Oil and Gas Exploration and Production Reserves, costs, contracts Third edition revised and updated Editions TECHNIP 25 rue Ginoux, 75015 PARIS, FRANCE 2011 Nadine BRET-ROUZAUT and Jean-Pierre FAVENNEC 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
Transcript
Oil and GasExploration and
ProductionReserves, costs, contracts
Third edition revised and updated
Editions TECHNIP 25 rue Ginoux, 75015 PARIS, FRANCE
2011
Nadine BRET-ROUZAUT and Jean-Pierre FAVENNEC
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)
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 annualOutstanding 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 asimportant treatment of the subject.
Translated byBowne Global SolutionsMr Jonathan PEARSE
FROM THE SAME PUBLISHER
• The Geopolitics of EnergyJ.P. FAVENNEC
• The Oil & Gas Engineering GuideH. BARON
• Project Management GuideM. DUCROS, G. FERNET
• Petroleum Refining. Vol. 5: Refinery Operation and ManagementJ.P. FAVENNEC
• Petroleum EconomicsJ. MASSERON
• Manual of Process Economic EvaluationA. CHAUVEL, G. FOURNIER, C. RAIMBAULT
All rights reserved.
No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechan-ical, including photocopy, recording, or any information storage and retrieval system, without the prior written per-mission of the publisher.
We first had the idea for this book in early 1999, when we considered writing about all theeconomic considerations associated with hydrocarbon exploration and production. It was thenthat we laid out its aims and devised the plan.
The idea was consistent with one of the missions of the IFP School’s Centre forEconomics and Management: to convey information about all aspects of the hydrocarboneconomy. 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 seenas 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 onit, and which shall continue to be dependent on it for a number of years to come. It looksback over the history of this raw material, investigates the changes in its price over the yearsand the changes in the way in which the whole oil industry has been structured. The secondchapter adopts a more technical approach and describes the expertise and technologies thatare used both in the search for hydrocarbons and in their production. The third chapter looksat the concept of reserves and discusses it, along with the various classifications and modesof assessment involved. The fourth chapter puts forward a detailed analysis of the invest-ments and costs involved in this highly capital-intensive industry. The fifth chapter deals withthe legal, contractual and fiscal considerations which govern the ways in which income isshared among the various stakeholders involved. The sixth chapter looks at the economiccriteria which are used when investment decisions are made in this sector. The seventhchapter looks at specific accounting features and other useful indicators that are used foranalysing 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 whichColonel 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 thefirst 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 anumber of specialists who were tasked with looking out for errors and putting forwardrecommendations for changes and improvements. Among them are Alain Auriault, AntoineCouturier, Alain Doat, Jean-Luc Mari and Alain Mascle.
Foreword to the third edition
Finally, we would like to thank Total, Shell and BP who were kind enough to provide uswith the photographs without which such a book would not have been possible.
Nadine Bret-RouzautDirector of the Centre for Economics and Management
IFP School
Jean-Pierre FavennecConsultant
Professor IFP School
September 2011
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It has been a long time since a reference book on the exploration and production of oil andgas was last published. This book therefore meets a genuine need: to explain to a well-informed readership (teachers, students, researchers, journalists, engineers, industrial andpolitical decision-makers) the key activities of this sector so vital to the world economy bothnow and in the future. It also provides essential information for the public at large on therelationships between energy and the environment, which involve many complex issues andstir public debate.
This book stresses the economic aspect of petroleum activities and provides a solid under-standing of the technical and contractual issues which underpin relations between thepetroleum industry and the producing countries, a wise choice since the economics of thesector cannot be understood without a solid grounding in the technical, legal and politicalaspects.
I should like to pay tribute to the IFP and the IFP School for having taken the initiativeto compile this book, particularly valuable because of two features: it brought together, atboth 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 wellas recognised academic and industrial experts.
The book therefore sets a fine example in our rapidly changing world, and should beinstrumental in attracting new talents to a sector which will remain exciting and vital for atleast the next 50 years and probably longer.
I hope this book is rewarded with the success it deserves.
1.2 Historical background 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51.2.1 The large oil companies up until the First World War, early competition . . . . . 51.2.2 Between the wars: the role of the state . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141.2.3 Between the wars (2): cooperation and competition between oil
companies. The example of the Turkish Petroleum Company . . . . . . . . . . . . . . . . . . 171.2.4 After WWII: increasing oil consumption, new oil companies, creation and
References to petroleum (literally oil from stone) or more precisely bitumen, asphalt or evenpitch, can be found in writings going back to earliest antiquity. These texts effectivelydescribe the heavy and viscous residue which remains when petroleum reaches the earth’ssurface and loses its lighter fractions as a result of natural evaporation. This residue has manyuses, in particular the caulking of ships. It is said that Moses’cradle may have been tarredto 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 otherimportant purposes: as a medicine it was considered a panacea (see Box 1.1 and Fig. 1.1).
1Petroleum:a strategic product
Figure 1.1 Oil, a universal remedy.
The ailments which it was supposed to cure were numerous: scurvy, gout, toothache,rheumatism, even ingrowing toenails according to Morris and Goscinny, authors of thecartoon 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 fore-runners of modern-day napalm.
