth of layers.

•

Seismic methods, which involve making an ultrasound image of the subsoil by studying the way waves are propagated, thereby providing prospectors with information on the subsurface structures and stratigraphy.

The first two categories are in fact not used very often; seismic methods, and seismic reflection in particular, represent some 90% of geophysical operations, however. Seismic reflection involves transmitting sound waves into the subsoil which are propagated through the rock mass, undergoing reflection and refraction at certain geological discontinuities, referred to as reflectors. Like echoes, the reflected waves return to the surface and are recorded by sensors which convert the vibrations in the ground into electrical voltages (Fig. 2.6). There are two types of acquisition: two dimensional (2D) and three dimensional (3D) seismic acquisition. Traditional 2D acquisition is used for extensive exploration and in zones where access is difficult, whereas 3D seismic methods are used for finer prospecting and offshore programmes. On land the seismic waves comprise tremors on the ground surface generated artificially by buried explosives or “thumper trucks” (Fig. 2.7). The receivers or geophones are distributed at the surface in different possible configurations: in a straight line, along several parallel lines, in a star or rectangular shape or any other geometric configuration. They are connected to a recording truck which logs the data acquired.

Figure 2.7 Thumper trucks.

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Chapter 2 Oil and gas exploration and production

Geophysical methods fall into three categories:

Chapter 2 Oil and gas exploration and production

Source

Hydrophones

Seabed

Figure 2.8 Seismic exploration at sea.

Offshore exploration depends almost exclusively on seismic measurements made on board a vessel equipped with two crews, one to carry out the normal navigational operations and the other to perform the seismic measurements. The vessel generates waves by means of air guns and tows a tube called a streamer behind it which contains hydrophones. It is easier to collect seismic data at sea than on land because of the facility with which a boat can move in any direction. The geophysicist is therefore able to acquire more data than on land, and can produce, after processing the data, a more detailed 3-dimensional image at a lower cost (Fig. 2.8). The signals received by each sensor at the surface are then plotted graphically as a function of the interval until the signal is returned. Isochrones —i.e. lines joining subsurface points of equal return times—, can then be plotted. In order to obtain a depth section which represents a vertical cross-section of the subsurface, the durations need to be converted to depths using formation velocities obtained during drilling. 70

2.2.4

Exploration drilling

2.2.4.1 The exploration well Drilling is the final stage and the supreme arbiter of the exploration process. Knowledge of the subsoil acquired through geological and geophysical surveys allows the potential of a prospect to be broadly evaluated, but cannot definitely confirm the presence of suspected hydrocarbon resources. Certainty can only be obtained by gaining direct access to the subsurface through drilling. Drilling also provides prospectors with a range of valuable data on the lithology and fluids present.

Figure 2.9 Drill bits.

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Chapter 2 Oil and gas exploration and production

Seismic records collected by the geophysicists are then processed by powerful computers which seek to increase the signal to noise ratio. Advances in data processing achieved in recent years make it possible to discover new petroleum structures using old data using higher-performance imaging techniques. Once the seismic data have been acquired and processed, they have to be transformed into utilisable data in the form of isobath or isopach maps and interpreted geological crosssections showing the faults and the main reservoir layers. In order to provide the most accurate possible description of the subterranean structures the velocity of propagation of the waves must be known everywhere so that the time-lapse can be converted into depths. Preliminary assessments cannot be confirmed until a borehole has been drilled. The calibration of seismic reflectors using the measurements made in the wells is therefore a key step. The results of a seismic survey provide good indications of the subsurface structures, the inclination of the strata, their continuity and folds, thereby indicating the presence of possible traps which would be the target of drilling. They also allow gas reservoirs to be located in certain cases, or oil-water or gas-water contacts (oil-water contact: OWC, gas-water contact: GWC) to be identified.

Chapter 2 Oil and gas exploration and production

Drilling an exploration well can take several (2 to 6) months, but the precise duration is difficult to predict because of geological uncertainties at this level. Important doubts will always remain about the depths, the hardness of the rocks and interstitial pressures in the formation, which can only be swept away by drilling. On average one drilling in five results in the discovery of an economically feasible hydrocarbon reservoir. This falls to 1 in between 7 and 10 in relatively unexplored zones.

2.2.4.2 Principles of drilling The objective of drilling is to create a link between the surface and the target formation by penetrating the various geological strata down to a depth of up to ten kilometres (35 000 ft). The most widespread technique involves attacking the rock with a rotating drilling bit (Fig. 2.9). Three factors are involved in this process: the weight exerted by the drilling bit on the rock, its rotation and the removal of the cuttings using a circulating fluid (the drilling mud).

Crown block

Drilling cable

Travelling block

Hook

Injection head Drill pipe Rotary table

Drilling winch

Mud pumps

Figure 2.10 Main components of a rig.

72

In addition to cleaning the bottom of the well, drilling mud helps to cool and lubricate the drilling bit, to consolidate the walls of the wellbore and exercise pressure such as to contain the flow of oil, gas or water from a drilled formation. Drilling starts with a large bit, for example of 26 in. (66 cm) in diameter attached to a drill-collar and a drill-pipe. When drilling has reached a certain depth a new drill-pipe is added to the drillstring. This procedure is repeated each time the increase in drilled depth reaches the length of a drill-pipe, until a certain depth is reached, when the wellbore is cased. Lengths of steel casing of diameter corresponding to that of the wellbore are lowered into the wellbore one at a time, and cemented in place so as to protect the groundwater and control fluids emitted from the well. Several items of equipment are fitted to the upper extremity of the casing to insure suspension and seal the opening. Safety devices known as blow-out preventers are also fitted at the wellhead, fitted with high pressure valves which allow the well to be sealed rapidly using remotely controlled valves in the event of a sudden surge. The casing and other equipment are subjected to a series of pressure tests, and if the requisite safety requirements are all met the next drilling stage can begin. A new drilling bit of smaller diameter is lowered into the hole inside the surface casing, and operations proceed in the same manner as before. When a certain depth has been reached the hole is again cased using smaller casing which matches the diameter of the new hole. The size of the drilling bit is again reduced, the procedure is repeated, and so on. As drilling progresses, successively smaller drill bits are used and the diameter of the cased hole decreases, as shown in Fig. 2.11. Drilling proceeds at a rate of several metres per hour, the rate declining with increasing depth, punctuated by difficulties and the need to regularly replace the drilling bit, which involves withdrawing the entire drillstring As drilling advances a drilling log is maintained in which information is entered regarding the drilled depth, the nature of the rock and the fluids encountered, the drilling durations and any noteworthy events. This document is of great value to geologists and geophysicists.

2.2.4.3 Choice of drilling equipment For onshore exploration the choice of drilling rigs depends on the target depth, access facilities to the site and the availability of the derrick. Offshore there is the additional constraint of the depth of water, climatic conditions and the remoteness from the logistical base. The main difference between onshore and offshore drilling is related to the way in which the rig is supported. Offshore operations are conducted from platforms which either float or are fixed to the sea bed, and which are capable of performing all the functions normally carried out at an onshore drilling site as well as certain other services such as diver support and a meteorology station. The platforms may be either fixed platforms resting on the sea bed, floating structures or semi-submersibles. Self-raising or jackup rigs are generally used in shallow waters. Barges and semi-submersibles with dynamic positioning tend to be kept for deeper waters. These mobile units only remain stationary during drilling, which can last between several weeks and several months (Fig. 2.12). 73

Chapter 2 Oil and gas exploration and production

The drilling bit is attached to a drillstring made up of tubular elements which are screwed on as the drilling advances: drill-pipes and drill-collars close to the bit. This assembly is suspended and manipulated from a derrick (Fig. 2.10). Depending on the type of well the rotary movement is generated either: – From the surface by means of a rotary table and a transmission pipe known as a kelly, or by a power swivel connected directly to the last drill-pipe; or – At the bottom of the well only, by means of a drilling turbine or engine (turbodrilling).

20" (508 mm)

Surface casing 250

17 1/2" (444 mm) Technical casing 1

13 3/8" (340 mm)

750 12 1/4" (311 mm) Technical casing 2

9 5/8" (244 mm)

Depth (m)

Concrete

8 1/2" (216 mm) 7" (178 mm)

2 500

Production casing

Liner hanger 3 300 5 3/4" (146 mm) 5" (127 mm)

Liner 3 600

Figure 2.11 Cased wellbore.

Jack-up rig

Jack-up rig semi-submersible

Dynamically positioned drill vessel

500

1000 Water depth (m)

Chapter 2 Oil and gas exploration and production

26" (660 mm)

1500

2000

2500

3000

Figure 2.12 Mobile platforms for offshore drilling.

74

During drilling, prospectors keep records of a number of physical parameters of the rock and the fluids encountered, known as logs, which they represent graphically as a function of depth or time. The mud log comprises the various measurements provided by the mud circuit. These include the penetration rate, the characteristics of the drilling mud and the cuttings and cores description. The study of the cuttings brought up to the surface as the drilling progresses, and particularly the cores obtained by replacing the drill bit by a hollow tool known as a core barrel, provides information on the main characteristics of the formations encountered (Fig. 2.13). These relate to the lithology, the fossils present in each stratum (which dates them), porosity, permeability, and fluids saturation.

Figure 2.13 Core samples.

Wireline logging, also commonly known as electrical logging, is carried out during interruptions to the drilling. It uses a tool known as a sonde lowered into the wellbore at the end of an electric cable or wireline. Logging while drilling, on the other hand, is carried out with the help of instruments included in the drillstring (Fig. 2.14).

2.2.5

Appraisal

If an exploration well leads to a discovery, it is necessary to prospect further in order to delineate the reservoir and evaluate its potential. This appraisal stage essentially involves carrying out the following tasks iteratively: 75

Chapter 2 Oil and gas exploration and production

2.2.4.4 Logging

55 30

GR

140 170

Logs NPH

-5

RH08

270

2360 2370 2380 2390

Chapter 2 Oil and gas exploration and production

Logs

2400 2410 2420 2430 2440 2450 2460 2470 2480 2490

Figure 2.14 Log plots.

76

When these tasks have been completed, a decision will be taken, based on the available information, whether to develop the field and put it into production or to shut it in until economic prospects become more favourable or whether to abandon it. The appraisal stage is a period of high economic risk. On one hand, a precise appraisal programme needs to be undertaken and targeted studies need to be conducted so that sufficient information is obtained to take the right decision, which takes time and requires investment. On the other hand it is important to know when to bring this phase to an end, either to cut losses and entirely abandon the programme, or alternatively to proceed with the development of the field and production as quickly as possible in order to ensure the project remains profitable. When the field has been delineated, data are available on: – The thickness of the reservoir and its porosity at the location of the wells; – Oil and gas saturation rates; – The composition of the effluent; – The reservoir pressure. So we know the volumes of oil and gas in place. Several vital questions have to be answered at this stage: Is the field commercial? Should it be developed? If so, what should be the development scheme? Answering these questions involves understanding the interplay of geology, geophysics and reservoir engineering. The total recoverable resources will depend on how recovery is to be effected: the production Box 2.1 The most common forms of wireline logging. The spontaneous potential (SP) measures the electrical current which flows in the formations adjacent to the hole resulting from differences in salinity between the drilling mud and the water in the formation. The SP can be plotted on a graph against depth, and interpreted visually in order to demarcate reservoirs and clay overlays. Resistivity logging is essentially used to calculate saturation levels of water, oil and gas. Depending on the type of mud used and the radius of investigation, different tools are used to measure the resistivity of formations: induction, conventional resistivity or the laterolog. High resistivities indicate the presence of oil and gas. Radioactivity logging measures the natural and artificial radioactivity of formations. Gamma rays allow impermeable formations (such as clays and clayey sands with higher natural radioactivity levels) and formations likely to comprise reservoirs to be detected. Neutron and density logging provide data on the type of rock and on porosity, and allow gas, oil and water zones to be distinguished. Sonic logging provides another means of evaluating porosity. It makes use of the differences in propagation time of a sound wave across the strata of a formation, this propagation being faster through dense than through porous rock. These data also allow the geophysicist to establish a correspondence between the geological strata and seismic markers.

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– Mapping (making a more accurate evaluation of the size and position of) reservoirs using the seismic data and the information obtained from the exploration wells; – Reservoir simulation; – The drilling of additional wells several hundred or thousand metres away in order to obtain additional data, like the limits of the field.

Chapter 2 Oil and gas exploration and production

rate, the drainage methods adopted, the number and positioning of the wells, etc. The overall economic context (prices, taxes, etc.) and the circumstances of the company itself (financial resources) are of course also relevant. These circumstances are subject to change. For this reason the results from the exploration and appraisal stages and other sources are studied by multidisciplinary teams comprising geologists, geophysicists, petroleum architects, drillers, producers and reservoir engineers. They also take account of the thinking of economists and financiers. These teams build up a detailed picture of the size of the reservoir, its characteristics and of the resources present. This allows various development scenarios to be considered and tested with the help of simulation models, and their value in economic terms evaluated.

2.3 DEVELOPMENT AND PRODUCTION If the appraisal stage demonstrates that the characteristics of the reservoir are sufficient to justify production then the development stage begins. This involves drilling the future production wells and installing all the associated equipment required for production.

2.3.1

Reservoir management

2.3.1.1 Characteristics of the reservoir In order to design the production installations, information is needed on: – The composition of the effluent; – The planned rate of production and expected total production for the wells; – The number and position of wells required for the optimum production from the reservoir; – The workovers frequency on the wells. It can be obtained from the geological data, the seismic data, the characterisation of the reservoir rock, the study of fluids and the well tests. The geological data, seismic data, maps and logs allow a picture to be put together of the reservoir, its internal structure and the distribution of the fluids. Petrophysical analyses based on logs and core analysis provide information on the capacity of the reservoir rock, i.e. its porosity and the possibility for the movement of the fluids through the rock, i.e. its permeability. By providing indications of hydrocarbon saturation, calculated as the ratio of hydrocarbons to total fluids in the pores of the rock, this allows an estimate to be made of the total hydrocarbons present. Studies of the fluids, referred to as PVT (pressure, volume, temperature) tests, are made in order to characterise the physical and thermodynamic properties of the effluents, based on which the most appropriate production methods are determined. Finally, well tests are carried out by measuring downhole pressure at the level of the reservoir before and during production. These provide information on the nature of the fluids, the drainage area of the well and the permeability of the formation. They also provide indications of the quality of the producing formation and the impact of the drilling on well productivity (skin effect). The producers deduce the optimum oil or gas production rate from these data. 78

2

3

1

5

3 5

Gas cap

4

1

2

6 6

Oil

4

Water

Oilfield from above and placement of wells

Vertical cut

Figure 2.15 Saturated oil reservoir (Source: Total).

In the case of a single-phase gas field, the wet gases will generate, at the surface, condensates and dry gases comprising light fractions such as methane and ethane. In gas fields subject to retrograde condensation, liquid hydrocarbons will be deposited in the reservoir during production, and the effluent will have a high liquids content at the surface. Water is also associated with the hydrocarbons in the reservoirs. Most reservoirs were formed from sediments which settled in or close to the sea. Part of the water will have been displaced during the migration of the oil, but some remains in the form of interstitial water adsorbed as a film onto the rock around the pores. Water is also often found in reservoirs below the oil or gas, forming an aquifer. Geologists and geophysicists begin by evaluating the volume of rock impregnated by hydrocarbons, the percentage of this volume effectively occupied by hydrocarbons and the distribution between hydrocarbon types, in order to estimate the total tonnage. The reservoir engineer then estimates the reserves. Capillary forces within the reservoir make it impossible to recover all of the hydrocarbons from the field. It is estimated that an average of 75–90% of the gas, but only 30–40% of the oil, can be recovered. 79

Chapter 2 Oil and gas exploration and production

The downhole thermodynamic conditions and the composition of the hydrocarbons present allow the reservoir to be classified according to the way the fluids will behave during production. When brought to the surface, oil and gas often have quite different properties, in terms of volume and quality, than while in the reservoir. In an oilfield the associated gas may be dissolved in the oil or may be present as free gas. An oil reservoir is described as being undersaturated when the hydrocarbons are initially single phase liquids: the natural gas present in solution is released at the surface when the oil is produced. On the other hand if the oilfield originally contains both liquid and gaseous phases, the oil is described as being saturated and the free gas which is not dissolved in the oil resides in a gas cap (Fig. 2.15).

Chapter 2 Oil and gas exploration and production

2.3.1.2 Recovery mechanisms The reservoir engineer studies possible production levels, field life duration and the number and types of wells, based on the characteristics of the field and its effluents, and draws up a development plan in collaboration with the petroleum architect. At the outset of the development phase the information needed to define the functional sub-systems is not always known sufficiently accurately for all the options to be determined at that time. Furthermore, the information will vary over the years. A. Primary recovery After the wells have been completed (see Section 2.3.2.2) hydrocarbons can be produced at the surface. They flow from the reservoir into the well under the effect of the pressure gradient between the reservoir and the well bottom (Fig. 2.16). As production proceeds the pressure in the reservoir falls, thus reducing the natural flow rates of the hydrocarbons, and the oil in particular. In the case of gas fields natural flow through single phase expansion is the most effective recovery mechanism, allowing a recovery rate of about 80%. For oil, primary recovery is less effective and may even prove very limited where there is no effective source of energy such as the expansion of a gas cap, aquifer activity or the expansion of dissolved gases. Where an oilfield has a gas cap, as oil is produced and there is a consequential pressure drop in the oil zone, the gas cap expands, driving the oil into the production wells. There is considerable energy in the system, thereby allowing the oilfield to produce for a long period of time, depending on the size of the gas cap. In addition, when there is a sufficient fall in the reservoir pressure, gas which was initially dissolved is freed in the oil mass, and entrains the oil towards the producing well. When a sufficiently large aquifer lies under the oilfield, the pressure is maintained for as long as the water replaces the oil in the pores during the production. In this case the wells go on producing until the water production becomes excessive. Primary recovery typically allows from 5-10% to 30-50% of the oil to be recovered. B. Enhanced recovery In most cases the volumes of crude oil extracted under primary recovery is not economically viable. It is therefore often necessary to resort to mechanisms for enhancing the recovery rate after a production period which can vary. A distinction is traditionally made between secondary recovery, which involves maintaining the pressure of the oilfield, and tertiary or enhanced recovery which refers to a number of advanced methods which improve the displacement characteristics of the oil. Secondary recovery is effected by means of water injection and gas injection, water injection being largely used. It involves either drilling injection wells or converting production wells into injection wells. Water is then introduced into these wells under pressure. This both maintains the pressure in the oilfield by taking the place of the produced oil in the pores of the reservoir rock and flushing out the oil remaining in the producing rock, driving it towards the production wells. The injection of immiscible gas rests on the same principle, the fluid injected into the reservoir in this case being natural gas, nitrogen or flue gases from combustion, under pressure. This can be an attractive technique in desert, remote or offshore areas where there is no market for natural gas and where flaring is forbidden. 80

Wellhead pressure (WHP)

Well bottom pressure (WBP)

Reservoir pressure (RP)

The hydrocarbons are propelled from the reservoir to the surface by the pressure differences RP > WBP >WHP > AP

Figure 2.16 Principle of primary recovery.

81

Chapter 2 Oil and gas exploration and production

Atmospheric pressure (AP)

Chapter 2 Oil and gas exploration and production

OIL PRODUCTION

Water injection

Gas injection

Gas injection

Water injection

Figure 2.17 Maintaining pressure by injecting water into the aquifer and gas into the gas cap.

Fewer injection wells are needed for gas than for water injection, but heavy compression equipment is required (Fig. 2.17). The injection of water or immiscible gas into an oilfield leads to recovery rates which are higher (40–60%) but still limited because the flushing of the cavities in the reservoir is incomplete (macroscopic sweep efficiency) and because residual oil is trapped by capillary action in the flushed areas (microscopic sweep efficiency). Tertiary recovery processes, known as EOR (enhanced oil recovery), make use of chemical and thermal techniques, and seek to enhance the spacial sweep efficiency and to reduce the capillary forces by making the fluids miscible or improving their mobility. They can improve recovery by a further 5–10% of the total oil resources in the oilfield (Fig. 2.18). 82

After tertiary recovery (gas lift) Gas

Oil

Oil

Oil

GOC

Gas

Oil-water emulsion Oil

Oil Water

Water

WOC Water

Percentage oil recovered

R = 0%

R = 50%

R = 65%

Figure 2.18 Oilfield at different stages of recovery.

The behaviour of the fluids during the production phase is carefully observed and analysed so as to ensure that production continues to be optimised. Finally after a period of, typically, 15–30 years, the limits of economic recovery are reached. The production facility is then dismantled and the site is rehabilitated.

2.3.2

Reservoir simulation models

A reservoir simulation model starts by taking a geological model, i.e. a static representation, of the oilfield. The first stage is to synthesise the information collected by the geologists, geophysicists and the reservoir engineer from the appraisal wells. It is advisable to analyse these data critically because of the large uncertainties attaching to the hypotheses in the exploration phase. The modelling phase proper involves interpreting the data in order to construct a system which replicates the behaviour of the actual oilfield. The reservoir is represented by a grid of discrete cells. This grid may be in two or three dimensions, and may be rectilinear, polar (around a well, for example), or irregular (in order to show up heterogeneities, etc.). The parameters which characterise the reservoir must be defined for each cell (Fig. 2.19). Equations are then added to this static model which describe the fluid flows between adjacent cells, and between cells and the well, in order to obtain a dynamic model. The final stage consists of simulating the behaviour of the reservoir in time and space according to different production scenarios which are subjected to a range of economic calculations. Economic optimisation, using various hypotheses linked to the environment allows the most appropriate development programme to be chosen. 83

Chapter 2 Oil and gas exploration and production

After secondary recovery (water injection)

Outset

Chapter 2 Oil and gas exploration and production

Box 2.2 Enhanced oil recovery. Chemical methods involve adding chemicals to the injection water. There are two main types: micro-emulsions and polymers. Micro-emulsions consist of mixtures of oil, water and surfactants, stabilised with alcohols. They enhance the displacement action of the injected water, i.e. the ability of the water to drain the oil from the rock pores. Dissolving polymers in the water enhances its flushing action and increases its viscosity by a factor of 50 or more. Thermal recovery involves increasing the temperature in the reservoir in order to reduce the viscosity of the oil and increase the productivity of the well. This can be done either by generating heat at the surface in the form of steam and transmitting it to the formation via an injection well, or by injecting air into the well and inducing in situ combustion or an oxidation front in the formation close to the injection well. Miscibility methods promote thermodynamic exchanges between the oil in the reservoir and the fluid injected to reduce the capillary forces. The nature of the fluid to be injected depends on the type of reservoir: carbon dioxide on its own or followed by water, LPG under pressure, methane enriched with light hydrocarbons, nitrogen under high pressure. These methods may increase the recovery factor by 30% to 40%, but are constrained by practical difficulties in the fields and economic considerations.

Figure 2.19 Grid representation of oilfield using Athos software.

Once the project has been approved, the site prepared, the production wells drilled and completed, and the gas collection, production, processing, storage and dispatch equipment have been installed and the living quarters built, production can begin. Numerical simulation models are subject to continual improvement as production proceeds and knowledge about the field increases. Refinements made in the course of production allow more reliable studies to be made of the impact of drilling new wells, horizontal drain holes, methods of assisted recovery, etc. This will make a significant contribution to investment decision-making during the different stages of the life of the field. 84

2.4.1

Directional drilling, horizontal drilling, multidrains

The principles underlying development drilling are the same as those for exploration drilling, but more specific use is made of directional and horizontal drilling, and multidrain systems. Modern drilling can be controlled so accurately that wells can be drilled according to a precisely predetermined profile so as to target a precise subsurface location. Directional drilling can be carried out in a J or an S configuration. It is normally used: – When the drilling zone is inaccessible or urbanised; – To circumvent a subterranean obstacle such as a salt dome; – To reduce the number of surface drilling installations, for example to limit the number of platforms when drilling offshore, or to obviate the need to move them; – To test several potential reservoirs; – To deal with a well in which there has been an accident. Horizontal drilling is a special case of directional drilling in which the borehole is horizontal, parallel to the reservoir strata. As indicated in Fig. 2.20, it is used: – When the production zone is a long way from the drilling rig; this technique can even be used to access resources under the sea bed from an onshore location, thus avoiding the need for offshore equipment; – To enhance productivity, and therefore recovery; by draining a reservoir over a length of, sometimes, more than a kilometre, the oil flow rate can be increased, making it feasible to develop an oilfield of small thickness or low permeability; – To prevent the local deformation of the oil-water or gas-oil contact close to a producing well (known as coning) which occurs with traditional drilling, which results in an excessive production of gas and water. Multidrain wells allow production from different parts of a reservoir with a single well. They can be used at any stage in the life of a field. In the exploration and appraisal stages, sidetracking provides a less risky and lower cost means of delineating a field in unknown areas. The profitability of a production well is assured by the main wellbore drilled into a known reservoir (Fig. 2.21).

Offshore

Drilling from the coast

Inaccessible site

Emergency operations

Multiple zones Sidetracking

Figure 2.20 Horizontal and directional drilling.

85

Chapter 2 Oil and gas exploration and production

2.4 DEVELOPMENT DRILLING

Chapter 2 Oil and gas exploration and production

Figure 2.21 Multidrain wells.

During production, multidrain systems multiply the number of wellbores and therefore increase production while reducing the development costs per barrel. Drilling multidrain systems in existing wells in the depletion phase slows the rundown of mature fields by tapping into secondary reservoirs and allows a programme of water or gas injection to be carried out for optimal flushing of producing formations.

2.4.2

Completion

Completion involves making the well ready for production. It begins when the drilling phase comes to an end, when the last piece of casing has been cemented into place in the producing formation. First of all a connection has to be made between the wellbore and the reservoir, by drilling into the reservoir, treating it, equipping the well and putting it into production. The equipment and methods used in well completion are quite varied, depending on the type of effluent, the kind of reservoir, the requirements to be met by the well during its lifetime and the economic circumstances at the time of drilling. The completion must at least ensure the integrity of the walls of the hole and the selectivity of the fluid or production level while permitting the unhampered flow of the fluid. It must ensure that the well is secure, allow measurements to be made, facilitate maintenance, allow the flow rate to be regulated and the well to be put back into production. Wellbore-reservoir connection There are two types of wellbore-reservoir connection: cased hole completion and open hole completion. Cased hole completion is the most common. After the reservoir formation has been drilled the last piece of casing or liner is set and cemented in place. Perforations are then made at the level of the production zone to reestablish a connection between the reservoir and the well. These perforations must pass through the casing and the cement sheathing before penetrating the formation, which may then be subjected to stimulation treatments. 86

Tubing The configuration of the tubing mainly depends on the number of production levels and the production selectivity sought. In conventional completion, we generally use a tubing which is totally contained in the casing string. Completion may be single or multiple. In the latter case production can take place at several levels selectively, allowing the field to be developed with fewer wells and therefore more rapidly, but maintenance costs are higher. It should be noted that that there is a type of completion where tubing is not used. This involves cementing and perforating a small length of casing in place at the level of the production zone. This is appropriate for small gas fields poor in associated liquids and at low pressure. Once the well has been completed, the wellhead is attached to the top so as to control the flow of fluids (Fig. 2.22). The wellhead is made of: – The casinghead to which the casing is attached; – The tubinghead which supports the tubing; – The Christmas tree which comprises various valves and gauges.

Christmas tree

Tubinghead

Casinghead

Figure 2.22 The wellhead.

87

Chapter 2 Oil and gas exploration and production

In open-hole completion the well is simply drilled into the reservoir, which produces in an open hole. A variant of this involves placing a pre-perforated liner against the wall of the formation, so as to maintain its general shape. This type of completion tends to be used when there is a single zone only which is either highly consolidated or where sand control by gravel packing is adopted. In practice this procedure is rare for oil wells, but is sometimes applied on gas wells.

Chapter 2 Oil and gas exploration and production

2.4.3

Well productivity

Well tests are carried out in order to evaluate the productivity or injectivity index of the well, and any damage which may have occurred. These tests together with the results of further laboratory testing will reveal whether any treatment is necessary. The well is then put into service and evaluated. It will subsequently undergo measurements, maintenance, workover or abandonment.

2.4.3.1 The drillstem test The term drillstem test (DST) refers to all the well testing carried out during drilling. The DST is basically a test intended to establish the production potential of a well and allow it to be characterised. When a DST is conducted the well is temporarily completed and a special assembly is lowered, equipped with various valves allowing the well to be shut off both at the wellbottom and at the surface, as well as pressure gauges. A sequence of periods of production and observation is defined and the test involves continuously monitoring the pressure of the reservoir during this time. By comparing this with a diagram for different stabilised flow rates, important information is obtained on the depletion of the zone in which the well is producing. Several production tests are carried out with different wellhead settings in order to obtain production data. This allows certain physical characteristics of the well to be derived, as well as the maximum possible production rate.

2.4.3.2 Methods of stimulation The productivity of the well, measured in this way, may prove to be poor because of the petrophysical characteristics of the well, or because of damage caused by the drilling. When the natural flow rate of the oil is weak, however, it can be improved by stimulation methods such as acidising or hydraulic fracturing. Acidising consists of injecting acid which infiltrates the reservoir and dissolves some of the obstructing material. Additives are included to prevent corrosion of the casing or tubing, or blockages resulting from the reaction of the acid with certain types of crude oil. Hydraulic fracturing is practised in the reservoir in order to open fractures in the reservoir rock by means of high pressure produced hydraulically. These cracks are then wedged open by introducing propping agents such as sand, shells, aluminium balls, glass or plastic.

2.4.3.3 Activation methods When an oilfield does not contain enough energy to drive the oil up to the surface treatment facilities it is necessary to resort to activation, i.e. either gas injection or pumping. This is necessary in more than three-quarters by number of wells worldwide, although these wells probably account for no more than 20% of world production. When there is an economical supply of gas and the quantities of oil justify the expense, a technique known as gas lift is applied. Gas is injected into the fluid column in a well to lighten it and make it rise as a result of the expansion of the gas. Depending on the production characteristics of the well and the manner in which the gas injection equipment is deployed, the gas can be injected continuously or intermittently. Various different types of pump are used for conventional pumping:

88

Chapter 2 Oil and gas exploration and production Figure 2.23 Pumping jack.

• Sucker rod pump: a downhole volumetric pump assembly driven by a surface recipro-

cating action power source via a rod. • Centrifugal pump: an electrosubmersible pump immersed in the effluent at the bottom of

the well, the power being supplied by means of a special cable. • Hydraulic pump: a downhole reciprocating pump linked to a hydraulic motor.

2.4.4

Well interventions

There are two categories of interventions practised on a well in the production phase: well servicing and workover. These are both intended to maintain or enhance output from production wells. Well servicing involves the partial replacement of equipment such as downhole pumps, gas lift valves, production tubing and the sealing systems which may fail because of corrosion, waxy hydrocarbons, etc. Well servicing also includes simple operations such as cleaning and sand control. Workover includes more major repairs such as removal of sand which has intruded into the wellbore and recompleting the well for production from a different zone.

2.5 PROCESSING OF EFFLUENTS The production facility includes: – The effluent processing units; – The storage, metering and dispatch facilities (Fig. 2.24); – The utilities required by the production facility, i.e. electricity, water and heat. The production facility often uses its own gas. All the equipment is controlled from a control room. 89

Chapter 2 Oil and gas exploration and production

Figure 2.24 Production facility.

In the case of oil production, the wellhead effluent is often a three-phase mixture of oil, gas and water. It may also contain sands, clays, mineral salts, the products of corrosion and sometimes carbon dioxide, in varying proportions. The water from the well and other impurities must be removed before the hydrocarbons are stored, transported and sold. The function of the processing plant is to bring the oil or gas up to the specifications required for export.

2.5.1

Separation process

The first stage in the processing of the effluent is to separate the three phases —oil, water and gas— by passing it through multi-stage separators. These are cylindrical installations under pressure which may lie either horizontally or vertically. Within each separator water, which tends to be retained in the lower compartment, and gas, which accumulates in the upper part of the separator, are extracted.

2.5.2

Oil treatment

The oil separated in this way still needs further treatment to bring it to a specification where it can be marketed. Watery emulsions must first of all be broken down with the help of a de-emulsifier which allows the water to coalesce into larger droplets which can be separated more easily from the oil. Inhibitors, solvents or heat are used to prevent the waxy hydrocarbons from precipitating out. And finally the oil is desalted by washing it in soft water. It will then be dispatched either by pipeline or tanker.

2.5.3

Water treatment

Production water is produced in quantities which are generally quite small initially but become progressively greater as production proceeds. It is imperative, for reasons at once technical, ecological and economic, that this water is purified before being released into the 90

2.5.4

Gas treatment: sweetening and dehydration

The natural gas or associated gas from an oilfield often contains carbon dioxide, hydrogen sulphide (H2S) and water. Depending on how the gas is to be used and transported, more or less processing is required, and it must be sweetened and dehydrated. Natural gas may be transported to the area where it is to be consumed by pipeline or may be liquefied and transported in LNG tankers. The propane and butane fractions are known as liquefied petroleum gases, and are transported in special tankers. The natural gas can either be burned to produce electricity or heat, or it can be reinjected into the oilfield as a means of effecting secondary recovery or gas lift. Hydrogen sulphide is very toxic. If the gas is to be used commercially the hydrogen sulphide must be completely eliminated. If it is to be liquefied, the CO2 content needs to be reduced, by chemical absorption, physical absorption or adsorption, in order to prevent subsequent crystallisation. If the gas has to be transported by pipeline for processing at another location, as this is the case for offshore production, small quantities of H2S and CO2 may be tolerated but the gas must be dehydrated using glycol, by passing it through a molecular sieve or by condensation. At high pressure and low temperature the traces of water present in the gas can lead to the formation of hydrates which can accumulate and cause obstructions in the pipelines. But the formation of hydrates can be avoided by injecting a hydrate inhibitor such as methanol or diethylene glycol. In offshore production these installation have to be located on platforms with a restricted surface area (Fig. 2.25).

Figure 2.25 Offshore plateform Visund (© Øyoind Hagen/Statoilttydro).

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Chapter 2 Oil and gas exploration and production

environment or used in the production process. Firstly, all traces of oil must be removed and added to the oil stream. The solids must then be removed so that the injection wells do not become plugged. The content of dissolved gases, particularly corrosive oxygen, must also be lowered. And finally, the sulphate-reducing bacteria in the water must be removed.

3

Hydrocarbon reserves

The concept of hydrocarbon reserves, absolutely fundamental to the oil industry, is a complex one. In broad terms, the reserves are the total resources available to meet present and future needs. In order to anticipate demand, the size of these reserves needs to be known. Very broadly the world’s ultimate reserves of oil (i.e. past, present and foreseeable future) amount, at the beginning of the 21st century, can be estimated at around 3 000 billion barrels (Gbbl), which can be broken down as follows: – 1 000 Gbbl of reserves already used; – 1 300 Gbbl proven reserves remaining (about 40 years’ production at the present rate); – between 300 and 900 Gbbl reserves remaining to be discovered (conventional and unconventional oil like oil sands); – 300 Gbbl to be added to reserves by virtue of enhanced recovery techniques.

1000 Gb

Consumed reserves

1300 Gb

Reserves proven to consume

300 - 900 Gb 300 Gb

Reserves to be discovered Enhanced recovery

Figure 3.1 Breakdown of world’s ultimate oil reserves.

The proven reserves of gas remaining are 177 Tm3 (60 years of production at the present rate), and the ultimate reserves can be assumed to be of the order of twice this figure. Of these figures, the only figures known with certainty are the quantities already used. Figures announced for the reserves are essentially speculative. In practice, we do not know 93

Chapter 3 Hydrocarbon reserves

a great deal about the hydrocarbons still in the earth’s crust. And even where we know of the existence of an oil- or gasfield, the reserves can rarely be recovered in their totality with present technology or given the policy on exploration practised by the states which own the mineral rights. Furthermore even where technical and political conditions permit production, costs may be too high under present market conditions to permit their commercial exploitation. In order to define what we really mean by reserves, three questions need to be answered: – What has already been discovered and what remains to be discovered? – What fraction of these quantities is it technically possible to recover? – And finally, are production costs low enough for the reserves to be commercially viable? These questions are in fact not mutually independent: the first two are strongly affected by the third. The price of crude greatly influences both the level of exploration activity and the rate of technological progress. A high price means that it is profitable to recover hydrocarbons with higher production costs. A low price, on the other hand, excludes any possibility of investing in programmes whose economic viability is uncertain, such as high-risk exploration programmes or fundamental research. The three questions above behave like filters, narrowing down the concept from that of hydrocarbons present in the ground to that of economically recoverable quantities. They illustrate the difficulty of rigorously defining the concept of reserves. In 1986, for example, the OPEC countries changed their definition of reserves. Their estimates of proven remaining world reserves were increased artificially but considerably from 700 to 900 Gbbl without there being any real change in the global stock of hydrocarbons. In this chapter we shall begin (Section 3.1) by reviewing the definitions used by the industry. We shall then go on, in Section 3.2, to specify the various types of hydrocarbons extant and will look particularly at those referred to as “non-conventional”. Unlike so-called conventional hydrocarbons (broadly, those that are easy to produce and market in today’s conditions) non-conventional hydrocarbons are at present unprofitable to produce, but could become profitable in the future. This category includes, for example, ultra-deep offshore resources, extra-heavy oils and synthetic petroleum. These resources, even though they may be recoverable with present technologies, cannot strictly be classified as reserves at present, but this situation could change in the shorter- or longer-term future. Non-conventional hydrocarbons exist in quantities incomparably greater than the proven reserves of conventional hydrocarbons, and could therefore have a major impact on the oil industry in the future providing technologies emerge which allow them to be produced profitably. We will then go on, in Section 3.3, to consider reserves in relation to production. We will show that hydrocarbon production curves are linked to the reserves in the relevant geographical zones and allow the impact of technological progress in terms of creating new reserves to be shown. The study of production profiles has led many writers to try to forecast the ultimate reserves and production rates by simple extrapolation. These theories can in fact lead to two radically opposed visions of the future of hydrocarbons, corresponding to an optimistic and a pessimistic view. Energy experts armed with the same data disagree about the short-term future of the oil industry. This debate rages on, and will be considered in Section 3.4 of this chapter. And finally, in Section 3.5 we chart the main hydrocarbon-producing sedimentary basins in the world, continent by continent, giving the reserves and production volumes for the main producing countries. 94

There are many different definitions of hydrocarbon reserves. The first point to note is that the term reserves denotes a technico-economic rather than a geological concept. A distinction is made between: – Reserves: the volumes of hydrocarbons which are or will be recoverable, and – Resources: the volumes of hydrocarbons which are present in an oil —or gasfield, without reference to constraints as to their accessibility and/or cost. This concept is identical to that of the hydrocarbons in place, in common use. McKelvey (1972) and Brobst and Pratt (1973) defined the reserves of fossil fuels as being “identified deposits which can be extracted profitably using present-day techniques and under present economic conditions”. The widely used term “recoverable reserves” is therefore a pleonasm because broadly speaking the term “reserves” refers to hydrocarbons which are destined to be produced and are economically viable.

3.1.1

Political and technico-economic constraints

The term resources refers to all the hydrocarbons present in the Earth’s crust, whether they have already been identified or not. The first stage is the identification of these resources, i.e. exploration, so that hydrocarbon resources can be discovered. Exploration is limited by two factors. The first factor is political: certain geographical zones are only partially open to exploration by the states which control them. The second is technical: there are zones where the geological or geophysical exploration methods described in Chapter 2 are not yet sufficient (for example ultra-deep offshore). But there is a third barrier to resources becoming reserves: a technico-economic constraint on production. There are in fact many accumulations of hydrocarbons for which the technology simply is not available today to put them into production. These accumulations, although fully identified, may lie in waters which are too deep, or may comprise crudes which are difficult to recover because their viscosity is too high, for example. Technology is not the only obstacle to transforming resources into reserves. There are resources for which the extraction technology exists, but where the recovery cost would exceed the proceeds from selling the hydrocarbons extracted. Or, which boils down to the same thing, the energy required to produce the hydrocarbons exceeds the energy content of the products. These resources would not be economically feasible, and would therefore not be put into production. Resources can therefore only become reserves by passing a number of successive tests, illustrated in Table 3.1. Reserves are of course of political and strategic importance both to the oil companies and the producing countries. Estimates of reserves may be intended to have a certain impact, and should be viewed with caution. In fact estimates are beset by a lack of precision which is intrinsic in the quantitative definition of the term “reserves”.

3.1.2

Deterministic and probabilistic estimates

As described above, the term “reserves” applies to hydrocarbons which will be put into production within the short and medium term. Reserves are therefore hypothetical volumes 95

Chapter 3 Hydrocarbon reserves

3.1 DEFINITIONS

Chapter 3 Hydrocarbon reserves

Tableau 3.1 From resources to reserves (by kind permission of Jean-Noël Boulard).

R E S O U R C E S

Accessible to exploration

Identified

Production technically feasible

➂

Economically

RESERVES

viable

④ Not economically viable

Production not

②

technically feasible

Not identified

➀ Not accessible to exploration

because they are prone to various uncertainties and depend on variables such as technological change, the economic climate, etc. The only reserves known with certainty, i.e. deterministically, are the reserves already produced. It is often said that the reserves present in a field are not known until production finally ceases. A deterministic approach assumes that the value of each parameter needed for the calculation is certain. It obtains an estimate which is assumed to be totally reliable, not subject to an error margin. Any other approach to measuring the reserves in which there are uncertain parameters is necessarily speculative. It provides probabilistic estimates in the form of a range, or in statistical terms, confidence intervals or, more precisely, prediction intervals. Chapter 2 described the different stages in exploring and appraising an oil- or gasfield and the uncertainties to which the results are subject. This approach produces a probability that a particular prospect does indeed contain hydrocarbons. This is a probability because the estimates of the uncertainties involved are themselves formulated by experts in the light of their own experience, based on their own hypotheses. The probability estimates are therefore described as subjective, or as a priori probabilities. Once a formation has been declared to contain hydrocarbons, the total quantities of hydrocarbons physically present (these figures are rarely published) are evaluated, and the associated reserves are estimated. To do this it is necessary to evaluate the ratio of the recoverable hydrocarbons to the total quantity of hydrocarbons in the reservoir. This quantity is known as the recovery ratio, and we will return to it shortly. Modern geoscientific techniques (geology, geophysics, geochemistry and geostatistics) allow the potential reserves in the field to be described by means of a probability distribution function. Because of the uncertainties in the measured values it is meaningless to say that the reserves in a field are 100 million barrels (Mbbl). What can be said is that there is a certain probability that its size exceeds 100 Mbbl. The size distribution of a particular field is generally reasonably well represented by a lognormal distribution (see Fig. 3.2)1. In practice the reserves are represented by providing a number of the parameters of the lognormal distribution (the mean or a number of percentiles: 10%, 50%, 90%, etc.) which is supposed to represent the size of the field. 1. There is however a debate on this matter. The main weakness of the lognormal distribution is that it does not represent small fields well, and in some cases completely misrepresents them.

96

Chapter 3 Hydrocarbon reserves Figure 3.2 Lognormal distribution function modelling the size of an oilfield.

3.1.3

P90, P50, P10, etc.

Px is defined as a number such that there is an x% likelihood that the true reserves exceed Px. For example if the P10 of a field is 100 Mbbl, there is a 10% probability that the actual size of the field exceeds 100 Mbbl. The P50 is also called the median of the distribution, and there is an equal probability that the actual reserves are greater or less than P50. The percentiles most frequently used when estimating the size of a field are P95, P90, P50, P10 and P5. Estimates are also sometimes given in the form [minimum, mode, maximum] or [minimum, mean, maximum]. The minimum and the maximum here are actually P5 and P95 respectively, or P10 and P90. These are misleading terms, because the true minimum and maximum of the lognormal distribution are 0 and +∞. The mode is the theoretically most likely value of the distribution. The mean (or expected value) would be the average value observed for a large number of fields whose size is characterised by precisely the same a priori probability distribution. Figure 3.2 shows a typical lognormal distribution for a field for which the P50 is 500 Mbbl. The curve shows, for any x, the size for which the probability that that size is exceeded is x%. This way of describing the size of the reserves is one of the most rigorous there is. However many other methods are described in the literature.

3.1.4

1P, 2P and 3P reserves

Also widely used are the three values referred to as 1P, 2P and 3P, derived from the percentile approach, and which also provide a probabilistic evaluation of the reserves in a field. These values correspond with the Px in a manner depending on the company or writer concerned: – 1P is generally equal to the P90 or P95 described above; 97

Chapter 3 Hydrocarbon reserves

– 2P is always equal to P50; – 3P is generally equal to the P10 or P5. Finally the next section presents another terminology, also commonly used, which originates from an older, deterministic way of regarding reserves.

3.1.5

Proven, probable and possible reserves

The terms proven, probable and possible reserves most often correspond, although there are many exceptions, to the values 1P, (2P – 1P) and (3P – 2P). Or putting this the other way round: – 1P = proven; – 2P = proven + probable; – 3P = proven + probable + possible. It should be noted that these definitions were formulated and officially adopted in 1997 by the SPE (Society of Petroleum Engineers) and the WPC (World Petroleum Congress). More precisely, “proven reserves” are those which are reasonably likely to be produced; “reasonably likely” here actually generally means P90. However these definitions are by no means universally accepted, and are contested by some in the oil community. When figures are quoted, they usually refer to the proven reserves. However does that mean P95, P90 or something else? It is almost impossible to answer this question properly, and often the vagueness is intentional on the part of the users. Examples can still be found where figures given for “proven reserves” may mean an unspecified value between P50 to P98. Caution is therefore needed when using the figures variously given for the reserves.

3.1.6

Need for caution in using definitions

The probabilistic approach to quantifying the reserves in a field is tending to become more widespread. The approach is not without risks, however. For example it is not as easy as it might appear to add together a set of reserves to arrive at the reserves for an entire basin or country. This is because the figure obtained by summing together the Px (or the modes) of the reserves for a number of fields is not generally equal to the Px (or the mode) of the sum of those reserves. For the record, summing the reserves 1P (proven reserves) for the fields in a basin tends to underestimate the reserves 1P of the entire basin, and summing the reserves 3P (proven + probable + possible reserves) for the fields in a basin tends to overestimate the reserves 3P of the entire basin. In the case of 2P the error can go either way. Furthermore whether they are an overestimate or an underestimate is a random process. The only estimates which can legitimately (in mathematical terms) be summed together are the expected values, because the sum of the means is equal the mean of the sums. Broadly speaking, the mean is the only simple and robust statistical tool which allows a forecast to be made. However it is important to realise that the mean only proves to be effective when used a large number of times: taking Fig. 3.2 as an example, the expected value of the distribution will only be achieved in 15% of cases. In concrete terms this means that if several fields have this distribution, only 15% of them will turn out to have reserves greater than the mean of the distribution! But it should be noted that the sum of the actual reserves of the fields will be close to the number of fields multiplied by the expected value 98

Great care therefore needs to be exercised when doing calculations involving reserves. However estimates of reserves for individual fields have to be summed in order to obtain order of magnitude estimates of the reserves at a more macro level (region, country, fields owned by an oil company). Usually only the proven reserves are published. These therefore provide the only data available for statistical studies. Although summing them arithmetically may not be mathematically correct, there is usually no alternative.

3.2 CHARACTERISTICS OF RESERVES As mentioned earlier, a distinction is traditionally made between conventional and nonconventional hydrocarbons. We will not deal with the case of condensates —light liquids sometimes associated with natural gas— because these reserves are generally included in the figures for the gas reserves, except, usually, in the U.S. and Canada. It should be noted however that condensates account for up to 20%, in terms of energy content, of the reserves of the field.

3.2.1

Conventional and non-conventional hydrocarbons

In this area also there is not a clear and precise definition of which hydrocarbons are conventional and which are not. A qualitative description of petroleum was given in Chapter 1. Natural gas is described less in terms of quality parameters (calorific value, content of sulphur or inert gases such as CO2, etc.) than in terms of its origin. A distinction is made, therefore, between gases associated with oil or condensates and so-called dry gases (which account for two-thirds of present world gas reserves). Whether a particular gas deposit is considered conventional or not depends on how difficult it is to extract and put into production. Colin Campbell, Alain Perrodon and Jean Laherrère (1998) regard conventional hydrocarbons as being hydrocarbons which can be produced in the technical and economic conditions of the present and the foreseeable future. This definition, which is very close to McKelvey’s definition of proven reserves (see Section 3.1), allows however for technological progress and future economic circumstances. Non-conventional hydrocarbons therefore become, putting it somewhat simplistically, those which are difficult and costly to produce. But it is extremely difficult to know what the technical and economic conditions will be in the future. The impact of a new technology on the extraction of hydrocarbons can be measured post hoc, but how can we predict where technology will be in 20 years? This is well exemplified by the deep offshore sector. At the end of the 1970s all offshore hydrocarbons situated in water at a depth greater than 200 metres were considered nonconventional (and therefore not included in estimates of proven reserves). The technology of the time was simply not able to put these resources into production profitably. Nowadays 99

Chapter 3 Hydrocarbon reserves

of the distribution. This apparent paradox results from the law of large numbers, which states that deviations from the mean will tend to cancel one another out, i.e. that the mean of the deviations will tend to zero. It is therefore just as crucial to know the standard deviation (the quadratic mean of deviations from the expected value). This information allows prediction intervals to be constructed. But it should be borne in mind that the size distributions of hydrocarbon fields are characterised by large standard deviations, giving extremely wide prediction intervals.

Chapter 3 Hydrocarbon reserves

we commonly envisage producing from reservoirs in depths of water 5 or 10 times as great, i.e. at depths of 2 000 metres. The boundary between conventional and non-conventional hydrocarbons has retreated considerably over time. Heavy and extra-heavy hydrocarbons furnish another example. The Orinoco basin in Venezuela, which has been known since the 1930s, contains extra-heavy crudes (8–10°API). In 1967 a first evaluation of the total resources present there arrived at an estimate of 693 Gbbl (i.e. equivalent to more than half of the world’s proven reserves of conventional oil). The position in 1967 was therefore: resources = 693 Gbbl, reserves = 0! A new evaluation in 1983, however, estimated the resources to be 1 200 Gbbl and the reserves (these were strictly speaking not proven reserves) to be of the order of 100 to 300 Gbbl. It can be seen, therefore, that the boundary between conventional and non-conventional tends to be pushed back over time in the direction of hydrocarbons which are more and more difficult to produce in terms of production conditions, situation, quality and overall, in terms of extraction costs. However geopolitical factors also come into play, modifying this picture somewhat. In the Middle East, for example, oil tends to be easy to produce and abundant. One of the consequences of the oil price shocks2, however, was to enable the discovery and commercial production of less accessible petroleum throughout the world. The oil which is cheapest to produce is therefore no longer necessarily the only or even the first resources to be exploited. Non-conventional hydrocarbons are therefore the reserves of the future. This shifting of the boundary is referred to by some authors as the fossil carbon continuum. When the reserves of a certain type of hydrocarbon which can be produced are exhausted, other types are sought, including non-conventional hydrocarbons. Gradually, and with the help of technological progress and political exhortation, the production of these new hydrocarbons becomes the norm, becomes conventional or “conventionalised”. We have therefore graduated from oils in the U.S., Algeria and the Middle East which are easy to produce, to offshore, and are now turning to extra-heavy oils and ultra-deep offshore hydrocarbons. The main families of non-conventional hydrocarbons are considered in the sub-sections below.

3.2.2

Deep and ultra-deep offshore

A distinction is generally made between deep offshore (between 400 meters and 1 500 meters water depth) and ultra-deep offshore (up to 1 500 meters). The former can nowadays be easily accessed, thanks to advances in data processing and their application to 3D seismic data. Deep and ultra-deep offshore reserves are estimated between 160 Gboe and 300 Gboe (IEA, 2005). More than 70% of these reserves are located in Brazil, Angola, Nigeria and United States. Today, most of the production comes from the Gulf of Mexico but the growth is expected from Angola and mainly Brazil with the pre-salt discoveries.

3.2.3

Heavy, extra-heavy oils and oil sands

An oil is termed heavy if its API gravity is less than 22°. Below the range 12 to 15°API it is referred to as extra-heavy. Many of these deposits are referred to as oil sands. These

2. Term referring to large and abrupt changes of price, see Chapter 1.

100

3.2.4

Oil shales

Oil shales are not oils in the same way as the aforementioned hydrocarbons. They do not originate from the migration of oil from source rock to a reservoir, but remain in the source rock. The source rock is usually a clayey sedimentary rock which can produce oil after undergoing crushing and pyrolysis at a temperature of about 500°C. The production of oil from shale requires heavy industrial installations. Shale can claim a first in petroleum history: at the beginning of the 20th century there were numerous sites where shale was quarried throughout the world. These shales produced surface outcrops which were of course exploited. At a time when petroleum geology was virtually non-existent, no exploration was needed to find these deposits. Shale can be found on all five continents, as can be seen from Table 3.2, but the largest deposits occur in the U.S. Except in the U.S. and in Estonia, the oil produced from shales is currently confidential. The process produces large volumes of solid waste and CO2, and these will lead to additional environmental protection costs. Furthermore, enormous quantities of water are required. For example it has been calculated by the company Unocal that it would be necessary to use the entire flow of the Colorado river in order to produce commercially from the Green River Canyon shales.

Table 3.2 World resources of oil shales (Gbbl).

US

South America

Australia

2 200

800

(of which 20 of Stuart shale oil)

Africa

Former USSR

Asia

(unofficial)

(unofficial)

200 Resources

101

115

1 400

2 800

Chapter 3 Hydrocarbon reserves

substances are genuine petroleum, having passed through the entire cycle which characterises the formation of petroleum. They originate from hydrocarbons expelled from a source rock into a reservoir (generally sand), often very large in size. Long oxidation and the gradual disappearance of the lighter fractions have resulted in extra-heavy and extremely viscous oils. The two main examples of deposits of this kind are the oil sands of Athabasca in Western Canada and the Orinoco belt in Venezuela. The total resources of these oils are considerable: of the order of 4 700 Gbbl, i.e. four times the proven reserves of conventional oils! More than one-third (1 700 Gbbl) of these resources are found in Canada, with 870 Gbbl in Athabasca alone. Russia may have 1 500 Gbbl of heavy oil resources, although the official statistics do not indicate the densities involved, which makes classification risky. After Russia, Venezuela possesses 1 200 Gbbl in the Orinoco belt. The U.S. and Indonesia also have large resources. Oil sands have so far remained within the domain of non-conventional oils, despite the vast resources involved. Today, only 5% of these resources appear to be economically viable. By 2025–2035 the recovery ratio may have reached a threshold of 15–20%, whereby oil sands could be regarded as a conventional hydrocarbon.

Chapter 3 Hydrocarbon reserves

3.2.5

Synthetic oils (Fig. 3.3)

The Fischer-Tropsch process for converting gas or coal into synthetic oil was developed in Germany during the second world war (see Chapter 1), where it was the only source of motor fuel. The process remains a difficult one. The market for synthetic oil produced from gas could grow. Until recently, there were only a few units which convert gas into oil —a production capacity of 100 kbbl/d from 30 Mm3/d of gas— notably in Malaysia (Shell experiment) and South Africa (a remnant from a boycott by producing countries provoked by the policy of apartheid. Things have changed with the new market conditions based on a higher crude oil price. New projects are now under consideration. In the Pearl Gas to Liquids project, Shell and Qatar Petroleum are investing hugely to build two 70 kbbl/d trains dedicated to convert gas into oil. China has turned its attention to coal liquefaction technology. In 2004, Shenhua Group, the country’s largest coal producer, was assigned a project to build a coal liquefaction plant in northern China. The first phase is intented to bring on stream annual production capacity of 1 Mtoe output by 2008. A second phase could then raise the project to its full design capacity (100kbbl/d of oil equivalent output). South African Sasol sees also coal to liquids potential in China (feasibility studies are conducted for two 80 kboe/d plants) and in the US (in Montana, Illinois and Wyoming).

Figure 3.3 Possible applications of the Fischer-Tropsch process.