But the modern development of petroleum is mainly attributable to the invention of theoil lamp (Fig. 1.2) by the physicist Argand, later improved by Quinquet, a Parisian phar-macist. This lamp provided exceptional lighting, and caught on very quickly. From ourvantage point in the new millennium, these lamps, very varied in size and shape, testifyvividly to the daily life of our forefathers. Originally they often used whale oil. But apartfrom endangering the survival of their prey, whalers were not able to meet the needs ofconsumers. It was replaced by paraffin, or “kerosene”, a petroleum product. However naturalseepage rapidly became insufficient to meet growing demand, prompting subsurface explo-ration to increase production. On 27 August 1859 Colonel Drake carried out the first drilling
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“He continued:
– In those days, the sons of our warriors did not learn how to read. They did not go toschool but they understood the language of the birds and of all the animals that the Great Spirithad created in the sky, the waters, the prairie and the forest. They learned without a teachereverything they needed to live. Often, in the forest or in the mountains, they came across blacklakes, 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 attractedfrom 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 theharsh winter without feeling the cold lick the grease from their paws; for us, if we drink theseoily 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 apowerful remedy against all the ailments which threaten a warrior during his lifetime. Thosewho drank from these waters no longer suffered headaches or stomach aches; they saw theworms which incessantly gnawed away at man’s liver and entrails leave their bodies. Thosewho poured it over their heads felt their hair grow longer; those who applied it to their woundswere cured more quickly than with the balsams of our medicine men. Those who rubbed iton their bodies were protected against snakebite; even the Iroquois claimed that if they mixeda 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 groundwhere salt was plentiful, on the surface of the earth. They threw their woollen blankets in theseholes. At sunset, they prayed to the Great Spirit for mercy. And often, in the morning, theywould 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 apaleface who came to this country, many years ago, when the Indians knew no other masterthan the Great Spirit, between earth and sky.”
“The land of oil”
Hugues Le Roux, Félix Juven Publishers, 1901.
Box 1.1 The balsam of the Senecas
at Titusville, Pennsylvania. This was successful. At a depth of 23 metres the bottom of thepit 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 distil-lation techniques practised at that time allowed the heavy fractions to be separated and usedas lubricants, but part of the crude was deliberately discarded; environmental constraints werenot yet what they were to become a century later!
Increases in the consumption of kerosene led to a rapid growth in the demand for crudeoil. By the turn of the century oil lamps were being progressively replaced by the electriclight bulb, and the consumption of kerosene began to decline. But declining demand forkerosene was offset by growing demand for petrol for cars, and later diesel. This was ofcourse 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 Lordof the Admiralty 1911-1915, urged the adoption of this fuel by the British fleet whoseeventual agreement made an important contribution to the development of petroleum.
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Figure 1.2 Oil lamp.
Figure 1.3 Delivery van in the 1920s (by kind permission of BP).
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 wasstill the dominant source of energy. It was only after the war ended in 1945 that oil was tobecome the energy of reference. Consumption rose from 350 Mt in 1945 to over 1 Gt in1960, over 2 Gt in 1970 and over 3 Gt in 1990. Now at the beginning of the 21st centuryconsumption is close to 3.5 Gt/y.
1.1.2 The importance of oil
Yves Lacoste claimed that “geography is used to make wars”. We could paraphrase him byadding that so does oil. It would be possible to do without metals or certain agriculturalproducts 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 Russianoilfields of the Volga. Berlin later directed its forces towards the Middle East where largedeposits 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’sprosperity but even his survival may depend. Georges Clemenceau declared at the end of
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Figure 1.4 German army advances towards the Volga and the Middle East.
Nor
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Moscow
Stalingrad
Sovietcounter-offensive
Britishcounter-offensive
Turkey
IranIraq
El Alamein
EgyptLibya
Algeria
Morocco
WW1 “Petroleum is as necessary to the economy as blood to the human body”. But theexamples of Japanese and Korean industrialisation show that it is control over the supply ofpetrol 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 naturalgas and LNG) may make some inroads into the market for auto fuels, but the only seriousrival is electricity. However technological and economic problems mean that it is likely tobe many years or even several decades before electricity begins to make major headway inthe auto fuel market. It should also be noted that, even if electricity were to become a seriouscontender, it would probably still be necessary to have recourse to petroleum or gas as energysource in the fuel cells. For the moment there is no prospect of replacing oil products. Mean-while another oil product is likely to continue to grow: the fractions which are used as feed-stocks for petrochemicals. The demand for petroleum is likely to go on increasing in thecoming years to attain a level in excess of 4 Gt/y.
1.2 HISTORICAL BACKGROUND1
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 thatof 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 oilsector belonged to John D. Rockefeller. He initially headed up a wholesale business, one ofwhose 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 burgeoningpetroleum industry. He acted according to a number of simple but effective principles:control the various links in the petroleum chain (storage, refining, transport, distribution infra-structure) 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 onthe 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. Aftera decade of fierce struggle with his competitors Standard Oil achieved a dominant positionin the market, controlling 80% of the distribution of the principal oil products, and inparticular kerosene.
But the success—and size—of Standard Oil provoked defiance and hostility not onlyamongst its competitors but also amongst some sections of the public and the authorities. Inorder to defuse these attacks the company formed itself into a trust in 1882. The shares inthe various operating companies in the group were presented as being no longer the propertyof a single company but rather as being held in trust on behalf of their owners, the share-holders of the main company. The Standard Oil Trust issued 700000 shares, distributed
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1. This section was inspired particularly by Étienne Dalemont and Jean Carrié: Histoire du pétrole. PressesUniversitaires de France, 1993.
amongst its members; it received, in trust, the shares of all the companies in the group (14were totally controlled and 26 partially controlled). The group continued to be run by a smallteam led by Rockefeller.
Against a background of rapid growth in the demand for lighting, heating, lubricants andgreases, 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 oilproduction in order to guarantee its supplies of crude. This strategy of developing itsproduction capacity proved particularly judicious when in 1888 a chemist employed byStandard Oil perfected a refining process which permitted sulphur to be removed from oilproducts, particularly kerosene. Hitherto kerosene with a high sulphur content had beenimpossible to sell because of the odour produced when it burned. This invention meant thatnew high-sulphur crudes could be used.
Having become a trust in 1882, Standard Oil was forced to transform itself after anti-trustlegislation was enacted (Sherman Act, 1890). In 1899 a new holding company, the StandardOil Company of New Jersey, was created, bringing under its umbrella all the companies thenconstituting the group.
The new company continued to represent a great concentration of power, attractinghostility not only from the authorities, who sought to promote competition, but also from
* and on 27 August 1859, having drilled to a depth of 23 metres, Drakediscovered oil, lots of it. This was the dawn of a new era for mankind…
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 thejournalist Ida Tarbell, subsequently compiled into a book, “The history of Standard Oil”, hada tremendous impact. Eventually action was taken in the courts, and in 1909 the FederalCourt ordered the break-up of Standard Oil. Despite delaying tactics employed by thecompany, the ruling was confirmed in 1911. The group divided up into 34 separatecompanies (see Box 1.2).
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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, 8turned to other activities and 21 continued their development, in some cases buying outtheir 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 mergerwith 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 “offspringcompanies” of Standard Oil.
The strategy adopted by Standard Oil illustrates the constant concern of industry tocontrol the entire chain of its activity. Furthermore this desire for control rapidly translateditself into a financial obligation, the demands of technological and industrial developmentimposing investments on companies which only the largest could bear. This was conduciveto the emergence of a vertically integrated and oligopolistic industry. Although in the firsttwenty years of its existence the petroleum industry was American, and dominated byStandard Oil, it rapidly became an international industry, even though the U.S. continued toaccount for more than half of world production until 1950. The growth in the consumptionof kerosene, followed by gasoline, diesel-oil, and fuel oil was a worldwide phenomenon. Notonly Europe but also Russia and Asia became important markets. New oil companies werecreated (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 becamethe “majors” (also known as the seven sisters).
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 bythe 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 andthe Far East. It was transported by camel in goatskins.
The early discoveries of oil in the U.S. rekindled interest in the Baku resources, anddrilling commenced there in 1872 (Fig. 1.6). Oil production grew rapidly, attaining 1 Mt in1889, 4 Mt in 1890 and 10 Mt in 1900. At that time this was half of world production, andexceeded U.S. production. Among the first to buy up land on the banks of the Caspian wereRobert 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, refineriesand 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 inthe region. Of course a problem which rapidly presented itself was how the oil was to betransported out of Azerbaijan, across Georgia to the Black Sea. The isolation of the oilresources 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 toBatum 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. anda refinery on the Adriatic. He agreed to participate in financing the pipeline, and went on toestablish a company, BNITO, which was to become one of the largest in the region.
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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, theRothschilds were much more dependent on foreign markets. The latter therefore turned toMarcus Samuel (Fig. 1.7), a London businessman specialising in imports and exports, partic-ularly the import of antiques and sea shells from the Far East, in regard to the transportationof their products.
For many years there was fierce competition between Standard Oil and the Caspianproducers. 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 1917the Bolsheviks took power and overthrew the Tsar. During this whole period the Baku regionwas being shaken by a whole series of strikes and industrial unrest caused by the deplorableworking conditions. One of the leaders of these actions was a certain Jossef Djugashvili, laterto become the notorious Stalin. In the face of this situation, the Rothschilds decided in 1912to sell most of their interests to Royal Dutch Shell, which had been set up in 1907. In 1918the new Soviet regime nationalised the entire oil industry. Royal Dutch Shell lost 50% of itsoil supplies at a stroke. The last remaining Nobel was stripped of all his assets, which StandardOil of New Jersey nevertheless bought from him, doubtless convinced that it would one daybe able to resume operations on Russian territory. This hope was dashed, because despite theadoption of a new and more liberal New Economic Policy in the 1920s, none of the companieswhich 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 turnof the century. By 1930, however, it had regained the level it had enjoyed before the outbreakof the 1914 – 1918 war, the government being in dire need of foreign currency earnings fromoil 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 nine-teenth century, and there was particularly fierce competition between Standard Oil, theNobel brothers and the Rothschild family.
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Figure 1.7 Marcus Samuel, founder of Shell (by kind permission of Shell).
In order to find new markets in the East the Rothschilds, seeking new transport possibil-ities, 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 toAsia (Singapore and Bangkok via the Suez Canal (Fig. 1.8)). Marcus Samuel gradually builtup his oil interests, and in 1897 he created the Shell Transport and Trading CompanyLimited to manage these activities. The company prospered, trading not only kerosene butalso, after 1885 when Karl Benz invented the internal combustion engine, gasoline.