3.2.6

Non-conventional gas

The resources of non-conventional gas are thought to be considerable, but are not yet well charted. Reservoirs of non-conventional gas are characterised by low recovery rates: of the order of 10–20%, against about 80% for conventional gasfields. These are reservoirs in which the entrapment mechanism is very different from that of conventional reservoirs. The three main types of non-conventional gas originate from: – Coal deposits (coalbed methane); – Shales and formations with a low permeability (tight sands); – Gas in solution in aquifers and zones of geopressure. Gas obtained from coal deposits in the U.S. are the best known. But estimates of US resources vary between 2.8 and 9.8 Tm3. The other countries with large resources are China (30–35 Tm3), Russia (20–100 Tm3) and Canada (5–75 Tm3). The figures tell their own story 102

3.2.7

The polar zones

Several fruitful exploration programmes have been carried out in the Arctic, and these have identified some 10 basins with real potential. Most of these basins are in Alaska, Greenland and Russia, the latter looking the most promising. In the Arctic as a whole, resources of 8 700 Gbbl of oil and up to 20 Tm3 of gas have been discovered. However the fields concerned probably contain much more gas than has been announced. It should not be forgotten when considering these figures that production of these resources will be particularly difficult given the very harsh climate, the ice cover, the lack of infrastructure and the remoteness of the site from existing markets. The Antarctic, on the other hand, looks very much like being the poor relation of its Northern counterpart. The geology of Antarctica seems unpropitious for the discovery of significant deposits of oil. Furthermore, quite apart from the difficulties associated with the extreme climate and inaccessibility, all industrial activities on this continent have been forbidden since 1991, in order to preserve its environment.

3.2.8

Other types of non-conventional hydrocarbons

There are many other categories of non-conventional and other hydrocarbons, for example: • Very small fields (less than 10 Mboe) are classified as non-conventional. There are very

many such fields. But their small size makes them difficult to find. Furthermore there needs to be pre-existing infrastructure nearby. Development costs must be kept low if very small fields are to be remotely profitable. • Oils won by assisted recovery techniques are themselves sometimes treated as being

non-conventional products, although most of these techniques are becoming standard. • High-pressure, high-temperature (HP-HT) reservoirs are subject to the same kind of

inconsistencies because the various record-keeping agencies do not use the same pressure and temperature criteria (these vary around 700 bar and 150°C) for classification. This 103

Chapter 3 Hydrocarbon reserves

as to the uncertainty attaching to the estimates. Production remains limited but is growing significantly in the US —where 45 Bcm were extracted in 2004— and in China where 10 Bcm could be produced in 2010. Tight gas sand reserves figures remain unknown. Canada estimates vary in the range 2.5–42 Bcm. US ressources are estimated to 7 Bcm. Production is growing. In 2005, 100 Bcm of natural gas were extracted from tight gas sand reservoirs in the US. As far as shale gas is concerned, figures of 100 Tm3 have been suggested, but 40 Tm3 is probably a more realistic figure. In any case, production is mainly located in the US (17 Gm3 per year in 2005). The solubility of methane in water depends greatly on pressure and temperature (for example 17 m3 per m3 of water at a depth of 6 000 m and up to 170 m3 at 10 000 m). Because of the sensitivity of the calculation to the conditions within the trap, estimating the resources present can be a perilous undertaking, and the figures which follow are of a highly speculative nature. Russia has estimated that its resources are 1 000 Tm3, and U.S. estimates vary in the range 30–200 Tm3 (including 150 Tm3 for the Gulf of Mexico alone). In the early 1980s an estimate of 1 000 Tm3 were made for a single reservoir in the Gulf of Mexico! The production of non-conventional gases is growing fast in North America and China. In any case, production remains limited compared to conventional gas extraction..

Chapter 3 Hydrocarbon reserves

means that fields with the same pressure and temperature characteristics may sometimes be classified as conventional and sometimes as non-conventional. • Gas hydrates are very important potential sources, and some authors consider that these may

exceed in magnitude the total known reserves of hydrocarbons. These are gases in a solid form which occur in the form of crystalline hydrates. It is impossible to say now whether we will one day be able to transform these resources into reserves. Two hurdles will have to be overcome to make the production of these substances viable: their low energy density and the considerable input of energy needed to transform them from a solid into a gas.

3.3 THE PRODUCTION OF RESERVES 3.3.1

The decision to produce

A new discovery is not put into production unless there is a profitable market for the hydrocarbons produced. This self-evident statement illustrates the extent to which the concept of reserves is economic in nature. However the circumstances for gas are rather different from those of oil. At present and allowing for existing rates of consumption the reserves of gas will outlast those of oil (about 65 years, against 40 years for oil). Furthermore it is generally agreed that gas production will peak (point at which production begins to decline) later than oil production. The demand for gas, although real and considerable, is therefore less sustained than that for oil products, or to put it another way, in consuming energy we tend to give priority to the most economic option (at present oil), with their wide variation in energy content. It should be remembered in this connection that gas is 5 times as costly to transport as oil. The oil market is rather more demand-driven than that of gas, where supply is often waiting for demand. This phenomenon is well known because it also applied (and still applies) to the coal market. In practice there are very many extremely large known gasfields which will probably never be put into production. At the present rate of production, coal reserves will last more than 160 years. This statistic is difficult to interpret, however, because it seems very likely that two centuries from now coal will have all but disappeared as a source of energy. This means that some of these reserves will deliberately not be exploited. This being the case, these latter should be classified as resources rather than reserves. The same applies, on a smaller scale, to natural gas. In the past, large quantities of gas have been flared because there was effectively no market for it. In the two succeeding sections we will consider how reserves are estimated, and production is forecast, using production profiles at the level of the field, basin or province.

3.3.2

Production profiles

The production profile of a field is a graph in which production (usually annual) is plotted against time. A production profile can be prepared in the same way for a well, a field or a complete geographical zone by the same process as that applying to a petroleum system, a basin or a country. The profile can be descriptive (i.e. historical data) or predictive. Predictive profiles are usually constructed for a well or a field once the production tests have been completed. Two theoretical examples are given below which are typical of production profiles for an oil —or gasfield. The field reserves are represented by the area under the curve 104

Mbbl 18

3.2

16

2.8

14

Mbbl

2.4

12

2

10

1.6

8

1.2

6

0.8

4

0.4

2 Years

0

Years

0

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 444648 50

0

Figure 3.4 Characteristic production profile for a very small oilfield (20 Mbbl).

4

8

12

16

20

24

28

32

36

40

44

48

50

Figure 3.5 Characteristic production profile for a large oilfield (500 Mbbl).

which defines the production profile. The preparation of a predictive production profile therefore also involves estimating reserves (equal to the area under the curve). At the level of the field, there are broadly two types of profile, corresponding to small and large fields. Small fields (Fig. 3.4) exhibit a very steep rise in production and are rapidly exhausted, so as to reduce the production costs by concentrating them over as short a period as possible. Conversely, the production profile of a large field (Fig. 3.5) tends to be more spread out in time. After an initial testing period it climbs steeply to reach a production plateau which is maintained for a number of years, depending on the size of the field. The decline in production as the field becomes depleted is generally slow. It can be seen that production profiles tend to be very asymmetric around their production peak (or maximum). When, however, production profiles are summed to give estimates for an entire basin or country, the aggregated curve is often symmetrical about its peak, with a rather bell-like shape. This fact was first applied by King Hubbert at the end of the 1950s to forecast the peak and decline of oil production in the U.S. But is this forecasting method of universal applicability?

3.3.3

Hubbert theory of decline (Fig. 3.6)

3.5

Annual production of US (48 states)

3

Fitted norma curve

2.5 2 1.5 1 0.5 0 1850

1900

1950

2000

2050

Figure 3.6 Hubbert’s historic example (Source: www.hubbertpeak.com).

105

Years

Chapter 3 Hydrocarbon reserves

4 3.6

Chapter 3 Hydrocarbon reserves

Around 1960, King Hubbert, then an engineer at Shell, forecast, by fitting a normal curve to the production profile of 48 American states, that production would reach its peak in 1969. Production would then decline in a manner symmetrical to the growth phase. His forecast of the peak proved correct to within a year. This success won its author great acclaim and recognition from his peers. There are various Internet sites which promote the work of Hubbert and his disciples. However the fact that his theory was vindicated for one particular example does not mean that his model has been validated generally. An entire school of forecasting has been erected on this solecism. The object of this section is not to refute Hubbert’s conclusions or methodology but rather to point out that there has been no valid scientific proof of the effectiveness of this method, and still less of its universality. The model does however have the merit of comprising a particularly simple example of a method of forecasting production (and therefore also the ultimate reserves). As we argue in Box 3.1, it is legitimate to make some criticisms of the tendency to force everything into a normal distribution; there are many regions in the world, including the U.S., where aggregated production profiles are not distributed normally, or even symmetrically. A model of this kind makes time the only explanatory variable for the production of a region. This is a astonishing idea, implying an ineluctable decline mirroring the growth phase, and does not allow the possibility of reserves being created as a result of technical progress. Box 3.1 Hubbert and mathematics. Even if, in several regions of the world, production profiles are found to be distributed normally, there is no reason to believe that all production profiles will display this pattern. However attempts have been made to explain or justify the Hubbert phenomenon “mathematically”. One such attempt, tenacious and false, appeals to one of the most celebrated theorems of probability theory: the central limit theorem. This states that under certain regularity hypotheses the sum of a large number of independent random phenomena (even if highly asymmetric or multimodal) tends to produce a random variable with a normal distribution, that is, symmetrical with a bell-shaped distribution, like that used in the Hubbert approach: the distribution function of the sum of the processes is close to being normally distributed. But the probability density of the sum is not equal to the sum of the probability density (in this case the production profiles of the fields). Furthermore the Hubbert phenomenon does not fall within the scope of this theorem. In the first place the production profiles summed are obviously not independent of one another, particularly when they relate to the same geographical zone, and secondly the theorem relates to numerical distributions rather than temporal distributions, as in Hubbert’s model. Temporal distributions are subject to a completely different tool of probability theory, namely time series analysis. Great care must therefore be taken not to misuse this method which, however appealing it may seem on the basis of a few examples, has no scientific basis. If certain aggregated profiles exhibit the characteristics of the normal distribution, these are curiosities, the real reason for which it would be very interesting to explore, rather than a phenomenon of general applicability as claimed by Hubbert and his numerous followers. Hubbert himself ended up by repudiating the normal curve in favour of the logistic curve which unfortunately is no more justified than the normal curve.

106

The impact of technical progress on the production profile

A profile is usually constructed when production commences, once the production tests have been completed. Post mortem profiles, i.e. those which can be drawn when production comes to an end, are often very different from those initially envisaged, however. This difference is usually caused by technological progress, which may increase the reserves (Fig. 3.7) or permit their accelerated production (Fig. 3.8).

3.5

3.5

Mbbl

Mbbl

3

3

2.5

2.5

2

2

1.5

1.5

1

1

0.5 0

0.5 Years

Years

0 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40

Figure 3.7 Effect on initial production profile (mauve) of the creation of reserves due to technological progress (grey).

Figure 3.8 Effect on initial production profile (mauve then white) of the accelerated extraction of reserves due to technological progress (grey).

The two scenarios presented below show the impact of an assisted recovery technique put into operation after 16 years of production. In the first case there is no change in the resources, but additional reserves are created (the area under the curve rises from 50 to 60 Mbbl). There is said to have been an increase in the recovery ratio (see Box 3.2). In the second case no new reserves have been created (the dark shaded area is exactly equal in size to the blank area under the curve corresponding to the original production profile), but simply an acceleration in the extraction of the existing reserves. Production comes to an end 10 years earlier, without any loss in the total reserves extracted. Although there is no increase in the reserves, the acceleration is definitely economically advantageous for the producer as it allows him to avoid a long period of run-down and to receive the revenues earlier. There are many examples of both cases. The Alwyn field in the North Sea is a textbook example of the first scenario. A variety of measures were taken resulting in a succession of significant increases in the reserves. A number of writers have identified numerous examples of the second scenario. The second model of technological progress takes a pessimistic view about reserves. In relation to conventional oil, technology simply accelerates depletion and therefore hastens the onset of scarcity. As already mentioned earlier, there are two schools of thought in relation to ultimate reserves. The object of the next section is to present both sets of arguments so that the debate can be properly understood. 107

Chapter 3 Hydrocarbon reserves

3.3.4

Chapter 3 Hydrocarbon reserves

Box 3.2 Indicators used in the upstream petroleum industry. There are many indicators commonly used in the petroleum industry, either at company level or for the entire sector. These may have a warning function, may be for general management purposes or to signal scarcity. R/P The first and most widely used indicates the outstanding life of the reserves at the present rate of production assuming that no further discoveries are made: it is the ratio reserves/production, often indicated by R/P. It is expressed as a number of years. The ratio has fluctuated considerably over the years, as the following table shows:

Oil Gas

50′

70′

80′

90′

00′

150

30 50

35 55

40 60

40 63

Since 1970, when it appeared that oil would be exhausted by 2000, the outstanding life of the reserves has only increased. These indices, shown above for the global level, can also be calculated by region, company, etc. These ratios vary from 8 years (North Sea) to 80 years (Middle East), according to region and are traditionally in the range 8 to 15 years for companies, depending on their policy. These ratios have a certain strategic importance for the companies, who try to keep to the value reasonably constant at approximately 10 years. A ratio which falls too low indicates a company in poor health. It should be noted that this ratio is very sensitive to the definition of reserves adopted. In 1986 the method used in the Middle East to evaluate reserves changed, leading to a substantial rise in the R/P ratio. Success rate This indicator, used by the upstream petroleum industry, is the ratio of non-dry wells to the total number of wells drilled. It is therefore, at the company level, a measure of its success in exploration. However this index must be interpreted cautiously. A non-dry well which discovers reserves of 1 million barrels is obviously not equal in value to one which discovers reserves of 1 billion barrels. The ratio should therefore reflect the size of the reserves involved; a high success rate in a region where the reservoirs are small is of no great interest to the company. The success rate nevertheless provides a measure of the effectiveness of exploration. Its value has climbed over the last 30 years, from 1/10 to 1/5 and even 1/3 nowadays. Recovery factor The recovery factor, defined for a field, is the ratio of the reserves to the resources in the field. It varies with time, along with the estimates of reserves and resources. Average recovery factors for conventional hydrocarbons are at the moment 30–40% for oil and 80% for gas. One of the ways of increasing reserves —the other being exploration— is to increase this percentage by taking advantage of technological advances. This is sometimes referred to as field growth. The recovery factor is often used as a criterion to distinguish between conventional and non-conventional hydrocarbons, particularly for gas. As far as heavy oils are concerned, recovery factors are of the order of 10% or less. There is obviously great scope for improving these rates, and nowadays reserves are mainly created by increasing the recovery factor from deposits of non-conventional hydrocarbons.

108

It was seen in the previous section that the forecasting of reserves is particularly important for the petroleum industry. There are several theories in this area, and these lead to schools of thought which are radically opposed to one another.

3.4.1

Two schools of thought

It would be an oversimplification to reduce the argument between optimists and pessimists into a debate between the defenders of the validity of this or that index (see Box 3.2). Nevertheless linking the various views with the behaviour of the indices allows ideas to be put into perspective. The R/P ratio is increasing over time, which appears to indicate that the point in time when stocks will become depleted, already distant, is receding still further. Furthermore the success rates announced by the industry tend to increase over time, indicating that explorers are finding increasing numbers of oilfields, and that the fear of shortages is not at all justified. This optimistic view, as we see analytically defensible, is criticised by the pessimists, who argue that these indicators are biased: the R/P ratio does not represent the actual number of years of reserves because production is increasing regularly by 2–3% per year, while oilfield discoveries are becoming less frequent. R/P is therefore an over-optimistic indicator. This index continues to enjoy very wide use in the petroleum industry, however, and will continue to be used regardless. It is incumbent on the analyst to be aware of the bias inherent in this ratio and interpret the figures accordingly. Similar remarks apply to the “success rate” for exploration, which by definition only allows for numbers of successes, and is not weighted by the size of the finds. It therefore also remains a relative and biased indicator of exploration performance (see Box 3.2). But the optimistic and pessimistic theories, the main arguments for which are summarised above, draw on two opposing economic theories.

P r i c e

P r i c e

Time

Figure 3.9 In a closed market falling prices stimulate demand until signs of scarcity begin to appear, when prices rise again, thereby reducing demand.

Figure 3.10 In an open market three types of energy are competing. Prices fall as the current energy type is progressively substituted by less costly alternatives (here NRJ 1 is substituted by NRJ 2 and then NRJ 3). This process is known as economic reproduction.

109

Chapter 3 Hydrocarbon reserves

3.4 OPTIMISTS AND PESSIMISTS

Chapter 3 Hydrocarbon reserves

There are several theories of exhaustible resources, particularly Hotelling’s theory, for which the reader is referred to Chapter 1. The following comments appeal to the law of supply and demand. Let us assume that the oil market is a closed market, that is, we only have to consider the resource itself; there are no interactions, for example substitutions with other types of resource. The depletion of the resource due to its consumption will lead inexorably to increases in its price (Fig. 3.9), in accordance with the law of supply and demand. Conversely when a market is open, other types of resource which are potential substitutes offer competition. This competition ensures that as a resource is gradually depleted there will be a transition, over time, to new sources of energy. This progressive substitution serves to stabilise or even reduce the market price over time (Fig. 3.10). This phenomenon is sometimes referred to as economic reproduction. Resources are depleted in physical terms, but the reserves reproduce themselves in an economic sense. These are the two sets of ideas which oppose one another, corresponding to the views of the pessimists and the optimists. The pessimists Given that the quantities of sub-surface hydrocarbons are finite, each quantum consumed brings the exhaustion of reserves closer. In fact, production and consumption are growing over time (in particular because of demographic growth). The pessimists regard this development as unsustainable, being liable to lead to shortages, and therefore sharp increases in price. Many scientists, industrialists and ecologists fervently espouse the pessimistic view, regularly predicting the peaking and decline in the production of hydrocarbons, because for a number of years the new reserves discovered worldwide have been less than production. The petroleum price shocks of 1973 and 1979 were caused in part by the fear of shortages and an artificial reduction in supply. During the 1970s the economies of the industrialised countries were very dependent on oil. A reduction in the reserves therefore contributed to the very large increase in the prices of hydrocarbons, in accordance with the law of supply and demand (see Chapter 1 for a presentation of the associated geopolitical issues). However this recurrent fear led the oil companies and governments to step up their R&D efforts in order to devise new techniques which would render feasible certain activities which had hitherto been marginal, such as nuclear energy or the extraction of certain nonconventional oils. Despite these efforts, economies remain largely dependent on the production of existing conventional hydrocarbons. The pessimists tell us that despite the technological advances made we are heading for a third and final price shock3. The optimists This school of thought began to develop in the mid-1980s, and is based on the failure of the expected increase in prices to materialise. There is of course no denying the fact that the reserves of conventional hydrocarbons, finite in quantity, are being consumed. However oil prices remain stable over the long term. The vaunted price rises have not happened. This can 3. This only applies to conventional hydrocarbons. As far as non-conventional hydrocarbons are concerned, technical progress is obviously creating new reserves because it leads us to go and explore for hydrocarbons in hitherto unexploited zones in the world.

110

3.4.2

Naturalists or economists?

Whatever one’s point of view, the conclusion for the long term remains the same: energy policy for the future must focus on radically new types of energy (first and foremost nuclear, followed by solar, wind, biomass, etc.) or hydrocarbons which have so far not been exploited because they were not economically feasible (e.g. non-conventional). In both cases there must be energy substitution, economic reproduction. The vision of the pessimists differs from that of the optimists, however, in that it assumes that a very active posture, and the building of public awareness of the impending shortages and risk of sharp price rises, are needed to negotiate the transition to the new energies. The optimists, on the other hand, believe that the transition to the new energies will occur naturally (as implied by the concept of the fossil carbon continuum) as a result of technological progress and market forces such as the competition between the various energy types.

3.4.3

Concluding remarks

Our intention at the end of this chapter is not to arbitrate between these two points of view. It has to be conceded that in the short term the pessimistic view of the petroleum industry is supported by many concrete and incontrovertible examples. On the other hand the optimists can also produce evidence suggesting that the petroleum industry has been able to adapt to change through revolutionary technologies which have made it possible to commercialise hydrocarbons which were previously ignored or whose existence we were unaware of. This has enabled it to increase reserves during the last 20 years. Despite this major divergence of opinion there is consensus that the ultimate reserves, available for consumption during the next 20 years (see introduction to this Chapter), are close to 2 500 Gbbl. This figure is very different from the estimate of several tens of thousands of Gbbl of non-conventional resources mentioned in Section 3.2. Furthermore these 111

Chapter 3 Hydrocarbon reserves

be interpreted as a refusal by the markets to accept that the shortages proclaimed by the pessimists are imminent. As described in Section 3.2.1, there has been a gradual substitution of conventional by non-conventional oils which can now be commercially produced, in accordance with the concept of the fossil carbon continuum mentioned earlier (in Section 3.2.1). Furthermore the two oil price shocks in the 1970s encouraged the emergence of new energies (particularly nuclear energy) and new technologies which allowed certain non-conventional oils to be made commercial. To the proponents of this view, petroleum appears to be characterised by the open market model (Fig. 3.10) in which the process of economic reproduction is taking place, rather than the closed market model. Furthermore this model is in keeping with the present trend towards economic liberalism. However economic reproduction will only occur if technology is successful in developing new types of energy. We saw in Section 3.3.4 that technological progress can be an agent for accelerating depletion rather than a catalyst for economic reproduction. But the risk of depletion should be reflected in a perceptible increase in prices, whereas no such increase can yet be detected. The argument between the two camps appears to reduce to a confrontation between a common sense, “naturalistic” view that if an exhaustible resource is consumed it will become scarcer, and the partisans of progress and economic liberalism, the openness of markets and the theory of economic reproduction which stems from it. Does this mean that naturalists are essentially pessimists, and economists optimists?

Chapter 3 Hydrocarbon reserves

speculations may rage, but as we saw, in the medium to long term both camps ultimately agree that a transition to new energies or new hydrocarbons is inevitable. The debate therefore boils down in the end to a personal conviction as to how the transition will come about: through an abrupt increase in prices for the pessimists or as an orderly and gradual shift for the optimists.

3.5 GEOGRAPHICAL DISTRIBUTION OF RESERVES AND PRODUCTION This section presents a table for each geographical region summarising the proven reserves, annual production and R/P ratios for the main producing countries, together with a map showing the most important producing sedimentary basins. All the data quoted are taken from the BP Statistical Review 2007. The maps are adapted from the USGS World Petroleum Assessment. Table 3.3 Proven reserves and annual production worldwide. Proven reserves (Gbbl) (Tm3) Africa Middle East Asia-Oceania Europe Former USSR North America South America Total

Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas

117.5

Oil Gas

1 239.9

Annual production (Mbbl) (Gm3) 3 766

14.6

R/P (years) 31.2

190.4

755.3

9 190 73.2

76.6 82.2

355.0

40.8

2 886 14.5

> 99 14.1

391.5

16.3

1 893 5.7

36.9 8.6

274.9

129.5

4 783 52.7

20.8 27.1

781.9

69.3

4 988 8.0

67.4 13.9

775.8

111.2

2 421 7.8

10.3 45.9

150.8 29 925

176.4

2 920.3

112

51.5 41.3 60.4

North America Table 3.4 Proven reserves and annual production, North America. Proven reserves (Gbbl) (Tm3)

United States Canada Mexico Total

Oil Gas Oil Gas Oil Gas

29.4

Oil Gas

69.3

Annual production (Mbbl) (Gm3) 2 511

6.0 27.7

(years) 11.7

545.9 1 208

1.6 12.2

R/P

11.0 22.9

183.7 1 269

0.4

8.9 9.6

46.2 4 988

8.0

8.0 13.9

775.8

10.3

C A N A D A

U N I T E D S TAT E S Offshore sedimentary basin Onshore sedimentary basin

MEXICO

Figure 3.11 Main sedimentary basins in North America (excluding U.S.).

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Chapter 3 Hydrocarbon reserves

3.5.1

Chapter 3 Hydrocarbon reserves

3.5.2

South America Table 3.5 Proven reserves and annual production, South America. Proven reserves (Gbbl) (Tm3)

Argentina Brazil Trinidad & Tobago Venezuela Other Total

Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas

2.6

Annual production (Mbbl) (Gm3) 255

0.44 12.6

10.2

669

0.48

18.8

39.0

5.15

28.5

1.33

> 99 16.8

27.2 2 421

7.76

12.3 91.2

487

111.2

31.9 14.2

954

8.2

9.8

11.3 56

87.0

(years)

44.8

0.36 0.8

R/P

48.9 45.9

150.8

Offshore sedimentary basin Onshore sedimentary basin Main producing country Other countries

Figure 3.12 Main sedimentary basins and hydrocarbon producing countries in South America.

114

51.5

Europe Table 3.6 Proven reserves and annual production, Europe. Proven reserves (Gbbl) (Tm3)

Norway Netherlands United Kingdom Other Total

Oil Gas Oil Gas Oil Gas Oil Gas

8.2

Oil Gas

16.3

Annual production (Mbbl) (Gm3) 933

3.0 – 1.2

8.8 33.0 – 64.5

597 0.4

4.5

(years)

89.7 –

3.6

R/P

19.4 6.0

72.4 363

1.1

5.7 12.4

48.3 1 893

5.7

22.6 8.6

274.9

NORWAY

UNITED KINGDOM

Netherlands

Offshore sedimentary basin Onshore sedimentary basin Main producing country Other countries

Figure 3.13 Main sedimentary basins and hydrocarbon producing countries in Europe.

115

20.8

Chapter 3 Hydrocarbon reserves

3.5.3

Chapter 3 Hydrocarbon reserves

3.5.4

Africa Table 3.7 Proven reserves and annual production, Africa. Proven reserves (Gbbl) (Tm3)

Algeria Angola Egypt Libya Nigeria Other Total

Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas

12.3

Oil Gas

117.5

Annual production (Mbbl) (Gm3) 730

4.5 9.0 –

46.5

1.5

44.3 61.5

15.2 860

5.3 14.4

– 15.8

675

36.2

54.5 14.3

–

2.1

99 42.1

35.0 613

1.2

> 99 23.5

10.7 3 766

14.6

Algeria

16.8

259

41.5

(years)

83.0 629

4.1

R/P

> 99 31.2

190.4

Libya Egypt

Nigeria

Offshore sedimentary basin Onshore sedimentary basin Main producing country Other countries

Angola

Figure 3.14 Main sedimentary basins and hydrocarbon producing countries in Africa.

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76.6

Middle East Table 3.8 Proven reserves and annual production, Middle East. Proven reserves (Gbbl) (Tm3)

Iran Iraq Kuwait Qatar Saudi Arabia United Arab Emirates Other Total

Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas

138.4

Oil Gas

755.3

Annual production (Mbbl) (Gm3) 1 606

27.8

R/P (years) 86.2

111.9

115.0

783 3.2

> 99 > 99

–

101.5

958 1.8

> 99 > 99

12.6

27.4

437 25.6

> 99 62.7

59.8

264.2

3 801 7.2

> 99 69.5

75.9

97.8

1 064 6.1

94 92

49.2

11.0

540 1.6

> 99 20.4

45.6 9 190

78.2

35.1 82.2

355.0

> 99

I r a n

I r a q Kuwait

Saudi Arabia

Qatar United Arab Emirates

Offshore sedimentary basin Onshore sedimentary basin Main producing country Other countries

Figure 3.15 Main sedimentary basins and hydrocarbon producing countries in the Middle East

117

Chapter 3 Hydrocarbon reserves

3.5.5

Chapter 3 Hydrocarbon reserves

3.5.6

Former USSR Table 3.9 Proven reserves and annual production, former USSR. Proven reserves (Gbbl) (Tm3)

Azerbaijan Kazakhstan Russian Federation Turkmenistan Uzbekistan Others Total

Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas

R U S S I A N

Annual production (Mbbl) (Gm3)

7.0

317 1.3

22.1

544 1.9

124,3 73.2

27.3 3 642

44.6

69,6 21.8

607.4

0.6

72 2.7

73.5 8.3

67.4

0.6

42 1.7

39.6 14.4

58.5

2.1

166 0.4

129.5

(years)

10.3

39.8 79.4

R/P

29.7 12.6

11.0 4 783

52.7

39.1 27.1

781.9

F E D E R A T I O N

Offshore sedimentary basin Onshore sedimentary basin Main producing country Other countries

Figure 3.16 Main sedimentary basins and hydrocarbon producing countries in former USSR.

118

67.4

Asia–Oceania Table 3.10 Proven reserves and annual production, Asia-Oceania. Proven reserves (Gbbl) (Tm3)

Australia China India Indonesia Malaysia Others Total

Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas Oil Gas

Annual production (Mbbl) (Gm3)

4.2

205 2.5

R/P (years) 20.5

40.0

15.5

1 366 1.9

62.8 11.3

69.3

5.5

292 1.1

27.1 18.8

30.2

4.4

354 3.0

35.1 12.4

66.7

5.4

276 2.5

45.0 19.6

60.5

5.8

393 3.5

41.0 14.8

124.8

40.8

2 886 14.5

28.3 14.1

391.5

China

India

Offshore sedimentary basin Onshore sedimentary basin Main producing country Other countries

Malaysia Indonesia

Australia

Figure 3.17 Main sedimentary basins and hydrocarbon producing countries in Asia-Oceania.

119

36.9

Chapter 3 Hydrocarbon reserves

3.5.7

4

Investments and costs

4.1 INTRODUCTION Due to the role of energy in the global economy, oil is a crucial global commodity, with a world market of more than $2.0 trillion per year. Investment in oil and gas exploration and production is very high, amounting every year to more than $300 billion. The oil and gas sector is the biggest consumer of steel through its oil and gas pipelines. The total fleet of oil tankers amounts to more than 10,000 vessels (with around 500 very large carriers of more than 200 thousand tons) and 350 million tonnes of oil capacity. Oil and gas production is a very dynamic sector. The growth of demand is around 2% per year, which is not a very high rate of growth compared to dynamic activities like electronics or telecoms. However each oil and gas field has a limited lifespan: around 15 to 20 years for an oil field and 20 to 30 years for a gas field. Furthermore, this is the conventional view as some new fields, especially offshore in the North Sea, Gulf of Mexico and even Africa have much shorter lifespans. Thus there is a strong rate of decline of production which varies from less than 3% per year (putting the lifespan over 30 years) in some Middle East countries, to more than 10% in mature zones for satellite projects. Taking a mean value of 5% per year for the rate of decline, this means that in 10 years, more than 50% of today’s production must be replaced with new production. For an oil company, to keep its market share, the annual rate of growth is over 7% per year, so there is a real challenge for the industry to find and put into production enough oil and gas to provide for the next generation. The oil and gas upstream sector is therefore a very capital intensive sector. Globally, the ratio of investment to revenue is around 8% for the whole sector. For the upstream segment of international oil companies, the ratio of capital expenditure to revenue is much higher, around 17%. This can be compared to a global industrial ratio of around 6-7% in the US and Europe. Today more than 150 oil and gas projects with a capital expenditure over $1 billion are in development. Deciding to develop new E&P projects is the main task of the executive 121

Chapter 4 Investments and costs

committee of major oil and gas companies and capital discipline is a necessity to balance technological, geological, financial and geopolitical risks. The decision on capital is very important because of the uncertain nature of oil and gas production. When oil or gas is discovered, analyses of the drainage mechanisms allow reservoir engineers to determine the nature of investments required and to establish production profiles. Using cost estimates, oil and gas price assumptions and fiscal and contractual terms, oil companies can develop a revenue model for the entire life of the field. Oil and gas exploration and production remains a risky business, despite technological progress. Discovering and producing new resources is a very challenging process, with physical, environmental, technological conditions becoming even more difficult. During exploration activity, despite constant progress in our understanding of the subsurface, a percentage of an oil and gas exploration investment will vanish in dry wells. Over the last ten years, globally, the rate of success in exploration activity has been around 25% (success is measured by the ratio of discoveries with respect to exploration wells drilled, and this indicator gives an optimistic view as it includes discoveries that are not yet commercial, under today’s price and technology). When new oil is discovered, choosing the best development concept is a key decision for an oil company, because re-engineering is very costly, as it often completely defines the operating conditions of the field. Although the initial investment is of fundamental importance, there is a very strong technological evolution which constantly brings marginal projects into development. The frontiers of offshore depth, reservoir temperature, and pressure and viscosity (i.e. heavy oils) are constantly being increased. In order to bring challenging new resources into production, access to new technology (derived from research) is required, while maintaining control of costs. Between 1990 and 2003, technical costs were decreasing, accompanied by technological improvements and strong competition in the service sector. Since 2004, with the strong surge in oil demand, the pattern of costs has changed. With the higher oil prices, oil companies have raced to develop new resources as quickly as possible leading to a tense situation in the oil services sector. As demand has grown very quickly, resources like oil rigs, technical capacities and skilled labour are in short supply. The long-term trend of decreasing costs has been replaced by a strong increase in many of the service sectors. After a peak in 2008, the economic crisis has provoked a small reduction. However costs will remain now much higher than at the beginning of the century.

4.2 COSTS CLASSIFICATION Economic evaluations of petroleum projects include, in addition to assumptions about the value of hydrocarbons, three types of data: – Production profiles, constructed by reservoir engineers from analyses of the drainage mechanisms; – Capital and operating costs, evaluated by cost estimators and managed by the project manager and the field manager respectively; – Contractual and fiscal conditions, which can have a decisive role (they can prevent an excellent project from ever seeing the light of day, for example).

122

4.2.1

Types of costs

Normally speaking there are four types of costs involved in a project in the upstream petroleum industry. These comprise: • The exploration costs incurred mainly before the discovery of a hydrocarbon deposit.

These include the seismic geophysics, the geological and geophysical interpretation, exploration drilling including the well tests; • The investment costs incurred in the delineation and appraisal phase, necessary to gain

knowledge of the reservoir; • The development investments, which include:

– Drilling the production wells and, if appropriate, the injection wells; – Construction of the surface installations such as the collecting network, separation and treatment plant, storage tanks, pumping and metering units; – Construction of transport facilities such as pipelines and loading terminals; • Operating costs including transportation costs.

4.2.2

Examples of cost breakdowns

The relative weights of these different types of cost differ from project to project depending on the environment, the nature of the reservoir and its fluids, the export conditions and, in a very different vein, any contractual constraints which may apply. The exploration costs can vary enormously. They may be limited to a seismic programme and a dry well, in the case of an unsuccessful exploration (generally between $5 and $20 million, occasionally much more). They may represent a very small proportion of the development cost when the discovery is clearly established and well defined. In other cases these costs may make the economics of the project problematical when considerable appraisal work is needed (for example several delineation wells) and the discovery is a marginal one. Two actual examples of cost breakdowns, including delineation, are given in Figs. 4.1 and 4.2. These examples show, and many projects exhibit a similar pattern, that the development costs are fairly evenly divided between drilling operations, the production installations and transport systems. Similar attention therefore needs to be devoted to each of these categories, in terms of the technical definition and the control of implementation. The same of course applies to the operating costs. The total operating costs over the life of a field are of a similar 123

Chapter 4 Investments and costs

The relevant importance of these three elements can of course vary depending on the project context. In the evaluation process these three types of data have to be analysed independently of one another, but also subjected to an overall optimisation cycle such as to maximise value added. This optimisation process almost always leads to a choice being made between alternative development options in which the minimisation of capital and operating costs is a fundamental and ongoing requirement. The company’s profitability and competitiveness depend on this. This imperative applies at all stages of the project. Choosing the right development architecture, accurate costing and controlling expenditure across the board are the keys to success.

Chapter 4 Investments and costs

17% 11% 24% 22%

Drilling and completion Surface installations

20% 21%

Subsea installations Gas export pipeline

44% 41%

Figure 4.1 Example of the cost breakdown for an offshore development (North Sea, water depth 300 m).

30% 38%

Drilling and completion Production installations Transport system

32%

Figure 4.2 Example of the cost breakdown for an onshore development (South America).

magnitude to the investments, although for the decision-maker their weight is lessened by the effects of discounting over a long period1. The object of this chapter is to give a general overview of the orders of magnitude of each of the main items of expenditure, to present some of the methods currently used by estimators and project managers and, finally, to suggest a number of routes by which costs can ultimately be reduced.

1. A decision-maker does not place the same value on a given receipt or expenditure in a number of years as on the same sum now. Discounting consists of applying a given annual rate (this rate is specific to the company) to future receipts and expenditures to estimate their present value. Discounting tends to reduce the impact of future cash flows (see Chapter 6).

124

Exploration costs are generally less important than other items of expenditure (see Section 4.2.2). On the other hand they incur before the discovery of hydrocarbons, and will therefore have a direct impact on the accounts of the company, the recovery of these costs being linked to the likelihood of success of the exploration programme, in general between 10 and 30%.

4.3.1

Geophysics

Petroleum geophysics is dominated by seismic methods, both in terms of the volume of activity and the investment costs. We will therefore confine ourselves in the present section to considering the costs of seismic methods, since only marginal amounts are invested in other methods (radar, potential methods, etc.).

4.3.1.1 Acquisition costs Two-dimensional seismic methods tend to be used for large-scale exploration and in particularly difficult zones. The costs are usually expressed in $/km2. A. Impact of type of terrain Nowadays, companies specialised in seismic exploration are capable of operating in extreme environments (high mountains, swamps, the Arctic, etc.) (Fig. 4.3). However the cost of seismic methods is very dependent on the environment: 3D seismic exploration costs are around $5000/km2 offshore, but can reach $50000/km2 in onshore difficult areas.

A

B

Figure 4.3 Two examples of harsh environments. A. Borneo swamplands. B. The Bolivian sierra.

125

Chapter 4 Investments and costs

4.3 EXPLORATION COSTS

B. Dominant factors The costs of data acquisition offshore are dominated by the costs of the equipment needed (a modern 3D seismic vessel costs around $100 million). Service providers’ fleets are tending to move towards larger vessels capable of sophisticated automated manoeuvring. The movement of seismic equipment onshore cannot however yet be automated. This means that personnel costs are significant, and depend on the cost of local labour. When the terrain is difficult, costs may be increased substantially by the need to use a helicopter or specialised equipment such as thumper trucks where access allows, or floating machinery for swampy terrain. Because of the major investments required to maintain seismic teams, the 1980s saw the oil companies abandoning their own activities in this area, to the advantage of specialised companies such as CGGVeritas and Schlumberger.

4.3.1.2 Data processing costs In the same way as data acquisition, the processing of the seismic data is also subcontracted to service companies, apart from a number of specialised processes and studies which are still carried out by the large oil companies.

Cost ($ million/100 km2)

Chapter 4 Investments and costs

Marine seismic is the least costly by virtue of a technique known as 3D multiflute, which permits the acquisition of strips 500 m wide in a single pass at a speed of about 10 km/hr. On land it is impossible to obtain this density of data economically, and the acquisition grid needs to be reduced. Figure 4.4 shows a comparison of the expected costs of 2D and 3D seismic exploration in different environments. It can be seen that offshore there is not a great difference in costs between a 2D seismic 500 × 500 grid and a 3D programme, so that the latter is being used increasingly frequently. A striking feature is the low cost of seismic for offshore exploration (particularly deep offshore) compared with drilling exploration wells: the exploration costs for an area of 100 km2 would be around $0.5 million for 3D seismic, whereas the cost of drilling an offshore exploration well can be more than $100 million.

14 13 12 11 10 9 8 7 6 5 4 3 2 1 0

Desert Agricultural Urban area

Offshore 3D seismic mini

3D seismic maxi

Jungle

Marshland

2D seismic (500 x 500 m grid)

Figure 4.4 Effect of terrain type on seismic costs.

126

Mountainous

Cost of drilling well

4.3.1.3 Analysis of data Once the seismic data have been acquired and processed, they have to be transformed into data which can be used by the decision-makers (maps, drilling profile, reservoir model, etc.), whether in the exploration or development phase. There is as yet no technique which allows the seismic data to be transformed directly into data which can be used to locate where a well is to be drilled or draw up a development plan. The processing and interpretation of the data using software therefore has to be carried out under the control of specialists. Depending on the accuracy required or the complexity of the subsurface geology, the interpretation of the seismic data can be a task of between a few months and several years. This work will involve personnel and data processing costs which may be in the range $100 000 to $1 million for a seismic survey.

4.3.1.4 Trends in costs A. Effect of technological progress 3D seismic techniques are in a constant state of evolution. Unit costs have fallen considerably since the late 1970s when the technique was first introduced. This reduction in costs has been achieved through technological progress in the following areas: – Optimisation of parameters so as to eliminate data redundancy; – Multiflute/multisource 3D data acquisition which allows a large number of traces to be acquired simultaneously; – On-board automation. Significant reductions in the length and expense of projects have indeed been achieved thanks to the fall in the cost of information technology. However, as the projects that the oil companies are working on today are increasingly difficult, part of these savings are de facto absorbed by the increasingly complex operations required for the processing and analysis of data. B. Effect of the market If technological progress exerts a downward pressure on geophysical costs in the long term, volatility in the prices of hydrocarbons affects costs in the short term. These costs are subject to fierce competition between the service companies operating in the local markets: seismic contracts are awarded on the basis of competitive tenders in the countries concerned.

2. 1 Terabyte = 1012 bytes; 1 byte = 8 bits.

127

Chapter 4 Investments and costs

The data processing costs are lower than the data acquisition costs, being of the order of $500/km2 for 3D seismic and $100/km for 2D. These are the costs of producing the standard data (a 3D programme for deep offshore will involve several terabytes2 of data). When the data require certain advanced or detailed processes which are time-consuming and labourintensive the processing costs may be considerably higher. This applies, for example, to a “depth migration before addition of 3D” which allows three-dimensional subsurface images to be obtained as close as possible to reality from series of images over time created from the seismic records. This process can cost several thousand dollars per km2.

Chapter 4 Investments and costs

Furthermore in mature exploration zones (North Sea, U.S., etc.) the oil companies often award contracts for “off-the-shelf” seismic surveys on a fixed price basis. These “speculative” programmes, which are the property of the contractors who bear the cost of the preinvestment, are often offered at a cost as low as one-tenth of the price which an operating oil company would pay for an exclusive customised survey. For these reasons the mean costs per km2 indicated above must be adjusted to allow for temporal and geographic factors, which can produce variations of a factor of 5 or 10 relative to the mean value.

4.3.2

Exploration drilling

Most of the costs of an exploration programme are accounted for by the drilling. Onshore and offshore drilling each has its own technical peculiarities; they differ particularly in terms of cost if not duration. An offshore well typically costs between $20 and $100 million and takes 30 to 100 days to drill. The corresponding onshore costs are $5 and $20 million, the duration being of the same order. When the conditions are particularly difficult the costs may be much higher, occasionally exceeding $200 million. The main components of the cost of drilling an onshore exploration well are indicated in Fig. 4.5. The duration of drilling is difficult to predict due to geological uncertainties regarding the drillability of the rock, the interstitial pressures of the formation fluids, the depths, etc. Difficulties and unanticipated setbacks such as mud loss, jamming of the drill bit, etc. can cause delays of several days. Some 70–75% of the drilling costs are proportional to the duration of the drilling: equipment hire costs paid to petroleum service companies and the costs of supervising the works (operating company personnel or prime contractor). Only 25–30% of the drilling costs can therefore be estimated with a reasonable degree of precision. These are the costs which depend on the depth drilled (essentially the casing), the cost of the wellhead, etc. For this reason it is a difficult exercise for the technicians to set a budget for an exploration well.

Petroleum services 29.5%

Consumables 32.8%

Consumables Logistics Management and supervision Hire of drilling rig Petroleum services Hire of drilling rig 20.1%

Logistics 12.5% Management and supervision 5.1%

Figure 4.5 Breakdown of costs of onshore exploration drilling.

128

700

550

Number of platforms

450 Supply

400 350

500

300 Demand

250

400

200

Jack-up Gulf of Mexico

300

150 Semi-submersible North Sea

100 50

200

80

82

84

86

88

90

92

94

96

98

00

02

04

06

08

Daily rate (thousand dollars per day)

500 600

0 10

Figure 4.6 Daily hire cost of offshore platforms expressed in thousands US$ per day.

4.3.2.1 Logging and geological parameters The acquisition of petrophysical and petrochemical data involves logging3, core sampling and initial production testing from the reservoir strata. The duration of this work varies from case to case. The monitoring and interpretation of the geological results from the drilling makes use of two techniques practised by specialised service companies. The first of these is mud logging, i.e. the acquisition and surface interpretation of samples, data and information carried via the mud circuit. The second technique involves recording physical parameters which allow the nature of the formations, their pressure regimes and the fluids which saturate them to be characterised. These records are gathered either during drilling by means of sensors incorporated in the drill string (in which case it is referred to as logging while

3. Logging: The recording of various electrical, acoustic and radioactive characteristics of the formations penetrated, as a function of depth.

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Chapter 4 Investments and costs

The hire of the drilling rig alone can represent between 20% (for the above example) and 35% of the total drilling costs. The daily cost depends on its power, which in turn depends on the depth of the well and, for offshore drilling, the water depth involved. It will also depend on the current availability of drilling rigs on the market, that is the relationship between the supply of the drilling companies and the demand of the oil companies. Daily costs for offshore rigs are usually several 10 thousand dollars but can reach several 100 thousand dollars if the market is tight. For the drilling contractor, the capital cost involved can be between $10 and $16 million for onshore equipment, between $120 and $180 million for a jackup platform and between $300 and $380 million for a semi-submersible or drillship with deep water capability. Figure 4.6 illustrates the evolution of daily hire cost of offshore platforms.

Chapter 4 Investments and costs

drilling, or LWD), or after drilling by means of sensors lowered into the wellbore at the end of an electric cable (wire line logging). Both of these techniques are usually necessary, and they produce complementary data. Their costs are quite different, as we shall see below.

4.3.2.2 Surface geological records Sensors situated at the surface (on the mud circuit, the pumps or the winch) are connected to a central data processing unit located in the mud logging room which also includes a small geological laboratory used for sample calcimetry, UV analyses, etc. (Fig. 4.7). The costs relate to the provision of equipment and specialised personnel during drilling operations. The magnitude of these costs depends of course on the local logistics, but predominantly on the extent and complexity of the required measurements. For example the characterisation of gaseous indices by gas chromatography with flame ionisation detection requires the hire of specific equipment costing several hundred dollars. Competition between mud logging contractors over the last decade has kept costs relatively low, of the order of $1 500–3 500/d. The costs of surface geological records represent 2–3% of the total cost of the well.

4.3.2.3 Logging Whatever the actual contractual terms negotiated for logging, the effective costs of these services comprise two components: – The direct costs, i.e. the sums actually billed by the service companies; – The indirect costs, arising from the enforced idleness of other services contracted for the drilling of the well when the logging is being carried out (drilling rig, mud units, cement units, mud logging equipment, etc.). On average, logging operations account for about 5–7% of the total drilling time. Logging costs depend on the level of activity and the type of well being drilled (exploration, appraisal or development), each of these different types of well requiring more or less

Analyser

Extractor

Well:ML-1

Data processing Gas logs

Interpretation

Figure 4.7 Geological records (surface).

130

4.4 DEVELOPMENT COSTS The development costs include the costs of drilling the development wells, the costs of the production installations and any systems required for the transport of the effluent. These investments are directly linked to the initial definition of the project. In fact the costs of constructing the chosen system have to be met at this stage, which is why the various opportunities to appraise the project before it is authorised are so important. This subject is considered further in the following sections.

4.4.1

The key stages prior to project authorisation

The authorisation of a project is the culmination of a process of study and evaluation, each phase of which is intended to define more precisely the project and its associated investment and operating costs. Starting with exploratory studies the work proceeds through preliminary study, the conceptual study and ending up with the preliminary design, the final stage before the project is authorised. The process is illustrated in Fig. 4.8. Studies Preliminary studies

Conceptual studies (screening, feasibility)

Go-ahead for more in-depth studies or exploration

Go-ahead to start preliminary design

Project

Preliminary design

Go-ahead to proceed with project

Basic engineering

Engineering, procurement, construction (EPC)

Selection of contractor

Completion of construction and commissioning

Operations Start-up

Operation

Provisional acceptance of the installation

Production and final acceptance of the installation

Figure 4.8 The project life cycle.

4.4.1.1 Exploratory study The purpose of the exploratory study is to evaluate whether a particular object being explored has commercial potential. It includes a geological stage which will define the potential hydrocarbon resources present, evaluate the probability that an exploration well will be successful, and estimate the development costs in the event of a discovery. By referring to three geological scenarios, i.e. “mini”, “mode” and “maxi” scenarios, and often by drawing analogies with other similar fields, the researchers will seek to define a development architecture and the capital and operating costs involved. These data will help a decision to be made on whether the proposed exploration programme should proceed. How relevant the analogies and extrapolations made in this type of approach are will depend on the reliability 131

Chapter 4 Investments and costs

sophisticated measurements. They are often expressed as a cost per metre drilled, which allows trends over time to be evaluated and comparisons made between different zones. Direct costs amount to around $100–$120 per metre drilled, to which must be added the indirect costs of $50–$80 per metre drilled.

Chapter 4 Investments and costs

of available databases. Furthermore the usefulness of analogies may be limited when new technologies are involved.

4.4.1.2 Preliminary studies The preliminary study is intended to present a first economic evaluation of a discovery so that a decision can be taken on how to proceed, i.e. whether to abandon, sell the interest, proceed to delineation, run a long duration production trial or, less frequently, proceed to immediate development. The purpose of these studies is not necessarily to identify the optimum development but to estimate, on the basis of the development concept most appropriate in the light of the available data and experience, the capital cost accurate to within 30–40%.

4.4.1.3 Conceptual studies This is a key phase in defining the development architecture. It is impossible to overemphasise that the largest reductions in investment costs are made by getting the final concept right. The purpose of conceptual studies is to define the “final concept”. This necessarily involves: – An exhaustive search for basic data; – A detailed comparison of different possible technical variants (fixed or floating platform, surface (i.e. installed on a platform) or subsurface wellhead, air or water cooling, etc.); – A reliable comparison of the costs and of the difficulties involved in realisation. If possible, the estimates for the different alternatives being considered at this stage should all be of a similar accuracy (traditionally of the order of 20–30%).

4.4.1.4 Preliminary design The preliminary design is carried out after the conceptual studies and before the basic engineering, if applicable. Its essential objective is to allow the investors to decide whether or not to go ahead with a development, that is, to authorise the project. This is a major decision. The decision-maker needs not only production forecasts but also coherent, validated technical picture covering all areas of operations. The preliminary design therefore needs to develop the “final concept” recommended by the conceptual study to a level of detail commensurate with the complexity of the subject matter, such that the uncertainties are reduced to an acceptable level. It should be noted that the preliminary design is the last stage at which there is still an opportunity to make major changes in the definition. The preliminary design usually lasts two to six months, and as a rule provides estimates of the capital costs accurate to within 20%. In order to maximise the likelihood that the project will be successful, the preliminary design is usually confirmed in an agreement between the party responsible for the project conception, the party who will in future be in charge of the project and the future operator. This agreement will set forth the parameters and fundamental choices, as well as detailing the optimisation studies remaining to be carried out. In summary, therefore, the sequence of studies out lined above allows the uncertainties in the costs to be reduced and the risks inherent in the project to be identified, as shown in Fig. 4.9 and Table 4.1. 132

+ 40 + 30 + 20 + 10 0

– 10 – 20

Preliminary studies

Conceptual studies

Preliminary design

Basic engineering

Detailed engineering

–3 – 40 Project go-ahead

Figure 4.9 Reducing uncertainty in costs as project proceeds.

Table 4.1 Different study phases before a project is authorised. Development studies

Objective

Exploratory studies

Establish broad feasibility

Identify the risks (qualitative).

Preliminary studies

First economic evaluation of a development project Basic data, no optimisation of operating concept

Identify the risks and estimate the degree of uncertainty attached to the economic results.

Conceptual studies

Risk evaluation

Choice of a development concept from set of alternatives studied:

=> Choice of concept cost, planning, economics, risk

Preliminary design

Analysis of the risks associated with the solutions studied.

Technical and economic definition sufficiently accurate for: • a decision to be taken on whether to go ahead with the project, • a “project action plan” to be drawn up.

Feasibility demonstrated, subject to clearly described uncertainties. Analysis of risks => Helps in defining objectives and “project action plan”.

These studies require the participation of many engineers and specialists, and are therefore not without costs. There are no hard and fast rules for determining the costs but, as a percentage of the total expected investment, they are of the following order of magnitude: – Preliminary studies: between 0.05 and 0.1%; – Conceptual studies: between 0.1 and 0.2%; 133

Chapter 4 Investments and costs

Accuracy of the estimate (as % of total project cost)

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– Preliminary design: between 0.2 and 0.5%; – Basic engineering: between 1 and 3%. It should be stressed that it is as important to keep the studies on schedule as within budget. When a study is completed there very often follows a process of negotiation and decisionmaking which depends on annual programmes and requires the approval of many partners. An objective of the studies is also to produce a timetable of the expenditure flows for the project. This timetable should show the estimated percentage of the investments to be disbursed each year relative to a start date and to the forecast project implementation timetable. This timetable, known as an S-curve, is important in a number of respects. The postponement of an item of expenditure to a later year can significantly enhance the economics of the project when the decision is made. Furthermore, optimising the timing of investments often also gives insight into possible improvements in the project conception. Many parameters can affect the shape of this S-curve. Due regard should be had, in constructing this curve, to the point in the calendar year when the project will commence, its duration, size and nature (onshore/offshore, pipeline, etc.). Also relevant are the type of expenditure (studies, equipment, contracted activities), the country involved, the billing basis written into the contract if known, the payment methods (in advance, milestone dates, reimbursable, etc.). As a first approximation the curve in Fig. 4.10 can be used. Project planning

Year 1

Year 2

Year 3

Design Supply Construction Installation/Hook up

% Investments

20%

60%

Figure 4.10 Example of S-curve.

4.4.2

Development drilling

Unlike exploration drilling, development drilling involves repeated operations, so that the lead times involved are easier to plan and the costs are often easier to control. The time required for the actual drilling has to be increased to allow for the time needed for well completion, which varies according to the complexity of the completion. In any particular environment, the development wells are generally drilled more rapidly than the exploration wells; this effect is illustrated in Fig. 4.11. When a series of development wells need to be drilled in the same field, it is possible for the technological parameters to be optimised on successive wells so that the drilling time can be reduced. Figure 4.12 illustrates this “learning curve” effect. In a recent offshore development the time taken to drill a development well (2 700 m in depth, with horizontal drains of 1 000 m at the bottom) was reduced from 26 days for well no. 1 to 13 days for well no. 7. 134

geology completion

drilling

Exploration or appraisal drilling

Drilling Geology

drilling

geology

testing abandonment

Production Testing Completion

0

10

20

30

40

50

60 70 Duration (days)

Abandonment

Figure 4.11 Typical timings for drilling operations.

30

Drilling duration (days)

25

20

15

10

5

0

1

2

4

3

5

6

7

No. of wells Installation

16” phase

12 1/4” phase

8 1/2” phase

Completion

Figure 4.12 “Learning curve” for development drilling.

Tables 4.2 and 4.3 and Fig. 4.13 illustrate a typical breakdown of offshore development drilling costs. Special conditions can heavily influence the costs of a development well, as shown by the following examples. Although the great majority of exploration and appraisal wells are vertical, nowadays 50% of development wells are substantially deviated (>60°) or horizontal. The cost of a horizontal well is 20–30% higher than those of a vertical well (but their productivity may be 3 times as great). 135

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Development drilling

Chapter 4 Investments and costs

Table 4.2 Cost breakdown for offshore development well. Oil-producing well – SouthEast Asia – water depth 70 m. Phase

% of total cost

34

Consumables Wellhead, piping, drilling bits and core barrels, mud and cement products, accessories, energy, water.

8

Logistics Fixed price (trucks, aircraft, removal of drilling rig…).

3

Management and supervision Studies and project management, supervisory arrangements, geology and reservoir.

41

Hire of drilling rig Drilling contract, mobilisation/demobilisation of drilling rig.

14

Petroleum services Mud, cement, casing, tubing, supervision, electric logging, mudlogging, miscellaneous services, miscellaneous completion, diving team and ROV, insurance, miscellaneous equipment hire.

Total cost

100

% of total cost

100

Duration (days)

55

Table 4.3 Duration for drilling an offshore development well (same project as in Table 4.2). Erection and removal

Drilling

Geology

Completion

Total

1

33

5

16

55

Duration (days)

Petroleum services 13.8%

Consumables 34.2%

Consumables Logistics Management and supervision Hire of drilling rig Petroleum services

Hire of drilling rig 40.7%

Logistics 7.9%

Management and supervision 3.4%

Figure 4.13 Cost breakdown for offshore development well.

136

4.4.3

Production and transport installations

It would be a vain enterprise to seek to list exhaustively the costs of all the various items of equipment currently used in development drilling. Instead we describe below some typical onshore and offshore project configurations and review some of the methods traditionally used to cost these installations. We then present a set of unit costs and ratios which can be used for very preliminary evaluations. More detailed descriptions will then be given for two specific cases: a deep offshore development programme and an example of an LNG project. Whether onshore or offshore, the principles of production, gathering, separation, treatment and transport of the products remain the same. The structures and equipment will vary according to the composition of the effluents, the product specifications applying to transport and sale, but also, obviously, according to the characteristics of the environment.

4.4.3.1 Onshore development In an onshore oil or gas production facility the wells, whether isolated or grouped into clusters, are linked by a network of gathering lines to a production and processing facility from which one or more transmission lines run (Fig. 4.14). Some remarks follow on the different components of the production facility. A. Well cluster Each cluster normally includes the facilities needed to test the output of each well. B. Gathering network The lines of this network are generally made of carbon steel, but occasionally of more sophisticated alloys (Inox or Duplex steel) or composite materials. They are subject to attack both external and internal, in the form of corrosion and erosion. They can also undergo processes such as blocking, scaling, the deposition of minerals (sand, sulphur) or hydrocarbons (paraffins, asphaltenes) through settlement or the formation of hydrates. They are therefore equipped with cathodic protection or systems which inject protective or preventive chemicals, heating and insulation systems, systems for scraping and detection “pigs”.

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Another example is a high pressure, high temperature (HP/HT) well: more sophisticated well and completion equipment is required, so that the consumables required are more costly, increasing the costs by up to 20%. The same applies to exploration wells where the conditions are difficult. A well producing corrosive fluids requires completion equipment made of more sophisticated metallurgical materials, which can also increase costs by up to 20%. Furthermore an oil producing well where subsea pumping is necessary will require multiple workovers in order to maintain the pumps. Environmental constraints can equally affect drilling costs. These are increased if drilling waste such as rubble or liquid wastes have to be treated in order to comply with national legislation. The additional costs are very variable ranging between 1 and 5% approximately. These can be reduced if smaller diameter drilling is employed, for example in ecologically sensitive zones such as the Paris basin; the reduction which can be achieved in this way is of the order of 10–15%.

Chapter 4 Investments and costs

➂ The processing plant:

➁ The field: well clusters and gathering system

Separation Heating Storage Pumping Power generation

④ The pipeline ➀ Well cluster

⑤ The loading terminal

Figure 4.14 Onshore development concept.

C. Production and processing facility The effluent from a well is made up of gaseous and liquid hydrocarbons, usually water and sometimes salt, sand and solid hydrocarbons. The different phases present, which sometimes also include emulsions and foams, have to be separated. This is traditionally done in successive phases through pressure drops, the effluent waste (water and sediments) being separated from the oil and gas and treated, before being discharged. The specifications of the separation and treatment units touched on above will depend on the types of effluent, their quality and the specifications which need to be met. • Separation requires separators, cyclones, hydrocyclones, desalters, filters, coalescers,

decanters and, less frequently, plate columns. • Oils are treated mainly by removing the water, salt and excess gas so that they can be

stored, transported and handled by normal methods. Desalters and stabilisers are the most common installations. • The gas is treated to remove the pollutants (CO2, H2S, water) and heavy hydrocarbon frac-

tions which can be condensed out. There are various processes for sweetening, drying and condensing the heavy fractions: molecular sieves, adsorbent beds, chemical or physical absorption, traps with cooling coils or self-refrigeration by expansion and recompression. The gaseous fractions are compressed for transportation or reinjection into the reservoir or, very occasionally, for storage. • The water treatment usually involves a treatment plant and pumping facilities which

reinject the water back into the reservoir. • The production facility may also supply the utilities required (electricity, water and other

services). • The effluents are transported to a terminal, factory, etc. by pipeline.

138

In an offshore installation the wellhead may either be on the platform or underwater. Combined surface and subsurface production facilities are becoming increasingly common in offshore development. The production support, which may be a fixed platform or a floating vessel, houses the utilities needed for production (particularly power) and all the safety installations. For reasons of weight, installation cost and maintenance, the offshore processing equipment is often limited to that which is necessary to ensure that the effluents can be transported ashore. These are transported by pipeline or, sometimes in the case of oil, stored for loading onto tankers. The remaining processing needed to ensure that the products comply with the delivery specifications are carried out on arrival. Accommodation for personnel, the control room and offices and the amenities needed for life on board are situated either on the production platform itself or on a dedicated accommodation platform. Two common types of development are illustrated below: concepts based on fixed platforms and on a floating vessel. A. Development based on fixed platforms The well, processing and accommodation platforms are linked together by walkways to form a production complex, to which a small flare platform can be added (Fig. 4.15). B. Development based on a floating vessel The production support consists of a FPSO (Floating, Production, Storage and Offloading Vessel) linked to the underwater wellheads by means of flexible lines (Fig. 4.16).

ACCOMMODATION PLATFORM UTILITIES/PROCESSING PLATFORM

FLARE

Pipeline 32” - 82 km

WELL PLATFORMS

PROCESSING PLANT

Figure 4.15 Offshore development configuration with fixed platforms.

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4.4.3.2 Offshore development

Chapter 4 Investments and costs

Figure 4.16 Offshore development configuration with FPSO.

4.4.3.3 Key parameters of development costs The capital cost of developing an oil or gasfield may amount to several billion dollars. It is crucial that the key parameters are identified and evaluated so that the project can be properly defined and its viability assessed, because some of these parameters strongly influence the costs. A. Situation of the field and constraints on exploitation Onshore, the nature of the terrain is the main determinant of costs. Offshore it is the water depth, which may be conventional (to 300 m), deep (to 1 500 m) or ultra-deep (over 1 500 m). B. Oceano-meteorological conditions Producing oil and gas in a hostile environment means costly production installations: platforms must be able to withstand extreme climatic conditions, for example storms in the North Sea, hurricanes in the Gulf of Mexico or typhoons in the Gulf of Thailand. C. Reservoir type and behaviour These reservoir parameters determine the number of wells required, and whether water or gas injection will be needed during the lifetime of the field. D. Composition, pressure and temperature of the effluent The processing required in order to transport and sell oil products is influenced by the content of H2S, CO2 and asphaltenes, by high pressure and/or temperature, by the gas/oil ratio (GOR), by the API gravity, etc. High pressures and temperatures require heavy-duty equipment and sometimes hi-tech materials for the piping and pressure vessels. For example, a gathering line 10” in diameter costs about $30/m for an operating pressure of 50 bar, but about $150/m for 300 bar. 140

Table 4.4 is an example of a typical summary made by the estimators, in this case for an on-shore gas treatment plant. The methods used to prepare it will be explained later. The table shows that the technical costs4, although important, are just one element in the overall estimate. They are accompanied by a range of other costs related to the studies, surveys, project management and insurance.

Table 4.4 Example of structure of cost: onshore gas treatment plant. Project information Characteristics Gas flow: 1 000 mm.s.ft3/d Oil flow: 90 573 bbl/d Weight of equipment: 2 245 t Summary of costs • Direct costs Process equipment Utilities Ancillary equipment Infrastructure

Ratio (%) 42% 11% 2% 3% 58%

Total direct costs • Indirect costs Technical facilities Construction-related costs Costs related to transport of equipment and bulk materials

1% 2% 3% 6%

Total indirect costs • Technical costs (direct and indirect) Engineering

64% 10%

• EPC costs (technical costs and engineering) Basic engineering, surveys Project management Commissioning Insurance

74% 1% 7% 1% 1% 84%

Total costs (w/o contingencies) • Contingencies

16% 100%

Total costs

4. The technical costs are the sum of the direct costs (main equipment and bulk items such as pipework, valves and fittings, electricity, instrumentation, prefabricated materials and on-site construction) and indirect costs (equipment transport, temporary installations, etc.).

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4.4.3.4 Development costs summary table

Chapter 4 Investments and costs

4.4.3.5 Unit costs and standard ratios Table 4.5 presents various standard cost data for the main elements of the production and transport installations, which can be used for a very preliminary costing.

4.4.4

Methodology for estimating development costs

Our object is not to present a course in cost estimating to the reader, but to give him a rapid overview of the principal methods used by estimators during the various study phases referred to above. Before doing so we take this opportunity to define a number of terms and abbreviations which are not always understood by non-specialists in the way intended by estimators.

4.4.4.1 What is an estimate? An estimate is a statement of the most likely cost of an industrial project, elaborated before all the parameters of the investment have been defined. It should be borne in mind that: • An estimate assesses the most likely, rather than the lowest, cost of a project. If the actual

costs ultimately prove lower because the competition between the suppliers and other companies turns out to be keener than expected or because dumping is practised by some suppliers, all well and good. But an estimator may not assume a favourable scenario of this kind. • An estimate is an approximation rather than a precise forecast of costs: an installation

cannot be costed by referring to a price catalogue. Quantities such as the weights of structures or piping, dimensions, volumes of concrete, the length of cables, etc., are not yet known at the preliminary, conceptual or even the preliminary design stage. This is quite different from a contractor bidding for a job, who must begin by calculating the quantities of materials involved, so that he can price the job with the help of unit costs or price lists.

4.4.4.2 Basis of estimate To be complete an estimate must specify the following: – The technical definition of the project, a list of the technical documents on which it is based, the limitations of and exclusions from the estimate; – The economic basis, i.e. date, currency, exchange rate. It should be noted that estimates are generally expressed in constant prices, without assumptions about future inflation. The figure will be converted to current prices when the life of project budget is drawn up by a financial department. Other competent departments will then also add on the financing expenses, local taxes and customs duties so as to obtain a complete project costing in the local currency; – The accuracy of the costing will depend essentially on the methodology adopted and the level of the study.

4.4.4.3 Structure of a cost estimate Broadly speaking, a cost estimate is made up of the direct and indirect costs, which sum to give the technical costs, other general items and a “reserve for contingencies”. Readers are reminded of the definitions of each of these terms below. 142

Main equipment Carbon steel pressure vessels (less than 5 t) (between 5 and 20 t) (over 20 t) Multiplier for inox pressure vessels

15–35 18–20 5 3.0

$/kg $/ kg $/kg

Bulk materials Carbon steel piping (including fittings) Inox piping Duplex steel piping (including fittings) Steel for structure Carbon steel pipeline

6–7 20–22 25–30 1.5 1.5–2.0

$/kg $/kg $/kg $/kg $/kg

20–40 6 10–12 60–80 10–30

$/inch/m $/inch/m $/inch/m $/inch/m $/inch/m

Transport costs 5–10% of the purchase price of above items Pipelines Equipment Laying costs: onshore desert plain mountains offshore Labour ($/hr) Region

Onshore construction

Engineering

60 70 80 30 50

100 100 120 50 80

France UK ($1 = £0.5) Norway ($1 = NOK 5.96) Far East (Indonesia) Gulf of Mexico Marine vessels ($’000s/day) Region North Sea Middle East / Far East Gulf of Mexico

Supply vessel

Derrick barge < 2,500 t

Derrick barge < 6,600 t

Lay barge

20 8–10

1,100 300

1,300 850

400–1,100 500

5–10

300

850

400

Indirect costs Pipeline project, onshore or offshore Other project

15–20% of technical costs 25–40% of technical costs

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Chapter 4 Investments and costs

Table 4.5 Production and transport installations: standard costs and ratios (base 1st quarter 2007).

Chapter 4 Investments and costs

A. Direct costs These consist of the cost of the main equipment (ME): columns, separators, rotary drives, etc., required by the process plant and the utilities, and the cost of the secondary or bulk equipment such as pipework, valves and fittings, electric cabling, instrumentation, cladding, etc. Also included are the construction costs including the costs of onshore prefabrication of the elements and modules of the offshore platforms, as well as the on-site construction costs (installation and hookup). B. Indirect costs These include the costs of transporting the equipment, materials and the different structures, as well as the mobilisation/demobilisation of the marine equipment where appropriate. The general expenses, often referred to as EMS (Engineering, Management and Supervision) cover: – The engineering, i.e. the basic engineering and the detailed engineering, as well as services such as audit and certification, often performed by external service-providers; – The commissioning of the structures; – The management and supervision of the team in charge of the project, mobilised at different phases of the implementation; – The insurance of the structures during construction and installation as well as other indirect costs such as customs duties incurred by the subsidiary company. The term EPC (engineering, procurement and construction) cost is sometimes used. This corresponds to the value of the contract for the construction of the infrastructure, that is, a technical cost together with the general costs of the contractor responsible for carrying out the work. In a contractual arrangement of this kind the EPC cost must be increased to allow for the general costs of the prime contractor, or “company costs”, that is, the costs of the basic engineering, site surveys, management, project supervision and insurance. C. Contingencies The accuracy of a costing will depend directly on the technical definition of the project and on how much is known about the environment. Whatever the stage of a project, a provision for contingencies is always included in an estimate, in order to allow for uncertainties which cannot be identified or quantified at this stage.

4.4.4.4 Principal cost estimation methods There are various methods of estimating costs each with its own area of application (Fig. 4.17). A. Analogy with known costs This method is suitable for exploratory studies or screening studies in the widest sense. The cost is estimated by reference to the known (or appropriately updated) cost of an existing installation of the same type but a different capacity. It is assumed that the ratio of the costs of the two installations is equal to the ratio of their capacities raised to a power of approximately 0.6 (also known as the “scale factor”). This rule of thumb only applies when the capacities concerned are not too different from one another. 144

Preliminary studies

+25%

+20% Preliminary design

Conceptual studies –20%

–15%

+10% Final costing –10%

–30%

Define the general characteristics of the installation and apply general ratios

List the main equipment and apply specific factors

List in detail the equipment, bulk materials and specific quantities

Global methods

Factorisation methods

Detailed methods

Figure 4.17 Main costing methods.

B. Factoring methods These methods are widely used, particularly for preliminary and conceptual studies, and sometimes even preliminary designs. They are based on the observation that there is a fairly constant relationship between the direct installed cost of an item of processing plant or a utility, including auxiliary equipment and construction, and the costs of the main items of equipment. The latter are generally evaluated using small computational programmes or an equipment database. A multiplier specific to the type of equipment involved is then applied to obtain the direct installed cost. To these equipment costs have to be added the site preparation costs, ancillary or offsite installations (storage and loading facilities, firefighting and utility networks, pipe connections, industrial buildings, amenities, etc.) and the costs of the necessary infrastructure (roads, power cables, jetty or port, etc.). Finally the indirect costs, general costs and provision for contingencies are usually estimated using percentages. C. Detailed or semi-detailed methods This method involves estimating each item analytically. Since the quantities of bulk materials cannot be calculated at this stage of the study, they are estimated as a proportion of the main equipment. For example the tonnage of the supporting structure or piping associated with a particular item of equipment is estimated by applying a specific ratio to the tonnage of the equipment. The hours of labour spent on manufacture or construction on-site are also 145

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+30%

Chapter 4 Investments and costs

evaluated using ratios. It is estimated, for example, that the labour required for the manufacture of substructures for fixed platforms is between 60 and 80 h/t, or about 300 h/t for ordinary steel piping. Finally these hours are converted into costs by using a labour cost per hour and assumptions with regard to productivity. The general costs will be estimated at the most detailed level possible by evaluating, for example, the number of hours of engineering based on the numbers of items of equipment, or the management and supervision costs from hypotheses regarding the future contractual strategy and the organisation of the project team.

4.4.4.5 Need for feedback from projects The great majority of estimates in the preliminary or conceptual phase use a factoring method based on the costs of the main items of equipment; we therefore have two requirements: – A database, as complete as possible and regularly updated, of the main items of equipment; – Feedback from projects on the quantities of secondary equipment associated with each of the main items of equipment, on numbers of hours spent on manufacture and construction as well as costs, broken down by subject area and by structure type. This will allow the best possible estimate to be made of the ratios used in future costings. Feedback of this kind is difficult to obtain in the context of an EPC contract. This is because, firstly, we rarely have access to data on the cost of equipment, often purchased by the contractor, particularly secondary equipment. And secondly, although the overall value of the contract is known, it is difficult to break this total down into its different components: in fact the way the contractor apportions the overall price is arbitrary.

4.4.4.6 Provision for contingencies This provision is intended to cover the variations in the cost of the project due to events which are probable but not certain (or which cannot be identified) when the estimate is made. In practice, experience has shown that, statistically, a certain number of these events will occur. It includes, for example, uncertainties relating to “slight” modifications in the technical specification, modifications in the regulations, specific building problems, supplier delays, or variations in the cost of labour or in labour productivity. As already mentioned, however, this item cannot cover large and costly, though unlikely, events such as: – A significant change in the technical specifications of the project; – Provision for exceptional meteorological conditions; – A catastrophic event or natural disaster; – Political disorder, force majeure; – Extreme market turbulence, or a failure of competition; – A major change in contract strategy or in planning, etc.

4.4.5

Examples of developments

Examples are given below for two different types of development project, i.e. a deep or ultradeep offshore development project and a LNG (liquefied natural gas) supply system (entire cycle including liquefaction, transport and regasification). 146

4.4.5.1 Deep and ultra-deep offshore This is a very topical theme: many companies are currently interested in exploration in water depths in excess of 1 000 m and even occasionally 2 000 m. Advances in subsea technologies mean that it now appears feasible to produce hydrocarbons discovered at such depths at a competitive cost. At more familiar water depths up to 300–400 metres technological progress has led to significant reductions in costs. The cost of producing a barrel of oil (exploration, development and exploitation) at such depths had fallen from $13–15 in the 1980s to $5–7 in 2000 and grew again over $20. Extrapolating these results suggests that the development of offshore resources in deeper waters should be economically feasible. There are many production concepts of proven viability at moderate depths which could realistically be assumed to constitute the starting point for evaluating deep or ultra-deep offshore development projects (Fig. 4.18). The petroleum industry is currently focusing its efforts on very deep waters (>2 000 m), with the objective of getting to 3 000 m. A. Costing methodology A possible development programme can be evaluated on the basis of two major categories of parameters, those which describe the reservoir itself and those which describe its geographical location.

Figure 4.18 Deep offshore production concepts.

147

Chapter 4 Investments and costs

These two examples will give readers a better understanding of the orders of magnitude of the overall costs of projects in the petroleum industry and, in particular, the technical costs expressed per barrel of oil or per unit calorific value of gas, as appropriate.

Chapter 4 Investments and costs

Parameters associated with the reservoir are usually obtained from a “speculative” seismic exploration survey and by interpreting local geological phenomena. These parameters allow the size of the target object to be estimated, that is the reserves and the extent of the reservoir, as well as its potential, i.e. the density of the reserves, reservoir productivity and the types of fluids. The second category of parameters includes “physical” data (distance from the coast, water depth, depth of reservoir under the seabed) and data which describe the environment. These latter data relate to the oceanographic and meteorological conditions, the existing petroleum infrastructure and the extent to which it would be available, the market prospects for the production, local regulations, tax regime, etc. The values of these parameters will point the evaluator towards the most appropriate development plan. B. Example of estimation of capital costs By way of illustration the investment costs are estimated for two prospects of contrasting size and location, both situated in 1500 m of water. a. Prospect in the Gulf of Guinea This prospect is situated in 1 500 m of water in the Gulf of Guinea. The hydrocarbon deposits, of centred morphology, extend over an area of 90 km2. They consist of multilayer reservoirs lying at depths of between 900 and 1 700 m below the sea bed. The reserves are estimated to be 750 Mbbl of oil, and the field would have a life of about 20–25 years. The production will plateau at 200 000 bbl/d. Because of the lack of a local petroleum infrastructure and the remoteness of the markets, the development is based on a FPSO acting as a gathering station for a subsea production network (Fig. 4.19).

FPSO (capacity 200,000 bbl/d) Multiple mooring lines (16 moorage lines)

Offloads to tanker

Water depth 300 m 430 m

Cluster of 10 subsea wells

Gathering lines (length ~ 3 km) • production 2 x 12” • test 1 x 6”

Export lines (length ~ 2 km) 3 x 12”

Figure 4.19 Example of development concept, deep offshore (Gulf of Guinea).

148

Table 4.6 Gulf of Guinea prospect: development investments ($M). Water depth: 1500 m – Reserves: 750 Mbbl.

Production vessel Subsea equipment & control system Gathering lines Company costs1 Provisions Drilling – Wells Total capital cost ($M) Capital cost ($/boe)

Case 1 48 wells

Case 2 63 wells

1 700 1 000 1 700 600 500 2 000 7 500 9.9

1 700 1 300 1 900 700 600 2 600 8 800 11.7

1. Project management and supervision, studies, preliminary work, insurance.

b. Prospect in the Gulf of Mexico This prospect is situated in 1 500 m of water in the Gulf of Mexico. The reservoir, with an elongated morphology, has an area of 22 km2. It is multilayered, at depths of between 1 800 and 3 000 m below the sea-bed. The reserves are estimated to be 180 Mboe, and the field would have a life of about 15–20 years. The production will plateau at 60 000 bbl/d of oil and 100 Mft3/d of gas. This production level will be achieved by means of 15 wells. The development concept adopted involves a “spar” floating production platform with a deep draft (Fig. 4.20) with wellhead at the surface and the production being dispatched to existing installations. In contrast with a subsea development, this design has the advantage of carrying out the drilling and production from the same platform, allowing servicing to be carried out on a well without having to mobilise a drilling rig. This system also overcomes the problem of having to transport a multiphase effluent over a long distance. The spar 149

Chapter 4 Investments and costs

The FPSO, tethered in a fixed position by 16 mooring lines, will comprise a hull 300 m long and 60 m wide with the capacity to store 2 Mbbl of oil. The treatment plant and utilities will be situated in one or more independent modules on the upper deck. Their net weight (empty) is estimated at 20 000 t. The production wells will be connected to production manifolds which are joined to the gathering lines. Each production line is made up of two pipes thermally insulated by means of a layer of foam in a metallic case. The water injection wells are connected in twos to the injection manifolds. Three water injection wells are connected to the FPSO by three independent lines. The production lines, water and gas injection lines are connected to the FPSO by flexible, thermally insulated connections. A control and command umbilical is attached to each production line and water and gas injection line from the wells and the manifolds. The oil is pumped into tankers at a loading buoy anchored at a distance of 2 km from the FPSO. The associated gas is re-injected into the top of the reservoir. In order to determine the sensitivity of this development scheme to the size of the recoverable reserves per well, two cases are considered, in which there are 48 and 63 production and water and gas injection wells respectively. The capital costs were estimated by reference to projects similar to the one in question in the Gulf of Guinea and Brazil (see Table 4.6).

Chapter 4 Investments and costs

Figure 4.20 Artist’s impression of a spar.

comprises a floating structure with a circular cross-section at water surface level and along the length of the flotation tanks on which the production and drilling modules are placed. The cylindrical shell is 37 m in diameter and 215 m in height, with a hollow square cavity of 18 m square in the middle containing the risers. The spar is anchored by means of 12 semitaut catenary cables. The risers connecting the seabed to the wellhead at the surface are maintained under tension independently by means of flotation modules inside the cavity in the shell. The riser contains a special joint at the level of the spar keel in order to accommodate movements of the riser relative to the platform. The drilling and production module, including the living quarters for 110 persons, is made up of 3 decks 55 m in length, providing a total surface area of the order of 9 000 m2. The empty weight of this module is approximately 9 000 t. All the wells are pre-drilled as far as the surface casing. Four of the wells are drilled into the target formation so that production can commence shortly after the installations are erected and connected. The remaining wells are drilled from the spar. After separation, the products are exported to pre-existing installations situated in shallower water by means of two independent pipelines, i.e. a 10" line, 60 km in length for gas and a 16", 70 km line for oil. The capital costs were estimated from available data as indicated in Table 4.7. 150

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Table 4.7 Prospect in Gulf of Mexico: capital cost of development ($ millions). Water depth: 1 500 m – Reserves: 180 Mbbl. Production platform 1 Subsea equipment & control system Collection network Export system Company costs 2 Provisions Drilling – Wells Total capital cost ($M) Capital cost ($/boe)

900 – – 100 180 120 300 1 600 8.9

1. Including the drilling function\equipment and the production and export risers. 2. Project management and supervision, studies, preliminary work, insurance.

These two examples of deep offshore prospects show that, depending on location, the unit technical costs for fields of quite different sizes can be of a comparable order of magnitude.

4.4.5.2 LNG cycle The LNG supply cycle comprises, in addition to the gas production and condensate stabilisation plants, the following subsystems (Fig. 4.21): – The liquefaction plant, which provides for the treatment, refrigeration and liquefaction of the feed gas, and the storage and loading of the liquefied gas; – A fleet of LNG tankers to ship the LNG from the treatment plant to the terminal; – The reception terminal where the LNG is regasified and, possibly, an associated power station.

LNG plant

Feed gas

Refrigeration

Preprocessing

Precooling

LGN

Losses:

2%

+

Liquefaction

Sales gas

Regasification

LNG

Temperature = – 160°C

GPL

8%

+

2%

+

1%

=

13%

Figure 4.21 The LNG cycle.

A. Description The main characteristics of each component of the cycle are reviewed below. a. Liquefaction (Fig. 4.22) There are strict limits on contaminants in the LNG (CO2 between 50 and 100 ppmv, total sulphur approximately 3 ppm moles). Gas treatment units upstream of the liquefaction are 151

Chapter 4 Investments and costs

Fuel gas

N2

Denitrification

MCR™

LNG

MCR: Multi Component Refrigerant

Cryogenic exchanger (MHE)

Propane

Preprocessing Sour gases (CO2, H2S, mercaptans)

Feed gas

Reception

Amine treatment

Dryer

Mercury trap

Precooling

LPG

Liquids removal Fractionation

NGL

Figure 4.22 Simplified flowchart of a LNG plant.

more expensive than traditional liquids removal units. Any mercury in the feed gas is treated at this level; finally the gas is dried by means of molecular sieves before refrigeration. Two refrigeration cycles are generally needed in order to produce the LNG. The first cycle, which usually produces pure propane, cools the feed gas (usually to –20/30°C) and the refrigerant for the second cycle. The second cycle, which uses a mixture of nitrogen and light hydrocarbons, allows the gas to be condensed and cooled to –160°C. These units make use of large compressors driven by gas or steam turbines. The natural gas is liquefied in an exchanger (just one per train) with a large heat exchange surface. They are usually spiral tube exchangers 4 metres in diameter and some 60 metres in height. Depending on the nitrogen content of the feed gas, the liquefied gas will be passed to a denitrification unit in order to reduce the nitrogen content to a level acceptable for its transport (normally 1%). The nitrogen-rich off-gas from this unit is returned to the fuel gas stream. The heavy hydrocarbons are separated in a fractionation unit. This unit produces a gas rich in ethane which is routed back into the LNG stream. It also produces a propane/butane stream which can be reinjected into the LNG or sold as a separate product and finally, a heavier product with the characteristics of a light condensate. The liquefied gas is then stored in cryogenic tanks at atmospheric pressure fitted with loading pumps. The gas resulting from the evaporation of the LNG (“boil-off”) is returned to the fuel gas stream by means of dedicated compressors. The LNG is transferred from the loading bay onto LNG tankers by means of cryogenic loading arms. In view of the size and draft (approximately 14 m) of these vessels, and the precautions which must be taken during product transfer, a dedicated jetty and associated port facilities are needed. A large LNG factory may have several jetties. The LNG plant at Bontang in Indonesia, for example, has three jetties. 152

b. Transport The LNG market is characterised by long-term contracts, and a dedicated fleet of LNG tankers is normally used to transport the product. The number and size of the tankers forming the fleet is a function of annual volumes of LNG to be transported and the transport distance. The most common size for a tanker is 135,000 m3 or 65,000 dwt, or in energy terms, 3 TBtu per tanker-load. Much larger ships with a 250,000 m3 capacity now exist. A LNG tanker sails typically at 18–19 knots. The longest routes (from the Middle East to Japan) are approximately 6,300 nautical miles and the shortest (Algeria to Spain) about 350 nautical miles. c. Regasification On arrival at the reception terminal the LNG is transferred to storage tanks, and subsequently vaporised, after cryogenic pumping, and made available to the end-user. The gases which form due to the natural evaporation of LNG in the terminal installations are reincorporated into the liquefied gas before pumping. The vaporisation is effected either in trickle evaporators or in submerged flame vaporisers. If the calorific value of the gas is too high, nitrogen or air is injected into the sales gas. B. Size of the units In order to estimate the capital costs it is essential to know the capacity of the plant and the unit size of the liquefaction trains. a. Capacity of the plant There are 30 LNG plants throughout the world in 2011. Their capacities range from 1.1 Mt/y (Camel, Algeria, commissioned in 1964) to several 10 Mt/y (Qatar). The capacity of a plant depends on the size of the reserves which it will process and the market for which it will produce. Only one plant, in Kenai, Alaska, operates with a single liquefaction train; all the other plants have multiple trains. The maximum number of trains is eight, in Bontang. b. Size of the trains The capacities of trains of recent design can reach 8 Mt/y, using more powerful mechanical drives. The liquefaction trains are sized on the basis of the markets at which the plant is aimed, but also on the optimum production rate associated with the power of the refrigeration machine (initially assumed to be 14 kW per tonne of LNG per day). High-power industrial gas turbines come in only a limited number of sizes. The most appropriate turbine with a power which meets the requirements is therefore chosen. When choosing the rated capacity of the turbine, it should be borne in mind that the power actually available depends on the temperature of the air (there is a 0.7% variation in output power per °C): the capacity of the train will therefore be a function of temperature. 153

Chapter 4 Investments and costs

The liquefaction plant requires the following facilities: a cooling circuit (generally sea water), a heating system (steam, thermal oil or hot water) for the reboilers, fuel gas, power, compressed air and nitrogen (for inerting), a system for gathering and treating the liquid effluents and a system for flaring and liquids burning. Air-cooling is possible, but all the major plants (except North West Shelf in Australia) use sea water as the coolant.

Chapter 4 Investments and costs

It should also be noted that most liquefaction plants have been debottlenecked at some stage in their lifetime, leading to an increase compared with the initial (“design” or “nameplate”) capacity of 10–40% or even more. c. Storage capacity As a rule of thumb, the storage capacity should be no less than the capacity of a tanker plus a certain number of days” production for the plant when operating at full capacity. This number of days will depend on the particular circumstances of the case, particularly the availability of tanker capacity (which may be disrupted by weather conditions, for example). As a first approximation, 4–5 days should be taken. The number and sizes of the tanks will depend on the chosen capacity, but also on the unit cost, given that these are lower for a large than a small tank. LNG storage tanks are large: up to 250 000 m3 for an above-ground tank. d. Size of LNG tankers The size of a LNG tanker can reach 250 000 m3, but smaller vessels might be chosen for short routes depending on the limitations of the destination port. C. Energy losses An estimate is made in this section of the mean energy efficiency of the entire LNG supply cycle; this parameter is indispensable for any technico-economic analysis. The liquefaction plant requires around 10–12% of the feed gas for its own use. The precise figure depends on the pre-treatment necessary, the installations used to load the LNG onto the tankers, the source of power (gas or steam turbine) and the intrinsic efficiency of the liquefaction process. There is some evaporative loss of LNG during transportation, and this will be burned in the vessel’s boilers. In addition, some LNG will be used to keep the storage areas cold for the return journey. The loss of saleable product is estimated at between 1 and 3%, according to the distance involved. In addition an average of about 1% of the LNG will be used during regasification. The total energy loss over the entire LNG supply cycle is around 13% (± 2%) of the feed gas. D. Technical costs One of the measures of technical costs most commonly found in the literature is the specific project costs (limited to the turnkey or contractor’s cost), expressed in $ per t/y capacity. These specific costs vary in the range $500 to $800 per t/y, according to the technical definition, but also as a function of environmental factors such as the composition of the gas, the cost of labour, the adequacy and preparation of the onshore or offshore site, the remoteness of the site and the logistics. These costs also depend on the market conditions at the time the construction contract is signed. For a preliminary estimate of the cost of the LNG supply cycle it is suggested that the figures in Table 4.8 are used. Consider a LNG project involving the transportation of 5 Mt/y over 6 000 nautical miles. By applying the data in Table 4.8 and by making a few simplifying assumptions, we arrive at a production cost CIF5 including regasification but excluding feedgas for LNG of approximately $3/MBtu. These costs are broken down in Fig. 4.23. 5. Cost, Insurance and Freight: the price including the cost of the merchandise, insurance and maritime freight as far as the destination port.

154

Plant (capacity 5 Mt/y, 2 trains) Site preparation Processing Liquefaction Fractionation Utilities Storage Transfer Port Wharf Jetty Water supply

Proposed cost ($M)

% of total cost

150 250 900 50 450 300 50 100 200 50 50

6 10 34 2 18 12 2 4 8 2 2

2 550

100

Proposed cost ($M)

% of total cost

Storage Transfer Port Wharf Jetty Vaporisation Utilities/other

300 80 100 50 30 200 160

33 9 11 5 3 22 17

TOTAL

920

100

TOTAL Reception terminal

LNG tankers (capacity 135 000 m3)

Cost range ($M) 50–200 100–400

30–100 20–500 15–50

Cost range ($M) 50–100 5–350 15–50

Unit costs ($M)

Cost structure for the LNG cycle ($/MBtu)

150–200

3.5 3

OPEX 0.5

2.5 LNG tanker 0.7

2

Terminal 0.5

1.5 1

Plant 1.4

0.5 0

Figure 4.23 Cost structure for the LNG cycle ($/MBtu feedgas excluded).

155

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Table 4.8 Estimation of the cost of an LNG cycle using standard factors.

Chapter 4 Investments and costs

4.5 OPERATING COSTS The operating costs are the total expenditures relating to the operation of a production plant. The abbreviation Opex is used to refer to the operating expenditures, as distinct from Capex, the capital expenditures. However, the boundary between these two categories is sometimes somewhat grey, and depends on the organisation and the site. Some companies, for example, prefer for legal or fiscal reasons to hire equipment rather than purchase it, thereby giving rise to operating rather than capital costs. About two-thirds of the operating costs consist of four major items, i.e. general support provided by the operating companies (about 20% of total costs), well/surface operations (about 15%), maintenance and logistics (each about 15%). Personnel costs usually represent a large percentage of this total, but depend in the first instance, on the level of subcontracting. The balance includes contracts, purchases and services. The remaining one-third of expenditure comprises various items which account for between 1.5 and 8% of the total costs and include, for example, inspection, security, workovers and new works.

4.5.1

Classification of operating costs

The operating costs can be classified either by their nature (personnel, services, supplies) or by their purpose (production, maintenance, security, etc.). Where items are classified by their nature, they should generally conform to the accounting conventions, which may have a statutory character in the particular country concerned. They will include, in particular: – Personnel costs, accommodation, subsistence, transport; – Consumables (fuels, energy, lubricants, chemicals, office supplies, technical equipment such as piping, drill strings, joints, catalysts, molecular sieves, cladding, laboratory supplies, individual items of security equipment, spare parts, household supplies, food); – Telecommunications costs, miscellaneous hire charges, service and maintenance contracts. The classification by purpose allows the costs to be analysed in a manner which corresponds more closely to the objectives of the operator. The following breakdown is an example: – The direct costs comprise downhole (well services) and surface production, maintenance of the wells and surface installations, new works (excluding Capex), inspection, logistics, security, site management; – The transport costs are the costs related to the transmission pipelines and the terminals; – The indirect costs include technical assistance, operating company staff and head office staff. These breakdowns must be made according to very precise rules so that costs can be monitored throughout the life of the field, compared between installations, and so that the costs of planned installations can be estimated. Conditions and circumstances can vary enormously. We can only give orders of magnitude here: operating costs are subject to a very wide spread, ranging from $0.5 and $6/boe (1 boe = 6.119 GJ), depending on: 156

– The size of the field; – The geographical situation (e.g. onshore or offshore); – The region (desert, jungle, the Arctic, temperate zones, etc.). Two examples are given in Fig. 4.24 of the breakdown of operating costs by purpose, for an offshore and an onshore field respectively. 7 Head office support Head office management Technical support Production line Security Logistic New works Maintenance Surface production Downhole production

Operating costs ($/boe)

6 5 4 3 2 1 0

Figure 4.24 Examples of breakdown of operating costs.

4.5.2

Controlling operating costs

In order to maintain tight control over operating costs, a rigorous approach must be taken, initiated during the conceptual studies when the development architecture and operating philosophy are chosen. This is the stage at which the overall optimisation, and in particular the trade-off between Capex and Opex is virtually fixed. Optimisation is achieved through the engineering studies (detailed installation design, choice of equipment) and the preparations made (policies on recruitment and subcontracting, organisation of logistics). Particular consideration needs to be given to the operating philosophy, because this has a direct impact on personnel costs, preponderant in the field. It is vital to optimise the workforce when the units are being conceived. It would be illusory to think that savings can be made through antiquated methods such as using operators for remote monitoring for example. This would have the effect of inflating the production workforce, decentralising maintenance operations and ultimately straining budgets. A single operator costs in excess of $100 000/y, not allowing for various extras, i.e. $1 million over 10 years, far in excess of the capital cost needed to avoid this labour cost. During the operating phase, the steps taken to control operating costs are as described below: 157

Chapter 4 Investments and costs

– The ease with which the gas, oil, heavy oil, etc. can be extracted;

Chapter 4 Investments and costs

4.5.2.1 Control In order to enable the operating costs to be controlled, they are broken down into categories, sub-categories, equipment, components and items. A system must be established for recording expenditure, often using automated procedures, for the same elements in this hierarchical breakdown. By calculating costs at each hierarchical level, analyses and comparisons can be made.

4.5.2.2 Optimisation An analysis of the expenditure, beginning with the largest items, will allow areas to be identified where economies are possible by reviewing current practices and technical specifications. Examples of areas in which savings might be possible are: – Personnel costs (simplify organisation, mechanise, automate, sub-contract); – Consumption of chemical products (settings, change supplier, change process); – Use of spares (analyse parameters, carry out metallurgical analyses, change materials, change supplier); – Storage costs (change supply and stock policy, standardisation); – Review maintenance policy. At one site, for example, the frequency with which the 24 gas turbines present were reconditioned (unit cost between $200 000 and $800 000) was challenged. By considering the history of these machines it proved possible to increase the interval between reconditioning from 3 to 5 years on average. This led to a reduction of 5% in the total maintenance costs for the site. Account must also be taken of future production dynamics such as the run-down of the reservoir, the need for assisted recovery, the bringing into production of new reservoirs, etc. Regard must also be had to changes which will affect the installations over time (ageing equipment, obsolescence, extensions) and changes in the economic climate. The scope for optimising operations may be inhibited by poor development prospects or when there is an economic downturn, or may conversely be enhanced by organisational changes, or a modernisation of the installations when there is a major extension to the project, for example.

4.6 MASTERING COSTS It can be a major challenge for the team charged with designing and implementing a project to ensure that the installation is operational, secure, reliable and effective. Moreover if a petroleum project is to be successful, these objectives have to be realised at the minimum cost. In the past this consideration was paramount when the price of crude oil or gas was low. For a number of years now, considerations of cost minimisation have become a permanent feature for developers. As a direct consequence, there have been significant reductions in technical costs in the petroleum industry over the nineties. Fig. 4.25 shows that overall the technical costs have lost almost 50%, from $11/bbl in 1990 to $8/bbl or less in 2000. This reduction has affected essentially exploration and operating costs.

158

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20 18

Depreciation Exploration costs Operating costs

16

Dollars/barrel

14 12 10 8 6 4 2 0

1990

1992

1994

1996

2000

1998

2002

2004

2006

2008

20 18

Depreciation Exploration costs Operating costs

16

9.1

Dollars/barrel

14 8.1

12 7.0

10 8 6

4.4

4

0.8

2 0

1.9

6.0 4.7 0.8

1.7

5.2 1.2 0.9

0.9

3.4

3.5

3.9

4.7

2002

2003

2004

2005

5.6

2006

6.9

7.8

2007

2008

Figure 4.25 Technical costs in upstream petroleum industry (Source: Total).

Since 2000, this trend has changed: technical costs are rising and they have increased by more than 100% between 2000 and 2008. The increase finds its explanation first in the economic cycle, with higher price of commodities like steel and other metals. Second the high level of investment drove to strong constraint in the oil services sector. Exploration equipments like oil rigs, technical capacities, skilled labour are in short supply.

4.6.1

Impact of technological progress

The cost decrease observed in the nineties is a tribute to the efforts made by the petroleum industry to reduce its technical costs. A number of technological advances helped to make this achievement possible. 159

Chapter 4 Investments and costs

Major strides forward have been made in geoscience as a result of the processing capabilities of modern information technology. The systematic use of 3D, for example, has made it possible to reduce the number of exploration wells needed to uncover economically viable deposits of hydrocarbons. It has also allowed the wells to be positioned optimally, thereby limiting the need for further delineation. Advances in drilling have also helped to cut costs: deviated wells, horizontal and even multiple borehole drilling, to name but a few, have increased the number of objectives which could be reached from a single site (a platform, for example), as well as allowing multiple pay zone access from a single well. These techniques have had a radical impact on the productivity of wells by reducing the number required and, in consequence, significantly simplifying the linking infrastructure needed. Another notable advance has been the simplification in gathering systems made possible not only by reductions in the numbers of wells, but also to a great extent by advances in multiphase transport. Because the liquid and gas phases no longer have to be separated, it has been possible in some cases to halve the number of pipelines. In addition, separation units have been considerably simplified or even eliminated altogether, particularly in places where these are undesirable, such as in the vicinity of the wellhead. Of course some of these effects are offset by developments at the reception facilities, which have necessarily become more complex. But the overall net effect is substantially positive, a saving of the order of 10–15% of the total cost of a project. Technological advances have also led to remarkable improvements in production equipment (power generation, instrumentation, piping, rotary drives, etc.), in terms of reliability, availability, and ease-of-use. Other examples include the development and widespread use of digital process control systems, the advent of high-performance private telecommunications networks, the emergence at last of really reliable, powerful, light gas turbines, a spin-off from ongoing progress in the aero industry. Other important developments include the advent of the variable-speed electric drive, the contribution made by powerful electronics and technological advances in rail transport. It is difficult to quantify the effect on costs of all these improvements, but it is certainly considerable. We have got to the point where diminishing returns are beginning to set in. But further progress is always possible, and there are still many opportunities for making savings in all areas. Some of these opportunities are described below.

4.6.1.1 Mastering drilling costs In deep offshore work, a mastery of drilling techniques is absolutely essential. There are three main difficulties: the delicate matter of adjusting the weight of the mud, the low temperatures which create problems related to the rheology of the mud, and finally the presence of a rigid drilling riser, heavy, cumbersome and fragile. We now have a good understanding of these problems and are reasonably able to deal with them during exploration drilling. They now need to become routine, so that the costs of development drilling can be brought back to an acceptable level, particularly in deep water (in excess of 1 500 m). This process is already taking place, and there is no doubt that the petroleum industry will soon devise technically satisfactory and affordable solutions. But drilling costs are bound to remain high (between $8 and $25 million per well, depending on water depth and drilling distance) unless certain technological breakthroughs are made, such as drilling without a riser and drilling with casing. 160

It is impossible to over-emphasise the fact that 90% of the costs are determined in the definition of the object to be built. This underscores the enormous importance of the conceptual studies and the preliminary design, during which potential areas in which the costs can be reduced should be identified (Fig. 4.26). Sufficient time and resources and the best possible skills therefore need to be devoted to these studies to ensure an optimum project definition. Traditional methods need to be constantly questioned and new ideas systematically considered. A second way of reducing capital costs is to seek to simplify and standardise the equipment. This is not often possible because projects are usually different from one another. But duplication pure and simple can sometimes achieve savings —of the order of 40% for structures and 25% for construction and supervision— not counting savings in time, which may be as much as 3–5 months. Even if two installations are not completely identical, it is worth checking whether some of the units in the first installation cannot also be used without modification in the second. A third way adopted by some companies is to put the contractual arrangements with subcontractors on a different footing. The objective is to harness the skills of both management and workforce as a whole towards common objectives in terms of costs, deadlines and even production. This approach has spawned alliances, the concept of the target price, ventures involving profit-sharing. There is no doubt that service providers have taken on a broader role, becoming in the process more partners than subcontractors. Many have restructured, growing in the process, and with their technical competence considerably reinforced. The oil companies have relinquished entire areas which were hitherto very much their preserve. This new modus operandi is undoubtedly acting as a mechanism for the dissemination, spread and acceleration of technological progress, and has led to a division of work propitious to these advances, the service providers building expertise in new areas, and the oil companies taking on the coordinating role in relation to the complex set of tasks requiring inputs from a range of different specialities. Cost reduction potential

Screening studies

Conceptual studies Preliminary design

Basic engineering

Detailed engineering

Time

Figure 4.26 Cost reduction potential during the various study phases.

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4.6.1.2 Mastering the costs of surface installations

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Quite separate from this antithesis between service providers and oil companies, it is clear that the growing complexity of projects, together with the shortening of the development cycle in the face of economic pressures means that there is an increasing interdependence between the disciplines involved at an increasingly early stage. In other words, the need for a cross-disciplinary approach is making itself keenly felt; this is certainly the case in the field of R&D, where efforts are being directed towards technological innovation which can be used commercially, with attractive economics.

4.6.1.3 Mastering operating costs Opportunities to reduce the operating costs present themselves in both the design and operating phases. Design phase – Make use of modern techniques of installation management; – Simplify the control systems, concentrate on the instrumentation which is really necessary; – Allow rapid and easy access to machinery and equipment; – Minimise the number of machines or equipment installed (number of backup machines corresponding to availability requirements and acceptable risk level, need for multiple bypasses, etc.); – Select equipment based on criteria of maintainability, reliability, ease of diagnosis, and quality. Operating phase – Outsource all or some operating and management functions; – Increase versatility of some workers; – Optimise maintenance, plan major maintenance as a function of remaining life of project; – Limit measures on reservoir to those which are really justified; – Renegotiate contracts. It should be said that, in the study phase, operating costs may appear to have little impact on project economics because of the effects of tax and the effect of discounting future cash flows. In the operating phase, however, cost reduction has a permanent effect, and becomes increasingly necessary as declining production results in a rapid increase in the costs per barrel. This trend can make the venture uneconomic, even while there are still substantial reserves remaining. It is therefore important to keep operating costs under close review throughout the life of the project right from its conception.

4.6.1.4 Mastering costs by risk-taking Companies seek to achieve two objectives simultaneously: to increase production and cut costs. They use all the means at their disposal, although some are bolder than others in this regard. The petroleum industry long had a reputation for conservatism in its technical choices, preferring methods which were tried and tested. Broadly this continues to be the case. However some companies are increasingly demonstrating their capacity to innovate, 162

4.6.2

Impact of the economic cycle and the contractual strategy on project costs

4.6.2.1 The economic cycle Although economic conditions are outside the control of the operator, an evaluation of the level of economic activity at the moment when the main contracts are awarded can provide useful guidance on the mean price levels likely to apply. Since the lead times involved in decision-making and the realisation of petroleum projects are long (3 to 5 years) investment decisions are taken on the basis of long-term economic calculations, and there is no direct correlation between the costs of platforms under construction and the price of crude. The costs of platforms are more sensitive to the costs of raw materials (particularly steel), the order books of the companies concerned and the availability of large construction yards. Since 2003, the petroleum services sector has entered the high phase of an economic cycle with very strong demand and insufficient capacities to answer to this demand. Prices quoted for a given contract will vary by 20–30% but can go over 100%, depending on the state of the market. The firm awarded the contract may just be seeking to cover its operating costs to avoid closure. Or alternatively in overheated economic conditions the firm may have won the contract without any real competition, since the order books of its competitors were full. This is illustrated by the example of Korea, which dropped its 163

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particularly where this leads to significant rewards or where the technical parameters are such that innovation is needed to reach new reserves. Innovation obviously involves risk of greater or lesser magnitude, both financial and in terms of image. The wide use of multiphase pumps in place of the much heavier and more costly traditional system of compression pumping is an example of the industrial application of an innovation resulting from prolonged R&D. Risk used to be essentially of a geoscientific or geopolitical nature, and if considerable technical risks were sometimes taken, for example in the North Sea in the 1970s, these were not seeking to establish or strengthen the position or competitiveness of a particular company in a given context. Times have greatly changed in this regard. The oil companies differentiate themselves and promote themselves to the competent authorities in host countries in terms of their capacity to take technological risks and to bear the financial consequences which ensue. There are many reasons for this. For example there is no doubt that the technological “levelling upwards” requires the ability not only to realise an activity at a particular point in time but also to be able to bet on future performance in the short or medium term so as to retain competitiveness. Specifically the willingness is required to take risks at the moment when agreements or contracts are signed, i.e. well before the realisation stage, and to manage these risks subsequently. In other words, in the past when development opportunities were technology-limited, risktaking remained fairly low. At present the reverse applies, and technological risk-taking has become a consequence of commercial decisions taken on the basis of considerations of a different nature. The perils are increased further still by the sheer physical size and therefore financial implications of the stakes involved.

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construction prices by 35–40% in 1998/1999 in order to maintain an acceptable level of activity, whatever the cost, during the Asian crisis which began in 1997. It should be noted that at times in the economic cycle when prices are high, labour also tends to be in short supply, there are delays in obtaining supplies and in construction work; these factors tend to further increase project costs. Since 2004, the increase in costs has been very high. As we have shown in Figure 4.25, the technical costs have reached in 2008 a level of $18 per barrel. A limited decrease has been observed in 2009 and 2010. Once the project has been defined, the final capital cost can still be affected by various factors and circumstances, in particular the contractual strategy adopted when the main contracts are awarded, the organisation of the teams and project control.

4.6.2.2 Contractual strategy The expertise and experience of the prime contractor will help him to develop a contractual strategy appropriate to the nature of the project. A petroleum development involves the award of large contracts for a variety of works (studies, supplies, construction, civil or offshore engineering, etc.). The overall strategy for distributing these various activities between different contractors should be the subject of a general study by the company managing the project, so that the overall project costs and timetable can be optimised. It should be noted that this process induces a delay between services price rises and impacts in the cost of oil companies. This contractual arrangement has limited the increase in the technical costs: projects decided in the last 5 years have still an effect on these costs due to the long development phase. This strategic study, carried out at the start of the project, is usually referred to as the Project Execution Plan (PEP). The final cost of the project will depend to a great extent on the choices made at this stage. This point is illustrated by showing how two of the traditionally important parameters of the PEP can affect the ultimate capital costs. The first of these parameters is the method by which the various contracts are remunerated. The second is the maintenance of competition between contractors in all the project stages. A. Different methods of contractual remuneration The various contracts will be awarded within a framework which includes remuneration terms appropriate to the circumstances. There are traditionally three bases of remuneration, as follows: – A time and materials basis, under which the contractor is remunerated based on time spent (day-rate contract); – A foot-rate contract, where remuneration is based on measurable outputs; – A fixed price for the entire work, including the contractor’s profit (turnkey contract). Each of these forms of remuneration has its particular advantages and disadvantages. A day-rate contract gives management great flexibility in the way the work is organised: the project manager is free at all times to re-orient the work of the contractor as he sees fit. However the latter has no particular incentive to complete the work quickly and at minimum cost because this is of no advantage to him. There is therefore a tendency for costs to mount and timings to slip relative to the initial estimates. 164

B. Maintaining competition between contractors The other vital measure in reducing the final cost of a project is to maintain competition between contractors when contracts are awarded. 165

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This contractual basis is appropriate to phases of the study in which the basis of the project, and therefore the work required of the contractor (at this stage, consulting engineers), is still subject to great variation. These phases are not the most costly part of the overall project, and it is vital that the necessary resources are made available and that the work does not suffer as a result of relentless cost-cutting. This is the time when the installations to be constructed are being defined technically, and the quality of this work provides the best guarantee that the project will be completed within budget and on time. For large construction projects, on the other hand, day-rate contracts should be avoided, as overruns on multimillion dollar projects can be extremely costly. In a foot-rate contract the contractor is remunerated according to measurable quantities of work carried out (volumes of earthworks, tons of piping installed, etc.) based on a unit price schedule appended to the contract. This form of remuneration may be appropriate in the initial phases of construction when the works have still not been fully defined and a fixed price cannot yet be set. This form of contract only passes part of the financial risk to the contractor. It also presents similar risk of overruns to the day-rate contracts. Unlike a day-rate contract, a turnkey contract remunerates the contractor for the supply of a complete installation (where appropriate with performance guarantees) without reference to the time spent and materials used. Only the result counts. The contractor has to estimate the cost of the proposed works on the basis of a call for tenders prepared by the petroleum company, and prepare a fixed-price bid for carrying out all the work, including an element which compensates him for his risk, and his profit. For the oil company, this formula has the merit of constituting a formal commitment on the part of the contractor to complete the work on time and at minimum cost. The fact that the contractor has to bear the cost of an overrun gives him every incentive to keep to the initial estimates. The oil company needs to be aware of the fact that if a turnkey contract is to be effective the work to be carried out must be defined in a precise, complete and definitive manner. Any work not covered by the contract is likely to be billed at a rate which reflects the fact the contractor will be the only one able to carry out the work required. Turnkey contracts are therefore suitable during the construction phase when the design and technical studies have been completed and the project definition has been “frozen”. In practice it is often necessary, in order to stick to the timetable, to award contracts before the definitional studies have been fully completed. In such cases it is up to the oil company managing the project to ensure that the timing is such as to ensure an optimum trade-off between cost and time. In the foregoing we have presented a simplified picture of the various contractual options open to oil companies in implementing development projects. In reality it is up to them to adapt, mix and coordinate these various possibilities depending on the realities of the situation, so as to optimise the overall economics. Particular attention is needed to ensuring that the various contractual interfaces between the petroleum company managing the project and its main subcontractors are clear and well coordinated. Special care needs to be taken that responsibilities are well delineated, and that there are no overlaps or gaps.

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The price of executing a project can vary significantly (i.e. by 20–30%) depending on whether or not there is genuine competition between contractors or the price was imposed by a contractor acting monopolistically. If it is not careful, such a situation may be of the oil company’s own making, as illustrated in the following examples. a. Design of the modules of an offshore platform The trend within the oil industry to design ever larger and heavier modules in order to minimise the need to link up separate modules was in itself a good idea. However this idea was taken to extreme lengths, so that modules became so large that there remained only one contractor with the necessary equipment or a lifting barge of sufficient capacity, with the result that prices became prohibitive. b. LNG plants Over the years petroleum companies have got into the habit, for reasons of technical conformity, of using the same proprietary liquefaction process and the same contractors for the construction of LNG plants. A quasi-monopoly has therefore arisen between a few contractors, and this has pushed prices artificially high. This situation has in turn tended to reduce the number of new LNG projects which are economically viable. The entry of new, or the return of existing, contractors into the market and the emergence of new proprietary processes should lead to appreciable cost savings.

4.6.2.3 Organisation of the project team A project is usually put in charge of a project manager whose objective it will be to erect high-quality installations quickly (to an agreed timetable), within (if possible below!) budget, which meet the initial specifications. Alongside this basic objective the project manager must also ensure that a number of other ongoing requirements are met, such as workplace safety, environmental protection, plant security, quality and reliability. The project organisation must have regard to these different constraints, but will be heavily influenced by the contractual strategy adopted. The project manager will in any case monitor the critical activities directly, as far as management is concerned, by keeping tabs on the costs and planning, and in the key technical areas, which are often metallurgy, instrumentation and power. Costs will be controlled particularly tightly. This will be achieved by using specialist software which allows rigorous budgetary monitoring and an ongoing exchange of data with the different groups involved with the project, whether from the client organisation or the financial department of the company. The measures to control project costs will be accompanied by a series of reviews or internal or external audits aimed at optimising the safety and the quality of the installations under construction. Given the magnitude of the investments involved in petroleum developments, all oil companies have developed strict and planned control procedures in these areas. In some countries, local content policy means that much of the investment is made in the local market. In that case, international service companies need to establish a permanent local presence to get fully involved. However, questions exist around the ability of the supply sector to meet demand in term of local equipment and local human resources with the adequate skill sets. 166

The petroleum services sector, or more fully the upstream oil and gas supply and service industry, is not easy to define as it embraces activities of a very heterogeneous nature. It includes geophysical activities (the acquisition, processing and interpretation of seismic data), drilling and associated services, engineering and design, subsea engineering (pipeline laying) and the construction of platforms (shipyards). In addition there are hosts of manufacturers of tools (for geophysics and drilling), metal construction and mechanical engineering firms. What all these companies, whether large, medium-sized or small, have in common is that they provide a service or services to the petroleum industry.