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Figure 1.8 One of the first oil tankers, the Murex (by kind permission ofShell).
In order to diversify his sources of supply, Marcus Samuel acquired concessions in theDutch East Indies (East of Borneo), where he produced crude which was refined in a factoryin the Balikpapan region. He also acquired interests in oil produced in Texas from theSpindletop oilfield, discovered in 1901. Shell therefore became the first company with oilsources 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 byAeilko Gans Zijlker, a former head of the East Sumatra Tobacco Company who, on discov-ering traces of a paraffin-rich petroleum on the island, decided to throw himself into oilexploration.
After first drilling a dry well (without oil), he was successful on his second drillingattempt. In June 1885 there was a gusher from the Telaga Tunggal 1 well in Sumatra, whichhad been drilled to a depth of 121 metres; the oilwell continued to produce oil for another50 years. Supported by powerful allies (including the Dutch King Willem III, who grantedhim a royal seal), Zijlker founded the Royal Dutch Company. When he died, several yearslater, his mantle was taken on by Jean-Baptiste Auguste Kessler. A refinery with a capacityof 8000 bbl/d (400 000 t/y), about 50% of the production of which was kerosene, wascommissioned 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
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 alsointense with Marcus Samuel who owned a refinery virtually next door to that of the RoyalDutch in Balikpapan.
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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 rela-tionship was established whereby. Marcus Samuel became the Chairman and HenryDeterding, who had taken over from Kessler on the latter’s death in 1899, became ManagingDirector. Deterding also took on the day-to-day management, which was his wish. TheRothschilds became associated with this new organisation when the Asiatic PetroleumCompany was created also in 1902, bringing together these three interests who neverthelessretained their autonomy. It was not until 1907 that a more comprehensive agreement wassigned between Royal Dutch and Shell. In fact this made Royal Dutch, based in the Nether-lands, the senior partner, with 60% of the shares in the new company, Shell Transport andTrading, based in the UK owning 40%. The formation of this new Anglo-Dutch groupushered in a new chapter in the competition with Standard Oil. In order to avoid fallingvictim to the power of the American company, Henry Deterding decided to gain a footholdin the American market by buying the American Gasoline Company and the RoxanePetroleum Company.
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 ofthem played a particularly important role: Gulf (which disappeared in 1984 when it wasbought out by Chevron) and Texaco.
Gulf was created by the Mellon family around 1890. From 1889 they began to buy upoilwells 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 showedevery sign of wishing to achieve an unchallenged position in the American oil industry. TheMellon family resumed its interest in oil when the first explorations were being conductedin Texas, financing a drilling operation. This was at Spindletop in 1900, and on 10 January1901, when a depth of 300 metres had been reached, an oil gusher destroyed all the drillingequipment, hurling rocks, sand and earth into the air! The well produced several tens of thou-sands 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 toa fall in prices. The large oil companies, including Standard Oil and Shell, bought oil fromTexas in order to take advantage of the low prices. But after 18 months the flow fromSpindletop collapsed. In 1902 the Mellons raised further capital and founded another inte-grated company, also called the Gulf Oil Corporation. Their efforts were rewarded, becauseGulf 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 aproduction 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. Thelone red star logo (the symbol of Texas) was increasingly seen throughout the U.S. beforeembarking 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., Russiaand the Dutch East Indies. But there were many indications that the Middle East was poten-tially 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 thebeginning of the century, William d’Arcy negotiated the rights of exploration in Persia. Theproject got off to a bad start. The first four exploration wells all proved dry, also drying upthe funds which had been made available by the promoters of the operation. A new capitalinjection 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 fromthe exploration well (see Figs. 1.10 and 1.11). But in order to turn a discovery of oil into acommercial venture, major investments are needed for the production, transport and refiningfacilities. More capital was needed. In 1909 the Anglo-Persian Company was established torealise this objective. Burmah Oil remained a partner. The new company went on to becomethe Anglo-Iranian Company, and later, in 1951, the British Petroleum Company.
The new company required considerable capital to finance its development in consumermarkets. Ultimately the British government, finally responding to the campaign of the firstSea Lord, Admiral Sir John Fisher, (1904 – 1910) and subsequently, Churchill, to use fueloil 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 theboard of directors.
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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, theDutch East Indies and Persia. Oil was first discovered in Mexico in 1901, and in 1908 therewas a spectacular gusher in the Dos Bocas oilfield. Royal Dutch Shell, Standard Oil of NewJersey and Gulf successively developed oilfields in Mexico, leading to a production whichexceeded 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 oilcompanies set back production. In 1938 the oil industry was nationalised. Pemex (PetroleosMexicanos) was created and took control of all oil-related activities in Mexico. However
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Figure 1.10 First oil discovery in Persia (Iran) at Masjid-I-Suleiman (bykind permission of BP).
Figure 1.11 Steam production at Masjid-I-Suleiman (by kind permissionof BP).
production fell to a very low level (6 Mt/y) and never really recovered until the 1970s. Itwas at that time that large new discoveries allowed Mexico to become one of the world’sleading exporters.
Venezuela followed close behind Mexico, and in the 1920s became the second oilproducer 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 smallcompany, Pan American, were the main producers. After various incidents, Pan Americanwas 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 safe-guard the regular supply of heavy fuel oil to the British fleet. It also served as a clearreminder of the strategic importance of oil (another example is the support given to RoyalDutch by the Netherlands government when it was created). For consumer countries theproblem is to secure reliable supplies of a vital product. France is another good illustrationof the concern and the energy which a major industrial country largely devoid of hydro-carbons will mobilise in developing and protecting an industry capable of ensuring itsnational independence.