4.7.1

Historical background

The four major international poles of the petroleum services industry are the U.S., the UK, Norway and France. These national industries developed alongside the efforts in each country to develop national hydrocarbon resources. The U.S. has long set the pace for the petroleum industry worldwide; it has developed a powerful petroleum services industry which includes many companies which are global players. In the United Kingdom, although drilling began in the 1960s, it was the first oil shock in 1973 which really rendered exploration and production projects profitable and permitted the emergence of a national petroleum services industry which, on the back of its success in the domestic market, rapidly took on an international dimension. In Norway the first seismic profiles date back to the 1963. At that time the Norwegian government decided it would control exploration and production on its continental shelf. The petroleum services industry has developed in three stages: in the 1970s service companies cooperated with other countries with petroleum experience. In the early 1980s, nurtured by heavy protectionism and the publicly owned national oil companies (Norsk Hydro and Statoil) the large petroleum industry players emerged. Since the late 1980s these companies have been established themselves on the international market. In France the state played a role in helping the home-grown petroleum services industry to develop, despite the lack of a domestic market for these activities. But the French companies, which cover almost the entire spectrum of activities in this sector, have become major players in markets such as the North Sea and the Gulf of Guinea, and have thereby succeeded in gaining access to the international market. Apart from these main actors, China and South Korea, have significant petroleum services industries.

4.7.2

Investment in exploration and production: the market for petroleum services

The market for equipment and services in the upstream petroleum industry is made up of three components, as follows: • The first and largest category comprises investment by the oil and gas companies in explo-

ration-production. This accounts for three-quarters of the petroleum services market. • The second category (approximately 20%) comprises the operation and maintenance of

existing installations, only part of which benefits the petroleum services industry. This market is worth roughly $50 billion/y. 167

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4.7 THE PETROLEUM SERVICES SECTOR

in new equipment (construction or renovation of drilling rigs, seismic, pipe-laying or support vessels) and data acquisition systems (seismic, logging while drilling, etc.). These expenditures are difficult to evaluate, but vary between $10 and 15 billion/y. 500 450 400

G US$

350 300 250 200 150 100 50 0 2007

2008 North America South America Europe Rest of World

2009 CIS Africa Middle East Asia

Figure 4.27 Total investment in exploration and production in different areas (Source: IFP Energies nouvelles).

400 Onshore rest of World Offshore non US Onshore North America Offshore North America

350 Number of teams

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• The balance comprises the sums invested by the petroleum services companies themselves

300 250 200 150 100 50 0 2004

2005

2006

2007

2008

2009

Figure 4.28 Number of active seismic teams, onshore and offshore (Source: IFP Energies nouvelles).

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This decline directly affected companies in the oil and gas supply and service sector, which is directly dependent on oil company investment. Small companies were hit first, but even the biggest failed to emerge unscathed. Early in 2009 for example, Schlumberger and Baker Hughes were obliged to implement extensive redundancy plans. Depending on the sector concerned, this fall made itself felt in different ways.

120 000 World

100 000 80 000 60 000

North America

40 000 20 000 China 0 2004

2005

2006

2007

2008

2009

Figure 4.29 Number of drilled wells (Source: IFP Energies nouvelles).

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Over the last two decades the petroleum industry has undergone a transformation as a result of factors which affect the level of investment in the upstream industry: oil shocks and counter-shocks, major technological advances, large gains in productivity and radical restructuring. In the first half of the 1980s upstream investments by oil and gas companies were relatively high —varying between $80 and $90 billion/y— because of the high price of crude. After the counter-shock of 1985/86, investment fell back sharply, settling into the range of $45 to $52 billion/y. In the early 1990s the Gulf crisis produced a brief rebound in investment, to $79 billion, followed by three years of retrenchment, down to a level of $71 billion in 1994. Between 1995 and 1998 this trend reversed and there was a sharp increase in the capital flows in the upstream sector. In 1997 investments broke through the $100 billion barrier, an all-time high in current dollars. During the period 1994–1997 there was therefore strong growth in the upstream petroleum sector, which grew at an annual rate of 12%. In 1999, however there was an overall fall in investment, due to weak crude prices. From 2000, and up to 2008, the level of investment grew steadily, driven by rising oil prices, but also, and especially, by increasing costs. In 2009 the trend was reversed, with investments falling by an average of 16% (dropping 37% in North America but only 8% elsewhere in the world). The total of G$406 was G$80 less than in 2008, due to an economic environment that hardly encouraged companies to invest in developing new production capacity.

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4 000 3 500 3 000

World

2 500 2 000 Asia excluding China

1 500 1 000

North America

500 0 2004

2005

2006

2007

2008

2009

Figure 4.30 Number of offshore wells (Source: IFP Energies nouvelles).

In the geophysical market, seismic business continued to expand, increasing by 8% over the first nine months of 2009 but evidencing significant differences from region to region: major decreases in North America but 16% expansion elsewhere due essentially to offshore activity. Nevertheless, geophysics firms saw falls in their sales and profits figures due to renegotiation of contracts for lower prices. The leader in this sector continues to be CGG-Veritas (CGGV), followed by two other sector majors, PGS and WesternGeco. During 2009, drilling activity shrank by 32%, with 74,000 wells drilled of which 96% were on land. This was the segment that was hardest hit with a regression of 33% in its market. Nabors, Helmerich & Payne and Ensign, sector leaders, registered substantial reductions in their annual sales. Conversely, rigs at sea withstood the trend well, increasing slightly by 2.5%. Transocean remained the leader with 25% market share, ahead of Diamond Offshore and Noble Drilling. Offshore construction has continued to progress, expanding by 7%. The projects break down into 59% fixed platforms, 12% floating and 29% subsea. The three key actors, Saipem, Technip and Aker Kvaener, have continued to register growth in their annual sales.

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5

Legal, fiscal and contractual framework

5.1 THE KEY ISSUES 5.1.1

Ownership of hydrocarbons and the sovereignty of the State over natural resources

Two questions arise regarding the ownership of hydrocarbons. Firstly, who owns these resources while they are in the ground, either before or after their discovery, but before their extraction? And secondly, who owns them after their extraction from the subsoil, and at what point in time and space is ownership transferred if these two are not the same. As a general rule (except in the U.S. onshore), subsoil natural resources (and this includes hydrocarbons) are the property of the State. The State monitors petroleum activities and intervenes as custodian of the public interest, in particular when it licences individuals or organisations to explore for and produce hydrocarbons.

5.1.1.1 Hydrocarbon ownership regimes, origin of the State’s rights and powers Four main ownership regimes can be distinguished. In each case the State exercises considerable powers in its role as public authority. A. Ownership by accession Under this regime, land ownership extends both to the surface and to the subsurface, and hydrocarbons belong to the owner of the land by accession. This is the system applying in the United States on private land, i.e. excluding federal or state-owned lands. The owner can grant leases to any person he chooses, and in return receives a royalty. But even under this regime the right of ownership is limited by the powers exercised by the State in the general interest to guarantee security and the preservation of these resources. In all other countries, on the other hand, landowners have no rights or claims on the subsoil resources, these being the property of the State. 171

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B. Ownership by occupation Under this regime, the mineral rights belong to the first occupant of the land or to the person first applying for the right to occupy the land. This system was in force in some “new” countries, but is no longer applied for hydrocarbons. C. State discretion In this system hydrocarbons are not owned until they are discovered. At this time the State determines, by virtue of its power of patronage, the conditions under which the exploration for and production of hydrocarbons, which constitute part of the national wealth, will take place. The State grants mineral rights (leases or concessions) to the companies it chooses at its discretion, a process which may involve competitive bidding. The companies chosen are required to observe the conditions laid down by law, equal for all, without discrimination. The ownership of the hydrocarbons and the rules governing the transfer of this ownership are also laid down by the State. This is the system which applies in most industrialised countries. D. State ownership In this approach, which has its roots in the feudal system, hydrocarbon resources are owned by the State (the sovereign) and form part of its estate. Hydrocarbon exploration and production are governed by agreements or contracts made between the State and the company it chooses. This was the system which applied in the Middle East and Latin America, and involved applying application of the rule of the “inalienable and imprescriptible property of the State”. The principle of State ownership results in a State monopoly, companies acting as mere contractors with the task of developing the assets of the State. This is exemplified by the system of service contracts used in Latin America, Mexico, Brazil and Argentina until 1989. E. Hybrid regime In most countries today, the petroleum legislation lays down a regime which embodies the principles of State discretion or State ownership, the State exercising its sovereign rights over the natural resources.

5.1.1.2 Ownership of the subsoil and State sovereignty A. State property and mineral deposits National legislation, and occasionally the constitution, often contain explicit statements of ownership; hydrocarbons are the “property of the State”, “Crown property”, “State assets”, or “belong to the State”. These terms are sometimes difficult to interpret precisely. It is tempting to assume that State ownership is analogous to the relationship between an individual and his private property, including all the prerogatives which this confers on an owner over his assets. English-speaking countries use an expression difficult to render in other languages “vested in the Crown/State”. This expression seems to convey a concept of management rather than the complexity of ownership. Other national legislations classify mines, including hydrocarbon deposits, as belonging to the State without being too specific about it. However mineral resources do not fall easily 172

B. State sovereignty Developments in the way the international community interprets the concept of the sovereignty of the State are particularly important in practice. Since 1952 the United Nations General Assembly (Resolution 626) and then the United Nations Conference for Trade and Development (UNCTAD) have repeatedly reaffirmed “the inalienable right of all States to dispose of their wealth and natural resources in accordance with their national interests and based on respect for their economic independence” (1960). Resolution 1803 of 1962, restated in the third general principle adopted by UNCTAD at its first session in 1964, calls on States to exercise this sovereignty “in the interests of national development and the well-being of their peoples”. Subsequent declarations have been more radical, and the Resolutions adopted on 1 May 1974 by an extraordinary session of the UN General Assembly on raw materials introduced the notion of permanent integral sovereignty under the New International Economic Order. The principle was restated in the Charter of Economic Rights and Obligations of States, adopted by the General Assembly in 1974: the declaration of permanent integral sovereignty gives states the right to safeguard their mineral resources by exercising effective control over them. This principle was not to apply to mineral resources in the high seas. The United Nations designated (Resolution 2749-XXV of 1970) these as a “common patrimony of man” under the stewardship of sovereign states. The State exercises sovereignty over its national territory, the continental shelf and the 200 mile exclusive economic zone in the case of coastal nations. The UN Convention on the Law of the Sea (UNCLOS) of 1982, signed by 135 countries, sets forth the relevant principles in this regard. The interpretation of these principles can sometimes pose severe difficulties, as in the case of the Caspian Sea, where the determination of sovereignty has been a matter of dispute since the creation on its shores of new states formerly part of the Soviet Union. C. Nationalisation The right of states to nationalise companies or requisition them in the national interest is acknowledged in UN resolutions as a corollary of their sovereignty over their natural resources. Certain industrialised countries once resorted to this practice. But these resolutions also require that a public interest is demonstrated and that fair and prior compensation is paid. Nationalisation without or with inadequate compensation discourages new petroleum exploration. The basis on which compensation is determined remains a moot point. In equity it could be argued that the compensation should be based on the market value of the company, i.e. either the estimated or accounting value of the hydrocarbon resources and the installations or the present value of future profits derived from producing the known reserves. Such a basis is contested, however, because the reserves are the property of the State. The most common criterion adopted is that of the accounting value of the installations, as determined by an 173

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either into the State’s public domain (inalienable and imprescriptible) or its private domain. Although there are issues of the common good involved, mines are not an asset held for the benefit of all citizens, but nor are mines subject to the rules of private property. Some authors consider that mineral resources constitute a category sui generis of State assets, referring to them as “national property, intermediate between the two traditional forms of State patrimony”, or even, in the view of some South American jurists, as an “eminent domain” or “special domain” of the State.

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expert, with the possibility of resorting to international arbitration, although the latter is not accepted by all countries. It should be noted that problems of a similar order occur where the State, while stopping short of full-blown nationalisation, takes a share, as a partner alongside the other investors, in the lease or contract where this was not originally provided for, even though this is of course more acceptable to the investors than nationalisation. In contrast, the 1990s have seen a growing tendency in many countries towards the total or partial privatisation of certain assets and certain activities of the State or State enterprises. These transactions are usually effected by means of a call for tenders so that a purchaser can be selected and a value can be put on the transaction. Facing the new context of sustained high level of oil price since the early 2000s, some countries have decided a partial re-nationalisation (Russia, Bolivia, Venezuela).

5.1.2

Forms in which exploration and production can be undertaken

There are two options available to the owner of underground mineral resources: direct action or indirect action.

5.1.2.1 Direct action by the owner The owner of the mineral rights can carry out exploration and production activities for hydrocarbons himself/itself: – As the owner of the land (U.S.), whether a private individual, a state or the federal government; – In its capacity as the State, through the intermediary of public bodies (former USSR and Eastern European countries until 1990), or through national companies holding a full or partial monopoly (Latin America, Middle East) and where necessary calling on the assistance of service companies through technical assistance contracts.

5.1.2.2 Indirect action The State, as owner of the mineral rights and by virtue of its discretionary powers or proprietary status, can decide who will conduct exploration and exploit the hydrocarbon resources, subject to the relevant national legislation and contractual regime applying. The two main regimes for indirect State action are commonly referred to as “concession” (or licensing) and “production sharing”. Under a concession regime the contract holder is granted a mining title by the State: first an exploration license and, in the event of the discovery of commercial hydrocarbon resources, an exploitation license usually called “concession”. The license holder has the sole exploration and production rights for a certain area and for a certain period. Furthermore he has the beneficial use of the products extracted subject to fulfilling certain obligations towards the licensing authority. The State receives an income in the form of taxes. Under a production sharing regime the contractor does not hold a licence imparting mineral rights because the contract concluded with the State does not provide for such a title. The rights are often vested in a national oil company, and the contract is made with this company as representative of the State. The contractor is simply the exclusive provider of services to the State, and bears the technical and financial risks of exploration. In the event 174

5.1.3

Regulatory options

The foregoing shows that there are two opposite approaches to establishing a legal framework for exploration and production activities, i.e. the legislative and the contractual approaches. – In the legislative approach, which is that adopted in Europe, the U.S., Canada, Australia and Latin America, the legal framework is defined in detail and in a non-discriminatory manner by legislation and regulations; – In the contractual approach the relations between the State and the companies are essentially defined contractually, and are often discretionary. This is the system applying in many developing countries. In practice there are variants which involve a combination of these two approaches, particularly licence-based systems in which a detailed contract is made.

5.1.4

The content of petroleum legislation

5.1.4.1 Purpose The purpose of a law on petroleum exploration and production is mainly to define: – The legal regime applying to exploration for, and the production and transport of hydrocarbons (petroleum, natural gas and associated products), but excluding refining and distribution, which are industrial activities of a different nature; – The objectives of petroleum policy; – The modalities of State intervention, the competent administrative authorities charged with petroleum matters and, where applicable, the role of the national oil company; – The conditions under which petroleum contracts are approved and signed and licences are granted; – The way in which activities are conducted and monitored; – The tax, customs and exchange regimes. A petroleum law must be capable of continuing to apply for decades without major amendment, although amendments may be needed in response to particular circumstances. In a non-producing country, for example, the law needs to encourage exploration in the short term and, in the medium term, protect the State if major discoveries are made. Modern legislation provides a flexible framework, confining itself to laying down the principles, leaving the details, modalities and economic parameters to be dealt with in implementing regulations and contracts. The delicate balance which needs to be achieved is often the subject of major discussions between the legislature and the executive. 175

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of a discovery he has the exclusive right to develop and exploit the resources, and will receive a remuneration equal to a proportion of the production (whence the name). The State receives the remaining proportion of the production. In either case, certain countries stipulate that, in addition, the State may participate directly in the operations as a partner of the license holder or contractor, taking on the same rights and obligations in proportion to its level of participation. Under such an arrangement, the State is usually represented by the national oil company, and the arrangement can offer the State a number of advantages. Until the late 1980s such arrangements were to be found in many countries, the participation rate reaching 50% or more, but they are tending to be reduced or even disappear completely. However since 2005, some producing countries have re-introduced participation rates higher than 50% (Algeria, Venezuela).

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However legislation can be more or less flexible, depending on the constitution of the country concerned, particularly in relation to taxes and to contracts. In some countries, particularly developed countries such as the United Kingdom, Norway and France, tax is a matter for the legislature, which means that taxes are set in the law without leaving any margin for negotiation. Under this regime, petroleum taxes can be amended periodically by finance acts, and apply equally to all operators. Other countries adopt a more flexible approach, and make use of contracts which leave a considerable margin for negotiation.

5.1.4.2 Relationship with the rest of the legal system The legislation of general application in the country concerned also applies to petroleum operations unless the petroleum law provides otherwise in order to allow for particular aspects. Some countries have a mining law and an investment law. Because of the specific nature of this legislation, petroleum operations should be governed by specific petroleum legislation. The mining law sometimes extends to cover petroleum operations, but this is not the most appropriate approach. Over the last 30 years many countries have adopted a petroleum legislation which takes the place of the mining legislation in relation to petroleum matters.

5.1.4.3 Tax regime for petroleum Various options can be envisaged: • The petroleum law deals with the taxation of petroleum and, if appropriate, introduces a

specific regime for the taxation of the profits from petroleum exploration and production activities. • The petroleum law only deals with certain tax matters (royalties, taxation of profits,

special petroleum tax), other taxes falling under general taxation law. • The petroleum sector is dealt with by a special chapter of the general tax law.

5.1.4.4 Competent authority charged with petroleum matters The law must specify the competent government body charged with petroleum matters, and particularly with negotiating and signing petroleum contracts. This body will also, either directly or by delegation, supervise petroleum operations and monitor compliance with the applicable legislation. Some or all of these powers may be delegated to a national oil company. This can lead to conflicts of interest because the latter then has two theoretically separate roles: the representative of the State in its capacity as regulator but also a partner associated with other companies in joint petroleum ventures. In order to avoid this kind of conflicts, several countries have established separate bodies to act as independent regulators (Brazil in 1997, Indonesia in 2002, Colombia in 2003, Algeria in 2005).

5.1.4.5 Determining the rights and obligations of contractors and licensees Two approaches are possible. The first is to define these matters in great detail in the law and implementing regulations. This fairly inflexible approach is what happens in the indus176

5.1.4.6 Implementing regulations The petroleum law establishes the legal framework. The regulatory detail is spelt out in implementing regulations enacted in the form of decrees and regulations. These deal with administrative procedures, the technical aspects of operations, the environment, workplace health and safety as well as abandonment procedures when production comes to an end. They can be very detailed in countries such as the U.S., Canada, the United Kingdom and Norway in order to address the specific nature of offshore operations.

5.1.5

The objectives of the parties involved

The main objectives of the State and of the oil companies can be summarised as follows: The State • To promote petroleum-related activities at all levels: – to explore the country’s petroleum basins, – to develop and exploit the resources discovered, – to rehabilitate old fields or put into production discoveries as yet undeveloped for technical or economic reasons; • To maximise the revenues of the State while securing, if possible, returns to investors

commensurate with the risks run during exploration; • To establish an attractive, fair and stable fiscal and contractual regime, capable of adapting

to conditions as they evolve over the long term, thereby maintaining a satisfactory activity level; • To supervise and monitor operations in consultation with the companies, while ensuring

that activities are not hampered by red tape; • To acquire expertise through the transfer of technology and skills.

Petroleum companies: • To obtain a return consistent with the company’s objectives; • To recover the investment costs as rapidly as possible; • To gain access to oil and gas reserves; • To ensure that reserves are replaced; • To limit risk by diversifying their portfolio of exploration and production acreage.

The criteria adopted and the priorities set between these various objectives depend on many factors, both for the State and for oil companies, and can also change over time in response to circumstances, e.g. developments in international hydrocarbons markets, the potential and position of the country (producer or not, exporter or not, etc.), the importance of oil in the national economy and the company’s own particular strategy. 177

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trialised countries and older legislation inspired by the French model in Africa. An alternative approach is to define the broad principles, particularly in relation to taxation, by reference to a model contract prepared by the competent authority. This is a more flexible solution which allows the regime to be established in the contract. This model contract, which does not form part of the law, can be adapted to allow for the nature of the potential discoveries of hydrocarbons and the petroleum context.

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5.1.6

Reconciling objectives and sharing the economic rent

Clearly the objectives of the two parties are not always totally consistent. The legal, fiscal and contractual framework should be designed to create a win-win situation for the two parties. The core issue between States and oil companies is the way the economic rent is shared (this notion has already been considered in Chapter 4). Depending on the parameters mentioned above, this sharing may be more or less favourable for the State or for the companies, depending on the parameters mentioned earlier. We shall consider below the mechanisms by which this sharing is implemented and simple instruments by which it can be assessed.

5.1.7

Types of contract

It is important to be clear about the different types of contract used in the upstream oil industry. A contract for petroleum exploration or production deals with the relationship between the State (or the national oil company representing the State) and the license holder or contractor (which may comprise a consortium of companies formed exclusively for this purpose). This is the type of contract considered further here. When the license holder or contractor comprises a number of partners, the association between these partners is formalised by means of a Joint Operating Agreement (JOA) which spells out their relationship in regard to decisions and the conduct of operations, based on their stake in the partnership, under the responsibility of an operator chosen from amongst the partners.

5.1.8

Breakdown of petroleum contracts by type

Tables 5.1 and 5.2 show the incidence and breakdown of petroleum exploration and production contracts according to: – The different countries; – Geographical region. It should be noted that several regimes may coexist in the same country. An estimate shows that most of the volume of hydrocarbon production is still governed by concession regimes. This is due to the fact that this type of contract predated the production-sharing arrangements introduced more recently, in the late 1960s.

5.2 MAIN PROVISIONS OF A PETROLEUM EXPLORATION AND PRODUCTION CONTRACT 5.2.1

General structure of a contract

A petroleum exploration and production contract (within the meaning defined in the previous section, i.e. which confers exclusive rights on the beneficiary) generally consists of a document of, typically, about a hundred pages, with several sections: the preamble, the main text, and appendices which form an integral part of the contract.

178

Type of contract

Main producing countries

Concession (with possible participation by the State or by joint companies)

Most OECD countries (Australia, Canada, US, UK, Norway, etc.) Abu Dhabi, Angola, Argentina, Colombia, Brazil, Brunei, Gabon, Nigeria, Russia, etc.

Production sharing contract

Angola, Algeria, Azerbaijan, China, Congo, Egypt, Gabon, Indonesia, Kazakhstan, Libya, Malaysia, Nigeria, Peru, Qatar, Russia, Turkmenistan, Trinidad and Tobago, etc.

Risk service contract

Algeria, Iraq, Iran, Kuwait, Qatar, Venezuela, etc.

Production by the national oil company or a local company (in countries already open to foreign investment)

Algeria, Brazil, Iraq, Iran, Russia, Venezuela, etc.

National oil company with absolute monopoly

Saudi Arabia, Mexico

Table 5.2 Geographical distribution of different types of contractual basis (OPEC countries shown in italics).

1. America Concession Exporting countries

Producing countries

Non-producing countries

Colombia Trinidad and Tobago

Production sharing contract Bolivia Peru Trinidad and Tobago

Argentina Brazil Barbados Canada US

Chile Cuba Guatemala Surinam

Bahamas Belize Costa Rica Paraguay

Antigua Aruba Dominican Republic Guyana Haiti

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Honduras Jamaica Panama Puerto Rico Salvador

Service contract

Absolute monopoly

Ecuador Venezuela

Mexico

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Table 5.1 Types of exploration and production contract and countries in which practised.

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2. Western Europe Concession regime in all countries (apart from production sharing contracts in Cyprus, Greece, Malta).

3. Central and Eastern Europe, CIS countries Concession and joint companies Russia

Russia Other CIS Republics: Azerbaijan, Kazakhstan, Uzbekistan, Turkmenistan

Hungary Poland Slovakia Czech Republic

Albania Bulgaria Croatia Rumania

Exporting countries

Producing countries

Production sharing contract

Service contract or absolute monopoly Most production is presently carried out by State enterprises

Non-producing countries

4. Asia

Concession

Production sharing contract

Abu Dhabi, Dubai, Sharjah (United Arab Emirates) Brunei Oman Papua New Guinea Vietnam

Bahrain China Indonesia Iraq Malaysia

Producing countries

Australia New Zealand Pakistan Thailand Turkey

Bangladesh Burma (Myanmar) India Philippines Thailand

Non-producing countries

Fiji South Korea

Cambodia Nepal Laos Sri Lanka Mongolia

Exporting countries

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Oman Qatar Syria Yemen Vietnam

Service contract Iran Qatar

Absolute (or partial) monopoly Saudi Arabia Iraq Kuwait

Concession

Exporting countries

Algeria Angola Cameroon Chad Congo Gabon Libya Nigeria Tunisia

Service contract

Absolute monopoly

Algeria Angola Egypt Congo Gabon Equatorial Guinea Libya Mauritania Nigeria Sudan Tunisia

Nigeria

Benin Ivory Coast Ghana Democratic Republic of Congo Tanzania

Producing countries

Non-producing countries

Production sharing contract

Burkina Faso Niger Central African Republic Guinea Bissau Seychelles Madagascar Sierra Leone Mali Morocco Somalia

Ethiopia Guinea Kenya Liberia Madagascar Mozambique Senegal Togo Zambia

The preamble enunciates a number of general statements (customarily beginning with the word “Whereas”) whose purpose is to set the detailed provisions of the contract in their broader context, both legal (for example references to existing legislation which provides for the type of contract in question to be concluded) and political (for example references to the role of the State, national policy on the development of natural resources). The main text takes the form of a series of articles and subarticles numbered sequentially, and often arranged in chapters. It states who the parties to the contract are, its purpose, term of validity and the rights and obligations of the respective parties. Broadly speaking the provisions fall into four categories: – Technical, operational and administrative provisions, which deal with practical aspects related to the conduct of operations during the different phases; 181

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5. Africa

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– Economic, taxation, financial and commercial provisions, which deal with how the profits will be split between the parties, how petroleum costs will be accounted for, pricing and disposal of production; – Legal provisions, which deal with the application and modification of the contractual relationships between the parties; – Miscellaneous provisions, which deal with any other matters. Generally the appendices include: – a description of the contract zone in terms of its geographical coordinates including a map, and its surface area; – the accounting procedure which provides for the methods and procedures to be used for accounting for the petroleum operations covered by the contract; – the work commitments; – a guarantee by the parent company and/or a bank. The following sections describe the main provisions to be found under each of the above headings. Most of these are to be found in any petroleum contract, but some are specific to certain types of contract only.

5.2.2

Technical, operational and administrative provisions

5.2.2.1 Term and phases of a contract It is important to be aware of the different phases of a contract, as different provisions may apply to different phases. The first is the exploration phase, during which the contract holder carries out geological and geophysical surveys and drilling operations with a view to identifying prospects within the contract zone and then to drill the most prospective of these, i.e. those most likely to contain hydrocarbons. The second is the exploitation phase, which occurs when hydrocarbons are found which are judged to be commercially viable. This phase comprises a period of development followed by a period of production. As long as he has fulfilled his contractual obligations, the contract holder can withdraw at any time during or at the end of the exploration phase if a discovery judged to be commercial has not been made. There has been a recent tendency for countries once closed to foreign operators to open their industries up. Increasing numbers of contracts cover zones already explored and which already contain hydrocarbons. These might be discoveries which are not yet exploited because there is a need for technologies or funding beyond the capabilities of local operators (typically national oil companies). Or they may have been already subjected to exploitation activities, and now be considerably depleted and in need of rehabilitation or enhanced recovery which has not been carried out for the same reasons. In these cases the contract will take account of this specific situation by omitting the exploration phase and commencing the development phase immediately. When no exploration is necessary the risks are lower, and the State may require that this fact is reflected in the financial arrangements agreed. The situation can be even more complex where a contract is for further exploitation from an existing field but when further exploration is authorised, for example at greater depths corresponding to horizons not yet explored. These considerations demonstrate the need to define very clearly the terms used in a contract and the effective operations to which they relate, so as to avoid subsequent misinterpretations of the contract or disputes. 182

A. Term In setting the term of the exploration phase should two conflicting criteria need to be met: – It should be long enough give the contract holder the time he needs to conclude successfully the activities needed to evaluate the petroleum or gas potential of the exploration zone and to discover hydrocarbons; – It should be short enough discourage the contract holder from proceeding unduly slowly, thereby occupying for too long a large area which might be of interest to other companies. In order to reconcile these two criteria, the normal practice is to provide for a relatively long total exploration period (generally 5–10 years), but to subdivide this period up into a number of subperiods. The contract holder therefore has an initial period, renewable for one or two succeeding periods. At the end of each subperiod he may renew his entitlement for a further subperiod provided he met his commitments for the period just ended. At the end of the final subperiod the contract expires for the entire area covered by the contract except the zones containing commercial discoveries which will be developed. However it is customary to provide for an optional extension (on average 3–6 months) running from the expiry of the contract, to allow the contract holder to complete the exploration work still in progress. Up until 1986 the general trend was for a reduction in the duration and the size of the exploration area. Since then this trend has been reversed as a result of the changed petroleum environment, particularly in deep offshore locations. The initial exploration period begins when the contract takes effect. Because this is generally the longest of the exploration sub-periods, and in order not to quarantine a large area without any exploration taking place, it is normally stipulated that the contract holder must begin work within a certain period (typically 3–6 months) from the effective date of the contract. B. Contract area and relinquishment The initial area covered by the licence or the contract zone is specified by means of a map showing the boundaries and indicating the coordinates of reference points. It is often defined by the State before blocks are created, rather than by the applicant, particularly where there is an international call for tenders. Sometimes the size of a licence or a zone available for granting is limited by legislation. This area varies considerably depending on the particular circumstances applying. Although in some cases large areas are still granted to contract holders, authorities generally tend to allocate zones of medium size (of the order of 1 000 to 5 000 km2). If the area is too large there is a risk the holder will only explore a small part of it. The rest will therefore be “frozen”, thereby excluding other companies which might want to invest in that zone. It is important that the State adopts a policy which ensures the coherency of exploration programmes. Usually the contract holder cannot hold on to the entire area indefinitely. It is customary for a minimum reduction to be made in the area of the contract zone when an application is made to renew the exploration term. In most contracts which provide for an initial period and two additional exploration periods, the first and second renewals are accompanied by 183

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5.2.2.2 Exploration phase

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the mandatory relinquishment of up to 25–50% of the initial area, except where special circumstances justify a smaller or no relinquishment. The contract holder is usually free to choose the zones to be relinquished. To prevent him from relinquishing a large number of fragmented pieces, constraints can be imposed on the shape and the number of pieces relinquished. C. Exploration work obligations or expenditure obligations When the contract is signed, a minimum work programme is specified for each of the exploration sub-periods (initial period and additional periods) which the contract holder must carry out if he wishes to renew his rights. This programme is normally subdivided by type of operation: geological studies, seismic surveys and exploratory drilling. A minimum seismic programme is often only imposed for the initial period of exploration. The programme is defined in terms of a minimum number of kilometres of 2D profiles or 3D surfaces. The minimum drilling programme is defined in terms of a minimum number of wells to be drilled; this number will depend on the duration of the exploration period and on the area covered by the contract. Minimum depths for the drilling (or specific objectives to be attained) will also be specified. And finally the contract needs to state whether delineation and appraisal wells will be considered as exploration wells for the purpose of this obligation. The purpose of specifying minimum levels of activity is to satisfy the State that each contract holder will undertake sufficient exploration work obligations to ensure that the petroleum potential of the zones granted will be properly studied. The contract usually provides that if during one of the exploration periods the contract holder exceeds the specified minimum exploration work obligations for that period, the additional work can be carried forward to the following period, thereby reducing the obligation in that period. Sometimes the obligation imposed on the contract holder is defined in terms of the minimum expenditure on exploration work, either as a total or broken down by the various types of work. The contract needs to specify whether the contract holder must comply with both work and expenditure obligations or only one of these, and what the priority is. Usually work obligations take priority over expenditure obligations. In that case the only expenditure stipulated in the contract relates to the penalties applying in the event of failure to complete the specified work. In order to ensure that the contract holder can discharge his obligations to invest or carry out exploration, the State can demand that the oil company provides financial guarantees. This guarantee can take the form of a bank guarantee or a performance bond of the company. The contract holder may relinquish all or part of the area before the expiry of the exploration period. The contract provides that where there is a partial relinquishment of the area there is no diminution of the obligations in the current period, and that of the area is totally relinquished, the contract holder will be subject to the same rules and penalties as described above. D. Evaluation of a discovery If the contract holder discovers hydrocarbons during his exploration activities, he is required to notify the competent authority of this fact. If he considers that the discovery is worth an 184

5.2.2.3 Exploitation phase A. Declaration of commerciality and submission of a development and production plan It must be emphasised that the judgement as to whether an oil or gas field is commercial is a matter for the contract holder: it is the investor who will bear the risk and who is in a position to evaluate the profitability of the project based on his assumptions and strategy. Some countries have however sought to formulate a definition of a commercial discovery on the basis of which a contract holder can be obliged to undertake a development programme. This is based on certain objective criteria related to the volume of hydrocarbons discovered or a certain productivity per well achieved over a certain period. This approach has not really caught on, however. When the contract holder declares a discovery to be commercial, he prepares a development and production plan, which if necessary is submitted to the authorities for approval. Once the plan has been accepted the contract holder must commence development within a short period. The development plan is an important document which deals with all the technical and economic aspects: reserve estimation and future production profiles; development schedule, wells and production installations, storage and transport, timetable for completion and commencement of production, estimates of capital and operating costs; economic evaluation establishing the commercial viability of production; the environment and safety; the abandonment plan when production ends. B. Production period After a development plan has been adopted, the holder of the exploration rights is entitled to exclusive rights to exploit the resources discovered. The duration of the production period is variable, depending on the agreement. Production is usually authorised for an initial period, typically 20–25 years, which may be renewable for 10 years or more if further production is economically viable. 185

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appraisal, he must prepare an appraisal (or delineation) programme and a budget for the works. Certain countries then create a specific appraisal zone so that the work can be carried out. After this programme has been executed the contract holder informs the authorities of the results obtained from the appraisal and his conclusions, and specifically, whether he regards the find as commercial and whether he plans to develop it. Where the contract holder concludes that the discovery is economically marginal or noncommercial, some contracts may provide that he can propose to the State modifications to some of the provisions of the contract so that the contract holder is able to exploit the discovery. These proposals must be accompanied by economic studies performed by the contract holder which demonstrate the effect of the proposed changes on the project economics. The State is of course at liberty to accept or reject the modifications proposed. If it accepts them the contract holder is required to declare the discovery commercial and to propose and implement a development programme. Some contracts provide that if a discovery is considered non-commercial the contract holder must hand the discovery over to the State if the authorities wish to exploit it before the normal expiry of the contract. Special clauses may apply to gas discoveries (see Section 5.2.5).

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The grant of a production licence involves an obligation on the part of the contract holder to develop the field in question in accordance with the development plan. He is expected to produce in accordance with best international practice, with optimal recovery of the reserves. C. Area of production zones When a contract holder declares that a discovery is commercial he is required to submit to the authorities details of the precise configuration of the field which emerges from the delineation. The production zone corresponds to the extent of the field. Within a given exploration zone there will be as many production zones as commercial discoveries. The area of the production zone is determined at the time that the discovery is declared commercial. It can occur that the improved knowledge gained after several years of production means that the production zone needs to be enlarged. To cater for this possibility, a provision can be included allowing the production zone to be enlarged so that it corresponds with the new area of the zone which has now been found to be exploitable, providing that the additional area lies within the area of the exploration zone still held by the contract holder. D. Unitisation When an oilfield is discovered which straddles several different exploration zones granted to different contract holders, the contract needs to contain a clause which ensures that the recoverable reserves are exploited in a coherent manner (for example by appointing a single operator, adopting a joint development and production plan, etc.). Such a clause, known as a unitisation clause, has to be common to all the agreements made between the State and the contract holders, since in the event that such a clause has to be invoked, the rules must be identical for all. The special case of oil and gas fields which straddle national frontiers has to be dealt with by means of international agreements, as in the North Sea between the British and Norwegian sectors. When a dispute arises between several countries, this can be resolved by creating joint development zones governed by ad hoc statutory and fiscal arrangements, as in the celebrated Neutral Zone between Saudi Arabia and Kuwait, the Timor Gap between Australia and Indonesia, and the Joint Development Zone between Nigeria and Sao Tome and Principe. E. Obligations when production is abandoned When production from a field is abandoned, the obligations of the operator need to be specified. These may involve transferring all installations to the State without charge or decommissioning the wells and the disposal of the installations at its own cost. Contracts increasingly specify an abandonment plan, submitted to the authorities in advance, containing special fiscal provisions if appropriate, and providing for cost allowances to be set aside in advance to fund the abandonment costs. This may be a costly operation in offshore zones subject to stringent regulations.

5.2.2.4 Conduct of operations A. Good oilfield practice All holders must undertake to observe good oilfield practice in their operations whether or not there are detailed technical regulations in force. This requirement relates particularly to 186

B. Annual work programmes and budgets Before the start of each year the contract holder must submit to government a work programme together with a budget for the coming year, broken down by type of activity or expenditure (exploration, evaluation, development, production). The programme is provisional; and changes may be proved necessary as work proceeds. These are permissible provided the objectives of the work programme remain the same. C. Administrative supervision Petroleum operations are monitored by the State, acting through the department responsible for mining or hydrocarbons within the relevant ministry. The contract holder must inform this department of any major petroleum operation such as a geological or seismic survey, drilling activity, well-testing or the erection of installations so that the latter can dispatch a representative to the site. The department can also ask the contract holder to carry out any work necessary to safeguard health and safety during its operations. D. Information, reports and confidentiality As well as providing annual work programmes and budgets in advance, the contract holder must submit, at specified intervals, activity reports detailing the work carried out, supported by technical data where necessary. He must also submit to the State a copy of all the data obtained during operations as well as any information describing the subsoil: geological and geophysical data, logs, results of analyses, measurements made in production wells, pressure trends, studies of secondary recovery, estimates of the reserves in place and recoverable. It must also submit all the data on the production itself: quantities produced from the field, hydrocarbon sales, quantities of product shipped, including data on the purchasers, countries of destination, price of each cargo, etc. The contract must specify the ownership of petroleum data obtained during operations: usually the data are the joint property of the State and the contract holder. All the data obtained must be treated as confidential by the State and the contract holder for a period specified in the agreement. This period varies considerably, ranging from 3–5 years from the date they were obtained to the entire period of their validity. Finally, the contract holder must provide periodical reports on its activities and expenditure. These reports also allow the State to monitor the development of local employment in the petroleum sector. E. Training and employment of local personnel The contract holder may be required to give priority to the employment of local personnel for its petroleum operations. By their very nature, petroleum operations need experienced, highly qualified personnel, not always available locally. For this reason, this clause is always accompanied by provisions for the training of local personnel, and this involves setting up a minimum annual budget for various programmes. In some countries employment objec187

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resource conservation (optimum production) and safety. Nowadays environmental protection has also become a very important issue, and new standards are being formulated, including the requirement to carry out an environmental impact assessment and to monitor continuously in ecologically sensitive areas.

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tives are also set, expressed as the percentage of the workforce at a given level of qualification which should be made up of local employees. F. Priority for local products and services, and local development As well as requirements regarding local employees, there will likewise be expectation that local goods and services are used. Use is often made of international calls for tender in awarding contracts, with local businesses being consulted. Local development becomes a growing requirement in many producing countries. In October 2009, Nigeria adopted the concept of “Local Content Bill” to develop the local industry. Venezuela introduced the concept of “Desarollo endogeno”. In Canada, the oil producing Provinces of Nova Scotia, Newfoundland and Labrador propose “Benefit Plans” to measure employment and profits related to any oil producing project.

5.2.3

Economic, fiscal, financial and commercial provisions

5.2.3.1 Financing petroleum operations The contract holder has exclusive responsibility for the funding of the activities. Exploration costs are funded by means of equity capital. Development costs can be funded to a large extent by loan capital. The contract may specify a maximum percentage to be financed by loan capital, as well as other conditions for approval, the conditions relating to the tax deductibility or recovery of interest.

5.2.3.2 Determining the State revenues The manner in which revenues are calculated depends on the regime applying. These are dealt with in Sections 5.3 and 5.4.

5.2.3.3 State participation During the period 1970–1980 some countries introduced provisions permitting the State to itself participate directly in petroleum operations as a partner of the contract holder, taking on the same rights and obligations in proportion to the level of its participation. The main purposes of these provisions are to give it access to petroleum resources, to increase its net revenues (i.e. after meeting its share of the capital and operating costs) and to increase its involvement in petroleum operations, particularly in terms of increased control, closer supervision and the transfer of skills. The State participation usually involves an incorporeal association. The State, usually through the intermediary of a national company, becomes a partner in the contract with a defined share. The relationship between the partners is governed by a participation agreement. The State may enjoy certain specific advantages, for example a “carried interest” whereby its share of the capital cost is borne by the other partners during the exploration phase, to be reimbursed later from its share of any production. The other form of participation is implemented through a joint company. Such an arrangement is less common and can give rise to practical difficulties relating particularly to the financing the State’s share of the capital, the ownership of the reserves and of the production, the payment of dividends and the taxation basis applicable. However Venezuela adopted in 2006 a new law aiming at converting all existing contracts into the form of “empresa mixta”, where the national oil company PDVSA holds at least 51%. 188

5.2.3.4 Determining the price of hydrocarbons Since the revenue of each party is closely linked to the value placed on the hydrocarbons, this clause is of crucial importance. A. Price of crude a. Real sale price to third parties The price is based on the real market price for sales involving a change of ownership at a point of delivery agreed by the parties. The price normally used is the FOB price at the export port by tanker. Where sales are based on the CIF price (cost, insurance and freight) this price has to be adjusted to obtain the FOB price. Sales between affiliated companies should be valued at the weighted mean price for sales to third parties, for the same oil and during the same period, if it is possible to calculate this price. If there were no sales to third parties during the period considered, the real market price is established by considering the mean market price during the same period of crudes of comparable quality sold in the country or in neighbouring geographical zones. This price is therefore submitted for discussion and approval by the parties according to a procedure to be agreed. Some agreements contain a detailed procedure for determining the market price, with the possibility, in the event of disagreement, of referring the matter to an independent expert agreed by the parties whose decision will be binding on all. b. Posted price or fiscal reference price These theoretical prices, higher than the real sale price, were introduced by certain countries, notably OPEC, in 1964. Originally posted prices were negotiated with the companies, but with effect from 16 October 1973 the OPEC countries decided to set their posted prices unilaterally. The purpose of this reference price was to avoid discussions about the determination of the real sale price, the posted price being a fiscal reference price used to calculate State revenues (royalties, taxes). The use of posted prices not linked to the market price has now virtually been abandoned. B. Price of natural gas In contrast with crude oil, there is not really an international market price for natural gas because the price of gas essentially depends on the geographical location where it is sold, and on the level of integrated transportation infrastructure and market. However, a competitive market exists in the United States with a spot price. The price to be taken into account for the purpose of the contract is therefore the real sale price to third parties or, for direct sales to the government or an affiliated company, the price fixed by agreement between the parties. Sometimes the price of a substitute fuel such as fuel oil is referred to. The prices fixed in long-term gas sale contracts may be the subject of complex formulae based on the indexed price of a basket of crudes and petroleum products. 189

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Depending on the detailed arrangements, the participation of the State can have a major economic impact because the State does not share the initial exploration risk. And State participation reduces the shares of the other investors in the production. The State share can be 50% or even higher in some countries, but has generally declined considerably over the 1990s, in some cases to nil. As already mentioned, the opposite trend can be now observed in some major producing countries (Algeria, Bolivia, Venezuela).

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5.2.3.5 Marketing The contract holder is responsible for the marketing of all the products extracted or of his share of those products, depending on the type of contract applying, and is obliged to obtain the best possible price. There is often a requirement that the domestic market should have a first call on national production. In this case the sale price is either the market price or a reduced price, but the latter practice represents a hidden tax.

5.2.3.6 Auditing and accounts During the entire period of validity of the contract, the contract holder must keep separate accounts in accordance with accounting procedures appended to the contract. These procedures are set up in accordance with the rules applying in the country concerned, but may be subjected to slight changes to allow them to cater for specific petroleum mechanisms, for example depreciation procedures, the period of carry-forward of losses and the definition of petroleum costs. The clause in the main agreement relating to the accounts of the contract holder can therefore be quite short because it will refer to the accounting procedure in which all the practical procedures are indicated. It will specify the currency in which accounts are to be kept (often U.S. dollars), rules for conversion and the right of the government to have the accounts audited.

5.2.3.7 Customs regime Because of their particular nature, petroleum operations enjoy certain customs privileges or administrative facilities. These relate particularly to the right to import goods and services usually free of any import duties or taxes. The import of equipment which will eventually be re-exported is often treated as a temporary import only. The contract holder also has the right to freely export the production, possibly after supplying the domestic market in priority, usually free of any duty or export tax.

5.2.3.8 Tax incentives In view of the specific nature of the tax regime applying to petroleum exploration and production, contract holders and their subcontractors generally enjoy certain tax advantages, such as exemption from taxes on sales (in particular value added tax on services provided). Holders sometimes benefit from an exemption from dividend withholding tax or tax on loans raised in other countries. In other respects, and with the exception of any other provisions in the petroleum legislation, holders are subject to the normal tax regime. The taxation of service companies and foreign suppliers presents a difficulty in determining the profit resulting from one-off operations in the country. A deduction at source is often made of a fixed percentage of turnover.

5.2.3.9 Exchange control Holders are subject to exchange controls. However in order to facilitate petroleum operations, these controls are often relaxed. This will allow: – Bank accounts to be freely opened and used in other countries; – Payments to subcontractors and employees to be made in part in other countries; 190

Some exporting countries have in the past obliged companies to reinvest part of the profits in the country, in the petroleum or in other sectors. Very often the local tax legislation in a country which is already a hydrocarbon producer provides incentives for reinvesting, for example by making new exploration expenditure immediately tax deductible through the consolidation of different activities or by allowing a depletion allowance.

5.2.4

Legal provisions

5.2.4.1 Parties to the agreement An agreement is concluded on behalf of the country by the State or government, represented by one or more ministers, the minister responsible for petroleum affairs or the national oil company. As far as the company is concerned (or companies in the case of a consortium), the agreement is most often signed by a new subsidiary of the parent petroleum company created under local law. The latter will therefore guarantee that the contractual obligations of the signatory company are properly carried out. In some countries a local joint company with the involvement of the State is set up when a discovery has been made. This company is established to manage the operations but does not interfere in the marketing and does not participate in the profits.

5.2.4.2 Assignment and transfer The contract holder is entitled to assign or transfer all or part of his interests in the area covered by the agreement to other persons provided he observes the conditions imposed under this clause.

5.2.4.3 Force majeure In the event of force majeure (an unpredictable event or act beyond the control of the parties, such as a natural disaster, civil unrest, sabotage, war, etc.), the contracting parties are temporarily relieved of their obligations where these are affected. Once normal operations resume, the contractual periods are adjusted to allow for the delays incurred.

5.2.4.4 Settlement of disputes and international arbitration Arbitration is reserved for serious disputes, after attempts at reconciliation have been made. For disagreements of an operational and technical nature, it is preferable for the matter to be resolved by referring to technical experts, given the protracted nature of arbitration. In other cases recourse to the national courts or international arbitration can be considered. For agreements between developing countries and foreign investors a dispute would normally be referred to international arbitration using procedures established by the international organisations. 191

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– Sales revenues to be received directly in other countries free of any constraint (i.e. without repatriation) except for that part necessary to cover the expenditure in the country, i.e. the operating costs, taxes, etc.; – Foreign currencies to be converted and bought in the host country.

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5.2.4.5 Applicable law The applicable law is usually that of the host country. Where this national legislation is incomplete the contract can provide for the application of the more complete legislation of another jurisdiction, for example that of the state of Alberta in Canada (often referred to in petroleum contracts).

5.2.4.6 Responsibility The contract holder is responsible, with or without limitation, for any damage (including environmental damage) resulting from his petroleum operations, whether or not due to negligence or gross misconduct. The government and third parties have to be compensated for such damage. Where a consortium of companies is involved, these companies bear joint and several, rather than individual, liability. The contract holder is obliged to effect insurance.

5.2.4.7 Revocation of contract and withdrawal of rights A serious default on the part of the contract holder can lead, after a formal warning has been ignored, to the revocation of the contract and the forfeiture or withdrawal of the mineral rights (exploration licence or lease). Penalties may be specified for some infringements. Where such forfeiture is challenged the provisions relating to the settlement of disputes will apply.

5.2.4.8 Date of entry into force of petroleum agreements There are various options, depending on the country. The agreement may enter into force: – Immediately it is signed (in the case of an agreement signed by the head of State or the minister so authorised by the petroleum legislation); – After the announcement in the appropriate official journal of the signing of the contract (the contract itself may or may not also be published) or the granting of mining rights, in accordance with the petroleum legislation applying; – After government approval by decree; – After the agreement has been ratified by a law. This will be the case where an agreement signed by a minister or the national oil company involves departures from existing legislation or in countries which have not yet introduced petroleum legislation.

5.2.5

Gas clause

Natural gas can be produced either in association with crude oil (associated gas) or in its own right as dry or wet gas (non-associated gas). The production of natural gas has a number of specific characteristics: considerable and therefore costly infrastructure needed, the fact that it cannot be stored, special transport and distribution requirements, the need for a long-term and stable market. Special provisions are therefore included in contracts designed to facilitate gasfield development and production. As far as associated gas from a commercial oilfield is concerned, the usual procedure is as follows: • The natural gas is first used by the production facility for its own internal needs (as energy

source, re-injected for purposes of enhanced recovery, etc.). 192

authorities have been informed and, if necessary, have approved it. But flaring is more and more regulated to reduce the emission of greenhouse gases (GHG). • The State is entitled to use any natural gas destined for flaring for its own purposes,

without payment. Where a discovery of (non-associated) gas is made the following measures are usually taken to develop and exploit the discovery: • The deadline for declaring a commercial discovery can be extended, provided that an engi-

neering study and a preliminary feasibility study on the development of the discovery and the marketing of the production must be submitted to the authorities. These should demonstrate the commercial potential of the discovery. The deadline can often be extended by 3 to 5 years. • Either the authorities or the contract holder can decide at any time during this additional

period to develop the gasfield, the other party being free to participate in this development if it so wishes. • Economic and fiscal incentives may also be put in place in order to lower the commercial

threshold. Such measures have allowed small projects for supplying gas to local power stations to get off the ground in developing countries. In the case of associated gas, the purpose of such measures is ensure that the gas is only flared in certain conditions defined clearly in the agreement, and where there is no prospect of selling the gas. In the case of non-associated gas, these measures seek to prolong the exploration period, thus giving the contract holder more time to evaluate the commercial potential of the discovery and identify potential markets.

5.3 CONCESSION REGIMES 5.3.1

General framework

Under a concession arrangement the State grants the contract holder exclusive exploration rights (exploration licence), as well as an exclusive development and production right (lease or concession) for each commercial discovery. A contract established under a concession regime will contain the provisions described above. This may involve an actual petroleum agreement or simply the application of general and special conditions associated with the grant of an exploration licence or a lease within the framework of current petroleum legislation and accompanied by a schedule of conditions specific to the licence. The features which distinguish a concession agreement are the ownership of the hydrocarbons produced, the ownership of the production installations and the items of revenue to the State, and these three aspects are dealt with below. It should also be borne in mind that even where a legislative approach as referred to in Section 5.1.3 is taken, a concession comprises a contract in law, and this offers some protection to the holder in the event of subsequent changes in the petroleum law. 193

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• If the gas cannot be used by the production facility or marketed it can be flared once the

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5.3.2

The main features

5.3.2.1 Ownership of production Before they are extracted from the subsoil, hydrocarbons generally belong to the State. This State ownership of the subsoil and of the mineral resources is very common, and applies in most countries whatever the contract type (see Section 5.1.1). In a concession regime, however, the contract holder becomes the owner of all the hydrocarbons produced, subject to the payment of a royalty in kind (oil and natural gas) or in cash, from the time they are extracted from the ground and reach the wellhead.

5.3.2.2 Ownership of production installations Under a concession regime the holder owns the installations until his lease expires. When it expires the fixed installations usually revert to the State without compensation for the holder; the State is free to use them at its convenience if it considers this would be economically attractive. Alternatively the State can require the holder to remove at the latter’s expense some or all of the installations if it does not wish to use them. The holder is entitled to use the installations again for production from another discovery in the same country.

5.3.2.3 Items of revenue to the State Under a concession regime the State obtains its revenues through taxes. The main revenue categories are as follows: – Bonus (signature or production); – Surface fees; – Royalty on production; – Taxes on profits; – In some cases, excess profit tax. Petroleum legislation in different countries recognises, to varying extents, the contractual nature of a concession, so that the latter affords protection to the holder in the event of a change in the petroleum tax law. In most countries therefore, even where there is not actually a contract, some terms are fixed on the date the licence is granted (royalty, excess profit tax), but the taxation of profits is based on general tax law, and is therefore subject to change from time to time. There have, for example, been a series of reductions in tax rates in the 1990s in the UK, Norway and the Netherlands, and the petroleum industry has also benefited from these reductions. However, the UK has again introduced a specific petroleum tax which results in an overall tax rate increased to 50% in 2006.

5.3.2.4 Signature bonus Some concession agreements provide for the holder to pay a “bonus” on the date the contract is signed or the exploration licence is granted. This bonus is paid to the State in one or more instalments, and its amount varies depending on the contract, but can amount to several million or even hundreds of millions of dollars. This represents a major financial commitment for the holder, particularly since it is payable before production commences, and it will therefore have a fundamental impact on the profitability of the project. From the country’s perspective on the other hand, it represents a very attractive immediate lump sum revenue. Some countries do not provide for a signature bonus directly but award exploration licences on the basis of a bidding procedure. The payment made by the eventual holder 194

5.3.2.5 Exploration surface fees The holder may be required to pay annual surface fees to the State or other specified organisation proportional to the area to which the exploration licence applies. These fees usually remain fixed during each exploration period. Each time the exploration period is renewed these fees usually rise in proportion to the mandatory relinquishment. If, for example, the minimum mandatory relinquishment at the first renewal is 50%, the fees per unit area for the new period will double. The fees are also sometimes made subject to annual indexing. These fees are generally relatively small (typically between $1 and $10 per km2 per year), and do not impose a significant burden on the holder unless the area covered by the licence is very large.

5.3.2.6 Production bonus Production bonuses are one or more sums paid to the State which are triggered when certain production thresholds are reached on a field. The contract sets forth the sums to be paid when production first reaches certain levels (usually expressed in bbl/day) for a stated period. It can also provide for a “discovery bonus” to be paid. These production bonuses are very variable in magnitude, and depend on the oil potential of the country in question. Like the signature bonus, these bonuses can represent a commitment on the part of the holder of millions or tens of millions of dollars. Not all countries treat the signature and production bonuses in the same way for tax purposes. Some treat these bonuses as being deductible while others do not consider them to be deductible, thereby increasing their net cost to the holder.

5.3.2.7 Exploitation surface fees During the production from a commercial discovery the State can impose an annual surface fee on the holder proportional to the area over which the concession extends. This payment is analogous to the fees paid during the exploration phase. Since the area over which the concession extends is much smaller than that covered by exploration, the fees per unit area are much higher in the production than in the exploration phase.

5.3.2.8 Royalty on production A. Definition A royalty is an amount equal to a percentage of the value of production, paid by the holder to the State in cash or in kind. It is effectively a tax directly proportional to the value of production, that is a tax on turnover, and independent of profits. The amount of the royalty depends not only on the percentage applying, but also on a number of other parameters which must be carefully specified. 195

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following this procedure is analogous to a signature bonus, however. This procedure has been adopted when licences were granted in Federal zones in the U.S. Between 1986 and the end of the 90’s, the practice of paying a signature bonus has been declining, indeed has largely disappeared except in countries formerly closed to the direct involvement of the international oil companies, but which are now opening their borders. Representative examples are Venezuela, where very high bonuses were achieved in the first round of bidding for exploration blocks, organised in 1998, Brazil in 1999-2000, the JDZ between Nigeria and Sao Tome and Principe in 2004, Libya after 2000.