During the first world war there was a rapid motorisation of the troops, mainly unmo-torised 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 battleof the Marne was a decisive episode which revealed how important motorised vehiclescould be (Fig. 1.12). It was only by mobilising the famous Marne taxis that the troops couldbe conducted to the front, thereby avoiding a German breakthrough which could have endan-gered Paris. The importance which oil assumed in the first world war is encapsulated in twoquotations. Lord Curzon, President of the Inter-Allied Petroleum Conference, declared: “Theallied cause floated to victory on a sea of oil”. Senator Henry Béranger, who controlled theimport and distribution of oil in France during the war, concluded a speech with a phrasewhich continues to resonate: “The blood of the earth was the blood of victory”.
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Figure 1.12 The taxis of the Marne (Photo Monde et Caméra).
Until the Great War, French oil supplies depended on private, independent companieslinked 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 thegovernment by surprise. On the one hand the oil companies sought to maintain the regimeof competition characteristic of the sector. On the other hand, the international situationmeant that French supplies of Russian and Romanian oil were interrupted. The only sourcewas therefore American. Furthermore the attacks by the German navy on oil tankers in theAtlantic were interfering with fuel supplies, to the point that in 1917 the private companieswere not able to meet French needs. Clemenceau had to make an appeal directly to Wilsonfor the necessary shipments to be increased.
The war therefore demonstrated to France that the outcome of the war depended on thelarge oil companies, mainly American and British: Standard Oil, Anglo-Persian, RoyalDutch Shell. The French government realised that it was crucial to increase French inde-pendence in relation to energy supplies, in particular by ensuring that it participated in inter-national oil concessions such as those in Mesopotamia, where the British were very activeand 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 inthe Turkish Petroleum Company – TPC (see Section 1.2.3.1).
The British were fairly favourably disposed to France participating in the TPC, as thiswould act as a counterbalance to the influence of the American companies. This agreementproved particularly useful to Paris since the American companies decided after the war tostop supplying France, based on the decision of the authorities to maintain control over oilactivities after the end of hostilities. During the war the efforts of these same companies, asmembers 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 thisdependence. Apart from its efforts to gain direct access to crude oil, the French governmenttook other measures relating to the transport, refining and sale of products. Important deci-sions were also taken with regard to scientific research and training.
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 PetroleumCompany (see Section 1.2.3).
In 1923, at the request of the French government, Ernest Mercier set up a private, inde-pendent company, funded mainly by French capital. This company, with a capital of25 million francs, was founded on 28 March 1924, the main shareholders being a numberof large banks and the main French petroleum distributors, of which Desmarais was the mostimportant. 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 enter-prises of this kind, the direct involvement of the government considerably modified the natureof the market. The French state became a participant in a market expanding rapidly inresponse to the rise of the automobile, but which was largely being driven by developmentsbeyond France’s national frontiers. After the Second World War there was a tendency forthe state to continue its support, direct or indirect, for the national oil industry in importingcountries, both in Europe (with the creation of ENI in Italy (1953) and Elf Aquitaine inFrance (1976)) and in the U.S.
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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 helpof various laws designed to foster petroleum refining and distribution. The National Officefor Liquid Fuels, set up by an Act of Parliament of 10 January 1925, sought to regulate theindustry without actually nationalising it. Its aim was not only to promote oil exploration inother countries by French companies, but also to encourage exploration in France. At thesame time the Act encouraged the development of the French refining industry and allowedthe expansion of a fleet of tankers which would guarantee national supplies in the event ofwar.
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Figure 1.13 The Compagnie Française des Pétroles was created in 1924(by kind permission of Total).
Figure 1.14 The Gonfreville (Normandy) refinery around 1930.
Laws enacted in 1928 provided for monopolies on refining and distribution to be grantedby the state. The state authorised companies, either private or public, French or foreign, toimport and refine crude for a term of ten years, and to import and distribute oil products fora 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 capacityof 2 Mt/y, represented one-quarter of the total refining capacity in France at that time. Otherrefineries were also built, in Port-Jérôme by Esso, in Petit-Couronne by Shell, in Lavéra byBP 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 share-holders: a subsidiary of the Anglo-Persian Company, a subsidiary of Royal Dutch Shell andDeutsche Bank. Amongst its concessions, those for the regions of Mosul and Baghdad werethe most promising.
During the 1914 – 1918 war the Deutsche Bank shares were frozen by the Britishgovernment and at the same time discussions started between the British and French govern-ments. 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 ownterritory acquired, by invoking the “open doors” policy (oil concessions throughout theworld must be open to all the allies), shares for Standard Oil of New Jersey and StandardOil 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%;
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Figure 1.15 The same refinery today (by kind permission of Total).
– 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 October1927, of the very large Kirkuk oilfield (Fig. 1.16). In 1928 the Turkish Petroleum Companybecame the Iraq Petroleum Company (IPC), underlining its association with the newlycreated independent kingdom of Iraq, which included the former Mesopotamia.