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B. Royalty rate The royalty rate is usually different for crude than for natural gas, the latter being lower. In order to ensure that the royalty is adapted to the characteristics of the field, a sliding scale is sometimes specified in the contract, depending on the production level. There are various options, including: – A variable percentage which depends on the daily or annual production (per well, per reservoir, per concession, etc.). In order to prevent abrupt changes in the calculated amount for small changes in production, the percentages apply to incremental production rather than the whole amount; – A variable percentage which depends on cumulative production since production began; – A variable percentage which depends on economic criteria such as the R-ratio between cumulative cash flow and cumulative investment. C. Ring-fencing or consolidation In cases where the holder produces from several concessions both resulting from the same exploration licence, there are two ways in which production can be calculated: – For each concession separately: the holder pays a separate royalty for each concession, and these are calculated separately; – For all the concessions together: the holder pays just one royalty, based on the total production from all the concessions. Where the percentage used to calculate royalties increases with increasing production it is obviously more attractive for the State to aggregate the concessions for the purpose of the royalty calculation, but the impact on the holder will be greater. D. Payment procedure and frequency The royalty can be paid in cash or in kind, as the State chooses. Payments are made quarterly or monthly. Where payment is made in cash, the calculated amount of the royalty will depend on the value placed on production, on the point at which the royalty is calculated and on the frequency of payment. E. Point of calculation Three points are possible: at the wellhead, at the point of departure from the field, or at the point of export or the point where it is made available for consumption in the host country. F. Value of production Production can be valued on the basis of: – The posted price or the price fixed officially by the State, practised historically but now rare; – The actual market price. G. Tax treatment The impact of the royalty for the holder will depend on the way it is treated for the purpose of profit tax, i.e. whether as a tax credit (practised historically, but now rare), or as a charge deductible from the holder’s taxable profit. 196

The royalty is independent of profit, and becomes increasingly onerous for the investor as the technical costs rise or the oil price falls. The 1990s have seen a tendency for royalties to be reduced or even dispensed with entirely in order to encourage new investment. The percentage which was once typically 20% is nowadays more likely to be in the range 0 to 12%.

5.3.2.9 Direct taxation of profits A. Consolidation of profits The holder is taxed directly on the profits from his activities in the country. The profit is usually calculated separately for exploration and production when the holder is also active in other petroleum activities such as transport, refining or the liquefaction of natural gas. In the same way as for the royalty, the profits of the holder can be calculated by aggregating all his exploration and production activities in the country or each concession can be kept separate (the latter case is referred to as ring-fencing). It is financially beneficial to the holder to consolidate together as many activities as possible as this allows him to set off his exploration costs under one licence against production revenue earned on another. B. Basis for taxation: revenues and charges The calculated revenue for the holder will depend on the value placed on all the hydrocarbons sold and any other revenues to be counted (e.g. the hire of installations to third parties, sale of by-products such as sulphur, etc.). On the cost side, deductible costs need to be defined very precisely: operating costs, depreciation, financial charges, specific provisions and other permitted deductions. Certain costs are shared with operating companies within the group but in other countries, e.g. head office costs which have to be shared between all its subsidiary oil-producing companies. These costs may also include the cost of technical assistance and non-resident personnel attributable to the petroleum operations. Straight-line depreciation is generally adopted, over a term of between 4 and 20 years, depending on asset type. Other possibilities include double declining balance or depreciation based on the unit of production. A list indicating the categories and depreciation terms for each type of equipment can be specified in the accounting procedure appended to the contract. Some countries allow the holder, by way of tax relief, to write off more than 100% of the total effective investment, by giving an investment credit, or uplift, of 20 to 50%. Other relevant matters include: – The rules applying to the creation of provisions, for example to cover abandonment or a depletion allowance; – The ability to carry forward losses for a number of years or even indefinitely. C. Payment procedure and frequency Provision can be made for the dates on which taxes are paid to be different from those applying under general taxation law so that the State receives its oil revenues without delay. The holder may for example be required to pay regular instalments of tax in advance based on provisional amounts, a balancing payment being made when the accounts are closed. 197

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H. Recent trend

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D. Tax rate The tax rate may be that set by general tax law or a specific rate may apply for petroleum activities. Historically, the rate was typically at least 50%, and could reach up to 85%. Over the 1990s there has been a trend for the rate to fall to a figure of about 30–40%. As already mentioned this trend has been reverted in some countries, tipically the UK with a figure of 50%. Some countries have introduced in the past, and still retain, a special additional tax which is levied over and above the normal tax.

5.3.2.10 Additional tax on petroleum profits Following the oil price rises of 1973 and 1979 it became apparent that the traditional concession, involving the payment of a royalty on production and a tax on profits, no longer met the requirements of the new economic context of the upstream petroleum industry. Various approaches, more or less satisfactory, were adopted in order to increase the oil revenues accruing to the State after the two price shocks, which took account of the oil price and/or the characteristics of the oilfield (see Section 5.6.1.4). Conversely, in the situation of falling prices after 1981 modifications were made to the tax regime applying to oil companies in order to encourage investment, as described in Section 5.6, involving greater flexibility and a more progressive structure. Since the early 2000s, some countries have re-introduced such kind of additional tax (Alaska, Ecuador, Algeria).

$

Years

Royalty Profit tax Net profit to company Depreciation Operating costs Development costs Exploration costs

Figure 5.1 Typical breakdown of oil revenues under a concession agreement.

198

5.4.1

General framework

The legal framework for the production sharing contract was devised by Indonesia in 1966, in a contract made between the national oil company Pertamina and an American independent, and a similar contract was developed in Peru in 1971. Since then very many countries have adopted this basis. Some are oil exporters: Indonesia and Egypt, where more than 100 contracts of this kind have been signed, but also Malaysia, Syria, Oman, Angola, Gabon, Libya, Qatar, China, Algeria and Tunisia. But the approach has also been adopted in countries which export little or no oil, such as Tanzania, the Ivory Cost, Mauritania, Kenya, Ethiopia and Jamaica. Several countries in Eastern Europe and the CIS countries have also adopted this system (see Section 5.1.8). The success of this formula in developing countries and the transition economies is due to several original features. Of interest, for example, are the nature of the contractual relationship (the oil company is not a direct holder of mining titles) and the concept of the “sharing” of production. Also noteworthy are the greater control that the State can in theory exercise over the activities of the oil company, which acts merely as a service-provider or contractor to the State. We shall see, however, that in practice the State can exercise as much control through a modern concession arrangement as in a production sharing contract. In both regimes the oil company bears the financial risk, and is generally responsible for running and performing operations under the supervision of the State. Some concessions may even be considered more restrictive than production sharing contracts, in terms both of operating the facility and the economics.

5.4.2

The main components

5.4.2.1 Principles In legal terms the role of the State in a production sharing contract is reinforced by the following two principles: • The State retains all the mineral rights and title, and therefore also owns the production.

This therefore creates a de jure State monopoly on hydrocarbon exploration and production. The oil companies act merely as service-providers or contractors. • Although the State or national oil company draws on the technical skills and financial

resources of the oil company (which lends or prefinances the necessary capital), it retains ownership of a large proportion of the production. The contractor may only receive the lesser share of production to meet his costs and remunerate him for his services. It should be noted that it is this share of the production which appears in the annual company reports and not the total reserves. This system is therefore based on the principle of production being shared between the State or national oil company, which owns the mining title, and the oil company (or consortium). The latter is the operator, responsible for funding and running operations, and it is remunerated, in kind, only where a commercial discovery is developed.

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5.4 PRODUCTION SHARING CONTRACTS

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5.4.2.2 Recovery of costs: cost oil The manner in which costs are recovered varies between countries, and within a given country between contracts and depending on the date of signature of the contract. Only the general principles will be discussed here. In a production sharing contract the contractor has the right to recover his costs by appropriating a proportion, not exceeding a certain percentage, of the annual production in the contract zone. This proportion is known as the cost oil. The balance not yet recovered is carried forward for recovery in the following year(s) on the same principle. The cost oil is valued using the market price of crude oil before being compared with the recoverable costs. The maximum limit on the cost oil is known as the cost stop, and varies, depending on country and the particular contract concerned, but is typically between 30 and 60%, although it can be as high as 100%. The value of the cost stop has a profound effect on the economics of the project. The higher it is, the faster the contractor can recover his costs and the better the return on his investments. However the formula by which costs are recovered has gradually become more complex, as can be seen from the following provisions which have been introduced in some contracts: • Investment credit (17% in Indonesia, between 33.3 and 40% in Angola): in the former

case, for example, the contractor can recover 117% (rather than 100%) of his capital costs; this is designed to compensate him for the effect of inflation (recovery is in practice based on nominal value, without indexation). • Spreading the recovery of development costs over time: equivalent to a system of straight

line depreciation over a period of 4 to 5 years (Angola) or a double declining balance system (Indonesia). • More precise definition of recoverable petroleum costs:

– Whether or not bonuses and interest and financial charges are excluded; – Priorities for recovery of different cost categories (exploration, development, production, other); – Recovery of joint costs shared between the members of a consortium and the costs incurred individually for each of these members; – Methods by which costs are split between development zones if successive discoveries are developed. Production sharing contracts do not generally provide for the payment of a royalty on production, but where a royalty is paid, the cost oil is calculated on the production remaining after the royalty.

5.4.2.3 Sharing of production (profit oil split) The proportion of the oil left after deduction of the cost oil is known as the profit oil. The way the profit oil is shared between the State and the contractor has changed substantially over the last 35 years. Originally production was split on a fixed basis, negotiated per contract, independent of the characteristics of the discovery. In Indonesia, for example, the 65–35% split between government and contractor was changed to 85–15% for oil in 1976, but remained 65–35% for natural gas. These were the effective rates after payment of taxes on profits. 200

$

Years

Profit oil (State) Profit oil (Company) Cost oil (recovery of capital costs) Cost oil (recovery of operating costs) Development costs Exploration costs

Figure 5.2 Typical breakdown of oil revenues under a production sharing contract.

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Later, progressive sliding scales were introduced which depended on the daily production rate, for example progressive sharing rates increasing from 50–50% for low production rates to 85–15% for the top tier of production. In 1979 Angola introduced a progressive scale based on the accumulated production from an oilfield. These scales depend on the characteristics of the discovery and in particular, the environment (onshore, shallow or deep offshore). Some countries have adopted adjustment mechanisms which allow for changes in the price of crude (price capping). The government share for that part of the price which exceeds the price cap, which is indexed, may be as high as 100% (for example Angola, Malaysia, Peru and Indonesia before 1978). In 1983 a number of countries introduced new production sharing mechanisms, based not on the daily or accumulated production but on the rate of return (or some other measure of profitability) to the contractor on a given date. The countries involved were: Equatorial Guinea, Liberia (sharing according to the rate of return), India, Libya, Tunisia, the Ivory Coast and Azerbaijan (sharing according to the R-ratio, which seems to be a more acceptable basis, see definition in Section 5.6). There are quite large variations in the profit oil split between different countries and contracts. These reflect differences in the perceived petroleum potential and costs, the latter being directly linked to the characteristics and the location of the discoveries. The possibility of adapting the terms of a production sharing contract to the potential exhibited by a discovery is one of the advantages, and therefore explains the success, of production sharing contracts compared with concession, where there is less flexibility during negotiations.

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5.4.2.4 Taxation of profits To compare different production sharing contracts the treatment of taxation of profits needs to be considered. In production sharing contracts concluded up until 1976 the profit oil split was deemed to be calculated after tax, so that the contractor was not subject to an explicit tax on profit. His share was net of tax, the latter being assumed to be included in the government’s share. The contractor nevertheless received a tax return corresponding to this fraction. He was therefore able to deduct this sum from his tax liability in his country of origin thereby avoiding double taxation. In 1976 the U.S. Internal Revenue Service (IRS) stopped allowing the notional tax payment to the State as a tax credit. This led, at the request of the American companies, to a change in the simple form of the original production sharing contract. This involved the introduction of a separate procedure for determining the tax on profit, using the general rules for the taxation of commercial and industrial companies in the host country. This procedure did not apply to European companies. As a result, the profit oil split negotiated in contracts was revised to a before-tax basis. The impact of this measure where the tax rate is 50% is as follows. Consider an after-tax profit oil split of 70–30% between State and contractor. The 70% received by the State is deemed to include 30% representing taxes on the contractor’s profit, because the 30% the latter receives is free of tax. The corresponding before-tax split is therefore 40–60% between State and contractor. The contractor then has to pay tax on his 60%, i.e. 30%, so that his net remuneration is equal to 30% of the profit oil. The State’s share is 40% plus 30%, i.e. 70%. This rough calculation assumes that the depreciation used for tax purposes is precisely the same as that adopted for the recovery of the petroleum costs, which is not always the case in contracts. There are therefore some differences between the two sharing systems in terms of the timing of the tax payments due to the State. In the above example, if the tax rate is 50%, a before-tax profit oil split of 40% (State)–60% (contractor) is similar to an after-tax split of 70%–30%. The IRS subsequently adopted a more flexible attitude, so that American companies can opt for either basis.

5.4.2.5 Availability of production In contrast with a concession system, the contractor only has access to a proportion of the production equal to the cost oil plus his share of the profit oil. Furthermore the State is free if it wishes to take its share of the profit oil and market it. This is an advantage when there is a national oil company in existence.

5.5 OTHER CONTRACTUAL FORMS 5.5.1

Service contracts

These are contracts made by the national oil company in producing countries which allow oil companies to carry out petroleum exploration, development and/or production on their behalf. Service contracts are used mainly in the Middle East and Latin America, but their use is not widespread. Two categories of service contract exist, depending on the degree of risk borne by the oil company: 202

The terms and conditions of service contracts are very variable. The main provisions are summarised below.

5.5.1.1 Risk service contracts These are a time-honoured form of contract between producing country and oil company for exploration and production, originating in countries where oil was nationalised or where the national oil company was granted a monopoly, such as Argentina, Brazil, Indonesia, Iraq and Iran. This form of contract could enjoy a renaissance in those Gulf OPEC countries wishing to increase their production capacity, which may turn to the oil companies for their technical know-how and financial resources. It is the case of Iraq with the signature at the end of 2009 of different service contracts with companies like ExxonMobil, Shell, BP, CNPC, ENI, Occidental, Gazprom and Lukoil. A service contract is a contract by which a contractor undertakes to explore for hydrocarbons at his own risk and expense on behalf of a national oil company, and by which he is reimbursed for the costs he incurs and remunerated in cash depending on the success of the exploration. All production accrues to the national oil company, although the contractor may be able to purchase some of this production on agreed terms. The contractor runs the operations under the control of the national oil company, which may become the operator when development or production commences. The national oil company owns the installations, but the foreign company has the right to use this infrastructure. The fundamental difference between the risk service contract and the production sharing contract is that the contractor is paid in cash rather than in kind. The contractor is therefore not able to market the hydrocarbons extracted.

5.5.1.2 Buyback contracts This type of contract was introduced in Iran in the specific context of that country. The Iranian constitution does not allow petroleum rights to be granted in the form of concessions. However some relaxation in this position was made by the Petroleum Act of 1987 which permits contracts to be concluded between the Ministry of Petroleum, national companies and local or foreign companies or persons. Conoco concluded the first agreement in March 1995, relating to the development of the Sirri A and Sirri E oilfields. Following the cancellation of this agreement by the American government, the project was taken over by Total, and a new agreement was made in July 1995. These are risk service contracts in which the investor meets all the capital costs, recovers the costs incurred during production and receives a fixed remuneration, negotiated before the contract is signed and independent of any fluctuations in the price. The duration of the contract is limited to two short phases: a development phase followed by a cost recovery and remuneration phase. The total duration of the contract is 4–6 years. The timetable, the programme and the value of works are fixed in a master development plan appended to the contract. The operations are supervised by a joint management committee 203

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– Risk service contracts (or agency contracts) in which the contractor only recovers his investment costs where a project proceeds to production; – Technical assistance or cooperation contracts, which are non-risk-bearing, carrying out works on the basis of an agreed remuneration.

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comprising three representatives of each party, the National Iranian Oil Company (NIOC) becoming the operator when operations start. A proportion of the expenditure must be allocated to local sub-contractors. These contracts present investors with a number of specific constraints: they are short-term contracts, fairly inflexible during the development phase, in which the plan must be followed very closely. The share devolving to the contractor is relatively small, and they do little to bolster his reserves. In addition the fact that the remuneration and the cost of the investment are fixed at the moment the contract is signed introduces an element of risk which has to be managed. It is why some investors have decided to refuse any new buyback contract. Given that, modifications may be made in the future by the governments.

5.5.1.3 Non-risk-bearing technical assistance or cooperation contracts In this type of contract the contractor does not bear the risk and does not finance the project directly. He receives a fee for services rendered. This fee can be related more or less closely to the results. Technical assistance contracts relate mainly to the resumption of production from fields under depletion, and sometimes to development activities. The funding is provided entirely by the State or its national oil company, and not by the contractor. Examples of assistance contracts include: – Contracts to provide assistance with oil production, awarded by countries which nationalised their petroleum industry in the 1970s, such as Saudi Arabia, Kuwait, Qatar and Venezuela; – Contracts by which countries of the former Soviet Union and Eastern Europe provided assistance to developing countries up until the late 1980s, such as Cuba, India, Pakistan, Yemen and Ethiopia; – Association agreements for the development of new fields on behalf of a national oil company, for example in Abu Dhabi, India and Benin. It should be noted that some technical assistance contracts give the contractor the right to purchase a proportion of the oil produced. The contractor is usually subject to the tax law (profit tax) of the host country.

5.6 IMPACT OF THE ECONOMIC RENT SHARING ON EXPLORATION AND PRODUCTION ACTIVITIES 5.6.1

Flexibility and investment incentives

5.6.1.1 Specific nature of each exploration and production project Petroleum exploration/production agreements are an expression of the commitment on the part of the signatories to seek to develop the hydrocarbon resources in a given geographical zone having specific characteristics. Many provisions in a contract are independent of the characteristics of the zone to be explored. These include, for example standard legal provisions, matters relating to the conduct of onshore or offshore operations and the keeping of accounts. On the other hand there will be a number of clauses which take account of the specific characteristics of the zone to be explored: exploration risk, type of hydrocarbons, location, 204

These issues will be the main focus of attention in the negotiations and the decisions taken by oil companies when entering into a contract or licensing arrangement. Fiscal and contractual provisions designed for a particular zone or in particular market conditions cannot simply be transplanted without modification to other zones. A contract, and more generally a rent-sharing arrangement, must be suited to the context, and be sufficiently flexible to accommodate expected and unexpected changes. Incentives can also be introduced to foster investment in special zones such as unexplored basins, deep offshore, remote onshore locations, the Arctic, rain forest or the desert. Incentives may also facilitate the development and exploitation of natural gas fields.

5.6.1.2 Lack of flexibility in traditional contracts and tax systems Traditional contracts and tax systems here refers to either a concession regime with a fixed royalty rate and a tax on profits or a production sharing contract with a fixed rate of profit oil split. In both these cases the return to the oil company and the State’s oil revenues vary considerably depending on the characteristics of the field which directly affect costs (location, size of reserves, well productivity), and hydrocarbon prices. The commercial viability of a discovery of hydrocarbons is very sensitive to parameters of this kind. Simple economic simulations show that there is a gearing effect associated with the traditional systems with fixed rates. Less favourable cases are shown in an unduly harsh light, while the attractiveness of more favourable projects tends also to be exaggerated. In the case of a “marginal” discovery the unit technical costs are usually high, and the expected return may be adjudged too low. And conversely, in the case of larger discoveries with lower unit technical costs, the expected return may appear high, or very high where the reserves exceed certain levels. This can lead to an imbalance in the sharing of the profits between State and operator, making subsequent negotiations necessary to find a fairer basis. Producing countries realised that contractual and fiscal regimes needed to be devised which properly addressed these different scenarios. Most countries have gradually adapted their fiscal systems to make them more flexible, introducing systems which are often original, but are also increasingly complex and multi-staged. Practical difficulties have arisen in implementation, computational methods and audit which were not foreseen when they were conceived, but which have often necessitated adjustments to the new contracts. The mechanisms used are reviewed below.

5.6.1.3 The objectives of a flexible system In economic terms, the tax formulae and parameters relevant to the sharing of the economic rent need to be able to deal with two contrasting scenarios. 205

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existing infrastructure, level of costs, etc. These clauses will also have regard to the international oil market, both at the date of signature of the contract and in terms of anticipated developments during future production. They relate to the following aspects: – The duration of the exploration programme, the area to which the licence applies and the relinquishment terms; – Minimum exploration work or expenditure obligations; – The basis for sharing the economic rent between the State and the contract holder; – The conditions for the disposal of the production.

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Firstly, they need to be capable of improving the economics of marginal discoveries, which are becoming increasingly common, so as to encourage oil companies to explore and develop. This involves the State being willing to assume part of the risk and give up some potential short-term revenue. This short-term loss will be offset by long-term benefit, however, because activities are generated which would not otherwise have occurred. This trade-off between the long and the short term is a crucial political choice for a country. The second need is to prevent the company from reaping excessive profits, i.e. which go beyond the limit of acceptability. In this case the State share of the revenues needs to be increased. But at the same time the regime must be careful not to discourage investors by removing any prospect of a healthy profit commensurate with the risks run. During the period 1973–1981, when crude prices were rising, there was a swing in most countries, both industrialised and developing, towards the second objective. This period saw the introduction of excess profit taxes on petroleum additional to normal taxes or profit oil splits moving in favour of the State. But circumstances have moved on since that time. There were two subsequent new developments, already referred to earlier: a steady decline in prices during the period 1981–1986 followed by a period when prices were volatile but fluctuated widely around a fairly moderate price until the end of 1998; and increased opportunities in countries formerly closed to the international oil companies, particularly since 1990 in the CIS countries and Eastern Europe, but also Latin America and the Middle East. There has been a steady shift in the approach of the two parties during this period: investors have gradually come to accept the principle of a high State take in the event of exceptional profits, and conversely host countries are conceding that they need to reduce their take in order to foster less profitable projects or compensate for a reduction in oil prices. The sustained level of high oil price since the early 2000s has resulted in exceptional profits, so that a growing number of producing countries have claimed a higher state take and have introduced relevant contractual and fiscal provisions to reach this objective.

5.6.1.4 Instruments for flexibility in concession regimes A. Progressive rates of royalty on production A fixed rate is replaced by a rate increasing progressively to reflect: – Annual production; – Type of location (onshore, shallow offshore, deep offshore); – The date of discovery (old oil, new oil); – The type of hydrocarbons (crude oil, natural gas); – The effective return on the project (such as a profitability ratio recalculated each year, a rare system introduced in Tunisia in 1985). As was stressed in Section 5.3.2.8, the royalty on production can have a considerable economic impact, even if progressive in structure, because it is a tax on turnover. Some countries have therefore taken the radical decision to dispense with royalties altogether in certain conditions. For example for oilfields where the annual production is below a certain threshold or, as in Norway, for all fields declared commercial on or after 1 January 1986, whatever their production turns out to be. This measure was taken when a rather pessimistic view was being taken about the prospects for crude prices, and was intended to revive activity in Norway by encouraging the development of marginal oilfields and satellites of existing oilfields. 206

These can take the form of investment credits, depreciation uplifts or a variety of other devices which reduce the tax burden falling on the companies. This category includes the consolidation for tax purposes of all the exploration and production activities in a particular country rather than ring fencing each concession. This allows the holder to offset his exploration costs at one location against his revenues arising from production at another. This amounts to an indirect subsidy by the State, and the higher the tax rate the greater the value of this tax relaxation. C. Progressive profits tax rate This mechanism is fairly rare. It was introduced in Tunisia in 1985, for example, where a progressive tax rate applies depending on a profitability ratio recalculated each year, like the royalty. The complication lies in the fact that the scale is not the same as that established for the royalty and, what is more, is different for oil and gas. Another possible incentive is to allow a temporary exemption from profit tax during the first years of production. D. Progressive rates of participation by the State The rate of participation by the State can also be made progressive, depending on the same types of parameter as those mentioned for royalties. E. Excess profit tax As already mentioned in Section 5.3.2.10, many countries introduced this tax in various guises in the 1980s: the “Special Tax” in Norway, the “Petroleum Revenue Tax” in the United Kingdom, the “Windfall Profit Tax” in the U.S. and the “Exceptional Levy” in France. The adoption by OPEC countries of higher rates of taxes on profits —up to 85% in some countries— can also be regarded as an excess profit tax. These instruments have an impact on the profitability of the holder, but experience shows that they are not sufficiently selective in achieving the necessary objectives. They are in fact based either on the excess of the oil price over an indexed base price (in the case of the windfall profit tax) or on a pseudo-profitability criterion calculated on a purely accounting approach (the petroleum revenue tax) rather than being based on the true economic profitability of the operations in question. Because of these considerations, some countries —Papua New Guinea (1976), Madagascar (1981), Somalia (1984), Guinea-Bissau (1984), Senegal (1986), Australia (1988) and Namibia (1991)— have introduced a “resource rent tax”, calculated directly from the effective profitability of an exploration and production project. Most of these instruments ceased to operate after prices fell to levels well below those applying in the 1980s. However with the increase in oil price, they may be automatically reactivated. As already mentioned, some countries have re-introduced this kind of excess profit tax (UK, Alaska, Ecuador, Algeria).

5.6.1.5 Instruments for flexibility in production sharing contracts Because of the principles which underlie it, it is easier to modify the terms of a production sharing contract than those of a concession. This can be achieved by modifying the cost 207

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B. Investment incentives

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recovery mechanisms and defining a sliding scale for the profit oil split, because the parameters concerned are the result of a negotiation process rather than being enshrined in the law. A. Modifications in cost recovery mechanism This can involve: – Adopting a variable cost stop; – Modifying the period over which investments are recovered; – Introducing an investment credit or uplift similar to that described in relation to the concession system. B. Modifications in the profit oil split A fixed profit oil split is an overly rigid instrument which is only appropriate in zones where operating costs remain practically constant. Using the same concept as mentioned earlier, this parameter could be based on a sliding scale which increases with the annual production or the cumulative production from an oilfield. This mechanism would represent a worthwhile improvement, provided a significant relationship can be established between the production level and the potential return to the contractor, which is not always possible. This system does not allow changes in the price of oil to be taken into account directly. The introduction of a price cap increases the share accruing to the State when the price of oil rises beyond a certain threshold, indexed to allow for inflation: this device is found in certain contracts in Angola and Malaysia. There are various types of mechanism which allow a linkage to be established between the share accruing to the contractor and the effective profitability of his operations, as follows: • The introduction of an excess profit tax (as described for concession) which the contractor

pays in cash on his share of the profit oil, the latter being determined using the same rules as for a conventional shared production contract (Tanzania, Trinidad). • The profit oil split can be made a function of the effective rate of return. In the early years

all production with the exception of a small deduction for the State can go the contractor. The State share then increases progressively in a manner similar to that described for concession. This device has been adopted by two countries, i.e. Liberia and Equatorial Guinea, but did not achieve the success hoped for because of difficulties in putting into effect the necessary calculations. • The profit oil split can be made a function of a profitability ratio, or “R-factor”, calculated

each year as the ratio of the contractor’s cumulative net revenue to his cumulative investments. The amounts are calculated each year, and accumulated from the first year of the contract. The contractor’s share of the profit oil reduces as the R-factor increases according to a scale set forth in the contract. Unlike the device described previously, and even if the calculation and auditing procedures need to be defined precisely, the latter is far less difficult to implement. This instrument has therefore enjoyed increasing success and has been adopted, for example, in the following countries: India (1986), Egypt (1987), Ivory Coast (1990), Algeria (1991), Libya (1991), Nicaragua (1998), Peru (1998) and Cameroon (2000).

5.6.2

Comparison between systems

Comparing different systems of sharing the economic rent is a delicate business, involving several difficulties. In particular, the economic calculations which underpin them are often 208

• Between 30 and 50%: Argentina, Colombia, US (Gulf of Mexico), Ireland, Morocco, New

Zealand, Peru, United Kingdom; • Between 50 and 75%: Angola (Deep offshore), Australia, Cameroon, Egypt, Ecuador,

Gabon, India, Indonesia, Malaysia, Russia, US (Alaska); • Over 75%: Algeria, Bolivia, China (offshore), Iran, Libya, Nigeria, Norway, Oman,

Yemen, Trinidad & Tobago, Venezuela. In this category, Iran (buyback contract), Libya and Venezuela are around 90%. Some countries appear in different categories because they offer different terms for different zones. The countries in the first category are largely industrialised countries which are producers and consumers, and whose economies are not greatly dependent on their upstream oil activities. The second category is the most numerous, and comprises a heterogeneous group of countries with modest or moderate production, with petroleum policies which depend on their level of development. The countries in the third category are producing, and in many cases exporting, countries whose economies are highly dependent on these activities. There is increasing competition between countries to attract investors and to offer attractive conditions. A token of this is the periodic revisions which countries make in their legislation, tax regimes and contractual arrangements. This was exemplified by Cameroon and Morocco, which made major changes in their systems in 2000. Morocco introduced tax incentives, and is hoping to be able to attract deep offshore activity to its shores. Cameroon made sweeping changes to its systems, and also provided incentives to attract renewed exploration so as to reverse the downward trend in its production. 209

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made on a stand-alone basis, with no allowance for the possibility of consolidation with other activities in the country or region. Furthermore the technical conditions prevailing in one country may not be reproduced in another. And finally, the fact that the contracts tend to be strictly confidential does not make it any easier to get data; those obtained from indirect sources may not be reliable. While bearing in mind the reservations described in the foregoing, it is possible to rank the relative severity (from the investors’ point-of-view) of the economic rent sharing systems throughout the world by reference to the simple criteria of the total Government take. This parameter is expressed as a percentage. The word Government is taken in its widest sense, including any national petroleum companies with a participation in the petroleum operations. The calculation is performed for the simulated total duration of exploration and production. It should not be confused with the marginal Government take, calculated after all investment costs have been written off or recovered, and which is higher. A high value for this percentage corresponds to a basis which is favourable to the State and harsh for the investors. Obviously whether or not a system is harsh depends on the petroleum potential of the country. However activity levels are not necessarily inhibited by a severe system as long as the country in question has a well demonstrated potential or is very prospective. On the other hand countries with little or no production, or where production is declining and which are not able to renew their reserves, have no choice in the current very competitive environment but to try to entice inward investment into the country by offering an attractive package. To illustrate this, a number of countries with diverse backgrounds are classified below according to the State take. The classification is approximate, and more careful analysis might lead to some changes.

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Conservely, producing countries with expected additional upsides, have recently introduced revisions aiming at increasing the State take.

5.6.3

Perspectives

In order to assess fully the upstream petroleum activities, it is vital to have knowledge of the legislative, fiscal and contractual framework alongside the technical side and results of appraisal of the petroleum potential. These aspects lie at the heart of the relationship between petroleum-producing countries and investors, and play a crucial part in determining how the economic rent is shared. The objective is to try to optimise the benefits for both parties. On the basis of a number of relatively simple principles, universally accepted by the international community and of a number of systems usually adopted by countries, this chapter has outlined the huge diversity of instruments possible, both regulatory and economic. The terms offered by countries have evolved in response to a whole range of technical, economic and political parameters. Over the last twenty-five years international exploration and production have become quite competitive. New regions once closed to international investors or inaccessible within the technological constraints then applying have been opened up, thereby considerably increasing the choice of countries for possible investment. The oil companies have then become more selective because of budgetary constraints when prices are low, and there has at the same time been a reduction in the number of oil industry participants as a result of mergers and acquisitions. These large corporations apply different criteria with regard to the required return on investment from those used by the smaller independent companies. One consequence of the increase of the prices is a trend followed by the independent companies to invest in risky new areas when they made significant discoveries like Tullow in Uganda, Kosmos Energy in Ghana and Noble Energy in Israel. It seems likely that the trend towards increased competition between actual and potential hydrocarbon-producing countries will continue, resulting in still more flexible tax regimes and contracts. This tendency is particularly discernible in regard to exploration and production in more challenging environments. However competition also exists between oil companies which need to secure and renew their reserves. In parallel, established producing countries wish to benefit from the sustained increase in oil price, so that they have introduced new contractual and fiscal provisions to increase the global State take. Not all countries are in the same boat, however, or carry the same weight on the international scene. It is to be expected that a number of countries which still have enormous potential —Saudi Arabia, Iran, Iraq, Kuwait and Mexico— will open up to the international industry.

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6

Decision-making on exploration and production

The petroleum sector is a capitalistic industry par excellence, and investment decisions in the industry are absolutely crucial. This chapter therefore deals with the evaluation of capital projects. Our object is not to provide the reader with a potted manual on project evaluation, but rather to address a number of topics specific to the upstream petroleum industry, while recalling a number of more general principles. We shall begin by introducing the concept of strategic analysis which will help to establish the main constraints within which the project evaluation will be performed. We shall then touch briefly on questions which arise in connection with short-term decision-making, before turning to the techniques for estimating the return on capital. In this connection we shall first discuss deterministic methods before addressing, in the last section, the topic of risk analysis and decision-making under conditions of uncertainty.

6.1 STRATEGIC ANALYSIS AND DEFINITION OF THE OBJECTIVES OF THE COMPANY The strategies of many smaller enterprises are based purely on the intuition of senior management. Most large oil companies, however, use systematic procedures to determine the broad lines of their strategic orientation, and to illuminate the context in which decisions are taken on large investment projects. In so doing, use is made of a range of well established concepts and methodological tools, such as M.E. Porter’s analytical framework, BCG (Boston Consulting Group) matrices, etc. In this section we shall present a number of methodologies used in the upstream oil industry, before going on to consider briefly how oil companies organize their strategy departments and strategic thinking.

6.1.1

Understanding the environment in which the company is operating

In order to define the strategic options it is obviously necessary to have a good understanding of the environment in which the company is operating. One of the missions of the department 211

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in charge of strategy is therefore to monitor constantly and analyse the markets for crude price behaviour, the relationships between the participants, the political risks, etc. These elements were touched on in Chapter 1, and we will not dwell on them further here. Visions of the medium and long-term future are often expressed in the form of scenarios. Shell has established a reputation in this area which goes back many years. Where a comprehensive scenario is not available, it is necessary to specify a number of reference hypotheses so as to ensure the consistency of the analyses carried out by the different sectors of the company. Particularly important amongst these assumptions are those relating to technological development. While forecasts are difficult in this area, they have a major impact on a certain number of options. A decision to develop interests in natural gas inevitably involves making forecasts of future demand and the way the market will evolve. But it will also depend on the anticipated reduction in the costs of liquefaction and transport. Similarly, companies involved in producing extra-heavy oil in the Orinoco Belt were not simply betting on the eventual scarcity of “conventional” oil. They were undoubtedly also banking on future processing improvements, and therefore on better recovery rates and reduced production costs for resources of this kind in the future.

6.1.2

Strengths and weaknesses

Opportunities are usually identified by comparing the proposals of the operating companies in the group with analyses of the external environment. A “strengths and weakness” analysis is then carried out, both for the competitors and for the company itself. It is usually carried out for each separate business, and relates to all the factors which affect competitiveness: technology, finance, human resources, organizational aspects and political factors. In looking at competitors, their intentions also have to be analyzed. While some are very clear to see, others are only revealed by a closer scrutiny of their activities. The numbers of patents applied for may be an indication of technological preoccupations, while acquisitions, divestments and changes in shareholdings may provide indications of orientations, a refocusing on core activities or geographical diversification. Presentations made at road shows may also be a source of information. “Know thyself” enjoined Socrates. It is difficult to be objective about one’s own strong and weak points. A team which has proven its worth in one country may not necessarily be the most effective in another country or environment. This notwithstanding, it is obviously of crucial importance to assess critically one’s own company.

6.1.3

The portfolio of activities

In exploration/production the maturity of a sector is undoubtedly a more relevant criterion than market share. In seeking a balanced portfolio a company may follow the Boston Consulting Group in seeking balance not between products but between sectors of activity or project types. To preserve viability in the long term, the portfolio needs to include activities which may not justify themselves on the basis of present profitability only, but which may become profitable in the future as a result of changes in technology, markets, regulations, etc. Deep offshore may therefore be regarded as a “star”, certain high-risk countries may be viewed as “question marks” or even as “dogs”, while the “cash cows” are well known: these are the projects which allow the company to participate in pioneering projects without putting it in financial jeopardy. 212

The desire for a balanced portfolio is also based on considerations of risk, one of the objectives being to reduce the overall risk associated with the portfolio through diversification. This is one of the reasons why oil companies have long collaborated with one another on projects. Generally speaking it can be assumed that there is no correlation between the technical/geological risks, or more generally the risks related to the size of the reserves, for different projects. By increasing the number of projects we therefore reduce the risks for the portfolio as a whole. It should be noted, however, that increasing the number of projects does not entirely reduce the risks associated with variations in the price of oil because nearly all oil projects (that is, with the exception of projects governed by service contracts) are sensitive to price fluctuations. But this sensitivity can vary significantly between zones, depending on the cushioning effect of the tax regimes in place. The practice of sharing capital costs between competitors is characteristic of the upstream oil industry, and is not common in other industries.

6.1.4

Alliances

Although risk reduction is the most common reason for the associations observed in most large projects, political motivations should also be mentioned. The inclusion of certain partners can sometimes provide an “insurance policy”, contributing decisively to the successful realisation of the project. Total’s choice of partners in Iran was probably not based purely on economic considerations, but also on a desire to reduce the political risk. In general terms, and quite apart from mergers and acquisitions, strategic alliances provide a way of acquiring new skills and can provide an entry ticket into new activity sectors or countries. A particular focus in recent years has been the alliances between international corporations and national companies in producing countries.

6.1.5

Strategy Department: organisation and functions

The organisation of this department can vary greatly between one group and another, and we confine ourselves to a number of observations. Responsiveness is a very important attribute for success. A significant proportion of the opportunities in the upstream oil sector need to be grasped fairly quickly, either for political or economic reasons. The organisation should therefore be geared up to take rapid decisions, whether mainly at operating company or at group level. Most “strategic” projects are in new zones or activity sectors. The latter are analyzed by a central group (which may, as in the case of BP, be non-hierarchical), whose role is more than merely to coordinate. A medium-term plan is usually constructed, bearing in mind that planning should not be regarded as inconsistent with flexibility. The plan for the group is obtained by aggregating together and synthesizing the plans prepared by the different subsidiaries or operating units.

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In this connection, the fact (actually self-evident) is that that it may be necessary to venture beyond the confines of exploration and production activities to take full advantage of foreseeable developments. The acquisition of refining and even distribution interests may make it possible to gain a foothold in a producing country about to open up its upstream activities to international companies. It was undoubtedly this desire ultimately to gain access to the upstream oil industry that explained why so many companies expressed interest in the gas projects announced by Mexico and Saudi Arabia in 2000 and 2001.

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The preparation of these plans creates a channel of communication between head office and the other companies in the group. The latter enter into commitments in some areas and, in other areas, propose options for possible changes. The selection criteria and project analysis tools are determined by the Strategy Department in consultation with the Finance department: discount rate, techniques for analyzing risk, project briefs, resource allocation when capital is rationed. There will be one or more sets of macroeconomic hypotheses associated with these criteria and the way they are applied, in order to ensure overall consistency.

A crucial tool in the evaluation of projects is the discount rate or rates, and determining this rate for the company is therefore of particular importance. Its value cannot be derived by mechanically calculating the cost of capital, which is in fact never defined very precisely. The use of a relatively high discount rate tends to result in a “creaming” of projects. It reduces the likelihood that projects will turn out post hoc to be unprofitable, but leads to opportunities being rejected which may be grasped by the competition. On the other hand setting the discount rate to the lowest possible value consistent with the data on the cost of capital will tend to foster development and increase market share. This can be compared with the strategy adopted by Shell, which has grown more rapidly than Exxon in recent years. The latter, on the other hand, has obtained a better return on its capital, preferring to buy back its own shares rather than invest in projects not offering the desired return. In setting its discount rate a company is therefore also expressing its own strategic orientations. This is true at the level of a single company, but also for each sector of activities within a group. The petroleum sector therefore often uses different discount rates for different categories of activity, even within the exploration/production sector. These discrepancies may be due to differences in the financial methods applying, to differences in the risk profile, but may also be an expression of strategic decisions: setting a high discount rate acts to limit investment budgets. On the other hand, setting a relatively low discount rate can be a way of factoring other indirect benefits into the equation. When oil companies were integrated, for example, some companies used to use low discount rates for downstream projects in order to promote the development of the refining sector and distribution networks. This was justified not in terms of the profitability of these activities but in terms of the access it gave to outlets for crude production. More generally, adjustments in the discount rate can be used as a means of balancing an oil companies portfolio of activities.

6.2 ECONOMIC EVALUATION (DETERMINISTIC) AND SHORT-TERM DECISION-MAKING Before getting on to the appraisal of investment projects, we shall review in this section some of the analytical principles of short term decision-making. Decisions during the operating phase usually only have a short-term effect (one year, for example), and therefore generally do not involve complicated methodological issues. They may involve risk analysis and probabilistic calculations, but questions of this kind are considered in Section 6.4. We shall confine ourselves here to deterministic calculations, that is we either assume that the consequences of a particular decision are perfectly known or we make use of one or more defined scenarios representing possible futures. This being the case, the economic analysis is, broadly speaking, limited to making a comparison of the expenditures and revenues involved for the different possible options. But 214

Table 6.1 Polymer injection. Quantity of fluid injected (103m3)

25

32

40

49

60

70

73

Quantity of oil produced (10 bbl)

27.7

33.8

40.0

47.5

55.7

61.0

62.0

Cost ($ ‘000s/year)

383

500

585

660

745

840

880

CM ($/bbl)

13.8

14.8

14.6

13.9

12.9

13.8

14.2

3

Cm ($/bbl)

19.2

13.7

10

10.4

17.9

40

These data can be used to construct the graphs in Figure 6.1 which show how the total cost, average cost and marginal cost of the crude produced by secondary recovery vary as a function of the additional quantities recovered. • Marginal cost

Cm =

dC dQ

• Average cost

CM =

C Q

Assume the wellhead price of crude, P, is $15/bbl. If P is independent of the volume of production then the marginal calculation is very simple: when the quantity injected is low, the marginal cost is less than the sale price. This means that it is worthwhile to increase the volume injected, so increasing production. This can be increased as long as the marginal cost Cm is less than the sale price P. Production is optimized when Cm = P. Injection will be employed if it makes a positive contribution to profits, that is if the average cost is less than the sale price. In accordance with the theory1, we note that the average cost CM is a minimum when Cm = CM. If the wellhead price of crude is $15/bbl, then profits are optimised for an additional production of crude of about 57 000 bbl/y, obtained by injecting a volume of approximately 62 000 m3. The average cost of the additional crude will be of the order of $13/bbl, less than 1. The mathematical demonstration of this property is simple, and relies on marginal reasoning: when the marginal cost is less than the average cost, i.e. Cm < CM, the cost of a small increment in production will result in a reduction in the average cost. On the other hand when Cm > CM the average cost increases.

215

Chapter 6 Decision-making on exploration and production

many of the decisions which need to be taken correspond to modifications which may be made “at the margin” of a production programme. These decisions can be usefully analyzed by a “marginal analysis”, a practice we all use, whether or not we realize it! This can be exemplified by considering a problem of secondary recovery by polymer injection during the last year or years of production of a reservoir. The problem is to decide on the quantity of fluid to be injected. Table 6.1 shows the quantity Q of crude oil which can be recovered as a function of the quantity of fluid injected, and therefore of the corresponding cost C during the year studied. The operation involves a declining marginal yield and increasing marginal costs. There is no further increase in the production of crude once the quantity injected reaches 73 000 m3.

Chapter 6 Decision-making on exploration and production

the sale price, so that injection is worthwhile. It should be noted, however, that this cost is close to the sale price. It may be, therefore, that the decision will be taken on the basis of other considerations and criteria: uncertainty as to the behaviour of the reservoir, a desire to gain experience with injection, etc. Box 6.1 Marginal analysis. For a production facility which manufactures a single product, the optimum production level is generally not that which minimises average costs. Over a short period, and for a given set of equipment, the level which maximises profits is that for which the marginal cost (cost of the last unit of production) is equal to the marginal receipts (receipts procured for the last unit of production) (subject to appropriate assumptions regarding continuity, differentiability, increasing marginal cost being satisfied). If the sale price is independent of the level of production, production is optimised when the marginal cost is equal to the sale price. This can readily be proved mathematically by setting the derivative of the profit function Pr = PQ – C equal to zero.

It can be seen that the curves in Fig. 6.1 have a U-form similar to that traditionally shown in microeconomics textbooks. This is rarely the case in the refining and petrochemical sectors, where the cost function is often best represented by considering the cost C as the sum of a fixed term and a term proportional to the volume processed, at least as long as the capacity of the plant is not exceeded. Annual cost

Mean / marginal cost

900

30

800

25

Cm

700 20 600 15 500

CM 10

400 300 20

Additional production 30

40

50

60

5 20

70

Additional production 30

40

50

60

70

Figure 6.1

6.3 DECISION-MAKING IN RELATION TO DEVELOPMENT AND THE DETERMINISTIC CALCULATION OF THE RETURN The chronology of upstream operations in the industry should ordain that decisions on exploration are dealt with before decisions on development. But the former are based on 216

6.3.1

Discount rate and the cost of capital

6.3.1.1 The cost of capital A deterministic evaluation of an investment project is primarily a matter of comparing cash flows received and disbursed at different dates. The technique by which this is done is known as discounted cash flow: this technique involves applying coefficients to cash flows occurring in different years which make them comparable (see Box 6.2). The discount rate is generally defined as the average cost of capital. The most common method outside the upstream petroleum industry involves using a weighted average cost of capital after tax (WACC standard method). The cost of debt is therefore calculated after tax, i.e. (1 – t)d, in nominal terms, where d is the cost of debt in current prices before tax and t is the tax rate. Since interest is usually deductible from profits before the calculation of tax, the payment of O 1 of gross interest generates a tax saving of O t.

Box 6.2 Discounted cash flow. If we suppose that there is no uncertainty about the future, and that there is a perfect capital market (i.e. a market in which any economic agent can lend or borrow any sum of money at a unique rate of interest i), then a sum S0 in year 0 is precisely equivalent to a sum S0(1 + i)n in year n, since either can be exchanged for the other. On this basis, a sum Sn available in year n is equivalent in year 0 to its “present value” (or “discounted value”): Sn (1 + i )n In practice, real markets are not like this. A company has different sources of finance (retained earnings, share issues, loans, etc.). The discount rate is therefore the cost i of all its capital. This is generally a weighted average, equal to the marginal cost of finance assuming the proportions of the different types of capital remain the same. The discount rate can be regarded as the price at which the financial department is willing to provide capital funds to the department(s) responsible for the study and for implementing the investment project. It should be pointed out that the above theory does not depend on the assumption that the rates of interest applying to money lent and borrowed are equal. In practice if a company has funds available at a given time, these funds will generally not be lent out at the market rate, but will allow the company to reduce, during the period in question, its need to raise capital at a cost of i. The effect of this is therefore the same as if the money were invested at a rate i.

217

Chapter 6 Decision-making on exploration and production

probabilistic calculations and on risk analysis techniques, which cannot be carried out until we have quantified the value created (or destroyed) for the various outcomes of the decision being studied. It is this quantification, based on “deterministic” calculations specific to a particular assumption, which is the subject of the present section. In Section 6.4 we shall look at the effect of taking account of uncertainty and applying probabilistic methods. After making a few observations regarding the discount rate we shall present methods for evaluating investment projects. The basic principles will be reviewed in boxes incorporated into the text.

Chapter 6 Decision-making on exploration and production

In costing equity capital, the most commonly used approach is the Capital Asset Pricing Model (CAPM), based on financial theory (see Box 6.3). This was the method adopted by Elf Aquitaine in 1998 when it revised its discount rate. The parameter β is obtained by econometric methods. Various studies have obtained values of less than 1 for the oil industry: of the order of 0.9. Where an oil company is active in a number of different sectors, the coefficient β can vary significantly between sectors. Moving downstream from traditional petroleum activities, values for β of between 0.4 and 0,5 are observed in the pharmaceuticals and cosmetics industries. Box 6.3 The Capital Assets Pricing Model (CAPM). This model gives a method of quantifying the cost of equity capital as the return expected by the shareholders, which can be considered to be equal to the return on riskfree investments, increased by a risk premium. This risk premium relates only to systematic risks affecting the share market as a whole. In practice, non-systematic or specific risk, that is risks related to individual companies, can be reduced (vanishingly) by portfolio diversification. Based on the model, the risk premium can be expressed in the form: β (rM – ro) where: rM is the average return offered by all shares (market return), ro is the return on risk-free investments, β is a parameter representing the ratio of the covariance between the company’s return on capital and the average return for the market as a whole to the variance of the latter. It can be calculated from stock market statistics.

6.3.1.2 Different discount rates As indicated in Section 6.1, it is quite common for oil companies to use different discount rates for different sectors, and sometimes for different geographical zones. Leaving aside strategic considerations, these differences are mainly related to the need to allow for risk. The coefficient β, which characterizes the systematic risk to which the shareholders are exposed, can vary between one activity and another. The same is true of debt ratios, with the permissible debt ratio being a function of the risk involved: exploration is practically never funded by debt, while most development projects are funded in part by debt, and indeed the latter may exceed the equity element. This reduces the average cost of capital. It should also be mentioned that specific risk premiums are sometimes added to the cost of capital calculated in the manner described. Remember that this calculated cost of capital already includes, in the estimate of the cost of equity, a systematic risk premium. This practice will be analyzed briefly in the next section.

6.3.2

Constructing a schedule of cash flows, operating cash flows, general remarks

Economic evaluations involve determining the net cash flow in future years, i.e. cash inflows minus cash outflows. 218

Fk

–

Fk =

(1+ d )

k

Although in practice calculations may be carried out either in real or nominal terms, American companies generally advocate that calculations are made in nominal dollars, thus ensuring that the monetary units used in economic evaluations and accounting and tax documents are the same. In the first place we shall confine ourselves to looking at “operating cash flows”; these do not bring into the calculations any debt-related flows, corresponding to calculations of the overall return on capital.

6.3.3

Evaluation criteria for investment projects: net present value (NPV) and rate of return

6.3.3.1 Net present value or discounted cash flow

Box 6.4 Net present value. The net present value (NPV) is the algebraic sum of the present values of all cash flows Fk associated with the project: N

NPV =

∑ 1+ i k =0

n

Fk

( )

where: Fk : cash flows in nominal terms, – Fk : cash flows in real terms of year 0, i : discount rate, nominal terms, – i : discount rate, real terms, – where 1 + i = (1 + i ) (1 + d ).

219

k

=

∑ k =0

Fk

(1 + i)

k

Chapter 6 Decision-making on exploration and production

The cash flows are defined relative to the situation in which the project is not implemented: only those future flows related to the decision being evaluated should be brought into the calculation. A cash flow usually involves (with a few exceptions, such as the residual value of an item of equipment remaining at the end of the period studied) a real movement of funds, and not a mere accounting concept. An important difference between cash flows and profit and loss accounting relates to the treatment of depreciation. Depreciation does not involve the physical movement of funds in or out. Depreciation only has an indirect impact on cash flow insofar as it affects tax payments: depreciation can be a deductible expense in calculating taxable profit. Forecast cash flows can be expressed either in nominal (current) or in real (constant) terms. In nominal terms (current money), the receipts and expenditures in year n are entered in terms of the money of the day. Real terms (constant money) are notional monetary units in which the purchasing power remains constant and equal to that in a reference year. If year – 0 is the reference year and we assume a constant annual rate of inflation of d, the value Fk in real terms for year 0 of a flow Fk in year k defined in nominal terms, is given by:

6.3.3.2 Internal rate of return The (internal) rate of return of a project is the value of the discount rate which equates the project’s NPV to zero. When its value is unique, in particular for a “simple” project (i.e. negative cash flows followed by positive cash flows) this parameter is equivalent to the maximum rate at which the project revenues can remunerate the capital invested without the project becoming loss-making (Fig. 6.2).

Present value

Chapter 6 Decision-making on exploration and production

The net present value is an absolutely fundamental concept in economic evaluation. It is a measure of the value created by an investment and is equal to the maximum sum which can be borrowed in year 0 (by the project department from the finance department), in addition to the capital cost of the investment, such that the revenues generated by the project will repay the total of these amounts and give a return equal to the discount rate. The NPV criterion: a given project which is independent of any other project will be realized if the NPV is positive. In choosing between a number of mutually exclusive projects, the project with the highest NPV will be chosen.

r

Discount rate

F0

Figure 6.2 Graphical representation of internal rate of return.

This is equivalent to checking whether the rate of return on the project is greater than the discount rate or whether its NPV is positive. In choosing between two exclusive projects A and B, the project with the highest rate of return is not necessarily that with the highest NPV. The project with the greater capital cost, B, will be preferred if the incremental rate of return of B with respect to A is higher than the discount rate (the incremental rate of return is the rate of return on the incremental investment involved in investing in B instead of A). If the rate of inflation d is stable during the study period, the rate of return in nominal terms, r, and in real terms, r-, are related as follows: 1 + r = (1 + r-) (1 + d ) r ≅ r- + d 220

When studying the development of a reservoir it is usually appropriate to compare different production alternatives (for example relating to the number and locations of wells). One of these variants may be the option to deploy an early production system. Such a situation often leads to multiple rates of return, a phenomenon uncommon in other sectors. Multiple rates of return cannot occur unless forecast net cash flows display several changes of sign over time. This is the case, however, when we are looking at a project which involves accelerated production. What happens is that the capital expenditure (negative cashflows) leads to an accelerated or increased production in the early years (positive cashflows), and a loss of receipts in later years (negative cashflows). When the NPV associated with this cashflow schedule is plotted against the discount rate, there may be two zeros, indicating two rates of return (see Fig. 6.3). The net present value of a project involving early production will be positive between these two values. Obviously in a case such as this great caution is necessary in using the criterion of rate of return as defined in the previous section.

NPV

I (%) 10

20

30

40

50

60

70

– 230

Figure 6.3 A multiple rate of return.

6.3.4

Equivalent cost

When studying an investment project, the sale price of the hydrocarbons produced may be subject to uncertainty. It can then be very useful to determine the minimum sale price needed to ensure that the project is profitable, or in other words to calculate the equivalent cost of production. Determining the equivalent cost allowing for tax and recalculated to a before tax basis is simplified when calculating an equivalent cost after tax is relevant, particularly in cases where the project accounts are consolidated with those of other activities, the total being in profit because a known tax allowance can be associated with every item of deductible cost. In exploration/production it is common, due to the practice of “ring fencing”, for this not to be the case, with some projects giving rise to losses which are carried forward. These 221

Chapter 6 Decision-making on exploration and production

6.3.3.3 Early production, multiple rates of return

Chapter 6 Decision-making on exploration and production

Box 6.5 Equivalent cost. The equivalent cost, in annual or unit form, is an (annual or unit) equivalent of the total costs associated with a project. It includes both the operating costs and an investment equivalent cost. We consider here only the case where it is appropriate to regard it as constant over time, when it can be assumed that the annual receipts or the sale price of the products will remain stable during the study period. When an annual equivalent cost is determined, it is a constant annuity equivalent to the sum of the present values of the capital and operating expenditures. The unit equivalent cost, or average discounted cost, is the ratio of the sum of the present value of expenditures to the sum of the present value of production. A project has a positive net present value if and only if the annual (or unit) equivalent cost is less than the annual receipts (or the sale price of production). Allowing for the effect of tax, the unit (or annual) equivalent cost allowing for tax and recalculated to a before tax basis , is equal to the sale price (or annual receipt) such that the net present value is zero.

losses engender tax savings only when the taxable profit (after carry forward of losses) becomes positive, this depending on the price of crude. In order to calculate the precise equivalent cost it is then necessary to proceed iteratively to arrive at the sale price such that the present net value is equal to zero. When the main uncertainties relate to the price of crude, the difference between this price and the equivalent cost throws light on the acceptable degree of fluctuation in the price of crude, and is often more informative than the value of the NPV or the difference between the rate of return and the discount rate.

6.3.5

Financing mix and the equity residual method

When the early studies are being made for an investment project and particularly for the discussions between the partners, the calculations are generally carried out using operating cash flows as defined above, without bringing in elements related to the loans required to finance the project. These calculations relate to the WACC method. The data relating to the finance are implicit in the discount rate, the internal price at which the finance department is willing to allocate funds. This allows financing decisions to be kept separate from investment decisions. For small projects this overall approach (WACC method) is generally the only one used: projects are assumed to be financed from a common pot of capital available. For large projects this WACC method is also adopted when the debt ratio α defined by the company for all its projects is strictly fixed. In such a case, if the debt ratio exceeds α on a particular project, the debt component on other projects needs to be reduced to a lower level. It is then appropriate to maintain a separation between the sources of funding and their application. For large exploration/production projects a flexible approach is often taken with regard to debt. When the studies reach a sufficiently advanced stage and the financing arrangements have been defined it may be desirable to look at their impact. To this effect, most companies advocate supplementing the calculations of the overall return on capital (possibly making use of the method of Arditti, which we shall look at presently) by a calculation of the return on equity (see Box 6.6). This will in fact be the main criterion in a case where the project finance 222

Box 6.6 Standard WACC method and Equity Residual method. Standard WACC method (After Tax Weighted Average Cost of Capital, ATWACC method, overall return) Cash flows are operating cash flows (i.e. not including any flows linked to debt). The discount rate is defined as the after tax weighted average cost of financing. The standard WACC method reflects the viewpoint of the department responsible for investment projects. Equity residual method (return on equity) A calculation of the return on equity, on the other hand, reflects the viewpoint of the shareholders. Payments made to service debt and the associated tax shields are therefore included in the calculation. The discount rate used is therefore that appropriate to the shareholders, the cost of equity. If the tax rate on company revenue, t, is stable, the relationship between the overall return on capital ro and the rate of return on equity re, both in nominal terms, is as follows: i = α′ (1 – t)b + (1 – α′)ke where: b interest rate on debt (in nominal terms), α′ proportion of project capital funded by debt, re equity rate of return . This relationship is exact if the debt ratio for the project remains stable during the life of the project. If this is not the case, the relationship is approximate only. This can be interpreted very simply: the overall return on capital is the weighted average of the cost of debt and the return on equity.