The Company ran rapidly into serious difficulties. There proved to be a divergence ofinterests between the CFP (for which the IPC was the only source of crude) and its Americanpartners in particular. The so-called “Red Line” agreement, which stipulated that the partnersin the IPC should act in concert in all the former Ottoman Empire territories, resolved thesedifficulties 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 interestswould be harmed, and established a form of cooperation between them. We will considerthis agreement in greater detail in Section 1.3.
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2. The agreement is so named because, after long discussions, C.S. Gulbenkian grabbed a map and drew ared line around the territories within which the partners in the TPC (later the IPC) would be obliged to actin concert.
Figure 1.16 The discovery of oil at Kirkuk (Iraq) in 1927 (by kindpermission of Total).
1.2.3.3 Oil in the Arabian peninsula (Fig. 1.17)
Around 1920 the geologist Frank Holmes published evidence pointing to the presence of oilin the Bahrain region, and obtained concessions in that Emirate, as well as in Kuwait andSaudi Arabia. However, short of money, he sold all these concessions to Gulf in 1927. InBahrain, Gulf sold these interests on to Standard Oil of California (Socal). The first discoverywas made in 1932. This was fairly modest in size, and the production of the Emirate did notexceed 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. Itsinitial reserves were estimated at 10 billion tonnes, making it at the time by far the largestoilfield yet discovered.
In Saudi Arabia IPC was competing with Socal. The new king, Sultan Ibn Saud preferredto negotiate with the Americans and granted Socal a 60-year concession in 1933. In 1948the Ghawar oilfield was discovered, still the largest ever discovered.
At an early stage Socal formed a joint venture with Texaco in order to develop itsresources in Bahrain. The latter controlled major outlets in Europe and Asia, whereas Socal
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Black Sea
USSR Caspian Sea
MediterraneanSea
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Iraq Iran
KuwaitTransjordan
Egypt
SuezCanal
Neutral Zone
TrucialStates
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Bahrain
Oman
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Figure 1.17 The Middle East in the 1930s. This region accounts for two-thirds of the world’s oil reserves.
had an excess of crude. Socal and Texaco established two new companies: Casoc (CaliforniaArabian Standard Oil Company), which looked after Socal’s production interests in Bahrainand Saudi Arabia, and Caltex (California Texas Oil Company), which looked after theTexaco distribution networks in Europe and the East.
The 1939-1945 war interrupted oil extraction activities in Saudi Arabia. The full potentialof the Arabian peninsula only became fully apparent after the war. But the investmentsneeded to develop the resources of the Wahhabite kingdom were considerable. Socal andTexaco sought partners. After lengthy discussions, Esso and Mobil joined Socal and Texacoto form Aramco (Arabian American Oil Company). The other IPC partners, who could havedemanded 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 rateof about 7% per year. Automobile transport was developing rapidly, and demand fordomestic and heavy fuel oil was increasing steeply. These two fuels were making majorinroads into the traditional markets of coal.
Supply remained abundant, however, thanks to large discoveries not only in the MiddleEast (Fig. 1.18) but also in Africa (Algeria, Libya and Nigeria) and in Venezuela. Russianexports were also increasing. However the entry of new producers—the American inde-pendents—onto a market hitherto controlled by the “majors” (current term used to designatethe large oil companies) increased and modified the nature of the competition. These newcompanies sought to counter the declining profitability of American operations by interna-tionalising their operations and gaining a foothold in Libya, in particular.
European governments were also taking an increasing stake in oil and creating nationalcompanies such as ENI (Ente Nazionale Idrocarburi), Elf and Fina, intended to increasenational energy-independence. These companies grew rapidly.
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Figure 1.18 Another major Middle East producer: Abu Dhabi.
1.2.4.1 After 1945: a new relationship
The Second World War changed the nature of the relationship between the producers andthe international oil companies: the producing countries were no longer content to grantconcessions in the traditional way. They wanted a greater share of the rewards arising fromthe extraction of their oil wealth.
Negotiations in Iran in 1949 to revise the terms of the Anglo-Iranian concession got offto a difficult start. The young Shah had to contend simultaneously with the very influentialreligious community and a powerful communist party. The first proposals for modifying theconcession were rejected by the Iranian parliament, which demanded nationalisation. Thethen Prime Minister announced to parliament that he rejected nationalisation, and urgedinstead modification of the concession. He was assassinated several days later. The newPrime Minister, Muhammad Mossadegh, had Parliament confirm nationalisation. After manytroubled months the Iranian authorities negotiated an agreement with the oil companies (ledby the American companies): the oil companies recognised the ownership by the Iranian stateof the Iranian land and mineral resources. The National Iranian Oil Company (NIOC) wasformed. It became the owner of the resources, with production being entrusted to aconsortium 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 toachieve 300 Mt in 1973.
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Figure 1.19 Lacq: the major French gasfield (by kind permission of Total).
In the 1920s, Italy formed a national refining company, the AGIP (Azienda Generali ItalianaPetroli) based on the model adopted in other countries. By the outbreak of war, this companywas of comparable size to the local subsidiaries of foreign companies operating in Italy. Atthe end of the war Enrico Mattei, an industrialist who had fought with the Resistance, wasappointed to head up AGIP, whose installations had suffered severe war damage. Dynamicand ambitious, Mattei sought to develop AGIP and allow it to play a major role in guaran-teeing Italy’s oil supply. However capital was needed. The discovery of major reserves ofnatural gas in the Po valley met this need. SNAM (Societa Nazionale Metanodotti), thecompany formed to produce this gas, would generate the necessary capital. The ENI wasformed in 1953, bringing together various companies in the hydrocarbons sector, most ofwhich were run by Mattei.