6.3.6

Acquiring participations, valuing a project

When the purpose of a study is to decide whether or not to proceed with a given project, and when the project finance is in line with the financing of all the investments in the same sector, the various different methods of evaluation —overall return on capital, return on equity but also Arditti’s method— all tend to indicate the same decision. In other words, the NPV for the different methods all tend to have the same sign. But they will not have the same value and indeed may diverge considerably. The problem of putting a value on a large project crops up frequently in the upstream petroleum industry, where development often involves consortia, and where companies seeking to optimize the return on their portfolios may seek to buy into a project, or divest their interests, at any stage during development and exploitation. Investors need to be able not just to know its net present value, but to be able to calculate its value in any year. Based on the criterion of overall return on capital, the value of the project in any year k in the future is the sum of the values of future cash flows discounted to that year: 2. We only have to set the equation in the Box 6.6, assuming it holds precisely, with α′ = α, beside the formula for the discount rate i = α(1 – t)b + (1 – α)ke, to realise that re ≥ ke if and only if ro ≥ i.

223

Chapter 6 Decision-making on exploration and production

has no impact on the debt ratio applying to the company’s other investments (in the case of non-recourse financing, for example). When the project is financed on the same basis as the overall portfolio of investments, the two approaches, i.e. WACC and equity residual should lead to the same decision2.

Chapter 6 Decision-making on exploration and production

N

Vk =

∑

n = k +1

Fn

(1 + i)

n−k

In particular, once an investment I has been made in year 0, the value of the project at the end of year 0 is: N

V0 =

∑ 1+ i n =1

Fn

( )

n

= I + NPV

Before an investment is made the value of the project (i.e. of the right to invest) is equal to the NPV. But if the equity residual method produces a very different value, how can a company determine the maximum price it is willing to pay for an interest in the project, or for that matter, a minimum price at which it is willing to sell? In order to address this question, we shall invoke a result which may appear theoretical, but which can cast useful light on the question: The NPVs for the two methods are equal not when the initial amount of the loan is equal to αI0 but when it is equal to α(I0 + NPV) —assuming that the debt ratio for the project remains stable for its entire duration. To make this point clear, we observe that the capacity of a company to borrow is determined not by the capital cost of the investments but by the capacity of the company to service the loan, that is, by its expected revenues. Suppose there is a third party with the same expectations as to return and the same financial structure, and therefore the same discount rate, as the company we are considering. He is considering purchasing the right to carry out the project. The maximum sum he is prepared to pay is equal to the NPV of the project. If we add the capital cost of the project, the total acquisition costs including the construction of the plant amount to I + NPV, a fraction α of which he can finance by debt. The company itself would only be able to borrow αI, so it would benefit from a lower gearing than the imaginary third party, and its return on equity is therefore lower. Which is in fact the correct value? The answer is related to the question of how the project is financed. If debt is limited by considerations of risks specific to the project, if it has no impact on the debt ratio for other projects, it is the NPV on equity which should be used. If on the other hand taking a smaller loan in connection with this project would result in increased capacity to borrow elsewhere, the objective of complying with the reference ratio for the totality of investments means that the WACC method using the relevant discount rate should be used: the assumption that the debt ratio remains stable, and is defined by reference to the value of projects, is implicit. It is therefore the overall NPV on capital which is the relevant indicator.

6.3.7

Another approach to calculating the return on exploration/production projects: the Arditti method

6.3.7.1 The nature of the problem The standard WACC method presented above is performed using a discount rate defined as the after tax weighted average cost of capital. But in the upstream petroleum industry, determining the after tax cost of debt can be problematic. 224

Furthermore the return on equity, a parameter very sensitive to the assumptions regarding financing, is usually only used in the final study phases. These various considerations have led the oil industry to make fairly widespread use of another method, known as the ArdittiLevy method.

6.3.7.2 The Arditti-Levy method (before Tax Weighted Average Cost of Capital) This method uses a discount rate equal to the average cost of capital before tax. This parameter is easier to calculate than the cost after tax, and its value is independent of the tax regime. The method therefore allows the number of discount rates to be limited, possibly to just a single rate, remembering that the cost of capital before tax varies little from one geographical zone to another. The cash flows to be considered therefore (hereafter referred to as the A-L flows) will include tax allowances earned relative to interest on loans, but will not include the loan drawings or redemptions, or interest payments. In other words, the deductibility of interest is not allowed for in determining the discount rate (as happens in the standard WACC method), but in calculating the cash flows in each year, by using the tax rate for the year. In practice the taxable profit and therefore the tax in each year are calculated by deducting the interest from the project operating revenue. Account is taken of all the specifics of the tax regime for the project (carry forward of losses, variable tax rates depending on one or more operating parameters, etc.) in the cash flow projection. Apart from the tax payments, the flows considered are the after-tax operating cash flows. The viewpoint adopted in this approach is that of investors, shareholders (the owners of the equity) and lenders. The A-L flows effectively include the sums received or disbursed by everyone, while the cost of capital reflects the average minimum return sought by the various providers of capital. The A-L flow is therefore equal to: – The operating cash flow increased by the tax allowances on interest; – The sum of equity flows and flows related to debt (before tax). The Arditti-Levy method generally results in the same decisions as the standard WACC method (when this can be used) and the equity residual method when the financing proposed 225

Chapter 6 Decision-making on exploration and production

The problem is that the operating companies involved in exploration and production are not always in profit, for example when they commence operations in a new zone. In such circumstances they are not able to deduct any accounting loss from profits associated with other activities. These losses must be carried forward to future years. Furthermore the practice adopted in some countries of ring fencing the exploration licence can prevent fiscal consolidation, even within a given country. Tax regimes are often complex, and generally vary between different licences. The tax rate may depend on the rate of production, etc. All this means that it is not possible to express the taxation of petroleum revenues (and its impact on financing costs) in terms of a single parameter. It is therefore not generally possible to determine by simple calculation the cost of debt after tax. This makes the standard WACC method an inappropriate method of evaluating a project. Even assuming the average cost of capital after tax can be calculated, the company would have to use as many different discount rates as there are petroleum tax treatments to consider.

Chapter 6 Decision-making on exploration and production

for the project is consistent with that for the firm as a whole3. In other words, there is a convergence of the viewpoints for the different methods: between that of all the various investors (Arditti), the shareholders (equity), the department responsible for investment (requiring a return on invested capital equal to the average after tax cost of capital). The Arditti-Levy method is widely used in the upstream petroleum industry. Care is needed in its application, however. The pitfalls are known to the specialists, but they make it difficult for decision-making to be decentralized. It is not enough to simply provide a user with the value of the discount rate. The first step must of course be to check that the financing assumptions made in determining the discount rate are compatible with the assumptions made in calculating the financing costs and the corresponding tax savings. In practice the method in its original version is only appropriate for the study of projects where the debt component of the financing is consistent with the overall debt ratio objective set by the company. Even in such cases, however, the non-specialist may encounter some difficulties. These include: • Sensitivity to the rate of interest on debt: the higher the rate of interest on debt then, ceteris

paribus, the higher the internal rate of return on the project. This may come as a surprise to an inexperienced analyst, who might be inclined to use the same discount rate. • Term of loan: This may be significantly shorter than the life of the project. In this case

the assumption of a constant debt-to-capital ratio over the entire study period is clearly not satisfied, and can lead to an underestimation, sometimes substantial, of the profitability of the project. • Economic value of a project: consider a project for which the debt-to-capital ratio is equal

to the debt ratio α set by the company, i.e. B0 = αI0. In this case the NPVs calculated by the traditional method and the Arditti-Levy method (as well as the equity NPV) should have the same sign, but be different in magnitude4. If the object is to decide whether or not to proceed with the project, both (or all three) methods lead to the same conclusion. But if the purpose is to determine an acceptable price at which the company can acquire or dispose of an interest in the project, it is the economic value of the project (Vn in year n) which should serve as the reference value. The fact that the two methods may give different results can also give rise to the problem referred to in Section 6.3.5.

3. More precisely, convergence is ensured when the debt-to-capital ratio α′ for the project remains constant over its life and is equal to the debt ratio α fixed by the company for projects of this type. The demonstration is similar to that for the convergence between return on capital and return on equity. The A-L rate of return rs is a weighted average of the cost b of debt before tax (return to lenders) and the rate of return on equity re (return to shareholders):

rs = α′b + (1 – α′)re Where the financing arrangements are not such as to preserve a constant debt-to-capital ratio, the formula becomes approximate rather than precisely correct. The A-L discount rate s is a weighted average of the cost of debt (before tax) and the cost of equity ke:

s = αb + (1 – α)ke For a project which satisfies the given assumptions, i.e. α′ = α, rs is greater than s if and only if ro is greater than ke. 4. The relationships between NPVs obtained in this case by the different methods are given by Babusiaux [1990].

226

A new approach: the generalized ATWACC method

At the time of writing, a new method is being studied with a view to its possible use by the Total group. It is described in detail by Babusiaux and Pierru [2001]. It is a generalization of the classical return on capital method, and caters for the case where profits arising from the project studied will be subject to a different tax rate from that considered in calculating the discount rate. We will begin by presenting the method under a simplified set of assumptions.

6.3.8.1 The generalized ATWACC method Consider a company subject in its country of origin to a tax rate t on its income (we shall revisit this assumption in the following section). It wishes to evaluate its investment projects in a sector with the standard WACC method, and uses a discount rate based on the average cost of capital after tax and nominal terms (using the usual notation): i = α(1 – t)b + (1 – α)ke We assume that all the projects of the same type must stick to a fixed debt-to-capital ratio, α, which we shall refer to as the reference ratio. The company is studying the return on an investment project in a foreign country with a different tax regime or, more generally, where revenue will be taxed at one or more rates different from t. We will confine ourselves to the case where there is no consolidation of accounts for tax purposes, or to similar cases5 which are quite common in the upstream petroleum industry. We assume further that the project can be financed partially by loan capital and that interest on the loans is deductible from the project’s taxable revenue. Let L′ be the loan obtained for the project. Whatever the amount of the loan, and whatever the debt ratio set by the company, the loan can be considered to be taking the place of a loan L put up by the central services of the company. The loan L, equal in amount to L′, would have been repaid over the same term and by the same method of repayment. In other words the redemption timetable would have been the same. This assumption, though it may appear somewhat theoretical, can be seen as a way of satisfying the requirement that the loan L must result in the same overall debt ratio each year as the loan L′ (the assumption currently adopted for project evaluation of a debt ratio fixed ex ante). The principle underlying the method is very simple: the difference in the after-tax cost of interest payments is assigned to the project. If the interest rates are the same in the host country and the home country this has the effect of assigning to the project the difference in tax allowances which arises when the interest is accounted for in the host country rather than in the company’s home country. Remarks • The procedure proposed is a generalization of that proposed by Babusiaux [1990] for

analyzing the profitability of a project in order to apply for a loan at a subsidized interest rate. • There are, on the face of it, no particular difficulties in adapting the method to cater for

contractual conditions specific to the upstream oil industry. In the case, for example, of 5. When for example local taxes are higher than taxes in the company’s home country, where profits worldwide can be consolidated.

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6.3.8

Chapter 6 Decision-making on exploration and production

a production-sharing contract, in which the financial costs are recovered in the form of cost oil, the cost oil simply reduces by an equivalent amount the quantity of profit oil which would have been shared between the state and the company.

6.3.8.2 Reference tax rate and optimum allocation of debt In the section above we considered a project subject to a different rate of tax from that applying to the company generally. An international oil company in fact has to contend with a large number of different tax regimes. How can the rate t be determined? In theory the company should take up loans in increasing order of after-tax cost (this would involve, for example, allowing some subsidiaries to become more proportionally indebted than others). The after-tax marginal cost of debt will then be the cost of the last loan to be taken up. It is this last loan which has to serve as the reference in defining the loan λ which would be substituted by the loan L′ for a project under study, as well as the tax rate applied to the revenues from which the appropriate interest can be deducted. The gain to be credited to the project is calculated by reference to the cost of this marginal loan (if it can be determined by the company’s central services).

6.3.8.3 Merits of the method In Section 6.3.7 we emphasized a number of problems posed by the use of Arditti’s method. The generalized ATWACC method does not suffer from these disadvantages, Furthermore it has the merit of simplicity. • Once the discount rate has been determined, the formulation is independent of consid-

erations of the debt ratio to be observed for all the company’s projects of the same type. • In most cases outside the upstream petroleum sector, the tax regime applying to the

revenues from a project are no different from that applying to the company as a whole. In this case the proposed method is equivalent to the classical method. Using the proposed method therefore allows a unified criterion to be adopted for all the activities of an oil company, a traditional criterion which is easier to use and whose use is more widespread than that adopted in the Arditti-Levy method. • The first studies of the profitability of a project, particularly in connection with discus-

sions between consortium partners, are usually performed without any allowance for debt. In other words they are carried out on the basis of projected operating cash flows. Furthermore, the ex post evaluation of the financial results is often based on the return on capital employed (ROCE). The accounting revenues used in this exercise exclude both interest charges and the corresponding tax savings. The ROCE is therefore analogous to a cost of capital after tax. Similarly, the economic value added (EVA) method defines the value added in a year as the annual accounting revenues (excluding financing items) less the cost of servicing the capital. The latter therefore also requires an after tax average cost of capital. In each of these different cases the explicit or implicit method of reference is the classical cost of capital method rather than the Arditti-Levy method. One of the advantages of the generalized ATWACC method is that it rests on a similar basis.

6.3.8.4 Theoretical developments Theoretical developments with regard to the generalized ATWACC method are presented in Pierru and Babusiaux [2000]. Although not proposing to go into detail, we present the 228

6.3.9

A first step in dealing with uncertainty: sensitivity analysis

Sensitivity analyses are usually indispensable in economic evaluation. They involve analyzing how the profitability of a project varies in response to changes in the assumptions regarding the different components of the cash flow calculation, such as, in the case of the development of a hydrocarbon reservoir: the cost of capital, the price of crude and/or gas, the size of the recoverable reserves, tax rules, etc.

The spider diagram In presenting the results of a sensitivity analysis a graph, the spider diagram, often conveys more than tables of numerical values. This is constructed by representing along the x-axis the variations in the different parameters to which the profitability of a project may be sensitive. They are usually represented by variations relative to a base case defined beforehand. The y-axis comprises the value of the criterion in terms of which the results are expressed: net present value, rate of return or equivalent cost. In each analysis just one parameter is varied, the other parameters being kept constant and equal to their values in the base case, to give a curve for that parameter. Figure 6.4 shows by way of example the results of a sensitivity analysis carried out for an investment project. The criterion used is NPV. The variations studied relate to the price of crude, the volume of the reserves and the cost of capital. The main purpose of such a graph is to display the results at a glance and to identify the parameters to which the profitability of the project is most sensitive. It also allows sensitivity analysis to more than one independent parameter at a time to be studied The possible variation due to two independent parameters, for example, can be estimated by taking the line segments representing the possible variations in these two parameters singly and completing the spider’s web as shown, or more accurately, by summing the two vectors represented by these line segments.

6. Pierru and Babusiaux [2000]. 7. See also Pierru and Feuillet-Midrier [2002].

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main formula which lies at the heart of the method, because it provides additional justification for the proposed method and throws fresh and instructive light on it. We shall confine ourselves in this section to considering a project financed in part by debt, the amount of which is determined by the reference debt ratio α. This debt ratio, defined by reference to the economic value of the project (see Section 6.3.7), is assumed to remain constant. In particular, the capital borrowed in year 0 is B0 = α(I0 + NPV). Under these assumptions, Axel Pierru6 demonstrated a theorem interesting in both theoretical and applied terms. His theorem states that the net present value of a project, and more generally its economic value in any year, calculated using the generalized ATWACC method, is equal to the value calculated by discounting the operating cash flows at a rate equal to the average cost after tax of financing the project. This property is intuitive. The theorem has a corollary: the NPV of the project is independent of the tax rate t in the country of origin. The parameter t can therefore take any arbitrary value. Each of the traditional methods (standard WACC, Arditti-Levy, equity residual) corresponds to a particular value of t, providing a very simple proof of their consistency7.

ice pr e ud Cr

Chapter 6 Decision-making on exploration and production

NPV

Ca

pita

l c ost

s Re

er

ve

s

Variation (%)

Figure 6.4 Spider diagram showing results of sensitivity analysis.

The same procedure can be used to consider the simultaneous variation of any number of parameters, as long as they are independent. In the general case the curves are not necessarily straight lines, and the “parallelograms” to be constructed are therefore curvilinear. It should also be noted that when the chosen criterion is the rate of return, the method can only be approximate, but can provide order of magnitude estimates. The graph makes it easier to characterize the set of favourable cases for which the net present value is positive, and the set of unfavourable cases (corresponding to the shaded halfplane in Fig. 6.4, which could be regarded as the “red zone” for the project). If, for example, it is considered that the investment budget could be exceeded by x%, the graph can be quickly used to determine what change would be required in another variable (sale price, for example) to lead to a negative NPV. In the case of a project to develop a field for production, the price of crude or the price of gas is usually the parameter to which the profitability of the project is particularly sensitive. The equivalent cost, as we saw earlier, is the threshold price which determines whether or not a project is economically viable. This criterion, which itself embodies information on sensitivity to price, is in its turn particularly well suited to be the subject of a sensitivity analysis relating to the other parameters. A decision to invest can be taken if the unfavourable cases are regarded as being unlikely (a subjective judgement, these probabilities not being quantified), and as long as the possible losses do not comprise a major risk for the company. Very often the sensitivity analysis is regarded as dealing sufficiently with the question of uncertainty to present a firm proposal to the relevant senior management. However it also often happens that the sensitivity analysis throws up a mix of favourable and unfavourable cases, each with their associated gains and losses, such that a decision cannot be made. For projects of a certain size, the analysis can be carried further by attaching probabilities to each of the various outcomes. This approach will be considered in Section 6.4. 230

The pay-back or pay-out period is an empirical criterion used by the petroleum industry, particularly in the face of major uncertainties: commercial risk, major political risk, technological risk (a technical advance may be of short duration), etc. It is defined in various ways, and can be calculated from the start of exploitation or from when capital expenditure starts (in the latter case we refer to the duration of financial exposure). Payback time may be defined in terms of discounted or non-discounted values. In any case this criterion is a good way of formalizing the desire not to carry out projects whose profitability depends on cash flows beyond a date when it becomes difficult to make forecasts. A drawback of this criterion is that it is rather arbitrary. To ignore project revenues beyond the desired payback period is to assume that they will be nil, which is generally not realistic. There are many projects of long duration in the petroleum industry (and in the energy sector generally). Despite these drawbacks, payback time is a criterion, albeit secondary, which many decision-makers find of interest. The maximum financial exposure (accumulated expenditure) is another parameter to which they pay particular attention.

6.4 THE DECISION TO EXPLORE: INTRODUCTION TO PROBABILITY 6.4.1

The “exploration” data sheet

When a decision needs to be taken in regard to development, it is often desirable to introduce notions of probability. In decision-making with regard to exploration it is almost indispensable, particularly when drawing up an exploration drilling programme. The decisionmaker has to contend not only with uncertainty about the volume of reserves, which applies when a discovery is made, but also with whether or not hydrocarbons are present at all. Once the preliminary geological and geophysical studies have been completed, the decision to drill is generally taken on the basis of an «exploration» data sheet. Companies ask geologists to make probabilistic estimates: probability of success and probabilities related to the reserves allowing the net present value to be described as a probability distribution function. It is general not possible to refer to historical frequencies, so the probabilities used are subjective probabilities. They convey the degree of likelihood estimated by an expert, based on his experience in similar situations.

6.4.2

Expected value

6.4.2.1 Definition The main criterion used to summarise a probabilistic future is the expected value of the net present value, i.e. the weighted average of the possible values of the NPV, the weights corresponding to their probabilities. This is the value to which the average would tend if the company were able to repeat the experience a large number of times. Actually it is not necessary for an identical experiment to be repeated a large number of times. The criterion of expected value is also justified by the law of large numbers if the 231

Chapter 6 Decision-making on exploration and production

6.3.10 An empirical criterion: payback period (duration of financial exposure)

Chapter 6 Decision-making on exploration and production

company carries out a sufficient number of similar, mutually independent projects. This is therefore the basic criterion used for all the “small” projects. Remark: It is possible to calculate the expected value of a revenue, a discounted cost or an annual equivalent cost. It is not in general possible, on the other hand, to calculate the expected value of a rate of return as a weighted average using probabilities. Let us consider a very simplified example of a prospect A whose recoverable reserves may be 250 Mbbl. This prospect could require a development with a NPV of $320 million. The probability of finding an oilfield of this size is 10%. There is also a 5% probability of finding a larger oilfield. The NPV in this case would be $400 million. The probability of discovering a smaller oilfield is 5% and the NPV in this case would be $200 million. The probability of failure is estimated at 80%. The cost of drilling is estimated to be $50 million. The expected value of the NPV is therefore the average of the possible values weighted by the probabilities, i.e.: –50 + (0.10 × 320) + (0.05 × 400) + (0.05 × 200) = $12 million

6.4.2.2 Estimation of the probability distribution function Whether we want to just calculate the expected value or we are interested in other characteristics such as the variance, we need to have an estimate of the probability distribution function associated with the net present value. But the latter is a function of a certain number of parameters; it is usually easier to associate probability distribution functions with these other parameters. In the case of the capital costs, it may be possible to refer to historical data to estimate the probability distribution function. It should be observed that this function is usually asymmetric (Fig. 6.5). The probability that the cost will be substantially less than the costing of the engineering department is nil, while the probability of major cost overruns is not nil. The mean value may therefore be significantly higher than the most likely value (the mode). And when an estimate is made it is often, implicitly, the mode which is intended. As far as the sale price and the volumes of products are concerned, subjective probabilities will generally have to be used. Often a broad-brush approach is taken to representing probability distribution functions. A uniform distribution represents a range of values within which it is difficult to define a most likely value. Conversely, however, when a most likely value (the mode) can be estimated, a triangular distribution function may be adopted. Frequent use is also made of the lognormal distribution.

Probability

Capital cost

Figure 6.5 Capital cost.

232

6.4.2.3 Simulation The technique most commonly used consists of performing a simulation using Monte Carlo methods8, and computer processing is normally required. A sample is drawn at random for each variable considered stochastic using the appropriate distribution function. These values are then used to calculate the corresponding possible value of the net present value (or the volume of the reserves, as the case may be). This operation is repeated a large number of times (several hundred), a sample set of notional values of the NPV is obtained. Statistical operations can then be carried out on this sample: construction of a histogram, calculation of mean, standard deviation, etc. If the sample is large enough, the method allows a probability distribution function to be derived for the NPV. In particular, the mean of the sample is an estimate of its expected value. This method has been in use by the oil industry since the early 1960s. One of the disadvantages of simulation methods is they behave like a “black box”. The probability distribution function of the target criterion is derived from probabilistic data for the different parameters. But, unlike what happens in a sensitivity analysis, the effect of individual factors is not apparent. In practice, the uncertainties attaching to the different parameters can be of different types. In the case of a development project for an oil or gas field, for example, the probability estimates for the physical and technical parameters repose on a large number of cases studied by the company, and on the experience of specialists. It is much more difficult, on the other hand, to obtain probabilistic data, even subjective, for the economic parameters (price of crude, tax rules). This is one of the reasons why simulation tends to be mainly used for evaluating the volume of the recoverable reserves. It allows the impact of uncertainties of a technical nature to be represented, while those relating to the price of crude are often better analyzed by means of scenarios. More generally, it is often the case that estimates of the future prices of products are more subjective in nature than the other parameters. Analogous to what was said in discussing sensitivity analysis earlier, simulation can be used just to determine the equivalent cost. This allows uncertainties related to the sale price to be kept distinct from all the other uncertainties which affect the net present value. Finally, the use of simulation, always a major exercise, can be avoided by using approximate formulae to determine the expected value and the variance of the net present value for a project.

8. These methods were popularised by D.B. Hertz [1964], and are sometimes referred to as the Hertz method.

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In the development of oil or gas fields, the parameters crucial to profitability are the volume of the reserves and the productivity of the wells. The latter depends on a number of variables which can be considered random: the area of the reservoir, the thickness of the reservoir bed, the porosity and permeability of the rock, the viscosity of the fluids, etc. These are the fundamental parameters which can be estimated and described in terms of probability functions by the geologists and geophysicists. Often an estimate has already been made of the minimum recoverable reserves required to make the development viable. The question then reduces to ascribing a probability distribution function to the volume of the reserves. Whether the object is to consider just the reserves or to determine a probability distribution function for the net present value (or equivalent cost), the problem is to derive this function from assumptions about the probabilities of the fundamental parameters.

Chapter 6 Decision-making on exploration and production

6.4.2.4 Use of approximate formulae Among these, the formulae related to the lognormal distribution are particularly simple. Most of the parameters involved in a project are non-negative quantities, and they are often distributed asymmetrically. This led R. Charreton and J.-M. Bourdaire [1985] to suggest representing the distribution of each parameter by a lognormal distribution, with lower bound zero, and characterized by its mode, a “mini” value and a “maxi” value. The mini and maxi values correspond to the 5 and 95 percentile points on the probability distribution function. This approach is particularly appropriate in the case mentioned above where we are seeking to determine the probability distribution function applying to the volume of recoverable reserves of oil as a function of the physical parameters. The formulae used to calculate volumes are largely based on products of variables. We can therefore apply the central limit theorem to the logarithm of the volume. Furthermore the lognormal distribution generally corresponds reasonably well to the observed data relating to reservoir size. The use of the lognormal distribution allows the mode and the mini and maxi values to be calculated for a product of variables. The mean and the variance are therefore given by the approximate formulae: m = 1 (mini + mode + maxi) 3 1 σ ≈ (maxi – mini) 3

6.4.3

Sequential decisions and conditional values

6.4.3.1 Decision trees So far we have considered a single investment decision. Sometimes a series of decisions have to be taken, the later decisions being a function of the (random) outcomes of earlier ones. For example, a first decision might be whether or not to drill an exploration well. The decision as to whether to develop, if successful, or to continue exploration, will depend on the outcome of the first drilling. The analysis therefore has to take account the subsequent chain of decisions. In order to do this a decision tree is constructed, as shown in Fig. 6.6. A decision tree is usually read from left to right, or sometimes from top to bottom. The connecting lines of the graph represent either possible decisions (continuous lines) or random outcomes of decisions taken (broken lines). The nodes therefore correspond either to a state of affairs or to information obtained. The nodes corresponding to decisions are represented by a square (decision points), while the probabilistic nodes, associated with random events, are represented by circles. Figure 6.6 represents a whole complex of possible choices in exploration/development. Prospect A is one which could result in the development studied earlier. Prospect B relates to a neighbouring, smaller structure. The geologists consider that there is a 30% likelihood of finding oil at B (10% likelihood of a small field, 20% likelihood of a medium-sized field) if there is oil at A, but the likelihood is only 15% (5% likelihood of a small field, 10% of a medium-sized field) if A is “dry”.

234

235

A

50

64

C

(0.2)

Explore prospect A

Abandon

B

32 0

E 45

Develop A 310

Explore prospect B

No discovery

Oil discovery

(0.8)

0

D

55

Small field

110

J

I

- 600

L

820

N

(0.6)

900

Favourable conditions

(0.4)

700

450

650

(0.8)

Favourable conditions

Unfavourable conditions

610

M

(0.2)

Unfavourable conditions

Chapter 6 Decision-making on exploration and production

220

K

– 500

Develop

Develop

Abandon

Medium-sized field

Small field

Failure

Medium-sized field

(0.1)

Failure

(0.10)

(0.05)

(0.85)

Figure 6.6 Decision trees.

(0.2)

H

(0.7)

27.5

G

Explore prospect B 45

Abandon

F

Chapter 6 Decision-making on exploration and production

The diagram does not show the lower part of the decision tree, corresponding to prospect B if A is successful. The section after node H in the lower part of the tree will be identical to the section in the upper part after node G. It should be noted that it is possible, instead of duplicating this part of the graph, to simply connect node G directly to nodes I, J and K, which means that we can formulate the problem considered as a stochastic dynamic programming problem. In order to determine the expected value of the NPV associated with a decision studied, calculations are carried out starting in the future and proceeding back to the present. In Fig. 6.6 we therefore move from right to left. A value is associated with each node (“value”, “score” or “potential”) which corresponds to the expected value of subsequent revenues. The evaluation starts at the nodes at the final stage (M and N). The score assigned to node M, for example, is the expected value of revenues from the development of a small field. The probabilities are indicated in brackets on the decision tree. The expected value is therefore: EM = 0.2 × 450 + 0.8 × 650 = 610 Having determined the values at the nodes of the last stage, we proceed to the nodes of the penultimate stage, i.e. J and K. While the last stage was the outcome of a random process, the preceding stage is a decision process. The decision is of course that which corresponds to the highest expected value. At node J “abandon” has an expected value of 0 while development, which requires an investment of 500, has an expected value of 610 – 500 = 110. The calculations proceed in the same manner, moving each time back to the preceding stage until we arrive back at the initial node A. In practice, the number of possible decisions is often large, and the number of possible consequences is even greater. The size of decision trees can escalate rapidly, and this imposes limits on the use of this method. Even if explicit calculations are not carried out, the decision tree is a concept to which it is useful to refer, even if only mentally, as a means of ensuring that consequences or possible actions are not forgotten.

6.4.3.2 Flexibility and option evaluation theory Once a field is discovered, a decision to develop it is often taken quickly. In some cases, however, the decision to develop is deferred, and will only be taken if certain conditions become favourable: a rise in the price of crude, a technical development which improves the recovery rate, changes in the tax regime, etc. The corresponding parameters can be regarded as random events or variables. The value of a production licence can be determined by means of a decision tree constructed as described above; this also allows the optimum strategy and the timetable to be defined which lead to the highest expected value of the NPV. Since the early 1980s a lot of research carried out and publications have referred to the possibility of using real options theory. An option (see Box 6.7) is a conditional asset, the value of which depends on the exercise of a right. The investment opportunity offered by undeveloped petroleum reserves can be compared with a call option. Proceeding with development is analogous to exercising the option. The capital required corresponds to the call price. The value of the field when developed (a function of the price of crude, which can be assumed to be a stochastic process) corresponds to the value of the underlying asset. The expiry date can correspond to the date of expiry in the case of a limited-term lease. 236

A call option gives its owner the right to purchase an asset at a given date or for a predetermined period at a fixed price (the call price). The standard method for evaluating an option is the Black and Scholes model. If we assume that the changes in the market price of the underlying share follow a normal distribution, the value of a European call option (i.e. a call option exercised on a fixed date) is

S N (d1 ) – Xe – r0t N (d 2 ) where:

Log d1 =

1 ⎞ S ⎛ + ⎜ r0 + σ 2 ⎟ t 2 ⎠ X ⎝

σ t d 2 = d1 – σ t , S X t r0 σ N(d)

,

price of underlying share, call price, time remaining before expiry, risk-free interest rate, standard deviation of the return on the share (volatility), probability that a standardised normal random variable is less than or equal to d.

Option valuation can be a useful tool in a situation combining flexibility and uncertainty, that is when a decision, which can be modified by changes in random factors, can be taken in the future. Apart from opportunities to develop oilfields, there are in theory many situations in the upstream petroleum industry which meet these conditions: the acquisition of an exploration licence, special contractual clauses, etc. Options theory is well adapted to evaluating asset market values, and does not require knowledge of a discount rate. It should be emphasized that models for valuing options assume the existence of a liquid market in the underlying asset, and that there are no opportunities for arbitrage. This may be true for the price of oil, but is less so for petroleum projects. The value of a given asset is the sum of two components: the intrinsic value and the time value. The intrinsic value is the value if the option were exercised immediately and can be determined by traditional NPV methods. The time value corresponds to the potential for appreciation in the present net value, and disappears when the option is exercised. The value of an option is affected by a number of different parameters: the value of the underlying asset, its volatility, the exercise price, the term and the risk-free interest rate. The greater the variations in the value of the underlying asset the greater the value of the option. As a result the value of undeveloped reserves will be greater ceteris paribus when the oil price is more volatile. By holding back with the development of certain gasfields in the North Sea, gas companies were able to change the nature of the competition in that area. As a result prices became more volatile, which in turn increased the value of the licences held by these companies. 237

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Box 6.7 Value of an option

Chapter 6 Decision-making on exploration and production

Although tools originating from the real options theory have not, or not yet at any rate, really caught on in the oil industry, occasional reference to them, even if only qualitatively, can be useful in making decision-makers aware of the choices and parameters which affect the value of certain assets which have similar characteristics to options.

6.4.4

Limitations applying to the expected value of NPV

6.4.4.1 Risk aversion The use of the expected value is justified where the company can be assumed to carry out a sufficient number of independent, similar projects for the law of large numbers to apply. This is not the case when a major project is being studied requiring very large investments, for example certain offshore development projects. Let us return to the example of the exploration decision mentioned in Section 6.4.2. The cost of the exploration programme is $50 million. The probability of finding a field of medium size is 10%. The corresponding NPV would be $320 million (excluding exploration costs). The probability of making a “large” discovery is 5%, and the NPV would then be $400 million, and the probability of making a “small” discovery is 5%, the NPV then being $200 million. The expected value of the NPV is therefore: –50 + (0.10 × 320) + (0.05 × 400) + (0.05 × 200) = $12 million Now consider another exploration opportunity in a zone where access is more difficult and less familiar. The cost of exploration there is higher: $ 160 million, but the sizes of the possible fields are considerably larger. The values of the probabilities and the discounted revenues (excluding exploration costs) for different possible discoveries are indicated in Table 6.8. Table 6.8 Characteristics of a possible discovery. Discovery

Probability (%)

NPV ($ millions)

Small

5

100

Large

10

1 000

Very large

5

1 500

The expected value of the NPV is therefore: –160 + (0.05 × 100) + (0.10 × 1 000) + (0.05 × 1 500) = $20 million Assume that the two opportunities studied only differ in terms of their costs and revenues as indicated, and that a choice has to be made between them. A large company would consider both to be small projects, and it would prefer the second to the first because the expected revenues are higher. For a small independent company, on the other hand, this may not be the best decision. It has to allow for the fact that the likelihood of losing money is higher for the second project, and that the maximum possible loss is also higher. In other words it is a riskier project. Generally speaking, companies are averse to risk. 238

Probability A

B

NPV

Figure 6.7 Comparison of projects.

The risk is generally characterized by the standard deviation9 (or the variance) of the discounted revenue. If two projects have the same expected revenue, a risk-averse decision-maker would opt for the project with the smaller standard deviation. A problem which can arise is that one project has a higher expected value but also greater risk. The decision-maker is then faced with making a choice based on two different criteria. The problem is similar when the decision is between accepting and rejecting the project. The fact that the expected value of the discounted revenues is positive is not enough. It is also necessary that the risk should not be too high. In practice both of these criteria (expected value and variance) are commonly used without their being universal agreement about the trade-off. As indicated earlier, in the oil production sector simulation methods are often used. These methods allow the expected value and variance of the volume of recoverable reserves, or going further, of the NPV for the development project, to be calculated. Nor do we necessarily rely on just the expected value and the variance, since the distribution function is also available. This allows us to calculated the probability, for example, that the project will result in a loss. A decision can often be taken on the basis of the information described above, possibly supplemented by considerations of a more strategic nature, without having to seek to quantify the weights to be attached to each element, in particular to the expected value and the variance (mean value and risk). 9. The standard deviation of a variable is the root mean square of the deviations of the variable from its mean. It is a measure of the dispersion of the variable. The variance is equal to the square of the standard deviation.

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Before examining possible responses to the question posed, let us take yet another example. Let us look at two development projects whose NPVs can be considered to be continuous random variables. Suppose the expected values of the NPVs for the two projects are the same. A risk-averse decision-maker will prefer the project with the smaller dispersion of NPVs, i.e., project A in Fig. 6.7, which presents the probability distribution functions for these two projects.

Chapter 6 Decision-making on exploration and production

Different approaches are used to deal specifically with risk. One of these involves using an expected value/variance criterion which uses weights derived from decision theory. Before presenting this criterion we shall look at a method widely used by companies in which a risk premium is included in the discount rate.

6.4.4.2 Discount rate and risk premium In Section 6.3.1.1 we mentioned the Capital Asset Pricing Model. This involves calculating the cost of equity by incorporating a risk premium. The theory links in with the practice adopted by many companies of incorporating a risk premium in their discount rate. A number of points need to be made in regard to this practice. In the first place, the risk premium determined by the CAPM only allows for systematic risk. In order to apply it to take account of the risks attaching to individual projects, it would be necessary to calculate the coefficient β associated with each project. But in any case, the model seeks to maximize the utility of a shareholder who can diversify his portfolio. The shareholder is therefore assumed to be indifferent to the risk specific to any given asset. This is not true for a shareholder who does not hold a very diversified portfolio, and in particular for someone holding a large proportion of the capital (as in a family business). And a fortiori it is clearly impossible for the head of a business to ignore specific risk. When reference is made in a company to the capital asset pricing model, it is usually in order to determine the cost of capital for the company as a whole and not project by project. This cost of capital is usually increased more or less explicitly by a premium which factors in the specific risk. This method will be analyzed briefly below. We shall use the term “specific risk premium” to refer to the safety margin which has to be added to the cost of capital to arrive at a discount rate. The adjective “specific” is used because the systematic risk is generally allowed for in the definition of cost of capital, but in practice the premium in question is often defined in a pragmatic manner, without there being a real distinction between specific and systematic risk. An increase in the discount rate reduces the impact of future cash flows, this reduction being greater the further they are in the future. Some writers justify this by arguing that the value of a future cash inflow is subject to uncertainties which become greater the further into the future we look. But this is not always true. When we seek modern equipment for an ultradeep offshore development, for example, the capital cost, which will have to be borne over the early years, may be much more uncertain than the longer-term receipts. A major problem inherent in this approach is obviously the fact that the definition of a risk premium is arbitrary. A high risk premium can only be justified in very special cases. As remarked by R. Charreton and J.-M. Bourdaire [1985], using a risk premium is equivalent to applying certain probability factors. If i0 is the discount rate not including any specific risk premium and pr is the specific risk premium, then the present value of a cash flow Fn in year n is: Fn

(1 + i0 ) (1 + pr ) n

n

A risk premium of 10%, for example, involves applying a factor of approximately 0.6 in year 5. This is equivalent to assuming that there is a 60% probability that the given flow will take place, and a 40% probability that it will be nil (e.g. complete expropriation without compensation). This would be a very high assumed risk. 240

6.4.4.3 Decision theory and the expected value/variance criterion In Section 6.4.4.1 we gave two examples where a choice between projects was modified when account was taken of risk aversion, and which show that the satisfaction created by an inflow of money is not proportional to its value. Decision theory permits this satisfaction to be quantified by means of a utility function. But translating theory into applications runs into a number of difficulties. Attempts to construct a utility curve (necessarily subjective) have usually been abandoned by the oil industry. R. Charreton and J.-M. Bourdaire1 [1985], on the other hand, have suggested a criterion consistent with decision theory, but simple, appealing and therefore easy to put into practice. For independent projects it consists of replacing the NPV by: m−

σ2 2P

where m is the expected value of the NPV σ2 is its variance L is a parameter which characterizes the ability of the company to accept risk and which represents the maximum acceptable loss which will not jeopardize the survival of the company; this sum can be estimated (relatively) easily by general management.

1. Charreton R, Bourdaire JM (1985) La décision économique. Que sais-je ?, PUF, Paris, France.

241

Chapter 6 Decision-making on exploration and production

When this method is adopted the safety margin used may vary between different divisions within a company, as a function of the risks to which the different activities are subject. A problem may occur if the same specific risk premium is applied to all the projects in a sector, when risks may in fact even vary for the different projects within a single sector. A strict application of the method may therefore lead to inconsistent decision-making. The use of a specific risk premium has another disadvantage. We saw earlier that the concept of the expected value is well suited to the study of small independent projects. Account only needs to be taken of risk in the case of large projects (or when projects are interdependent). Increasing the discount rate would lead to the same decision being taken, whatever the multiplier which one might choose to apply to the various cash flows for the project, on similar projects irrespective of their size. As a result, when a discount rate is adopted which incorporates a specific risk premium, the criteria which use this rate are never applied in a strict manner. Furthermore at present the oil industry appears to be using this device less than it has in the past. Where it is still being applied, lower risk premiums are being used (typically between one and a few percent). In any case an analysis is always needed of the risks and uncertainties applying to any project. In some cases a sensitivity analysis will suffice while in others, probabilistic calculations may be needed. There are techniques based on decision theory which permit the analyst to go beyond the multicriterion approach mentioned earlier.

Chapter 6 Decision-making on exploration and production

CONCLUSION Economic evaluations of investment projects using discounted cash flow are the rule in oil companies, as in other large corporations. It is important that these evaluations are carried out in a rigorous manner because, although the techniques are very simple, this very simplicity can lead the novice to forget the snares awaiting the unwary practitioner. We have mentioned a number of these traps: going, other things being equal, for the project with the highest rate of return when choosing between projects; unreflective use of a discount rate which includes a high risk premium; mixing values in current and constant prices, etc. Whether one sticks to a sensitivity analysis, always a must, or goes for more sophisticated techniques for analyzing risk, capital budgeting techniques are intended to summarise in a single or a small number of numerical values a large set of data. They are a tool for ensuring coherence between the assumptions used by different sectors in the company. Of course the economic evaluation is only one of the factors to be taken into account when making a decision, because it is never possible to quantify all the consequences of a decision. But the object should be for it to be used by all the different actors involved in investment projects: technical, financial and management specialists, etc. In this regard economic evaluation can provide a means of communication between specialists with different backgrounds: a genuine common language.

242

7

Information, accounting and competition analysis

In this Chapter we shall examine the issue of information on exploration and production activities, and how oil companies deal with this information in the context of their financial accounting. Management in this sector, like any other, relies on an information system so that they can steer the enterprise on a sound course, optimise its choice of projects and provide all the information needed for: – Investors who monitor the fortunes of the companies they intend to invest in, and who make use of competition analysis to benchmark performance; – Creditors and suppliers, who have to evaluate financial strength and creditworthiness; – Financial analysts, who appraise company performance with a view to advising potential investors; – Stock exchanges, when seeking a new stock market quotation; – Regulatory bodies, whose job it is to ensure that the company is in compliance with current regulations. These data are provided mainly in the form of a balance sheet, a profit and loss account, a statement of changes in equity, a cash flow statement and disclosures. These documents, mainly based on historical data, cannot claim to give a complete picture of the company, or, on their own, permit its worth to be measured. They must be interpreted with caution (for example a building bought several years ago appears in the balance sheet at its cost of acquisition rather its present value) and need to be supplemented with other information —including share price trends if the company is quoted on the stock exchange— and by qualitative information regarding non-quantifiable aspects. There are specific accounting issues which arise in relation to the oil and gas exploration/production sector, and it is vital to understand these so that all the information provided by petroleum companies can be used wisely. These specific issues result from the following characteristics of the sector: • The relationship between expenditure and revenue, both in terms of amounts and timing can

be very loose. A company may have invested $1 500 million (historical costs) in an oilfield 243

Chapter 7 Information, accounting and competition analysis

of 100 Mb, the value of which could collapse when production starts if the price of oil falls to $50/barrel or, conversely, soar if the price rises to $ 150/barrel. Furthermore the costs are incurred early on in the process, possibly extending over a period of 5–10 years, while the receipts which follow may be spread over a period of 10–20 years, or even more in some cases. The oil company will be required to provide information both in the short term (quarterly, yearly) and the long term (throughout the productive life of the oilfield). • The intrinsic value of a petroleum exploration/production company depends largely on the

size of its reserves. And yet when the company makes a discovery, this does not affect the assets in the balance sheet. • The sale price of hydrocarbons does not depend in any way on the seller. It is therefore

difficult for him to estimate the value of an oil or gas field, and yet he is required to carry out such an exercise to comply with various legal obligations. • Oil companies conduct their activities in association with other oil companies, and the

contracts that bind them to the host country are often specific, imposing particular constraints on data structures and the management of projects. This factor influences the way the company organises its internal accounting system. These difficulties make it an extremely complex matter for a financial analyst to carry out evaluations or comparative studies of the companies in the sector. However the history of the oil industry shows what a major role has been played by American companies, whose leading position is to reflect in the hegemony of United States of America Generally Accepted Accounting Standards ("US GAAP"') internationally. This situation has evolved due to the introduction of International Financial Reporting Standards ("IFRS") since 2005. Indeed, European listed companies have had to prepare their financial statements in compliance with IFRS since the beginning 2005. Many other countries are also choosing to adopt IFRS as their national regulatory bodies move to converge with the standards. The IFRS are becoming widespread and the oil and gas companies in Europe need to comply with these new standards. Furthermore, the leading international oil companies are all quoted on the New York Stock Exchange and are therefore bound by the requirements of the Securities and Exchange Commission (SEC). In this context, the knowledge of both US GAAP and IFRS is therefore essential, when examining non American companies' fmancial statements. We shall begin by analysing in detail the accounting principles governing investments, costs and oil and gas reserves, as well as depreciation and provisions. We shall then go on to look at information specific to the upstream petroleum sector which allows comparative studies of oil companies to be carried out. We shall begin with the information provided by oil companies in annexes to their annual reports, and will then define a Box 7.1 SEC (Securities and Exchange Commission). Companies quoted on the New York Stock Exchange have to submit a special form (form 10-K for US companies, form 20-F for other companies) to the SEC giving the balance sheet, profit and loss account and a statement of source and application of funds, all consolidated. Supplementary information is appended in annexes (analysis of fixed industrial and intangible assets, etc.) and, for oil companies, information prescribed by SFAS 69.

244

Oil and gas activities are dealt with by specific publications based on recommendations of the FASB. Their objective is to be able to measure the repercussions on the financial position of a company of the cost of exploration and development of oil and gas resources, and of the revenues from their sale. In 1977 the FASB published for the first time a SFAS (no. 19) requiring the oil industry to publish information about their oil and gas production activities. The term production includes extraction, gathering , processing and in situ storage. The following year a new concept known as “Reserve Recognition Accounting” (RRA) was introduced, based on the specifications of the SEC, published in the Accounting Series Release (ASR). This document requires that reserve data are published in the company’s financial statement, with an indication of forecast future production and associated expenses, accompanied by a very detailed description of past performance. This resulted in a financial statement not subject to standards, which led the FASB to propose a new standard in 1982, the SFAS 69, which defines the way in which the reserves and associated costs should be presented in an annex to the annual financial report. The recommendations in the SFAS 69 were accepted by the SEC. The definition of proven reserves in this document is largely based on the requirements of the U.S. Department of Energy. Box 7.3 IASB (International Accounting Standards Board). The International Accounting Standards Board was formed in 2001 and is an independent, private-sector body that develops and approves International Financial Reporting Standards (IFRS). The IASB operates under the oversight of the International Accounting Standards Committee Foundation. Concerning the European Oil and Gas companies, the IASB did not have time to develop a comprehensive standard on extractive industries in time for the entities converting to IFRS in 2005. Therefore, the IASB issued IFRS 6 in December 2004 and provided an interim solution by allowing entities to continue applying their accounting policy in respect of exploration and evaluation until a more comprehensive solution is developed. As a matter of fact, European Oil and Gas Companies have maintained their previous accounting principles such as SFAS No. 19 and SFAS No.69 as they did not conflict with IFRS.

number of indicators which can be constructed from these data. And finally we shall describe the many difficulties involved in using these data. For readers not familiar with accounting practices, an introduction to financial accounting is appended as an annex.

7.1 ACCOUNTING PRINCIPLES 7.1.1

Capital and operating costs

According to current usage, the term “capital costs” (or “investment costs”) is used during the exploration and development phase and the term “operating costs” during the production phase. These capital and operating costs relate to many different operations, as can be seen in Table 7.1. 245

Chapter 7 Information, accounting and competition analysis

Box 7.2 FASB (Financial Accounting Standards Board), SFAS 69 (Statement of Financial Accounting Standards).

Chapter 7 Information, accounting and competition analysis

Table 7.1 Costs in the upstream petroleum industry. Exploration Acquisition of mineral rights

Development (offshore) Development drilling Construction/ installation platforms

Preliminary studies Geological studies Seismic operations

Enhanced recovery: • wells • pumping equipment • other

Exploration drilling

(Flowline connectors)

Appraisal drilling/ delineation of discoveries

Production installations: • separation/processing • discharge • storage facilities

Production

Operating costs related to pumping, gathering, processing and storage systems

Transport costs

The distinction between an investment and an operating cost for the purpose of the accounts may not correspond exactly with the way these terms are used in everyday language. According to accounting principles (GAAP: General Accepted Accounting Principles), capital costs appear in the balance sheet and operating costs in the profit and loss account. While economists and accountants can agree on what constitutes a cost for the purpose of the profit and loss account, accountants may have different views about capital costs, depending on the method they apply. The U.S. accounting standard SFAS 19 provides for two methods of treating the exploration and development costs: the successful efforts method and the full cost method. Generally speaking the large integrated oil companies use the former method (at least for their consolidated accounts) and other companies, for example the American independents, prefer the latter. The two methods differ in their approach as to what is regarded as an investment during the exploration phase.

7.1.1.1 The successful efforts method In this method, only expenditure which leads directly to a successful discovery is capitalised. Let us consider each of the various categories of expenditure. A. Costs of mineral rights The costs incurred in acquiring mineral rights, for example the purchase of the licence, the payment of an exploration bonus, broking costs and legal costs are considered as capital costs. If the investments made do not result in a commercial discovery, they are written off from a provision set up for this purpose. B. Exploration and appraisal costs The preliminary studies and the geology and geophysics are charged directly against income –i.e. are not capitalised– because although these techniques provide fundamental information, they do not contribute directly to the discovery of oil and gas. 246

Successful efforts

Full costs

Capitalised

Capitalised

Geology/geophysics costs

Expensed

Capitalised

Costs of dry exploration well

Expensed

Capitalised

Costs of exploration well, productive or ongoing

Capitalised

Capitalised

Development costs (including dry development well)

Capitalised

Capitalised

Expensed

Expensed

Cost of acquiring mineral rights

Production costs

Apart from the purely accounting aspects, these two methods lead to differences in the overall results in terms of the annual profit/loss and the return on capital. When the full costs method is used, all the costs of an unsuccessful exploration are capitalised. As a result the book profit will be higher than that obtained using the successful efforts method (in which dry wells are treated as operating costs), but the return on capital employed will be lower.

The treatment of drilling costs depends on the outcome of the drilling: if the drilling is unsuccessful (dry well) the costs are treated as operating costs. If the results are successful, however, the drilling costs are capitalised. During the entire drilling period, the exploratory drilling costs are temporarily capitalized pending determination of whether the well has found proved reserves if both of the following conditions are met: – The well has found a sufficient volume of “not yet proved” reserves to justify, if appropriate, its completion as a producing well, assuming that the required capital expenditure is made in the course of the field development; – The company makes sufficient progress assessing the reserves and the economic and operating viability of the project. The final result of any exploration well is twofold: – The well will have added proved reserves : it will therefore be classified in the category of capitalized exploration; – The well has not found any proved reserves: its entire cost must be expensed. C. Development costs Development costs are the costs necessary to put the reserves discovered into production. They include seismic 3D analysis, which allows the field to be monitored dynamically, the drilling of production and injection wells, the installation of production and processing plant, gathering and storage systems and systems for transporting the product to the point of contractual delivery. These costs are directly linked to the reserves discovered, and are capitalised.

7.1.1.2 Full cost method This method provides for all exploration and development costs to be capitalised. The assets shown in the balance sheet are greater, for this method, than for the successful efforts method. 247

Chapter 7 Information, accounting and competition analysis

Table 7.2 Comparison of the successful efforts and full costs methods.

Chapter 7 Information, accounting and competition analysis

7.1.2

Reserves

7.1.2.1 SFAS 69 definition of reserves The reserves of hydrocarbons, which form the most important asset of oil companies, are not included in the balance sheet (except for purchases of reserves, which are included at their purchase value). Since 1982 however, the SFAS 69 specifies how information on reserves should be disclosed in the companies Annual report (booked reserves). The figures given relate to the proven reserves, i.e. the quantities of hydrocarbons the recovery of which from known reservoirs is regarded as “reasonably certain” in present technical and economic conditions.

A distinction is made between reserves of liquids (oil plus natural gas liquids) and of gas. The units are millions of barrels (Mbbl) for liquids and billions of cubic feet for gas. Conversions are based on energy equivalence, and every company uses its own ratio, depending on the quality of its gas. The conversion rates vary between 5 300 and 6 000 ft3/bbl. Variations in the amount of the reserves compared with the previous year must be allocated between six categories: 1. Changes resulting from an improved knowledge of the reserves (due to the drilling of a new development well, for example), or a change in the economic environment; 2. Enhanced (secondary or tertiary) recovery (injection of water, associated gases, steam, inert gas, etc.); 3. Enlargement and discoveries resulting from the exploration of an uninvaded or virgin zone, or from delineation beyond the perimeter of the proven reserves; 4. Acquisition of proven reserves; 5. Sales of proven reserves; 6. Production during the year. It is not always easy to make this allocation, and in practice there is a certain degree of freedom in the choice of category. A further complication is that a distinction has to be made between developed proven reserves (quantities which can be produced from existing installations and wells, without any further development) and those not developed. It should be noted that the SFAS 69 advocates identifying separately those reserves coming from subsidiary companies fully or proportionally consolidated (first category), and subsidiary companies consolidated by the equity method (second category). The SEC definition of reserves based on the notion of “reasonably certain” recovery, may give rise to problems of interpretation. Each company will have its own policy on accounting for its reserves. A very cautious company will always retain the most conservative estimate of its reserves as knowledge develops about the field. Others will post a best estimate , subsequently correcting this figure as needs be.

7.1.2.2 Reserves and the taxation/contractual basis The concept of reserves as understood by a petroleum accountant is very different from the physical reality of volumes of hydrocarbons discovered. First of all, he only recognises the existence of proven reserves; the concept of probable or possible reserves appears too uncertain for him. He therefore takes a strictly deterministic view of reserves, forgetting that part of the probable and possible reserves may become proven reserves in the future. Furthermore he will take account of the tax system applied to the 248

The Society of Petroleum Engineers (SPE), the American Association of Petroleum Geologists (AAPG) and the American Petroleum Institute (API) have made recommendations with regard not only to proven reserves but also to probable and possible reserves. These recommendations made by the petroleum industry are very close to those proposed by the SEC. Other efforts have been made at the international level to formulate acceptable definitions of reserves. In 1987, for example, the SPE published new definitions, including an extended discussion of the concept of “present economic conditions” and the need for the reserves to be “commercially viable”. At the World Petroleum Congress (WPC) in 1983 a working party drew up a nomenclature for reserves, confirmed at the 1987 WPC, which resulted in the report “Classification and Nomenclature Systems for Petroleum and Petroleum Reserves”. This WPC report, together with the 1987 SPE definitions, is widely used by government agencies (Nigeria, Syria, Venezuela) and oil companies (BP, Chevron) which use it as a reference point for their own definitions of reserves. None of these definitions permits a probabilistic calculation of reserves. In 1997 the SPE and the WPC jointly published a set of definitions which refer to both deterministic and probabilistic techniques. On December 31, 2008, the SEC issued its revised disclosure requirements for oil and gas reserves. The final rule and interpretations was published on January 14, 2009 (Final Rule). The Final Rule modifies the SEC’ s reporting and disclosure rules for oil and gas reserves by, most notably: – changing the pricing assumptions from the prior use of single day year-end price to the use of average prices during the 12-month period prior to the ending date of the period covered by the SEC report; – permitting voluntary disclosure of Probable and Possible reserves; – expanding the range of acceptable technologies used to reliably estimate a company’ s reserves; – requiring disclosure of reserves in each foreign country where more than 15% of a company’ s global proved reserves, in barrels of oil equivalent, are situated; – requiring the disclosure of the qualifications of those persons responsible for a company’ s estimates and audits.

production of the reserves in question in order to determine the amount of the reserves which will be disclosed in the financial statements. This means that a company operating under a lease will not enter the same amount as one with a production-sharing agreement. Historically, the first system to be adopted by producer countries was the system of leasing. The idea is only to take credit for the proportion of the reserves which it effectively owns. A leaseholder therefore only takes account of its interest in the field after deducting the royalty, paid in kind as remuneration to the owner of the site. The reserves in this case therefore correspond to proven reserves net of royalty. In certain leasing systems royalties can be considered as a tax on production, and are therefore not deducted from reserves. In this case the reserves are the gross figure. In this system, of course, in addition to producing the reserves and paying the royalties, the leaseholder also pays 249

Chapter 7 Information, accounting and competition analysis

Box 7.4 Historical background to the different definitions.