In order to guarantee access to petroleum resources, Mattei pursued a policy of main-taining active contacts with producing countries. Failing to secure an interest in the majoroilfields of the Middle East from the “seven sisters” (Mattei is reputed to have coined thissobriquet himself) he negotiated an agreement with Iran. Although Mossadegh had partiallyfailed, several years earlier, in his assault against the oil companies, the oilfields had stillbeen nationalised, and the state had more flexibility in its negotiations with foreigncompanies. Mattei signed an agreement with the Shah which envisaged a 75% share of theprofits for the state and 25% for ENI. This was a first in the oil sector. Until his death in1962 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 after1945, to promote exploration and production in France and other territories under its sover-eignty. Several companies were created and oil and gas discoveries were made in the southof 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 1944should be mentioned here (Fig. 1.22). The IFP arose out of the desire of the Frenchgovernment to support its national petroleum industry and to limit its dependence onimported processes, equipment and technology, particularly from the U.S. The brief of theIFP is to foster scientific and technical research into all aspects of exploration, production,transformation (refining and petrochemicals), applications (e.g. engines), including trainingand 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 propri-etary refining and petrochemical processes it has sold. In 2003 more than 1500 process unitsin many countries including Japan and the U.S. were using IFP processes, making it thesecond 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 IFPhas also played a major part in the creation of a world-class petroleum services industry inFrance. Technip and Coflexip, for example, originally set up by the IFP, and which recentlymerged, are amongst the world’s leaders in their respective fields.
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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 halfthe 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 thisfigure had doubled. These imports were attractive because the price of Middle Eastern oilin New York was lower than that of American oil. The American authorities, worried aboutthis competition, started by calling for voluntary restrictions, and in 1959 imposedcompulsory restrictions: import quotas. The American market was therefore partiallyprotected from the world market, leading to price rises. Prices outside the U.S., on the otherhand, 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, notablythe European and Japanese markets. In order to increase their crude sales, oil companieswidely adopted the practice of discounting the posted prices, which continued to be thereference price for the calculation of royalties and taxes. But competition also led tocompanies seeking to reduce the posted prices. Two reductions were made, by 18 ct/bbl inFebruary 1959 and 10 ct/bbl in August 1960. These reductions produced an automaticreduction in the incomes of producing countries per barrel sold. Unhappy with this devel-opment, the main producing countries (Venezuela, Saudi Arabia, Iran, Iraq, Kuwait) met inBaghdad in September 1960 and agreed to form the Organisation of Petroleum ExportingCountries (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 totransform the oil industry hitherto dominated by the international oil companies and, morediscretely, a certain number of consuming countries, above all the U.S.
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Figure 1.22 The first offices of the IFP (now IFP Energies nouvelles).
A. Political events
In 1956 the nationalisation of the Suez Canal resulted in its closure. As a gesture of supportfor Egypt, Syria interrupted the shipment of IPC oil. While everything was restored tonormal within several months, and good cooperation between the consuming countrieslimited the effects of the crisis, these events marked the emergence of third world countriesas 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 werealready productive wells. The following year the Iraqi government created the INOC (IraqNational Oil Company) which replaced the IPC.
In 1967, during the Six Day War, the Arab countries imposed an embargo on oil deliv-eries 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 thereclosure of the Suez Canal (see Fig. 1.27 and Section 1.2.4.10) led to an explosive growthin the demand for transport, i.e. tankers, because Middle Eastern oil destined for Europe andthe U.S. henceforth had to be routed via the Cape of Good Hope. North African oil wastherefore at a premium because of its transport advantage, a factor which would becomesignificant in the following years.
During the 1960s Algeria and Libya became important oil producers. In Libya, where notonly 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 in1970. But in 1969 King Idris of Libya was replaced by Colonel Gaddafi, who became thefirst 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 hydrocarbonsaccounted for half the energy needs of Europe and three-quarters of those of Japan, tworegions virtually devoid of their own oil. There was another cause for disquiet: the world’soil reserves were equivalent to only 30 years production at current levels in 1970, comparedwith 140 years production 20 years earlier (Fig. 1.25) 3. It was feared that oil resources mightbe largely exhausted by 2000. This was the backdrop against which the famous report of theClub of Rome entitled “Limits to Growth” was published in 1972. This report warned of thedangers of the depletion of natural, non-renewable resources, as a result of economic devel-opment. The report called for economic growth to be slowed so as to save raw materials andprotect the environment. Of course there was no simpler way to limit consumption than toincrease prices.
At the same time, new air quality legislation in the U.S. made it more difficult to burncoal, and encouraged the use of oil. But initiatives to open up new resources situated inecologically fragile areas (Alaska, California coast, Gulf of Mexico) were delayed followingactions taken by environmental protection groups. This led to a somewhat paradoxical situ-ation, since it made the U.S. dependent on foreign oil. In order to protect the interests ofdomestic producers, who were at a cost disadvantage compared with their foreigncompetitors, quotas were introduced. But these proved difficult to administer. In 1969 Pres-ident Johnson, who had been very close to Texan oil interests, was replaced by the Nixon
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3. By 2000 the R/P ratio (reserves to annual production) was back to over 40, for “conventional” oil alone.