Chapter 7 Information, accounting and competition analysis

one or more “petroleum” taxes each year which are charged against income in the profit and loss account; the reserves accounted for before these payments are therefore gross of tax. The advent of new fiscal regimes has further complicated this system of accounting. Production sharing contracts (PSCs) began to be developed with effect from 1966. In this system the oil company is a contractor, and only owns part of the production; it can therefore only bring that part of the reserves into its accounts, i.e. the cost oil (the repayment of all its costs) and its share of the profit oil. The rest of the profit oil accrues to the State, and is therefore not accounted for as the reserves of the oil company. Some PSCs, however, regard the State’s share of the profit oil as a tax, and the company can then include the total profit oil in its reserves. The reserves announced therefore correspond to “access to hydrocarbons”. In order to quantify them, financial modelling of the contract until the end of the field life is required. Finally, in the case of a service contract the contractor is reimbursed his expenses and remunerated financially rather than in kind. He never owns the reserves, and does not therefore include them in his financial statement. Contracts of mixed type are becoming more and more common, and it is not always easy to decide in which fiscal category a particular set of reserves fall. In order to decide, oil companies refer to rules laid down by the SEC to guide them as to what should be accounted for as reserves. These rules reiterate the matters which need to be dealt with in an international agreement or contract if proven reserves are to be identified and disclosed. These include the right to extract oil or gas, the right to take payment in kind, exposure to risk (technical and economic) through its activities and a clear mineral interest. In addition, the rules draw up a list of specific elements which do not require to be identified and disclosed as proven reserves. These include interests limited to the right to purchase certain volumes of hydrocarbons, supply or factoring agreements, services or financing which do not involve any risk or in which a clear mining interest is not involved. The main theme in the foregoing is related to risk and reward: the reward must be linked to a risk (technical and economic) if the company is to disclose an item as reserves.

7.1.3

Depreciation and provisions

In this section we shall only deal with those aspects of depreciation and provisions specific to the upstream petroleum sector. More general material on depreciation, and details of straight-line and declining balance depreciation will be given in the Annex to Chapter 7. We shall therefore deal with depreciation by the unit-of-production method recommended by the SEC and the FASB for investments in the upstream petroleum industry in consolidated accounts. We shall then look at depreciation for projects still in the development phase (slot ratio and reserve ratio) and will finally consider provisions for decommissioning and site rehabilitation.

7.1.3.1 Depreciation by the unit-of-production (UOP) method This method of depreciation considers that wear and tear to equipment is proportional to the quantity produced by the equipment. In the case of exploration and production activities this is not the production installation but the quantity of hydrocarbon reserves. The investments are amortised at a rate proportional to the consumption (or depletion) of the reserves. 250

The depreciable balance or net capitalised assets are multiplied by this rate to find the amount of the depreciation. Table 7.3 shows the depreciation profile obtained, based on an investment of $100 million and initial developed proven reserves of 100 Mbbl. It is assumed that the reserves are not re-evaluated during this time.

Table 7.3 Depreciation by the unit-of-production method. n

n+1 n+2 n+3 n+4 n+5 n+6 n+7 n+8 n+9 Total

Production (Mbbl)

10

20

20

15

10

7.5

7

Reserves on 31 Dec. (Mbbl)

90

70

50

35

25

17.5 10.5

5

3.5

2

5.5

2

0

Rate of depletion (%)

10.0 22.2 28.6 30.0 28.6 30.0 40.0 47.6 63.6 100

Capital cost ($ millions)

100

Net capitalisation at 31 Dec.1 ($ millions)

90.0 70.0 50.0 35.0 25.0 17.5 10.5

5.5

2.0

0.0

Depreciation ($ millions)

10.0 20.0 20.0 15.0 10.0

7.5

7.0

5.0

3.5

2.0

Depreciation ($/bbl)

1.0

1.0

1.0

1.0

1.0

1.0

1.0

1.0

1.0

1.0

100

100

1. The net capitalisation on 31 December in year n is equal to the net capitalisation on 31 December in year n-1, plus new investment in the year minus depreciation in the year.

It can be seen in this example that that the depreciation in terms of its absolute value varies tremendously over time, but is constant on a per barrel basis. In practice the exercise is somewhat more complex because the estimated volume of the reserves is subject to constant revision, and these changes have to be incorporated into the calculation. These variations result not only from production but also from successive re-evaluations, due particularly to improved knowledge of the field as new investments are made. Some of the probable and possible reserves, for example, will become proven reserves (there is a 90% likelihood that actual production will exceed proven reserves). 251

Chapter 7 Information, accounting and competition analysis

The depreciation rate is calculated according to the following formula: production of hydrocarbons from field in year n Depreciation rate = production in year n + reserves on 31 December in year n The reserves in question are the proven reserves but, depending on the costs being depreciated, a distinction must be made as follows: – Cost of acquiring licence: depreciation based on developed and undeveloped proven reserves; – Capitalised exploration drilling and development costs: depreciation based on developed proven reserves.

Chapter 7 Information, accounting and competition analysis

Table 7.4 UOP depreciation.

n

n+1 n+2 n+3 n+4 n+5 n+6 n+7 n+8 n+9 Total

Production for year (Mbbl)

10

20

20

15

10

7.5

Reserves on 31 Dec. (Mbbl)

40

45

50

35

25

17.5 10.5

7

5

3.5

2

5.5

2

0

Rate of depletion (%)

20.0 30.8 28.6 30.0 28.6 30.0 40.0 47.6 63.6 100

Investment ($ millions)

100

100

Net capitalisation on 31 Dec. 80.0 55.4 39.6 27.7 19.8 13.8 ($ millions)

8.3

4.4

1.6

0.0

Depreciation ($ millions)

20.0 24.6 15.8 11.9

7.9

5.9

5.5

4.0

2.8

1.6

100

Depreciation ($/bbl)

2.0

0.8

0.8

0.8

0.8

0.8

0.8

1.0

1.2

0.8

0.8

These changes can also come about as a result of the impact of changes in the economic environment on the profitability of production, either forcing the company to cease production earlier than anticipated or, conversely, allowing it to continue production. It should not be forgotten that reserves are no more than the sum of the quantities produced in each year from the first year of production to the last. Table 7.4 shows the depreciation profile obtained, based on an initial investment of $100 million and initial developed proven reserves of 50 Mbbl. It is assumed that the estimated reserves are increased by 25 Mbbl in year n+1 and a further 25 Mbbl in year n+2. It can be seen that these upward adjustments in the estimated reserves result in higher depreciation in the early years.

7.1.3.2 Slot ratio/reserve ratio for projects in the development phase A problem arises in relation to development installations used to produce from a field where some of the reserves have already been developed and others still remain to be developed. Typical examples of this kind of situation would be an offshore production platform ready to start production, while development wells still remain to be drilled, or a satellite field put into production using installations set up for the main field. It is possible to apply a reduction to the value of the installations to be depreciated so as to ensure consistency between the amount of the depreciation and the volume of the reserves associated with the appropriate investments. The reduction coefficient can be taken: – Either as the slot ratio, i.e. the ratio of the number of the wells actually drilled to the number expected; Slot ratio = number of wells drilled number of wells planned 252

Reserve ratio = developed proven reserves (end of the year n) + production year n proven reserves (end of the year n) + production year n These two definitions lead to different figures, as the following example shows: – An offshore production platform is constructed at a cost of $100 million; – An exploration well and two appraisal wells were drilled before development, at a total cost of $20 million; – The number of development wells planned is 22; – The total proven reserves amount to 30 Mb; – On the 31st of December n, three development wells had been drilled; – Production began in year n, amounting to 500 000 barrels; – The developed reserves as at the 31st of December n amounted to 5 Mbbl, i.e. 5.5 Mbbl originally, less production in year n. The capital costs therefore amounted to $120 million (successful exploration well, appraisal well and production platform), and have led to the discovery of oil and the construction of production installations for the entire oilfield. However since only part of the reserves have been developed, only part of these investments will be amortised: • based on the number of wells drilled, the slot ratio is equal to:

wells drilled/wells planned = 3/22 = 13.6%, i.e. 13,6% × 120 = $16.4 million. • based on the reserves, the reserve ratio is: developed reserves/total reserves = 5.5/30 = 18.3%, i.e. 18.3% × 120 = $22 million. The capital costs adjusted by one of these two ratios are then depreciated by the unit-ofproduction method based on the developed proven reserves.

7.1.3.3 Provision for decommissioning and site rehabilitation These costs relate to the estimated costs of dismantling and removing the equipment and rehabilitating the site less the value of any materials recovered. This work is generally carried out after production from the field has ceased, and the costs cannot therefore be amortised from future production. In accordance with US GAAP (SFAS No.143 Accounting for asset retirement obligations) and IFRS (IAS 37 Provisions, contingent liabilities, and contingent assets), liabilities for decommissioning costs should be recognised in the balance sheet when a company has an obligation to dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reasonable estimate of that liability can be made. The estimate of the fair value of the retirement obligation should incorporate the best information available and should be discounted using a credit adjusted riskfree interest rate for maturity dates that coincide with the expected cash flows. A corresponding item of property plant and equipment of an amount equivalent to the provision is also created. This is subsequently depreciated over the useful life of the facility or item of plant The decommissioning provisions are updated at each balance sheet date and any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding property, plant and equipment. 253

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– Or as the reserve ratio (beginning of the year), i.e. the estimated ratio of developed proven reserves to the total proven reserves:

Chapter 7 Information, accounting and competition analysis

7.2 COMPETITION ANALYSIS IN THE UPSTREAM PETROLEUM SECTOR Evaluating performance and benchmarking it against that of other companies in the same sector is one of the basic tools used by management. A comparative analysis of methods within the different divisions of a company, but also with a sample of other comparable enterprises, permits the company to be evaluated and its weak points identified, so that improvements can be made. Competition analysis has been in use for many years and was formalised in the 1990s in order to understand what others are doing and to learn from their experience. In order to carry out a competition analysis, the following are necessary: – Decide what is going to be compared; – Define the indicators to be used; – Decide on the internal sectors/subsidiaries and the other companies which will form the sample for the study; – Collect the data; – Analyse the divergences between the companies in the sample, and infer areas where improvements to one’s own company can be made; – Regularly update the data used. The most difficult task is to gather together data which are reliable and span a number of years. The best course is always to gather the data from source, i.e. from the company itself. Apart from internal documents, not accessible to the outsiders, the material published by the company and in the public domain are the most appropriate source. This includes annual reports, published by all companies, supplements containing statistical and operational material, produced by only some companies, and forms 10-K (American companies) or 20F (non-American companies), only available for companies quoted on Wall Street. The material of particular interest in these publications is the “supplemental information on oil and gas producing activities” in accordance with SFAS 69. In this document items from companies subject to full consolidation are fully included, whereas items from companies subject to consolidation by the equity method are included in proportion to the percentage interest of that company in the specific area concerned. The figures are broken down by geographical zone. It should be noted that the geographical classification is not fixed, and can differ from company to company, depending on its area of activity and preferred presentation. Using this information, various indicators of performance can be evaluated for a company operating in the upstream petroleum sector.

7.2.1

Supplemental information on oil and gas producing activities appended to the balance sheet

These include seven categories of information (unaudited). 1. Capitalised costs related to oil and gas producing activities. 2. Costs incurred in exploration, property acquisition and development. 3. Results of operations for oil and gas producing activities. 254

reserves. 6. Changes in the standardised measure of discounted future net cash flows. 7. Other information.

7.2.1.1 Capitalised costs related to oil and gas producing activities This category comprises the capitalised costs (excluding assets disposed of) net of all past provisions for depreciation. It begins with a statement of the gross capitalised costs, broken down between: – The acquisition of underground reserves, successful exploration (that is the costs of all exploration which led to the discovery of oil or gas) and development. These costs relate to proven reserves; – The capitalised costs relating to unproven reserves (acquisition of mineral rights). The total depreciation and past provisions are subtracted from the total of these costs in order to obtain the net capitalised costs.

Box 7.5 Impairment test (ceiling test). In accordance with US GAAP (SFAS No. 144 Accounting for the Impairment or Disposal of Long Lived Assets) and IFRS (IAS 36 - Impainuent of assets), a company needs to review the recoverable amounts of its property plant and equipment in order to ensure they are not overvalued in the balance sheet. Indeed, the objectives of these standards are to prescribe the procedures that an entity applies to ensure that its assets are carried at no more than their recoverable amount. An asset is carried at more than its recoverable amount if its carrying amount exceeds the amount to be recovered through use or sale of the asset. If this is the case, the asset is described as impaired and the standard requires the entity to recognise an impairment loss. In order to measure the ùnpairment loss, the company should calculate the economic value based on future cash flows and on a certain number of assumptions: – The price of oil and gas from the field (usually assumptions in the long term plan of the company considered); – Proven and probable technical reserves; – Capital and operating costs estimated on the basis of these proven and probable reserves including the decommissioning costs; – No allowance for cost of servicing capital or inflation; – A discount rate chosen by the company (usually between 4 and 10%). If the carrying amount exceeds the economic value, an impairment loss is recognised in the income statement. This test is not applied systematically. The calculation is only performed when there is a definite risk of non-recovery of the book value of the investments (reduction in reserves, cost overruns or changes in tax regime). Furthermore companies are allowed a lot of latitude as to how they perform the calculation (reserves, price of hydrocarbons, discount rate).

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4. Reserve quantity information. 5. Standardised measure of discounted future net cash flows related to proven oil and gas

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7.2.1.2 Costs incurred in exploration, property acquisition and development This category represents past expenditure, whether capitalised or expensed, broken down into three different categories: – The acquisition of mineral rights, distinguishing between proven reserves and other purchases; – Exploration costs; – Development costs. All oil companies present these three categories by geographical zone, but in varying degrees of detail. By aggregating the values given over all the different companies, this category allows overall trends in expenditure in the oil and gas exploration and production sector to be monitored at the global level.

7.2.1.3 Results of operations for oil and gas producing activities This category shows the value and direct costs of oil and gas production before capital servicing costs and head office overheads. As a result, the operating result thus obtained does not necessarily reflect the contribution of these operations to the group’s consolidated results for oil and gas activities. On the other hand it has the advantage of allowing the performance of the company to be evaluated separately from its mode of financing (equity or debt). The following categories are distinguished: – Revenues, including hydrocarbon sales and transport earnings (gas pipelines). Hydrocarbon sales can be gross or net of royalties and, for a production-sharing contract, gross or net of the State’s share. When the gross value is given, the royalties or the State’s share are included as costs. However the figures are presented, the net value remains the same. A distinction needs to be made between sales to third parties and transfers between companies within the group; – Production costs, which can include not only the technical costs but also sometimes the committed costs, and taxes on production; – Depreciation by the unit-of-production method and provisions (after recoveries) for the year; – Exploration costs (geology, geophysics, “dry” exploration); – Other revenues and costs (losses or gains on transfer of assets, products and costs related to transport activities); – Taxes, calculated arbitrarily by simply applying a mean rate (calculated in the country concerned) to income from producing activities. These are not the amounts actually paid; – The results of oil and gas producing activities before financing costs and overheads. Revenues – production costs – depreciation – exploration costs ± other revenues and costs = pre-tax income from producing activities – income tax = Results of oil and gas producing activities 256

7.2.1.4 Reserve quantity information The definition of reserves adopted here is that of SFAS 69 (see Section 7.1.2.1), consistent with the SEC standards. It comprises the total of both the developed proven and developed unproven reserves, and a breakdown of the annual variations. This amount will be included in the following tables in order to calculate the standardised measure of discounted future net cash flows and changes in this measure.

7.2.1.5 Standardised measure of discounted future net cash flows related to proven oil and gas reserves This category refers to the net present value, discounted at 10% p.a., of the proven reserves of the company as at the 31st of December, based on a number of computational assumptions. • The estimates are based on the proven reserves to be produced, accompanied by a forecast

of the production profile. This calculation is carried out using the economic conditions at the year-end, and assume that all the reserves will actually be produced. • The estimated discounted net future flows from the proven reserves are valued on the basis

of posted prices at year-end, except in cases where the existing contracts provide for fixed and determinable revaluations of the prices. • The estimated production costs (including, where appropriate, transport costs and taxes

on production), future development costs and decommissioning costs are deducted from future flows. All estimates are based on year-end economic conditions. • The estimates of future taxes on profits are based on the legal tax rate in force locally at

the year-end. A number of objections can be made to this calculation, for example, as follows. The assumption regarding the price is questionable. Companies operating in seasonal gas markets, for example —particularly in the United States— with prices which are higher in winter, and therefore on 31 December, the reference date for prices —will produce higher present net values. Only the proven reserves are allowed for. This is rather a pessimistic scenario, since the eventual reserves are very likely to exceed the proven reserves only. The future capital and operating costs are not those provided for in the basic scenarios used by the oil companies. The latter allow for the development and production not only of the proven reserves but also of a part of the probable and possible reserves, producing higher values for production and costs. The tax calculation is an estimate only; often the actual tax calculation is affected by activities beyond the confines of the field being considered. The methods used for arriving at this estimate vary between companies, which makes comparison difficult. The use of a single discount rate does not take account of differences in the real cost of capital to the companies holding the reserves. On the other hand the use of a standardised value allows inter-company comparisons.

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The most difficult aspect of this calculation is calculating tax. This is purely theoretical, and does not correspond to the real tax situation of the company (no account taken of losses in previous years brought forward to the current exercise, tax-allowable provisions different from book provisions, etc.). The result obtained is therefore a notional value which allows the results of different companies to be compared independently of their tax situation and their financing method.

Chapter 7 Information, accounting and competition analysis

7.2.1.6 Changes in the standardised measure of discounted future net cash flows This category assists in reconciling the measure of net present value in successive years. Apart from the turn over and the costs for the year, which have to be deducted from the net present value in the earlier year, because they no longer form part of the future, there are many other factors which contribute to the change. These various sources of difference fall into two main categories. The first category of changes to the net present value can be regarded as “constant perimeter changes”, i.e. changes which relate to the reserves as they were in the previous year. Sources of variation in this category include: – A different price of oil and/or gas on 31 December; – A re-evaluation of future production and development costs (new technology, improved knowledge of reservoirs); – The effect of discounting to a different reference year (one year later); – A variation in tax (not allowing for any change in production) resulting from a change in prices or in the tax rates. The second category of changes are related to changes the estimated size of the reserves as a result of acquisitions or sales, enlargement and new discoveries or modified estimates. This category demands careful application. For example it includes in the same category variation resulting from price changes in oil and gas (which affect the size of the reserves because of the change in the economics) and changes in costs.

7.2.2

Indicators

A number of indicators can be constructed from the “supplemental information on oil and gas producing activities” in oil companies’ annual reports, so that their exploration and production performance can be compared.

7.2.2.1 Reserve replacement rate This indicator is obtained by taking the ratio of the additions to proven reserves announced over a given period to the total production during the same period. addition to proven reserves in period p total production in period p Additions to reserves include discoveries and enlargement, revisions, enhanced recovery and, if appropriate, net purchases. The period generally adopted is five years. A company with a replacement rate of 100% has replaced what it has produced by an equal number of barrels of future production. It can be said to have replenished its stocks. When assessing this parameter at the global level, purchases and sales of reserves have to be excluded because these are merely inter-company transfers, and do not create new reserves. The calculation can also be performed by geographical zones, and separately for oil and gas. The larger the reserves held by a company, the harder it is for the company to maintain this rate at 100%.

258

This indicator is the ratio of production in the year concerned to the amount of the reserves at the beginning of the year. These reserves are calculated by adding the production in the year to the reserves at the year-end. production in year n production in year n + reserves on 31 Dec. of year n This parameter represents the rate at which the company is producing its developed resources. In terms of equipment, this ratio comprises the depletion coefficient used in calculating depreciation by the unit-of-production method.

7.2.2.3 Intensity of exploration and development investment There are two ratios which express the level of investment that the company will commit regarding its activity in a given period (usually between 3 and 5 years so as to smooth the result). The activity is represented by the quantity of hydrocarbons produced net of royalties. If only exploration investment is taken into account, we obtain the intensity of exploration: exploration investment in period p production net of royalties in period p In the same way, the intensity of development investment can be measured by including only development investment in the numerator. development investment in period p production net of royalties in period p

7.2.2.4 Finding cost The finding cost seeks to measure the expenditure a company has had to commit to find a barrel of oil or its gas equivalent. The principle appears simple, but a number of questions arise: • Which costs should be included? • Were the costs calculated according to the successful efforts or the full cost method? • Which reserves should count: discoveries, acquisitions, revisions, enhanced recovery? • If revisions and enhanced recovery are included, to which year should these quantities be

attributed: the year of discovery or the year of modification? • What time period should be taken? • What equivalence coefficient should be used between barrels and cubic feet? • Should the calculation be carried out at global level, by geographical zone or by sedi-

mentary basin? The source information, i.e. the six categories of “supplemental information on oil and gas producing activities”, was not intended for this calculation. Every company, depending on its accounting methods or the image it wishes to project, and every financial analyst (depending on the information he possesses) will use a different definition of finding cost. 259

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7.2.2.2 Depletion rate

Chapter 7 Information, accounting and competition analysis

In fact there are three competing definitions: – Exploration costs/additions to reserves (excluding revisions); – Exploration costs/additions to reserves (including revisions); – Exploration and development costs/additions to reserves (including revisions and enhanced recovery). The last definition is very deceptive, because it includes development. Some companies may occasionally include purchased reserves in the calculation. Since the purpose of this ratio is to determine how efficient the company is at finding reserves in its exploration activity, it seems illogical to include the purchase of reserves (purchase cost in the numerator and number of barrels purchased in the denominator) or enhanced recovery (cost of enhanced recovery in the numerator and additional number of barrels recovered in the denominator).

7.2.2.5 Finding and development costs This indicator is calculated by dividing the exploration and development costs for a given period by the proven reserves associated with the discoveries, as well as enlargement, revisions and enhanced recovery announced during the same period. This ratio is also equal to: exploration intensity + development intensity reserve replacement rate (excluding purchases)

7.2.2.6 Reserve replacement cost This cost is obtained by adding the cost of licence purchase (proven and unproven reserves) to the items included in the calculation of the finding and development costs. Finding costs, finding and development costs, reserve replacement costs The main difficulty in calculating these cost indicators is to ensure consistency between the numerator and the denominator. Over a period of three to five years we cannot hope to be able to link directly all the expenses in the numerator with all the reserves in the denominator. Certain expenditures now will permit reserves to be found at a later date, and conversely some of the reserves in the denominator are the result of expenditure well before the period in question. Finally, these ratios only make sense for fully or proportionally consolidated entities. Where consolidation has been carried out by the equity method, the reserves will be included in the denominator, but the corresponding costs will not be included in the numerator.

7.2.2.7 Barrel-based ratios These involve relating various items from the profit and loss account to the number of barrels produced (the production is expressed in accordance with the SEC standard, and is therefore net of royalties). In the same way as the reserve-based ratios, these ratios are only meaningful when applied to companies subject to full or proportional consolidation. The following elements can therefore be calculated: 260

Barrel-based ratio Mean revenue per barrel Production cost per barrel Depreciation per barrel

Non-capitalised exploration costs per barrel Pre-tax profit per barrel After-tax profit per barrel

7.2.2.8 Impact of contract types on the ratios In the same way as for the figures for the reserves appearing in the accounts, certain items in the profit and loss account and the corresponding per barrel ratios depend heavily on the fiscal and contractual system applying: the results will differ depending on whether the reserves are produced under a lease or a production-sharing contract (PSC). Let us consider the following four cases, the first a lease and the other three PSCs (for details on how various types of petroleum contract work, see Chapter 5). – A lease, royalty 20%, tax 85%: a standard lease. The reserves (which are simply the sum of the production each year) appear in the accounts net of royalties. – A PSC, cost oil 50%, profit oil 10%: a standard PSC. The reserves appear in the accounts net of the State’s profit oil. – A PSC, cost oil 50%, profit oil 10%, the State’s profit oil is included in the reserves. The profit oil is treated as a tax (“tax oil”), and therefore increases the figure for the reserves which appears in a standard PSC. – A PSC, cost oil 50%, profit oil 20%, tax on profit oil 50%, State’s profit oil excluded from the reserves. We assume that in the case of the PSCs, the excess cost is shared between the State and the company by using the same split as for the profit oil.

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Profit and loss account items Turnover – production costs (taxes on production generally included, as is royalty) – depreciation (the SFAS 69 standard advocates also including exceptional items and provision for site rehabilitation) – exploration costs (in accordance with the successful efforts method) ± other revenues and costs = operating profit / loss before tax – taxes on profits Net operating profit / loss

Chapter 7 Information, accounting and competition analysis

1 600

Net profit / Company profit oil

1 400

State profit oil Tax oil

1 200

Taxes on profit 1 000

Royalties Depreciation

800

Production costs 600 1: Lease 400

2: Standard PSC 3: PSC (tax oil)

200

4: PSC with tax

0 1

2

3

4

Figure 7.1 Under each of the four contractual bases the company’s net profit is the same. But the operating profit and all the per-barrel ratios are totally different. This means that comparisons of these parameters will not be relevant unless the analyst has a detailed knowledge of the contractual and tax systems used in the calculations.

Here are the other assumptions used in the analysis – production for the year ............................................................................

100 Mbbl

– sale price ..................................................................................................

$15/bbl

– production costs (recoverable in the year).............................................. $200 million – annual capital expenditures (CAPEX) depreciation ............................... $400 million Table 7.5 summarises the results for the company and the per-barrel ratios calculated by applying these contractual bases to the same field.

CONCLUSION All these indicators are useful in giving an appreciation of the value of a company, but they give greater insight into the past than the future. Furthermore they are calculated on the very conservative basis of proven reserves only. The most appropriate method would be to calculate expected future cash flows, extended to include all reserves, that is, allowing for: – The portfolio of fields currently under development or in production; – The portfolio of fields not yet developed; – Expected discoveries related to the company’s exploration activities. An analysis as described above needs to be complemented by a study of market-related factors, such as the market capitalisation of the company, the market value of its reserves 262

No. 1 Lease

No. 2 Standard PSC

No. 3 PSC (tax oil)

No. 4 PSC + tax

Quantities of crude sold Net quantities sold

Mb Mb

100 801

463 46

1005 100

527 52

Gross turnover Royalties Production costs Depreciation Operating profit Tax (and/or tax oil) Net profit

$M $M $M $M $M $M $M

1 500 300 200 400 600 5102 90

6904

1 500

7804

200 400 90 90

200 400 900 –8106 90

200 400 180 908 90

2.5 5.0 7.5 1.1

4.3 8.7 2.0 2.0

2.0 4.0 9.0 0.9

3.8 7.7 3.5 1.7

Production costs/bbl Depreciation/bbl Operating profit/bbl Net profit/bbl

$/bbl $/bbl $/bbl $/bbl

1. Total production less royalty, i.e. 100 – (100 × 20%) = 80 Mbbl. 2. (1 500 – 300 – 200 – 400) × 85% = $510 million. 3. Company cost oil + profit oil. Cost oil = production costs + depreciation = $200 + 400 million, which must be converted into barrels, so divided by the sale price of $ 15/bbl = 40 Mbbl, total profit oil = (100 – 40) = 60 Mbbl, i.e. a profit oil for the company = 60 × 10% = 6 Mbbl. 4. Cost oil + profit oil by value, i.e. $600 million + 6 Mbbl × $15/bbl = $90 million, i.e. $690 million in total. 5. The State’s profit oil (tax oil) is considered a tax, and is included in the production and reserves figures in the company’s accounts. 6. Tax oil, i.e. (100 – 40 – 6) Mbbl × $15/bbl = 54 × 15 = $810 million. 7. Cost oil + company profit oil. Cost oil = (200 + 400)/15 = 40 Mbbl, profit oil = (100 – 40) × 20% = 12 Mbbl. 8. 180 × 50% = $90 million.

as reserves if there is an active market serving as a reference, and indeed the analysis of information from other sources such as: – Press releases of the companies circulated by press agencies such as AFP or Reuters, and which are available on the companies’ Internet sites. These releases may give quarterly results or information on the strategies of the company; – Specialised publications produced by consulting firms or financial analysts, in the form of inter-company comparisons; – Computerised databases offered by consulting companies, for example giving the reserves held by the companies.

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Table 7.5 Per-barrel ratios for different contractual bases.

Annexe to Chapter 7 Basic principles of financial accounting

Financial accounting collects and organises information needed by a business and compiles it according to certain principles, as follows: • Historical costs: accounting documents are maintained in actual historical costs (current

prices), without correcting for inflation or discounting. • Methodological consistency: accounting methods must remain constant over successive

accounting periods. Any change must be justified. • Continuity: The keeping of accounts is obligatory, even where a company has not had any

activity during an accounting period. • Independence of accounting periods: accounts are closed off at the end of each accounting

period, so that the results for that period can be obtained. • Due care: the accounts must allow for foreseeable future risks. • Good faith: the accountants must act in good faith.

The purpose of financial accounting is to provide a periodical snapshot of the company’s situation in accordance with the chart of accounts or other contractual document (annexes to accounts). The position with regard to the assets and liabilities of the company is summarised in the balance sheet which provides information on the overall worth of the company on the date as at which it was drawn up. The consumption and production of the enterprise are dealt with by accounting for the costs incurred and revenues earned in the accounting period in which they occur, the results being shown in the profit and loss account (change in the worth) for that accounting period. Capital operations are shown in the funds flow statement. Furthermore, additional information can be shown in the disclosure of the Financial Statements. The purpose of the basic accounting principles as applied in drawing up the balance sheet and the profit and loss account (and the disclosures) is to give a true and fair view of the company’s financial position. These accounts are verified by independent auditors.

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7A.1 THE BALANCE SHEET In order to carry out projects a company needs to create wealth and make the necessary investment, allowing it to produce and market.

7A.1.1 Assets Investment involves creating the means of production. These may be tangible, such as purchased or constructed equipment, whether replacement, expansion or diversification; or they may be intangible, such as know-how, patents, etc. There are two major types of assets: • Durable assets of the company whether goods, rights or claims: land, buildings, indus-

trial equipment, vehicles, patents, mineral rights, etc. These are called fixed assets. These fixed assets appear in the balance sheet at their book value, that is, their cost of acquisition less depreciation (see profit and loss account). They may include securities, such as shares in other companies, and goodwill. Goodwill is the excess of an enterprise’s fair value over its book value at the date of acquisition. • Capital used in the company’s operating activities or in short term operations. These are

known as the current assets. They meet various needs (a) to have a certain quantity of raw materials, energy and services in hand in order to initiate operating activities, (b) to fund the requirements resulting from the delay between the time when expenditure is incurred in connection with an operation and the receipt of the corresponding revenue (working capital) and (c) the need for liquid funds. These assets fall into the following three categories: – Stocks (non-capitalised), including raw materials, work in progress and finished products. Stocks are generally either merchandise destined for sale or products which will be used to manufacture this merchandise; – Accounts receivable: these are invoices issued and credited but still unpaid at the date of the balance sheet. This amount can be considered a credit extended to customers which needs to be financed (trade debtors); – Liquid assets comprising cash balances or equivalent, such as cash accounts, bank deposits and short-term investments which can be realized rapidly. All these investments are included as assets in the balance sheet. They represent the total assets which need to be financed.

7A.1.2 Liabilities Liabilities refer to all the sources of finance. There are effectively three forms of finance. • Equity capital i.e. the financial resources provided by the shareholders. These are the funds

subscribed by investors when the shares were issued and retained earnings, i.e. earnings which have not been distributed in the form of dividends (reserves). These funds have to be remunerated, either by dividends or an increase in the value of the shares. Equity capital is made up of shareholders’ equity and minority interests. • Long-term debt, made up of loans from banks, financial markets and other companies, as

well as all the bonds and debentures of the company with a term greater than one year. They include financial debts (loans and bank overdrafts), provisions for the payment of 266

than one year, also referred to as current liabilities. These are partly operating debts. Accounts payable arise in the same way as accounts receivable from clients, but in relation to purchases from suppliers, and therefore comprise a source of finance. Other operating debts refer to all non-financial debts of the company such as taxes payable to the inland revenue authorities, salaries payable, social security outstanding, etc. There are also short-term debts, including bank overdrafts, those long-term debts which fall due within a year, use of credit lines, etc. The liabilities therefore represent all the funding available on the date at which the balance sheet applies, and the assets represent the way these funds were applied.

7A.1.3 Presentational forms of the balance sheet 7A.1.3.1 Classical presentation Figure 7A.1 shows the classical form of the balance sheet, separating the long- and shortterm components and showing the definitions of working capital, working capital requirement and net liquid assets. The presentation can vary, for example French companies interchange the positions of the short- and long term assets, the short-term assets being shown at the bottom of the balance sheet.

LIABILITIES Equity capital

Net fixed assets

Long-term debt Working capital

Capital employed

Fixed assets

ASSETS

Working capital requirement Operating capital Current assets

Net liquid assets Liquid assets

Current liabilities

Operating debt

Short-term debt

Working capital (WC): the amount by which the permanent funds exceed net fixed assets. It is therefore that part of the medium and long term financial resources which can be used to finance the operating activities. Working capital requirement (WCR): amount of capital needed to allow the capital to finance its operating activities. Net liquid assets (NLA): Short-term assets less short-term liabilities. We therefore have: WC = WCR + NLA

Figure 7A.1 Balance sheet, classical format.

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Basic principles of financial accounting

• Short-term finance, made up of all the company’s debt with an outstanding term of less

Annexe to Chapter 7

pensions, provisions for restructuring, provisions for site rehabilitation and deferred taxes (see § 7A.4).

The balance sheet can also be presented with operating items separated from items related to the financing (Fig. 7A.2). We then have: – net debt: long- and short-term financial debt minus the liquid assets; – operating liabilities: long-term provisions and deferred taxation.

Assets

Liabilities

Shareholders’ capital

Annexe to Chapter 7

Basic principles of financial accounting

7A.1.3.2 Simplified presentation

Minority interests

Fixed assets

Net debt Operating liabilities

Working capital requirement

Figure 7A.2 Simplified balance sheet.

7A.2

PROFIT AND LOSS ACCOUNT

The profit and loss account is a synthesis of the accounting events during an accounting period which increase (profit) or decrease (loss) the overall wealth of the owners. It incorporates all the revenues and costs during the period, the difference corresponding to the profit/loss for the period. The revenues are the events which add to the wealth of the owners. In the case of oil companies these arise mainly from the sale of oil and gas. The costs, on the other hand, are the items which deplete this wealth. The profit and loss account includes cash outflows resulting from the company’s operations corresponding to the direct use of materials, consumables and labour. However the profit and loss account must also allow for the calculated costs associated with the “consumption”, that is the wear and tear to the equipment and installations. These installations are designed to last for a certain period. There is therefore a lag between the time when their capital cost has to be disbursed, and therefore accounted for (this is done in the flow of funds statement) and the times at which these capital assets are actually used. The latter results in wear and tear which extends over time: this is depreciation, a non-cash cost.

7A.2.1 The presentation of profit and loss account The profit and loss account generally takes the form shown in Fig. 7A.3. The net cash flow (after taxation) or self-financing capacity is equal the net inflow of cash in the profit and loss account, i.e. net profit plus depreciation. 268

Net Cash flow

Depreciation Net profit / loss

Financial income

Figure 7A.3 Profit and loss account.

The net profit provides the company with resources to pay a dividend to shareholders and increase their equity.

7A.2.2 Presentation showing intermediate balances The profit and loss account can also show various intermediate balances (Fig. 7A.4), and can separate, as for the balance sheet, operating and purely financial items. Such a presentation is often only given in an annex (analysis of the result by sector of activity).

Operating costs Depreciation Operating revenue

Gross operating surplus

Taxation Operating profit / loss

Operating profit / loss after tax

Cost of net debt Net profit / loss

Figure 7A.4 Profit and loss account showing intermediate balances.

• The operating profit/loss represents the contribution to profit of each operating unit. It may

be before or after tax, but is always before financial charges. • The operating profit/loss after tax: this is the operating profit/loss corrected to allow for

the effect of taxation on operating revenue. This tax is before taking credit for reliefs relating to the servicing of debt. These reliefs are accounted for in the item “cost of net debt”. • The net cost of debt is made up of costs and financial credits directly attributable to the

items which make up the net debt (including the effect on taxation of these items). • The net profit/loss is therefore the operating profit/loss after tax less the net cost of debt.

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Basic principles of financial accounting

Financial costs Taxes

Sales

Annexe to Chapter 7

COSTS

REVENUE

Operating costs

Basic principles of financial accounting Annexe to Chapter 7

7A.2.3 Depreciation Wear and tear on the working equipment since its commissioning is reflected in the balance sheet item net fixed assets, i.e. the value of the all investments less depreciation. The wear and tear for a given year, on the other hand, appears in the profit and loss account in the form of a debit: the allowance for depreciation. The term depreciation (instead of allowance for depreciation) is often used for convenience to designate this item in the profit and loss account. The rules for calculating depreciation are imposed from outside the company. Three separate practices can be distinguished:

7A.2.3.1 The depreciation shown in the corporate financial statements This is calculated by adhering to the laws, norms and rules of the country in which the company is operating. Its main purpose is to establish the dividend to be paid to shareholders, but also to calculate the taxes the companies will pay.

7A.2.3.2 The depreciation shown in the tax accounts The taxes to which the petroleum industry is subject often consist of a series of levies, each calculated using its own amortisation rules, which can be different from those used to calculate the corporate income tax. In France (and countries operating on the French model) an investment can only be written down by reference to the production generated by that investment. In the UK and other countries which have adopted the British system, on the other hand, amortisation can start as soon as the capital costs have been incurred. This differing treatment has a considerable effect on project economics in cases where the petroleum assets are aggregated for tax purposes (no ring fence), that is, the calculation can be carried out for them all together. In the system applying in English-speaking countries a further distinction is made depending on the nature of the investment expenditure: – Intangibles (services or assets with no residual value) which are treated as a current expense in the operating account. Intangibles are not capitalised and do not appear in the balance sheet; – Tangibles (physically recoverable, or having a residual value at the end of life of the investment), are capitalised in the balance sheet and are depreciated in the operating account according to the rules laid down in the country concerned. It should be noted that the distinction between tangibles and intangibles can vary depending on the tax rules. Intangibles, for example, may comprise a specific part of an investment: the wellhead or casing in the case of a well. They may alternatively be linked to the physical position of the investment: platforms being tangible (on the surface) and wells being intangible (below surface) for a development investment.

7A.2.3.3 Depreciation in the consolidated accounts Finally, in drawing up consolidated accounts, and in particular for SFAS 69 accounts, companies abide by the recommendations of the SEC and the FASB (Financial Accounting Standards Board), which recommend unit-of-production depreciation on the basis of the developed proven reserves for investments in the upstream petroleum industry (SFAS 19). 270

Equipment wear and tear is assumed to be occur uniformly over its life. It is easy to see that this does not apply to an oil or gas field, since production declines over time.

7A.2.3.5 Declining balance depreciation This assumes that wear and tear are very high when production begins, and reduce with time. This basis of depreciation is more appropriate for writing down oil and gas producing installations, although it does not take account of the specific characteristics of the field. The rate of depreciation in this method is calculated by multiplying the straight-line depreciation rate by a factor determined by the tax or company accounting rules applying; the straight-line depreciation rate of course depends on the life of the item being depreciated. A particular case of this rate uses a multiplier of 2, and is referred to as the double declining balance (DDB) method. Table 7A.1 compares depreciation profiles for the declining balance and straight-line methods for an investment of 100, an asset life of 8 years and a declining balance depreciation rate of 25% (so a double declining balance since 25% = 2 × 1/8). Table 7A.1 Comparison of declining balance and straight-line depreciation.

Year

DDB and straight-line depreciation

1 2 3 4 5 6 7 8

Investment 100

Net value 31.12 (1) 100 75.0 56.3 42.2 31.6 27.3 15.8 7.9 0.0

Depreciation (2)

Straight-line over remaining life (3)

25 % × 100 = 25.0 100.0 : 8 = 12.5 25 % × 75.0 = 18.8 75.0 : 7 = 10.7 25 % × 56.3 = 14.4 56.2 : 6 = 9.4 25 % × 42.2 = 10.5 42.2 : 5 = 8.4 25 % × 31.6 = 7.9 31.6 : 4 = 7.9 7.9 7.9 7.9

DDB depreciation (4)

Straightline 8 years

25.0 18.8 14.1 10.5 7.9 7.9 7.9 7.9

12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5

1. Net value at 31.12 in preceding year (1) less depreciation for the year (4). 2. 25% of net value at 31.12 in preceding year. 3. Net value at 31.12 in preceding year divided by remaining life. 4. Once the result in column (3) exceeds the result in column (2), it is taken until the end-of-life.

7A.3 CASH FLOW STATEMENT The funds flow statement, also known as the statement of sources and application of funds or the statement of changes in financial position, summarises all the capital operations which have taken place during an accounting period. It is a dynamic account of what has happened during the period, and complements the point-in-time perspective of the balance sheet. 271

Basic principles of financial accounting

7A.2.3.4 Straight-line depreciation

Annexe to Chapter 7

This recommendation complies with IFRS (IAS 16 – Property, Plant, and Equipement). Investments shared by several fields (treatment facilities, export pipelines) are amortised on the basis of developed and undeveloped proven reserves, or even by straight-line depreciation (usually over 20 years).

Basic principles of financial accounting Annexe to Chapter 7

The table gives, for the period considered: – New loans contracted and any increases in capital, as well as the cash generated by the operations (cash flow): these are the sources of cash; – Capital expenditure, repayments of loans, dividends paid and the change in working capital requirement: these are the uses of cash. Figure 7A.5 shows the relationship between the tax account, the profit and loss account and the funds flow statement. The distinction should be noted between depreciation for tax purposes (tax depreciation) and depreciation for calculating the net profit/loss (accounting depreciation).

Tax account TAXABLE REVENUES

+ sales + financial revenues ALLOWABLE COSTS

– royalties – operating costs – financial costs – tax depreciation

= Taxable profit

– Losses brought forward

= Adjustedtaxable profit × rate = TAX

Profit and loss account REVENUES

Funds flow statement + NET PROFIT

+ sales (net of royalties)

+ accounting depreciation

COSTS

+ change in working capital requirement

= cash flow

– operating costs – accounting depreciation

= operating cash flow – investment

= OPERATING PROFIT (before tax) – taxes

= available cash flow

= OPERATING PROFIT (after tax) –/+ financial costs/revenues

+ change in debt + change in capital – dividends

= NET PROFIT

+ VARIATION IN LIQUID ASSETS

Figure 7A.5 Relationship between accounts.

7A.4 THE CONSOLIDATED ACCOUNTS There are different ways in which a company can develop its activities, particularly into other countries: it can simply establish itself or a branch without a separate legal status, it can set up a wholly (100%) or partly owned subsidiary, or it can take a holding in an existing company. When a number of companies are closely linked to one another, they form a group. A parent company holds shares in other companies in the group: if it holds more than a 50% stake (ordinary or partnership shares) in a company, that company is called a subsidiary; if the holding is between 10 and 50% it is called a minority holding. Exploration/production companies are often in this situation, because they are often operating out of the national jurisdiction of the parent company. The parent company draws up its balance sheet and corporate profit and loss account in the normal way in accordance with the rules applying in the country in which it is based, and its links with its subsidiaries impact on its accounts only in terms of financial flows (advances from and repayments to the parent company, dividends, etc.). If a proper analysis, not only financial but also industrial, of the group is to be made, it is necessary to have access to the consolidated accounts of the group. The principle of consolidation is that the financial statements of the parent company should give a picture of all the items which it effectively controls through its subsidiaries. 272

Full integration

Control on company

Yes 

Integrates the accounts as to 100% of all subsidiaries in which the parent company has effective control An additional item is introduced into the liabilities in the balance sheet: Interests of minority shareholders

No  Jointly owned company Oil/gas company held jointly with other shareholders in the common interest

Proportional integration Yes

All items included in proportion to shareholding

No  Equity method Significant influence on company



Holdings valued in proportion to share of equity (including profit / loss) of the companies

Figure 7A.6 Choosing the method of consolidation.

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Basic principles of financial accounting Annexe to Chapter 7

The method chosen depends on the level of control, essentially given by the percentage of the voting rights owned (Fig. 7A.6). As defined in IAS 27 Consolidated and separate financial statements, control is defined as the power to direct the financial and operational policies of an entity in order to obtain economic benefits from its activities. The parent company is presumed to have control when it holds more than 50% of the voting rights (exclusive control) or when, if it holds 50% or less than 50% of the voting rights, it benefits from: – Control of more than half the voting rights by virtue of an agreement with other investors; – The power to direct the fmancial and operational policies of the entity under a statute or an agreement; – The power to appoint or remove the majority of the members of the management bodies; – The power to cast the majority of the votes at meetings of the Board of Directors or the equivalent administrative body.

Basic principles of financial accounting Annexe to Chapter 7

Joint control, as defmed in IAS 31 Interests in joint ventures, is the sharing of control of an economic activity under a contractual agreement. This only exists if strategic financial and operational decisions in connection with that activity require the unanimous consent of the parties who share control (co-venturers). Such a requirement ensures that no single venturer is in a position to control the activity unilaterally. Significant influence, as defmed in IAS 28 Investments in affiliated companies, is the power to participate in the financial and operational policy decisions of the company without, however, exercising control over these policies. This is assumed when the investor holds directly or indirectly through subsidiaries 20% or more of the voting rights in the company held (including potential voting rights). The accounts of foreign subsidiaries are drawn up in the most important currency in the particular economic environment concerned, described as the functional currency. In most cases the functional currency is the local currency, except for a large number of subsidiaries in the upstream petroleum sector for which the U.S. dollar is the most important currency. The accounts are converted to the currency of the parent company at the rate applying on the day the balance sheet is made, and at the mean annual rate for the profit and loss accounts, conversion errors resulting being included in the equity capital. Investments are usually depreciated in consolidated accounts by the straight-line method over their life, with the notable exception of oil- and gas-producing assets, which are depreciated by the unit-of-production method, that is as a function of the production profile of the field. The fact that different depreciation bases are used for the tax calculations and in the consolidated accounts leads to the establishment in the consolidated balance sheet of an item for deferred taxation (with variations in this item appearing in the profit and loss account: provision for deferred taxation). These are equal, at any particular time, to the difference between the value for tax purposes and the book value of an asset or liability, multiplied by the most recent tax rate. Of course this difference is one of timing rather than in the total amount, so that the deferred taxes reduce to nil by the time an asset reaches the end of its life.

Table 7A.2 Balance sheet and profit and loss account of parent P and subsidiary S. Balance sheet parent P ASSETS Net fixed assets Shares in S Other assets

Profit and loss account parent P

LIABILITIES

COSTS

12 000 Capital 900 Reserves 4 900 Profit for year Debt

10 000 2 000 800 5 000

17 800

17 800

Operating costs Financial costs Taxes Net profit

900

Other assets

900

Total

1 800

Capital Reserves Profit for year Debt

10 000

10 000

Profit and loss account subsidiary S

LIABILITIES

Net fixed assets

Sales

10 000

Balance sheet subsidiary S (90% owned by P) ASSETS

REVENUES 8 000 500 700 800

COSTS 1 000 – 100 700

Operating costs Financial costs Taxes Net profit

1 800

REVENUES 3 600 100 200 100 4 000

274

Sales

4 000

4 000

Consolidated balance sheet ASSETS Net fixed assets

Consolidated profit and loss account

LIABILITIES

COSTS

Other assets

12 900 Capital Reserves 5 800 Profit for year Minority holdings Debt

10 000 2 000 890 110 5 700

Total

18 700

18 700

Operating costs Financial costs Taxes Net profit (P) Net profit (minority shareholder)

REVENUES 11 600 600 900 890

Sales

14 000

10 14 000

14 000

The consolidated balance sheet and profit and loss account are therefore as follows (Table 7A.3): Extract from balance sheet of company C: • Capital........................................................................................................

1 000 000 O

• Reserves .....................................................................................................

200 000 O

• Net profit....................................................................................................

40 000 O

The example below shows how the equity method of consolidation works. Company P has acquired a 25% interest in company C for O 200 000. The initial value of the shares included in the assets of P is replaced by the share of equity capital (capital + reserves + net profit) which they represent in company C. The difference relative to the original value of the holding is broken down between the items “consolidated Extract from balance sheet of company P: ASSETS: • Equity interest in C ...................................................................................... 310 000 O LIABILITIES: • Consolidation surplus (in consolidated reserves) ......................................... 100 000 O • Share of profits of affiliates .........................................................................

10 000 O

Extract from consolidated profit and loss account of company P: • Share of profits of affiliates .........................................................................

275

10 000 O

Basic principles of financial accounting

Table 7A.3 Consolidated accounts of P and S.

Annexe to Chapter 7

An example of full integration is shown in Table 7A.2. Parent company P has a 90% stake in a subsidiary S. Corresponding items on the balance sheets and profit and loss accounts are first summed. Then: – The reference to holding of parent P in subsidiary S is removed; – The minority shareholders’ share in the net profit of S is entered into the profit and loss account: Net profit (minority shareholder) = 10% × 100 = 10; – The minority shareholders’ share in the capital and in the net profit is entered on the liability side of the balance sheet: Minority holdings = (10% × 100) + (10% × 1 000) = 110.

8

Health, safety, the environment, ethics

8.1 RISK IN THE INDUSTRY Oil is often regarded by the public as a dangerous and polluting industry. This somewhat dramatic view relates particularly to the operations traditionally perceived as the most critical, such as drilling and transport by tanker and pipeline, which the public associates with spectacular accidents such as oilwell blowouts and “black tides” which result from major oil spills. In addition there have been several occasions when routine operations involving long-term installations have proven to be a source of danger. Events in the North Sea such as the capsize of the Alexander Kielland and the fire on Piper Alpha were major contributors to this perception. Exploration and production activities involve the manipulation of flammable substances at high temperature and pressure which sometimes contain very toxic gases. The main risks are essentially associated with uncontrolled escapes of hydrocarbons and other hazardous substances, which can cause fire, explosions and contamination. There are other dangers inherent in the very nature of the means and processes deployed, such as flares which can cause high levels of thermal radiation, or heavy, bulky objects which are difficult to manoeuvre. These effects can be amplified by the working environment, which often involves working in a constrained space in remote locations, particularly offshore. Apart from problems occurring during operations, often due to human error, shortcomings in the design of the structures is another major cause of loss of control in installations. In order to prevent this, an assessment of risk must be fully integrated into the design of a development project and all stages of the engineering. Exploration and production induce also various effects on the environment, soil, water or air. As all human activities, it contributes to greenhouse gas emissions, which means that specific efforts must be taken to limit these effects.

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8.2 SAFETY MANAGEMENT 8.2.1

The Piper Alpha accident

The accident which befell the oil and gas production platform Piper Alpha in the North Sea in 1988 called into question established offshore safety practices. This platform, situated 110 miles North-East of Aberdeen in Scotland, was destroyed in several hours following a series of explosions, killing 167 persons. It led to production being stopped immediately, for several months, at five other fields, with a total loss of production of 300 000 bbl/d, representing 12% of the production of the North Sea. It was estimated at the time that the loss of exports amounted to £550 million in 1988 and £800 million in 1989, with a loss of tax revenue to the British government of £250 million in 1988–1989 and £520 million in 1989–1990. The findings of the enquiry conducted by Lord Cullen had a very major impact, leading to a complete overhaul of the complex and sometimes conflicting British supervisory system, safety thereafter being overseen by a single administrative body, the Offshore Safety Division of the HSE. The report also led to changes in the law, with greater emphasis on objectives to be met. And finally it made clear the need for the development and application of a safety management system (SMS) by all companies, a practise now regarded as standard in the offshore industry. This system is based on making a “safety case” demonstrating that the design, construction and operation of every offshore installation is completely safe. It involves setting up training and safety awareness-building programmes for both contracted personnel and others. It also established a requirement for external safety audits. The safety case must be updated regularly and submitted to the HSE, which has to assess whether the document has identified, assessed and controlled the main risks to an acceptable degree. This notwithstanding, the operator retains full responsibility for the safety of operations. Legislation varies between countries, but many of the companies operating in the North Sea have applied the new approach to safety at other fields all over the world, and these practices have been disseminated throughout the entire oil industry.

8.2.2

Reducing risk

The central production facility must be designed in a manner such as to limit risk by reducing the frequency of malfunctions and minimising their consequences. More specifically this means: – Minimising the likelihood of a loss of control of production and particularly of escapes; – Reducing the probability of ignition/explosion where there is an escape; – Containing the consequences of any fire, explosion or escape of toxic substance; – As a last resort, ensuring that there are means of evacuation for all contingencies. In order to bring this about, safety imperatives are integrated right from the preliminary design stage into the overall layout, ensuring safe separations are respected, and systematically separating the oil and gas treatment plant from ignition sources. The organisation of each project therefore draws on traditional risk management methods such as quality control, risk assessment, safety reviews and audits. The treatment plant is equipped with specific safety facilities, most commonly firefighting systems. It is always equipped with an integrated process control system and an emergency 278

8.2.3

Safety management systems

Having looked at matters related to the design of installations, we shall now turn to safety issues associated with operations.

8.2.3.1 Legal aspects When an accident or disaster occurs, initial attention, and subsequently the investigations, focus first on technical defects and human error, and then turn to organisational deficiencies. Even in the nineteenth century, when there were no regulatory requirements imposed on those running businesses to take preventive measures, case law apportioning civil liability for accidents in the workplace often laid the blame on organisational weaknesses. In recent years, organisation has been a central issue in criminal investigations of blame, leading to subpoenas and indictments. This has been a feature of all the major industrial disasters in recent years. 279

Chapter 8 Health, safety, the environment, ethics

shutdown (ESD) system. Detectors continuously monitor pressure, temperature, liquid levels, etc. As an anti-fire precaution, gas detectors automatically shut down production and dispatch the contents of processing units to the flare. If a fire breaks out, fire detectors automatically trigger sprinklers in the zone where fire was detected. Reliability calculations are carried out for all safety systems which depend on sensors and automatic mechanisms (safety integrity levels or SIL). Other systems not directly related to oil processing have an essential safety function. The ventilation of certain confined areas, for example, ensures that the concentrations of flammable gases will be kept below the lower flammable limit in the event of a leak. Finally, safety precautions are put into effect on equipment whose main function is not safety. The accommodation quarters in dangerous areas are designed to withstand explosion and fire, and an overpressure is maintained in order to prevent gas, smoke or toxic substances from penetrating. The gangways and means of escape must be able to maintain their integrity for a minimum period following fire or an explosion. At each stage of a project safety reviews are conducted which are intended to ensure that processes in the treatment plant are robust. They identify the main hazardous events which threaten the installation: blowout, fires and explosions, escapes of hydrocarbons, ship collision, helicopter crash, etc. Estimates are made of the probability of occurrence of such events. They describe the measures taken to minimise the risks of accidents and identify their impacts: firewalls, fire-extinguishing systems, additional ventilation or the installation of walls able to withstand explosions, training and simulation exercises, protected shelters for personnel in the event of a serious accident. The consequences of every potential failure are evaluated in terms of human casualties, pollution and economic loss. Safety is monitored and controlled throughout the entire lifetime of installations. Safety systems and emergency procedures are developed by the operators. In the control room all installations are continuously monitored; at the same time, rigorous maintenance is carried out to prevent accidents and pollution. Those working in installations which process toxic gases, for example hydrogen sulphide, are equipped with gas masks ready for immediate use should there be a release. Gases no longer in their normal operating ranges are immediately flared. Finally, all personnel must ensure, particularly offshore, that they are ready for an emergency evacuation, a procedure practised regularly.

Chapter 8 Health, safety, the environment, ethics

The EU Seveso II Directive, which took effect on 3 February 1999 and relates to the prevention of major accidents, states clearly that it is the responsibility of all operating enterprises to practise a policy of prevention. Management therefore has a clear responsibility to formulate a safety policy and make organisational arrangements for safety. This legal requirement alone is sufficient argument for the company to ensure that it has in place an effective safety management system.

8.2.3.2 Human factors Human error is one of the major causes of accidents, and obviously has to be addressed by ways other than merely punishing the guilty party. This is made very clear by looking at the causes of errors. It can be seen that in most cases these are the result of underestimating the risk, suggesting inadequate management and an inadequate appreciation of this danger in the organisation of the work, equipment ergonomics, etc. What is more, as systems become more complex, human error rises because it becomes more difficult for the workers concerned fully to apprehend the danger associated with their decisions. Management studies have shown that, since the 1960’s, less than 15% of operational problems which arise, including the prevention of accidents, can be dealt with effectively by the individual. The organisation of work and training, and the dissemination of information is therefore critical to accident prevention and to minimising the consequences of error. This is why safety management is far more than a matter of merely solving technical problems and enacting regulations.

8.2.3.3 Trading off cost and risk Accidents impose considerable costs on the companies which sustain them; these costs are difficult to quantify precisely because they include not only the direct costs, but also various indirect costs such as reduced efficiency and the tarnishing of the company’s image. Accident prevention equally involves costs. And because risk can never be completely eliminated, these costs are theoretically unlimited. A limit must be imposed, however: this is done by making use of the concept of “acceptable” risk. Of course any death is unacceptable at the level of the individual concerned. But society appears to tolerate, if perhaps not to accept, that almost 10 000 die each year on French roads. If that were not the case, regulation and/or public pressure would ensure that vehicles were build more solidly with technical speed limitation, that roads would be made safer, that motorists would be subjected to more public information about the importance of their behaviour. Thus society at present appears less concerned by deaths on the road than in the workplace. Hence one may argue that a definition of “acceptable risk” is far from being widely agreed or consensual. For this reason, it cannot be left entirely to individual discretion. This is one of the fundamental aspects of safety management.

8.3 TAKING ACCOUNT OF THE ENVIRONMENT Keen to maintain a positive image, oil companies endeavour to prevent or control environmental problems resulting from their activities, and set clear environmental targets. These relate mainly to reducing the flaring of gas, emissions of hydrocarbons and the oil-content of effluent, minimising the environmental impact of their operations, preserving biological 280

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diversity and cleaning up the legacy of historical contamination. The companies are highly aware of the very severe financial consequences of accidents and pollution in terms of fines, compensation payments and the negative impact on their image. They fully appreciate the need for their operations to be clean and safe. The companies have a duty to minimise the risk of oilspills, the economic, ecological and, for many, psychological consequences of which can be enormously damaging to the industry. Over the last 20 years, and particularly since the Exxon Valdez catastrophe in 1989 and the high-profile hearing which followed leading to the award of massive compensation payments, a battery of regulations and a whole range of technical measures have been put in place internationally to contain possible disasters. Since the Kyoto Protocol in 1996 greenhouse gases, and combustion gases in particular, are under scrutiny. In response to concerns about global warming, and driven also by states desirous of making the most of their natural resources, the practice of flaring associated gases is declining, these gases instead being reinjected into the reservoir, used for secondary recovery or, when possible, marketed. A global initiative led by the World Bank the “Global Gas Flaring reduction” has the aim to reduce significantly the emissions of CO2 due to flaring. According to this organisation, natural gas flaring represents around 150 billion cubic meters every year, which is more than the annual gas consumption of France and Germany and around 15% of committed emission reduction by developed countries under the Kyoto protocol for 20082012. Flaring takes place all over the world, firstly in Africa (30%), Middle East (25%) and the Former Soviet Union (20%) but also in the Americas (10%), Asia (10%) and Europe (3%). Reducing flaring is not a simple task as it means limiting the emissions of associated gas in the process where the use or reinjection is not easy. The major international oil companies are members of this initiative and some of them have indicated that in new projects they will study and limit, as far as possible, flaring of gas (for security reasons, some flaring during installation or closure is to be maintained). For many international companies this “Global gas flaring reduction” initiative will mean a very significant reduction of GHG emissions in the next 5 to 10 years. There is surely a need to associate better national companies in areas like the Former Soviet Union and Middle East where there is also an important flaring of natural gas. It is still difficult to measure globally the situation but there is a strong commitment of many actors to improve the impact of exploration and production in this area. The main pollutants generated by exploration and production activities are sulphurous gases. Nowadays measures are taken to purify these gases so that they comply with appropriate standards. Liquid effluent poses a particular problem. Water is a by-product of oil production, and the water naturally contains hydrocarbon emulsions. It is vital that the effluent is cleaned up before being discharged. Effluent containing up to 40 ppm oil is presently tolerated, but oil companies are seeking to impose a more stringent standard of 15 ppm. Production from depleted reservoirs present difficulties, because large quantities of water are used in the production process. Site rehabilitation at the end of field life and in particular, the decommissioning of offshore installations, are currently the focus of considerable attention. About a hundred platforms are dismantled every year in the Gulf of Mexico. International regulations, which are only indicative, are generally implemented by host governments. They are currently being toughened in order to increase the protection offered to the environment.

Chapter 8 Health, safety, the environment, ethics

8.4 THE STAGES OF ENVIRONMENTAL MANAGEMENT: BEFORE – DURING – AFTER This integrated approach looks at all stages of the life of a project.

8.4.1

“Before”: the preparatory phase

Before embarking on exploration or production activities a thorough assessment must be made of the environmental impacts in accordance both with local statutory requirements, if existing, and the environmental policies and procedures of the company. In the first place a statement must be drawn up of the regional and local constraints, whether regulatory (protected zones, authorisation procedures), environmental (wetlands, forests, groundwater, coral reefs) or socio-economic (fisheries, fish farming, tourism, exploitation of water resources, etc.). The baseline study and the impact assessment are then carried out and, if the area is a sensitive one, an intermediate stage is carried out comprising a preliminary reconnaissance and a pre-impact study. The baseline study, which may be of a terrestrial or marine system, documents the features of the site including the physical, climatological, geological, hydrological, hydrogeological parameters as well as the chemical quality of the environment (recording any pre-existing contamination), the biological resources, i.e. the flora and fauna, as well as the socio-economic and local cultural context. The impact statement will be accompanied by recommendations on technical aspects of the project which will minimise the adverse effects, such as: – The design of the drainage network and water treatment installations; – The minimisation of visual intrusion; – The abatement of noise and emissions; – Proposed disposal of waste water: discharge or reinjection; – Waste management; – Impact on greenhouse gas emissions. In the case of a statutory impact statement —which most are— proper account needs to be taken of the lead times involved for the administrative procedures (approval may take 4–6 months), which means that the study needs to be carried out as early as possible. Very often the impact statement has to be prepared and submitted for approval before the engineering studies can start, so that a licence to build and operate can be obtained. The impact statement for a project constitutes a real commitment. The recommendations made in it represent a long-term undertaking on the part of the company to protect the environment.

8.4.2

“During”: the operating phase

The approach depends on the type of operation involved, but it will any case be broadly structured as follows.

8.4.2.1 The management plan The management plan, which is implemented by each subsidiary, must include, in addition to an organisation with clearly defined responsibilities which pays close attention to regulatory compliance, the following mechanisms: 282

It should be remembered that the baseline study and the impact assessment comprise initial studies of the environmental risks.

8.4.2.2 The anti-pollution plan Each subsidiary company engaged in exploration and production must have a contingency plan which includes: – An analysis of the sensitivity of the local environment to the potential risks, the regulatory framework and the resources available; – The definition of a strategy and appropriate action, a system of alert levels, lists assigning tasks and a plan for mobilising external assistance; – An up-to-date inventory of methods and equipment for combating pollution; – The formation of teams responsible for combating pollution, with arrangements to verify the effectiveness of the plan through regular practice and drills. These anti-pollution plans can usually be activated at three levels, enabling a graduated response according to the seriousness of the incident. Anticipating crises and responding to them are the two cornerstones of the contingency plan, which is why these exercises are of such huge importance.

8.4.2.3 Self-surveillance, monitoring and reporting The impact study broadly sets the agenda for the monitoring programme, the indicators to be adopted and the monitoring frequency (generally monthly). These indicators measure emissions and discharges (emissions to air, liquid effluents, waste, etc.) and environmental quality parameters (air, surface waters, groundwater, soil, flora and fauna). Some or all of this information may be reported to the authorities. Major efforts have been made to reduce the problem of waste. Special attention is also being paid to CO2 and other greenhouse gases.

8.4.2.4 Environmental audits Audits are regularly performed at exploration and production sites, both in regard to management issues (“systems” audits) and technical matters. The procedures must be clearly established, and are based on checklists which are periodically updated. A file is established for each aspect of the object of the audit comprising three elements: – An appraisal of the existing situation; – An assessment of the extent of compliance with a “reference situation” defined by the regulatory requirements, the management system, “good practice”; – Recommendations seeking to improve the situation and ensure compliance. 283

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– Impact and risk assessments for modifications or extensions of activities and installations; – Up-to-date operating procedures (management of waste and chemical products, procedures for dealing with incidents); – Emergency response plans (anti-pollution plan); – A programme of self-surveillance and monitoring involving the reporting of significant environmental indicators; – A programme of audits and environmental reviews.

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8.4.3

“After”: the aftercare phase

Abandonment and decommissioning are dealt with by regulations. The rules governing impact statements also often provide for account to be taken of site rehabilitation after production has finished. As far as onshore exploration and production are concerned, there are specific regulations in most countries: a mining code, an oil and gas law or, as in France, an environmental law for ICPE classified facilities or a «police des mines»(specific mining regulations). Offshore, the disposal of platforms is dealt with by various international treaties and rules, including UNCLOS (United Nations Convention on the Law of the Sea), the London Dumping Convention, the IMO (International Maritime Organisation) and various UNEP conventions.

8.4.3.1 Well capping It is not only production wells at the end of their productive life which have to be plugged; the same applies to exploration wells when these prove not to have development potential. Well capping operations are carried out on the basis of special rules and procedures, and involve manufacturing cement plugs of different types (e.g. to isolate geological formations, protect aquifers, etc.). Well capping programmes involve submitting an abandonment plan to the authorities for prior approval.

8.4.3.2 Offshore decommissioning The IMO has issued guidelines for the decommissioning of platforms which apply to all maritime regions except the North Sea, unless more restrictive rules apply locally. These rules provide as follows: • All platforms of less than 4 000 tonnes and at depths of less than 75 m must be entirely

removed. • Platforms which are larger or located in deeper waters can be partially dismantled as long

as a depth of at least 55 m is left clear. • Installations erected after 1 January 1998 must be designed such that they can be totally

dismantled. • For the North Sea and North Atlantic sectors, decommissioning is governed by Decision

98/3 of the OSPAR Convention, in force since 9 February, 1999: – any unused platform must be entirely removed; – sea burial at the site and partial removal as envisaged in the IMO Convention, is expressly banned; – exemptions may be allowed for certain categories of structure, particularly those which satisfy certain criteria (dates, weight). This applies particularly to certain concrete structures, or steel platforms erected before 9 February, 1999 and where the infrastructure or the jacket weighs more than 10 000 tonnes. For this last category the base or footings can be left in place once the decommissioning report has been accepted. In any case the superstructure (“topsides”) must be thoroughly cleaned, inerted and dismantled. To date some 20 platforms have been decommissioned in the North Sea, but more than 400 more remain to be dealt with in the coming years. 284

Some major rehabilitation exercises and, in some cases, site redevelopments, have been carried out recently, for example: – The reforestation of the site of an exploration well in the Madidi National Park in Bolivia; – The restoration, re-vegetation and implementation of anti-erosion measures along a pipeline route in South-East Asia (Burma); – The decontamination of groundwater at a field in Argentina by means of vacuum pumping together with a biological process (“bioslurping”); – The decommissioning of old platforms in the North Sea. At all three of these sites the contamination/disturbance predated the acquisition. It is therefore impossible to stress too strongly the importance of baseline audits, which allow the division of responsibilities to be determined when contamination is an issue. In conclusion, in implementing an environmental management system, identification and prioritisation of the risks is a crucial first step. But the dynamic element in the system which ensures that the approach will be perpetuated and improvement implemented, is the audit. By adhering to this approach the operating companies should have no difficulty in obtaining certification under ISO 1400 or EMAS. But apart from the quest for “recognition”, the environmental management system, like the safety system, must form a permanent part of an integrated approach to the management of the entire exploration/production activity.

8.5 THE INTEGRATION OF HEALTH, SAFETY AND THE ENVIRONMENT Safety and environmental matters are assuming an increasing importance for companies. The international companies have begun to deal with these issues within a single “health, safety, environment” (HSE) module. Although safety and environmental requirements can sometimes appear to conflict with one another, an approach which tackles these two issues together proves more effective than a piecemeal approach. It ensures that there will be an interaction between these two elements, and provides a vehicle by which management can set strategic objectives, establish rules and procedures specific to the company, supported by performance measures and remedial actions. Depending on the activities involved, HSE rules need to be defined: – Relating to technical solutions, in terms either of technical specifications or standards; – Procedures to be followed in emergencies. Practical systems for managing health, safety and the environment are based on quantified risk assessment. A guide describing best practice in industry and drawing on the principles of ISO 9000 certification was published and circulated in 1994. Many companies adopted these recommendations and developed a sophisticated system for the management of risk which they have often validated through ISO 14001 certification. The Norwegian system is an example: built on the TQM model (Total Quality Management, developed by the European Foundation for Quality Management), the purpose 285

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8.4.3.3 Site rehabilitation

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of which is to build awareness amongst managers and analyse the company’s activity, not only in economic terms but also in terms of safety, personnel satisfaction, environmental results and relations with government. The system adopted by American companies, on the other hand, emphasises the importance of motivating the personnel, cultural diversity, cost control and the putting into practice, by management, of all the key elements. Globalisation and technological progress have transformed the oil business, and nowadays the public expects more of the multinationals. At present the oil industry has to operate on the basis of three inseparable imperatives: economic development, social responsibility and environmental protection. The way in which the industry addresses safety and the environment has changed beyond all recognition in the last 20 years. Safety, once considered the exclusive domain of the safety department, has now become a concern of the company as a whole. Investment decisions have to be based not only on economic feasibility but also have to factor in environmental and social issues. Safety and environmental management have become an integral part of the business. These matters become even more important when companies are operating in harsh and sensitive environments such as deep offshore, tropical forests or the Arctic tundra, and coming into contact with remote communities. The most apparent change in the management of safety and the environment is probably the fact that commitments made by the company are now publicised externally. The overall strategy and the objectives to be met in these areas are communicated internally as well as to external partners and contractors, who are expected to fall into line. In many cases, oil companies try to take into account a price for CO2 in their evaluation to measure the effects in terms of emissions. This leads to a limitation of these emissions with regard to technical and economic conditions.

8.6 OIL AND ETHICS The oil industry, like other large industries, cannot develop without regard to the sociopolitical context in the countries in which it operates. This observation may seem a commonplace because all large industries have an impact on the environment, on the economy, on social development, and even on a political level. What singles out the oil industry in this regard, however, is the sheer scale of its impact: no other industry produces or transports such large volumes of a raw material which is potentially dangerous because it is inflammable, and even explosive in certain conditions. Furthermore it is a raw material which can harm the environment, that is, our biosphere and the infinitely complex living world which we subsume in the term “biodiversity”. These impacts can occur on land, sea or air. The oil industry therefore interfaces directly with our most precious values: our natural surroundings, our health, our safety. This is why public opinion is so sensitive to matters related to the activities of the oil companies. But it is not only in the areas of safety and the environment that the oil industry impacts on society. Its great economic importance, in both producing and consuming countries, means that it plays a key role in economic and social development. Since they are well enough known, we will not repeat here the statistics showing the importance of oil and gas in the budgets and the GNP of the major producing countries or in the trade balances of importing countries, or indeed in the private budgets of consumers, particularly those who own a car. 286

The term “ethical” is one which everyone seeks to appropriate: both politicians and those who make it their job to monitor the behaviour of politicians, both businesses and their critics. Amongst the most important stakeholders are the organisations referred to as NGOs, i.e. non-governmental organisations, so as to highlight their separateness from the state and supranational bodies whose function it is to make and uphold the law. We will not ourselves attempt to define the term “ethical”. Larousse defines it as “the science of morality”; it derives from the Greek ηθικοσ, or moral. Knowing what is moral and what is not, is one of the earliest questions to preoccupy man. Aristotle wrote three books on the subject, which remain reference works to the present day. It should perhaps be remembered that moral codes are not universal, and can change over time. One of the most variable areas in this regard, also in terms of its practical consequences, is probably that of the relative importance of individual rights over those of the community as a whole. A book on oil is not an appropriate arena for philosophical reflection, and we shall try to approach the problem of ethics by looking in practical terms at some real problems encountered by oil companies. We shall therefore attempt to tackle the most important of these problems at the confluence between law, morality, commerce, technology and politics. In this brief review we shall try to look at the expectations of public opinion and political leaders as a means of shedding light on the difficulties and contradictions which questions of ethics pose for the oil industry. In fact the oil industry has achieved an almost unique feat: it manages to project a negative image both in the wealthy, developed or consuming countries (“home countries”) and in the often poor and undeveloped oil-producing (“host”) countries. This doubly unfavourable image is due to the fact that, for their part, consumers hold the oil industry responsible for the prices, often considered excessive, of the fuels they use. People in producing countries, on the other hand, often perceive oil companies as veritable “states within a state” exploiting their natural wealth, causing pollution and economic and social imbalances, or even political destabilisation, in their country. In drawing up a list of the main ethical problems faced by the oil companies, it has been possible to refer in recent years to documents which most of them have in their possession: “ethical charters” and “guidelines for conduct”. These documents serve to complement more traditional texts dealing with problems of health, safety and the environment (HSE). Health, safety and the environment have already been dealt with in this book (Sections 8.1 to 8.4), and we shall only refer to them again where, because of their social and political consequences, they have a genuinely ethical dimension which transcends purely technical issues of prevention, or the rehabilitation of environmental degradation. These problems are of three kinds: 1. Ethical issues which arise relating to the oil industry and direct stakeholders: the oil companies, their employees, customers, suppliers, shareholders and partners. 2. Ethical issues relating to the relationships between the oil companies and the countries where they pursue their exploration and production activities.

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The vital economic role of oil and gas has a whole series of consequences which make for a complex and potentially difficult relationship with society. Public acceptability is of course one of the prerequisites for the harmonious development of any economic sector. An industry can only find and retain shareholders, employees, scientists and high-calibre managers if the public understands its contribution to development, and believes that contribution to be valuable, well managed, and acceptable on what might be called an “ethical” level.

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3. Fundamental ethical issues: global environmental problems, biodiversity, the preser-

vation of natural resources, sustainable development and human rights.

8.6.1

Ethical issues within the oil community

These are the questions which weigh least heavily on public opinion, because they are regarded as too specialised and of secondary importance compared with the fundamental ethical issues, or the relations between the oil companies and host countries. Furthermore they are not generally issues which are specific to the oil industry. However this category includes quite a few important issues, which are indeed crucial to the effective functioning of liberal and market economies. We shall consider a number of examples. First of all what should be the rights and duties of the companies in relation to the privacy of their employees? Is it permissible, and to what extent, for a company to control how its employees use their working time, their access to the Internet? Has it the right to limit their political activity if this is judged potentially detrimental to or in conflict with the activities of the company? How can it be sure that none of its employees will get involved in insider dealing on the stock exchange, or that they will not be tempted to accept some personal advantage if their duties include procurement or the award of contracts? Will a company be able to guarantee that career progression and promotion to management will be purely merit-based, without any form of discrimination based on gender, national or ethnic origin, religion or political affiliation? These are well and truly ethical issues, as is the issue of equity in dealings with partners and suppliers. Clear conflicts of interest can arise between practical expediency and ethics. Is it legitimate to favour one particular supplier of goods or services at the expense of others if relations with that supplier accord with the logic of industrial strategy, partnership or regional development? The oil industry has a symbiotic relationship with the service industries which supply it and a number of special factors apply in consequence. Many more examples could be mentioned, and we see that often there are different viewpoints, each in their way equally “ethical”, which can in practice conflict with one another, since they lead to different responses depending on which particular ethical aspect is regarded as paramount. Consider, for example, the issue of ethical conduct towards shareholders. On one hand there is a duty to ensure that information is transparent. On the other hand, there is a duty to conduct commercial and industrial activities as efficiently as possible. The latter imperative, by its nature, tends to limit the transparency of information. Striking the right balance between two ethical but conflicting considerations is not a matter for detailed and prescriptive rules. It has to be achieved by a combination of detailed knowledge and a good understanding of the problem, a good dose of common sense and, ultimately, the moral qualities of those who will make the necessary choices. There is a strong commitment to achieve a better balance between these two objectives. And some of the Sarbanne-Oxley rules try to avoid the excesses found in the behaviour of some companies like Enron.

8.6.2

Ethical issues involved in relations with host countries

This subject is one which finds a much more ready response amongst the general public, and which involves a number of risks for oil companies, sometimes difficult to deal with. 288

In the face of these problems the foreign investor has to manage its own interests, not having any real influence over the political choices of the host country. Such an influence would in any case be unethical, since interference in the political problems of the country would lack legitimacy. There would be no legality or morality supporting such interference. Is the company qualified to decide what is desirable for the development of the country and what is not? Some individuals and NGOs in both producing and consuming countries consider, however, that oil companies have a duty to intervene in these debates and decisions, i.e. to get involved in local politics, in such situations. Faced with dilemmas of this kind, the logical attitude on the part of the oil companies would be to refrain from interfering in local political affairs. But they then run the risk of being held jointly responsible for the injustices and even crimes perpetrated in the name of the State or other authorities in the country. Such problems are not new: ethical debates still continue today about the degree of culpability of Pontius Pilate! 289

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Central to this issue is the nature of the contracts which define the terms under which a foreign company —often powerful and usually from a developed country— will invest in a country which is often relatively undeveloped, and will be rewarded, if successful, for the risks it has taken. The terms of these contracts reflect the characteristics of oil and gas exploration and production, activities in which chance plays a large part, which are highly capitalistic in nature, and which, when successful, have a major impact on the host country. These contracts define how the proceeds from the production will be split between the investors and the host country. The appropriation and use of these proceeds, often large in amount, are a major political issue. They rapidly become central to the economic and political life of the host country, and are the root cause of a host of ethical problems which arise. These problems usually lead to resentment on the part of the public in that country, or of external observers. This resentment is not without foundation. Petroleum exploration activities generate large financial flows, and can lead to or exacerbate factionalism, or even fuel armed banditry. It is not always possible to make a clear distinction between these two types of destabilisation and violent disorder. There have been many oil-producing countries in recent years where attempts have been or are being made to seize power: examples include Angola, Burma, the Congo, Colombia, Sudan, Algeria, while armed banditry in various forms is rife in Nigeria and now in Algeria. In countries where the authority of the State is being violently challenged, the oil companies are considered by the insurgents as natural enemies in so far as they pay taxes to the State, and are often the largest contributors to their budgets. It is of course these budgets which provide the State with the funding needed to maintain law and order or exercise repression, the vocabulary used depending on the point-of-view of the speaker, i.e. pro- or anti-government. It is possible to draw up a list of problems created in practice by the management of oil revenues. We only mention the most common ones, which are faced both by host countries and oil companies. For the former the problems which crop up most frequently are: – Whether to use the revenues for development or for other purposes (prestige, arms, etc.); – Division of revenues between State and producing provinces or regions; – National or local development; – Risk of appropriation or misappropriation of a part of revenues for benefit of individuals or “clans”.

Chapter 8 Health, safety, the environment, ethics

Only someone completely ignorant of the distribution of oil and gas resources throughout the world would subscribe to the idealistic argument that oil companies should only invest in countries with “acceptable” regimes. Could useable criteria of acceptability be devised? We might doubt that. In the absence of reasonably solid criteria, could we delegate to particular authorities, and if so which ones, the task of deciding either to boycott new investment or to discontinue activities in countries where investments have already been made? It is clear that such authorities would need to have considerable legitimacy and powers if their action is to be effective: – Economic powers to provide for compensation mechanisms should activities be stopped; – Powers of inspection and sanctions to deal with non-compliance. In other words, the authority would have to be a powerful supranational body. In looking at questions of ethics which arise in relations between oil companies and host countries, we conclude that oil does not necessarily, in itself, lead to economic and social development, nor is it necessarily a democratising factor. However it will be appreciated that the adverse effects will be less severe where the political system is perceived by its citizens to be legitimate, and that these systems will permit the oil revenues to be distributed in an equitable and balanced way. Regimes of this kind would not necessarily have to conform to the model of parliamentary democracy, although that is probably the model best able to reconcile oil and socio-economic development or oil and ethics. Some recent initiatives have to be mentioned: • Chad. In order to export the crude oil produced in the Doba Basin fields, the construction

of a more than 1,000 kilometres long oil pipeline between Doba and Kribi (Cameroon) had to be built. However the construction of such a pipe line was costly and faced a large number of environmental problems. To make it possible, it was necessary to bring the World Bank into the project. In 1999 the World Bank Chad agreement introduced an innovative scheme designed to maximize the social use of oil revenues. With this system, all direct oil revenues (royalties and dividends) are paid into a sequestered account in the name of the Chad Government in London. After deduction of payments relating to the debts owed to the World Bank, the remainder of the revenues is divided up as follows: – 10% is paid into a fund for Future Generations, for the period after Chad's oil reserves are exhausted, – 72% goes toward capital investment in five "priority sectors" in the fight against poverty: education, health and social services, rural development, infrastructure and the environment and water supplies. – 4.5% is paid over to the oil-producing region of the Southern Chad, as additional reserve financing; – 13.5% is paid into the Chad Treasury to finance current public expenditure. But, the rise in the crude price put a new face on the situation. In January 2006, it led the government to denounce the agreement with the World Bank. Clearly making such a system sustainable over time is not easy. Nevertheless, this kind of agreements present promising solutions to provide a better use of the energy revenues. • The Extractive industries transparency initiative (EITI) has the objective to provide for a

detailed information on energy and commodity revenues, trying therefore to induce a 290

8.6.3

Major ethical issues: the environment and human rights

Quite apart from ethical questions, the activities of the oil companies mean that they are involved in a whole range of issues of a general nature. It should be remembered that oil products and gas are produced in order to meet society’s needs for energy. Approximately 50% of this energy is generated by the oxidation of the carbon contained in hydrocarbons (40% or more for natural gas and more than 60% for oil products). This results in the formation of carbon dioxide. This is in the nature of the process, and technological progress cannot change it. On the other hand technology can help us to reduce the amount of energy we consume to achieve a certain result, or perhaps even to “sequester” some of the carbon dioxide produced. However this is not in itself what the ethical debate is about. The debate arises from the fact that there is a correlation between the temperature in the lower atmosphere and its carbon dioxide content. This carbon dioxide content has been rising ever since the industrial revolution, and the question is to know whether increasing consumption of fossil energy could lead to major climate change. Such changes could be beneficial to some (Siberia, Canada, Nordic countries) but disastrous to others (countries with semi-arid climates and low-lying coastal regions in particular). These debates of course go far beyond the confines of the petroleum industry, but the latter inevitably occupies centre stage in relation both to the problems and the solutions or remedial measures which will need to be taken. This vast problem, known as the greenhouse effect, is not the only global or local environmental problem in which the oil industry is directly implicated. The climatic effect caused by airborne particulate matter and the health effects of urban pollution are due in large measure to the consumption of hydrocarbons. A number of ethical questions arise here where political leaders have to make trade-offs, of their nature difficult to justify, between short- and long-term effects, between public health and the economy. Although the oil industry does not itself have to make these trade-offs, it is directly involved, at very least in compiling technical reports which allow the facts to be established and understood before deciding how to try to limit the impacts. The oil industry is in particular heavily involved in transport-related problems. It has to provide for the transport of large volumes of oil and gas by land and sea. A number of environmental questions arise in this connection also, both local (oil spills, etc.) and global (emissions of methane from urban gas distribution networks). These questions also involve trade-offs between costs arising from the demands for ever greater safety and the implicit and explicit costs of pollution, either local or global. This again gives rise to questions of an ethical nature: what value should we attach, what priority should we give, to the survival of a particular plant or animal species threatened with extinction, what value to the conservation of biodiversity? What value should we attach to a human life? There are so many questions to which there are no natural and simple answers, whatever moral or philosophical frame of reference we adopt. 291

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better use of these revenues. This initiative is supported by more than 30 countries and 25 big oil, gas and mining companies. It is very interesting in that among the countries there are some of the more important oil producers in Africa or Central Asia, such as Nigeria, Gabon, Chad, Azerbaijan and Kazakhstan, Trinidad and Tobago. All the major international oil companies either American or European are involved in this initiative. A dynamic process has been initiated and it should provide for a better knowledge of commodity revenues.

Chapter 8 Health, safety, the environment, ethics

It is when major failures occur that these questions resurface: failures such as the wreck of the Erika off the coast of Brittany in the last days of 1999. A detailed analysis of this accident and its direct and indirect causes reminded all involved that only constant improvement in international regulations will allow risks of this kind to be diminished. This in no way means an abdication or absence of powers for national states. The latter have a double task: to put their full weight behind ensuring that the international rules are the best possible, and to ensure that the regulations are properly applied on their own territory as well as by the companies under their jurisdiction. A further point is that the objective of the oil companies is to produce fossil fuels, the reserves of which are considerable but finite. This is not the least of the ethical problems. To ensure that their activities are pursued within a framework of sustainable development, the oil companies must involve themselves in developing techniques and policies for reducing consumption so as to extend the era of oil and gas. Furthermore if they wish to extend their role as energy suppliers into the very long term they will have to get involved in the development of all forms of sustainable energy, whether renewable (solar, wind, biomass, etc.) or simply durable, such as nuclear energy. This last category also poses its own specific ethical problems. No discussion, however brief, of the major ethical problems in which the oil industry finds itself a participant can be complete without mentioning the question of human rights. We have already observed, in looking at the relationships with producing countries, that although the oil industry represents a source of wealth for these countries and therefore, potentially, of development, it can also be associated with major breakdowns in the political and social fabric, sometimes with tragic consequences. The oil industry therefore finds itself placed in the dock, or even declared guilty, by public opinion when dictatorial political regimes prosper, when civil war breaks out, or when cycles of violence and repression develop. In situations of this kind the oil industry serves as a scapegoat, and has to face a range of consequences. In such cases, as for the environmental problems discussed earlier, there are unfortunately no simple rules or clear answers as to what constitutes ethical behaviour by oil companies. But there are areas where progress is being made, and these must be explored, in particular through codes of conduct evolved between the governments of the countries of origin of the large oil companies and the companies themselves. The U.S. Department of State, for example, published an agreement of this type on 20 December, 2000, signed by the U.S. and the UK as well as a number of oil and mining companies from these two countries. Agreements of this kind cannot in themselves resolve problems of political instability or violence, but they have the merit of recognising that these situations exist, and of trying to articulate explicit rules of conduct for the companies in such contexts. Agreements of this kind comprise the first steps towards wider agreements which will also ultimately involve the governments of producing countries. We may be about to write a new chapter in international law, which recognises the right on the part of developed countries to interfere in the way large international companies conduct themselves in other countries. There is a clear movement from the oil industry to take into account the specific situation of the host countries as they are long-term partners in extraction activity. The international companies try increasingly to bring their contribution towards a sustainable development, whether it is about the direct consequences of oil and gas extraction, or about the consequences of economic development. It has to be a balance between the need for direct intervention and the need not to interference with the central and local government of host countries. 292

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It may be only a modest start, but is a token of a growing awareness of global problems. A global village needs global rules. In future the oil industry will not only have to comply with the rules but also to assume an important responsibility in ensuring that these rules are realistic, effective and ethical. If the oil industry succeeds in setting behavioural standards for the rest of industry, it will have fully accepted the responsibilities conferred on it by its economic weight and by the technical and human resources which it possesses.

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3. Annual Report BP Statistical Review of World Energy.

4. Review Oil and Gas Journal. Petroleum Intelligence Weekly.

297

Bibliography

2. Articles

Bibliography

5. WEB sites American Association of Petroleum Geologists: www.aapg.org. Energy Information Agency: www.eia.gov. International Energy Agency: www.iea.org. World Energy Council: www.worldenergy.org. American Petroleum Institute: www.api.org. U.S. Departement of Energy: www.fe.doe.gov. Organization of the Petroleum Exporting Countries (OPEC): www.opec.org. Oil History by Samuel T. Pees: www.oilhistory.com. Society of Petroleum engineers: www.spe.org.

298

This book is made up of contributions from the following authors:

Chapter 1

Denis Babusiaux (IFP Energies nouvelles) Philippe Copinschi (IFP Energies nouvelles) Jean-Pierre Favennec (IFP Energies nouvelles)

Chapter 2

Nadine Bret-Rouzaut (IFP Energies nouvelles) Élisabeth Feuillet-Midrier (IFP Energies nouvelles)

Chapter 3

Vincent Lepez (Total)

Chapter 4

Sébastien Barreau (IFP Energies nouvelles) Nadine Bret-Rouzaut (IFP Energies nouvelles) Roland Festor (Total) Michèle Grossin (Total) Pierre Sigonney (Total)

Chapter 5

Denis Guirauden (Beicip)

Chapter 6

Denis Babusiaux (IFP Energies nouvelles)

Chapter 7

Nadine Bret-Rouzaut (IFP Energies nouvelles) Michel Valette (Total)

Chapter 8

Pierre-René Bauquis (Total) Alain Chétrit (Total)

Nadine Bret-Rouzaut and Jean-Pierre Favennec were the overall coordinators.

Glossary

Arbitrage Financial operation which seeks to exploit geographical or temporal price differences. Arbitrage operations tend to reduce price differences and stabilise markets. Bonus Fixed sum payable by the holder of exploration and production rights to the state. There are three types of bonus: signature bonus, payable when the contract is signed, discovery bonus, payable when the discovery of a commercially viable field of hydrocarbons is announced and production bonus payable when certain production thresholds are exceeded. Brent A crude oil produced in the North Sea. Brent prices (both physical and paper prices) and the associated quotations serve as a reference in Europe and many other regions for determining the prices of other crudes. Broker Intermediary in the purchase or sale of crude oil and other petroleum products. Calcimetry Measure of carbonate content. Cash flow Casing

Receipts (cash in) less disbursements (cash out).

Piping cemented into the internal wall of a well in order to maintain it.

CIF (Cost, insurance, freight) Cost of crude oil or product which includes insurance and sea freight to the destination port. Club of Rome Think tank in the 1970s renowned for publicising the risks of depletion of natural resources due to over – rapid economic growth. Commercial discovery A discovery of hydrocarbons the commercial potential of which has been demonstrated by an operator based on technical, economic, contractual and fiscal parameters. A discovery cannot be developed and exploited until it has been declared commercial. Completion The operation of deploying production equipment in an oil well. Concession An arrangement by which the state grants the exploration and production rights within a given zone to the concessionaire who, in the case of commercial production, becomes the beneficial owner of the entire production in exchange for payment of the appropriate taxes (essentially a royalty on production and a tax on profits). The term also means, in some countries, the legal title to mineral hydrocarbons authorising exploitation, or in some countries, the contract associated with this mineral title. 299

Glossary

Consolidated profit Accumulated net profit/loss, both national and international, of the parent company and all its branches and subsidiaries in which it holds a significant share of the voting rights. Constant money a reference year.

Notional monetary unit based on the purchasing power of the money in

Conventional hydrocarbons Hydrocarbons which can be produced by “conventional” methods and have standard characteristics in terms of viscosity, density, etc. Conventional oils are supposed to be between 10 and 45° API in gravity. Coring Operation involving taking a cylindrical sample of rock, carried out by means of a special tool – a core barrel – in a probe. Cost oil In a Production Sharing Contract the fraction of the production allocated to recover the contractor’s costs (capital and operating costs). Current money Monetary unit applying in the year under consideration. Day rate contract Type of contract made between an oil company and a petroleum industry service company by which the former controls the operations and the contractor receives a fixed daily remuneration. Delineation After preliminary drilling has demonstrated the presence of hydrocarbons in a structure under exploration, the subsequent drilling programme which allows the potentially productive formations to be defined and delimited. Derivatives On futures markets a distinction is made between contracts (firm commitments to buy or sell a quantity of crude or a product) and derivatives: options, swaps,… Many derivatives are OTC (over the counter) transactions —carried out between two parties by mutual agreement, without the intercession of an organised market. Derrick Tower like lattice structure in the form of a truncated, elongated pyramid. In drilling equipment a derrick is used for hoisting and lowering. Development costs Costs associated with the drilling of the production wells (and if applicable the injection wells), the construction of the surface facilities (collection network, separation and processing plant, storage tanks, pumping and metering equipment) and transport infrastructure (pipelines, loading terminals). Diesel oil (diesel) Fuel used by diesel engines. Discount factor Factor applied to cash flows occurring at different dates to render them comparable. The discount factor for year n relative to year 0 is 1/(1 + i)n (where i is the discount rate). Discount rate Cost of capital (effective cost or opportunity cost), the internal rate at which the financial department requires remuneration from departments responsible for investment projects. A company usually defines the effective cost of capital as the weighted average cost of finance from different sources (assuming the capital to debt ratio is given). When capital is rationed, the discount rate may be higher than the average effective cost of capital to reflect a scarcity premium. Discounted value See Net present value. Discounting A decision maker does not place the same value on a given receipt or expenditure in a number of years as on the same sum now. Discounting consists of applying a given 300

Dubai

Reference crude for trade East of the Suez Canal.

Economic rent The difference between the value of production (gross revenue) and the technical costs (capital and operating costs), before tax. Equivalent cost time, we have:

When the equivalent cost (annual or unit) can be assumed stable over

• Equivalent annual cost: the annuity equivalent to the discounted capital and operating

expenditure. • Equivalent unit cost: the ratio of the total discounted expenditure to the total discounted production. Exploration costs Costs incurred before the discovery of a field, including costs related to the seismic/geophysical programme, the geological and geophysical interpretation, the exploration drilling including the test wells. Extra heavy crude Very heavy crude (specific gravity greater than 1, so API less than 10°), found particularly in Venezuela in the Orinoco basin. The Orinoco crude is a non conventional one since, before use, it needs a special treatment to make it suitable for processing in a traditional refinery Field A field can be defined as a receptacle comprising a permeable rock reservoir sealed by a cap made of impermeable rock and a favourable subsoil configuration referred to as a trap. There are different types of trap, including structural traps, stratigraphic traps and mixed traps. Fiscal regime or Taxation system The totality of fiscal and contractual conditions which determine how the oil profits are shared between the state and the holder of exploration and production rights FOB (free on board) The FOB price is the price of a crude oil or of a product when loaded onto a ship at the port of embarkation. In principle at any given time there is only one FOB price for a port (Ras Tanura for Arabian Light, Sullom Voe for Brent, Bonny for the Nigerian crude of that name) whereas there are as many CIF —see CIF— prices as there are destination ports. Foot rate contract Type of contract signed between a petroleum industry service company and an oil company where the latter controls the operations and the former is remunerated according to some measurable unit of activity (for example per metre drilled in the case of a drilling company). Full cost method Accounting method defined by SFAS 19 and applying to exploration and production expenditure. All expenditures (exploration and development) are capitalised. Futures markets Financial markets on which normalised contracts for crude or petroleum products are exchanged. They meet the needs of operators to protect themselves or exploit price fluctuations using hedging, arbitrage and speculation. Physical deliveries account for only a small part of the transactions effected on futures markets. Orders are transmitted by a broker and the security of operations is guaranteed by means of deposits to a clearing house. The main markets are the NYMEX (New York) the ICE (London) and the SIMEX (Singapore). Gas cap Gas already separated from the oil in an oilfield, most often situated close to the top of the structure. 301

Glossary

annual rate (this rate is specific to the company) to future receipts and expenditures to estimate their present value. Discounting tends to reduce the importance of future cash flows.

Glossary

Gas lift Production process involving gas injection which serves to emulsify and lighten the oil column. Gas oil A petroleum cut which can be used for diesel oil or heating oil manufacturing Gearing Ratio of debt to equity. Geneva Agreements Agreements (signed in 1972) between OPEC and the oil companies which provided for an increase in oil prices to allow for the devaluation of the dollar. GOSP (government official selling price) Between the first oil shock (1973) and the beginning of the eighties, the prices of the various crude oils —GOSP— were fixed by the OPEC governments. These prices replaced posted prices. Government take The total revenues accruing to the government including the earnings of the national oil company. It can be expressed as a percentage of the economic rent, and measures the severity (from the investor’s point of view) of the fiscal regime. Heating oil buildings.

Petroleum product used for space heating in residential and commercial

Heavy fuel oil

Fuel used by heavy industry, power stations and marine shipping.

Hydrocarbon tenement Legal document, often in the form of a decree, which assigns exploration rights (exploration licence) or production rights (production licence or concession) to a party. IFP (now IFP Energies nouvelles) French Petroleum Institute, a scientific institute devoted to research, training and documentation, founded in 1944, from which has emerged an extensive structure of companies and consultancy services. Internal rate of return (IRR) Discount rate at which the net present value of a project is nil. When unique, this is the maximum rate for which the project revenues allow the invested capital to be remunerated without the project going into deficit. In this case a project for which the IRR is greater than the discount rate has a positive net present value. On the other hand in choosing between several competing projects, it is not necessarily that with the highest IRR which is the best (highest net present value is a better criterion). Jet fuel

Fuel used by aircraft powered by turbines.

Kerosene Petroleum product from distillation which can be used for lighting or as jet fuel. Logging while drilling (LWD) Technique consisting of recording, at the bottom of the well during drilling, by means of sensors deployed in the drilling equipment, physical parameters which allow the nature of the formations, their pressure regimes and the fluids of which they are composed to be characterised. Logging The recording of certain electrical, acoustic and radioactive characteristics of geological formations. Migration reservoir.

A physical process in which hydrocarbons move from a source rock to a

Monte Carlo Simulation method used, in particular, to determine the probability distribution function of a variable (e.g. net present value) which is a function of other variables with given probability distribution functions. 302

National oil company Oil company fully owned by the state or in which the state has a majority holding, to which the government delegates the role of supervising oil operations and managing that part of the production accruing to the state where applicable. Net present value (NPV) The sum of the present values of the cash flows associated with a project. An investment project with a positive NPV will repay the investment giving a return equal to the discount rate and produce a surplus whose present value is equal to the NPV. Netback The netback value of a crude is equal to the value of the products obtained from its processing less refining and transport costs. The netback value of a crude can be compared with its FOB price. If the netback value exceeds the FOB price the refiner will make a profit, otherwise he will make a loss. Nominal value Value expressed in current money. Non conventional hydrocarbons These are hydrocarbons which, unlike conventional hydrocarbons, are difficult and costly to produce, and whose physical characteristics and geographical situation are exceptional. Non conventional oils include extra heavy oil (from Orinoco) and tar sands (from Athabasca – Canada) which both need a special processing before treatment in traditional refineries. Non conventional oil includes also ultra deep offshore fields. Offshore Refers to any exploration or production activity at sea, in contrast with onshore activities. The term “ultradeep offshore” refers to petroleum activities carried out at great depth. Oil quotas In 1982 the OPEC countries established quotas, or production ceilings, as a means of regulating prices. Since that date, each OPEC member state has had to remain within a production ceiling, adjusted periodically in the light of market conditions. Oil sands Very heavy crude oil of specific gravity around 1 (or 10° API), close to tar, in sand reservoirs. There are very large deposits of tar sands in Athabasca, Canada. The production of oil from these sands is currently being developed. OPEC Organisation of petroleum exporting countries, created on 14 September 1960 by Saudi Arabia, Iraq, Iran, Kuwait and Venezuela. Opening up Many producing countries nationalised their oilfields in the 1970s. Now certain countries are reopening their doors, allowing foreign companies to operate in their territory. Operating cash flow project.

Cash flow excluding flows related to loans used to finance the

Operating expenditures (OPEX) production facility.

Total expenditure which relates to the operation of a

Options Financial instrument giving the holder the option to buy (call) or sell (put) a contract at a given price until a given date. If the option is not exercised before it expires, the holder’s loss is limited to the price paid, whereas there is no limit to his possible gain. The price of the option represents the market value of the option. Paraffin Petroleum product used for lighting (also known as kerosene). 303

Glossary

Mud logging A technique which involves the acquisition and interpretation at the surface of samples, data and information, making use of the mud circuit.

Glossary

Petrol (gasoline–US)

Fuel used by spark–ignition engines.

Petroleum price shock Term used to describe a large increase in oil prices, particularly the “first price shock” of 1973 and the “second price shock” of 1979 – 1981. Petroleum system Designates the interplay of the geochemical, geological and physical parameters, the processes and the genetically related hydrocarbons which lead to seepage and accumulations of hydrocarbons originating from a given source rock. Production plateau

See production profile.

Production profile The way the production level of an oil or gasfield varies over time. Early in the production phase there is a steep build up in production, after which there is usually a period of stable production (plateau) followed by a progressive decline. Production Sharing Contract Arrangement by which exploration and production rights in a given zone are granted by the state to a contractor who, in the event of commercial production, can recover his costs from a part of the production (cost oil) and obtain a return on part of the remaining production (profit oil), the balance accruing to the state. Profit oil In a Production Sharing Contract, that part of production remaining after the cost oil. This part is shared between the contractor and the state on the terms agreed in the contract. R/P

Ratio of remaining reserves to annual production (expressed in years).

Real value

Value corrected for inflation, expressed in constant money.

Recovery rate Ratio of reserves to resources. Recovery rate is between 5 and 80 % for crude oil depending upon field and oil characteristics. Average value (for crude oil) is around 35 %. For natural gas recovery rate is around 80 %. Red line Line drawn on the map of the Middle East in 1928 in discussions between the partners in the Iraq Petroleum Company. This line marked a region within which the partner companies in the IPC were obliged to act in concert. Reserves There are many definitions of hydrocarbon reserves. The reader is referred to the index, which cross references these various definitions. In general when the term “reserves” is used as such, it is synonymous with the term “proven reserves”. Resources Total quantity of hydrocarbons physically present in the ground. Riser Pipe connecting the seafloor with the surface during submarine drilling. Royalties Under a concession system, the owner of land mineral rights (generally the state) grants an operator the right to produce oil in exchange for the payment of royalties equal to a percentage of the crude price. This royalty, often fixed at 12.5% of the crude price, can vary depending on the price of the crude and the characteristics of the field. SEC

Securities and Exchange Commission.

Seismic reflection Seismic prospecting technique in which seismic waves caused by explosions are reflected by the subsoil strata. Sensitivity analysis Analysis of the impact on the profitability of a project of possible variations in the different project parameters (e.g. investment costs, selling price, etc.). SFAS 69 Amendment defining how exploration and production costs should be dealt with. Companies may choose between the successful efforts and the full costs methods. 304

Statement of Financial Accounting Standards.

Spot market A market in which deals are struck on the day itself, with prices being fixed at the time. The products traded are physical cargoes of crude and refined products. There is no official record of transactions effected between operators, but estimates are published by specialised journals such as Platt’s. There are spot price estimates for both crudes and for the principal products for the main consuming and refining regions: Rotterdam or North West Europe, the Mediterranean, the Gulf, Singapore, the Caribbean, the U.S. The spot price of the main crudes (Brent, WTI, Dubaï) act as indicators of crude prices and as reference price in certain indexation clauses. There is also a spot market for vessel charter. Spot

See Spot market.

State participation Contractual provision by which the state has the option to participate in the contract in partnership with the contractor, to the extent of its participation. Success rate Ratio of non–dry wells drilled to the total number drilled. Successful efforts method The accounting method defined in SFAS 19 applying to the expenditure associated with exploration and production. The costs of the geology geophysics and unsuccessful exploration are expensed. Swaps A type of “paper” contract in which the difference is bought between its values quoted on the spot and forward markets. This instrument allows oil companies to make sales to their customers for delivery several months hence (up to one year) at a guaranteed fixed price. Tax In a concessionary system, the operator pays the owner of the field not only royalties but also a tax on profits. Technical cost Total costs : exploration + development + production costs Teheran Agreements Agreements (signed in 1971) between OPEC and the oil companies which provided for programmed increases in oil prices for the Gulf producers. Traders Persons who buy and sell commodities, currencies or financial instruments. Unlike a broker, whose function is merely to act as an intermediary between a buyer and a seller, traders buy and sell cargoes on their own account and therefore are exposed to significant risk. A petroleum trader may be attached to a producing country, belong to an oil company or a financial group or be an independent. See also Broker. Trading Buying and selling. Tripoli Agreements Agreements (signed in 1971) between OPEC and the oil companies which provided for programmed increases in the price of oil available in the Mediterranean. Turnkey contract, firm price contract Type of contract made between an oil company and a petroleum industry service company. Unlike a cost reimbursement contract or a contract based on a work specification, the contractor is responsible for the operations and is paid for services rendered (a drilling project, for example) at a contractually agreed overall price. Unitisation Contractual clause providing for the unified operations for a field extending over several contractual zones exploited by different operators. Uplift Device equivalent to an investment credit authorising the holder of production rights to write off (in the case of a concession) or recover (in the case of shared production) a sum in excess of the actual investments. 305

Glossary

SFAS

Glossary

Wire line logging A technique which involves using sensors lowered on the end of an electric cable to record physical parameters such that the nature of the formations, their pressure regimes, the fluids of which they are composed can be characterised. WTI (West Texas Intermediate) Reference crude in the U.S., on both the spot and NYMEX markets.

306

UNITS FOR THE PETROLEUM INDUSTRY, RATE CONVERSION Symbols k M G T t m3 ft3 bbl oe

= = = = = = = = =

103 = kilo = thousand 106 = mega = million 109 = giga = billion 1012 = tera = trillion ton cubic meter cubic foot (or cu ft) barrel oil equivalent

Petroleum units

Gas units 1 Tm3 = 35.3 T · cu ft (1 T · cu ft = 28 G · m3) 1 boe = 5.35 k · cu ft (1 k · cu ft = 0.18 boe)

1 bbl= about 0.14 t (1 t = 7.3 bbl) 1 bbl= 0.159 m3 (1 m3 = 6.3 bbl)

XIV

INDEX

Index Terms

Links

A Abandonment

186

Achnacarry Agreement

18

AGIP

23

Agreements

302

geneva

302

teheran

305

tripoli

305

197

305

Alaska

25

Anglo-Iranian

12

21

Anglo-Persian

12

14

15

17

19

46

Arab Light

30

44

Aramco

20

Arbitrage

50

Arbitration

191

Azerbaijan

8

B Bahrain

19

Baku

8

Balance sheet

266

Balikpapan

10

Barges

73

Benchmarking Between Iraq and Iran

9 11

254 31

This page has been reformatted by Knovel to provide easier navigation.

Index Terms

Links

Bonus

194

Brent

48

Brent blend

44

British Petroleum Company

12

Buyback contracts

195

203

C C.S. Gulbenkian Cash flow statement

18 271

Casing

73

Caspian

8

Caspian Sea

8

CFP

15

9 16

17

18 Churchill

12

CIF

45

Clemenceau

15

Club of Rome

25

Commerciality

185

Compaction

61

Compagnie Française des Pétroles

15

Competent authority

17

176

Completion

86

Concession

174

179

193

206

Consolidated accounts

272

Contract

164

day-rate

164

foot-rate

164

turnkey

164

Conventional hydrocarbons

99

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180

Index Terms Cost

Links 221

equivalent cost

221

Cost oil

200

Costs

125

127

131

156

158

255

270

271

256 capitalised

255

development

131

exploration

125

incurred

256

operating

156

trends

127

Counter-shock

35

D Decision trees

234

Decommissioning

284

Deep offshore

100

Depletion rate

259

Depreciation

250

declining balance

271

straight-line

271

UOP

250

Derivatives

49

Derrick

73

Deutsche Bank

17

Diesel

3

Diesel oil

44

Diesel-oil

7

Discordance

61

Discount rate

217

Dubai

44

49 This page has been reformatted by Knovel to provide easier navigation.

Index Terms

Links

E Economic reproduction

109

Ekofisk

44

Elf

15

EMS

144

ENI

15

EPC

144

Expected value

231

Exploration Extra-heavy oils Exxon

110 20 20

65 100 7

F FASB (Financial Accounting Standards Board) Fina

245 20

Finding cost

259

FOB

45

Forward

49

Fossil carbon continuum Fuel oil

100

111

7

Full cost method

247

Futures

49

Futures markets

48

50

G Gas cap

79

Gas clause

192

Gas hydrates

104

Gasoline

7

Geneva

27

111

44

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23

Index Terms Geology

Links 67

organic geochemistry

67

sedimentology

67

stratigraphy

67

structural geology

67

Geophysics

68

Ghawar

44

Government Official Selling

47

Government take

209

Gulf

12

Gulf of Mexico

25

Gulf Oil Corporation

12

Gulf plus

47

H Heavy fuel

3

Heavy oils

100

Henry Deterding

11

Horizontal drilling

85

Hubbert theory Hydrocarbons in place recoverable

46

105 95 95

I IEA Incentives INOC

29

50

193

204

25

Installations

137

production

137

transport

137

Institut Français du Pétrole

23

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207

Index Terms

Links

Intensity of

259

Internal rate of return

220

Investment

259

Investment credit

197

200

208

2

5

6

7

10

J Jackup

73

Jet-fuel

44

John D. Rockefeller

5

Jossef Djugashvili

9

K Kerosene Kirkuk

18

Kuwait

4

19

Lacq

21

22

Law

175

Legislation

175

LNG cycle

151

L

Logging

176

75

logging while drilling

75

mud log

75

wireline logging

75

Lognormal distribution

96

M Majors

7

Marcus

10

20

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36

Index Terms

Links

Marcus Samuel

10

Marne taxis

14

Mesopotamia

15

Mexico

13

Mining title

174

N Nationalisations

28

Net present value

219

Netback

35

Nobel

8

Non-conventional gas Non-conventional hydrocarbons Norsk Hydro

102 99 167

O OAPEC

28

Oil shales

101

Oil shock

27

Oklahoma

45

OPEC Optimists Options

28

30

24

28

30

31

32

33

109

110

49

Ownership

171

172

P Participation

207

Permeable

65

Pessimists

109

Petrol

110

3 This page has been reformatted by Knovel to provide easier navigation.

194

Index Terms

Links

Petroleum system

65

Platforms

73

Polar zones Porosity

103 65

Production profiles

104

Production sharing

174

Production sharing contract

179

180

207 Profit and loss account

268

Profit oil

200

208

Q Quotas

34

R R/P

108

Ras Tanura

45

Recovery

80

enhanced

80

primary

80

Recovery factor

108

Recovery ratio

96

Red Line

18

Regulations

177

Relinquishment

183

Rent

178

Reserve

258

Production-sharing contract (PSC)

261

replacement cost

260

replacement rate

258

Reserve ratio

19

260

252

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199

Index Terms Reserves

Links 93

1P, 2P and 3P

97

conventional

94

non-conventional

94

P90, P50, P10

97

possible

98

probable

98

proven

98

SFAS 69 definition ultimate

95

248

6

45

248 93

Resources

95

Rigs

73

Ring-fencing

196

Risk service contract

179

Rockefeller

5

Rothschild

8

Royal Dutch Shell

9

15

194

195

206

Samuel

8

9

11

Saudi

4

202

203

Royalty

S

Saudi Arabia SEC

19 244

Sedimentary basins

61

Seismic

69

reflection Semi-submersibles Service contract Seven sisters

69 73 180 23

SFAS 69 (Statement of Financial Accounting Standards)

245

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Index Terms

Links

Shell

9

Sherman Act

6

Six Day War

25

Slot ratio

10

11

252

Socal

19

Sovereignty

171

Spar

149

Spindletop in 1900

12

Spot markets

48

173

Stalin

9

Standard Oil

5

6

9

10

15

18

194

205

State participation

188

State take

209

Statoil

167

Subsidence

61

Success rate

108

Successful efforts method

246

Suez Canal

25

Swaps

49

Synthetic oils

102

T Tax

176 207

Tax incentives

190

Taxation

197

202

Teheran Agreement

27

Texaco

12

19

Texas

12

45

Texas Railroad Commission

46

Title

199 This page has been reformatted by Knovel to provide easier navigation.

Index Terms

Links

Traders

50

Trap

64

stratigraphic

64

structural

64

Tripoli Agreement

27

Tubing

87

Turkish Petroleum Company

17

U Ultra-deep offshore

100

Unitisation

186

Uplift

197

Uplifts

207

208

V Venezuela Volga

13 4

W Walter Teagle

46

Well capping

284

Wellhead

87

William d’Arcy

12

Winston Churchill

3

Work programme

184

Work programmes

187

Workover

89

WTI

49

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