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Figure 1.23 Service station in Senegal in the 1950s. Sales were increasingand equipment was being modernised all over the world (by kindpermission of BP).
Figure 1.24 Production and consumption of oil, showing the steep increasein the 1960’s.
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Administration, which decided to change course. American producers would be protectedby raising prices; this would not only allow quotas to be abolished because it would makeAmerican producers profitable, but it would also guarantee adequate revenues to theproducing countries (Venezuela, Gulf states), thereby stabilising the existing regimes, whichwere necessary partners of the U.S.
By 1970, the politico-economic climate was at last turning favourable to an increase inoil prices. The main actors (with the important exception of the major consuming countrieswithout oil resources) saw nothing but benefit from such a development. The event whichactually triggered the price rise was the decision by Libya, which demanded that the oilcompanies 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. Libyaobtained higher tax rates and an increase in the posted prices from the oil companies. AndVenezuela decided to increase its tax rate to 60% and enacted a law allowing the posted priceof 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 negotia-tions. In practice, two separate negotiations led to significant price increases, which in turnproduced an increase in the income—per barrel—for producing countries. The TeheranAgreement (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 SaudiArabia and Iraq output into the Mediterranean. Finally, following the devaluation of thedollar in August 1971, two successive conferences in Geneva in 1972 and 1973, led toincreases 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 ofYom Kippur, on 6 October. Initially events moved against Israel before reaching a balanceof force. The war ended on 25 October 1973 without a victor.
Figure 1.25 Ratio of reserves to production, illustrating the sharp dropfrom 1950 to 1980 and then the stabilization.
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 PetroleumExporting Countries: Abu Dhabi, Algeria, Saudi Arabia, Bahrain, Dubai, Egypt, Iraq,Libya, Kuwait, Qatar) except Iraq decided to reduce their exports by 5% per month untilIsrael withdrew completely from occupied territories and the rights of the Palestinianpeople 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 oilto the U.S., Portugal, the Netherlands, South Africa and Rhodesia, which were accusedof favouring Israel. The spectacle of Dutch motorways closed to traffic at weekends tosave fuel was a powerful image which remained engraved on European imaginations forlong thereafter.
Finally at a meeting in Teheran in December, OPEC took advantage of the turbulence toagain raise posted prices. The posted price of Arab Light rose to $11.651/bbl, the real pricewas of the order of $7.
1.2.4.7 Nationalisations
Another consequence of the increasing power of OPEC, perhaps even more important thanthe price rises, rock the oil world to its core: the main producing countries decided, one afterthe other, to nationalise their oilfields (see Box 1.3).
During the 1970s a wave of nationalisations by OPEC member countries gatheredmomentum. Over a few years most of these countries nationalised the assets of foreigncompanies, 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 strengthentheir negotiating position, acted as a catalyst to a movement which arose from age-old demands.
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Iranianrevolution
Secondoil shock
Iran/Iraqwar
OPECquota policy
Netbackcontracts
Iraq/Kuwaitwar
OPEC quotasAsian crisis
Cold winter
Agreement betweenMexico, Venezuelaand Saudi Arabia
11th September
Iraqwar
Oilcounter-shock
Attack on personnelin Saudi Arabia,trouble in Iraqand Nigeria
Economiccrisis
NewOPECquotas
HurricanesKatrina and
Rita
1970 1980 1990 2000 2010
Yom Kippur warFirst oil shock
Figure 1.26 The oil shocks.
The oil shock of 1973 marked the start of an economic crisis in Western countries as wellas a major turning-point in the development of the petroleum market. Firstly, a new type ofactor in the oil market began to emerge beside the Western oil companies and the majorimporting countries: the producing, exporting countries themselves. These countries actedeither individually or in some cases through OPEC. In 1973 these countries controlled over50% of the world’s production of crude and more than 80% of its reserves. Secondly, a splitdeveloped in the oil industry at the global level, with oil production, now under the controlof state companies, remaining separate from refining and distribution, most of which wasstill 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. ThisAgency was set up within the OECD (Organisation for Economic Cooperation and Devel-opment), with just over 20 members, including the U.S. and Canada, Western Europe (withthe exception of France, which did not join until 1992) and Japan, to mention the largest oil-consuming 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 energysources and relevant R&D.
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In producing countries petroleum has often been considered a natural resource whichbelongs to the people, and must be used in their interests. This is sometimes actually writteninto the national constitution. During the period between the Second World War and 1970this concept reached its climax. Many countries became independent either after the war orduring 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 1970and 1980. In the Mediterranean countries nationalisations often occurred on a company-by-company basis: in 1971 Algeria took control of 51% of the concessions of the Frenchcompanies. Starting in 1971 Libya successively nationalised BP and then ENI (50%) and theother companies (51%), and Iraq nationalised the last IPC concessions. In 1972 negotiationsbetween the oil companies and OPEC led to the “participation” agreements (New YorkAgreements), which envisaged the progressive acquisition of concessions by producing coun-tries. 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 factoccurred much faster than envisaged in the agreement: Kuwait and Qatar in 1975, Venezuelain 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 thatthe national public should have access to oil products at as low a price as possible. InVenezuela, Nigeria and Saudi Arabia petrol prices are very low, often below the internationalprice excluding taxes and distribution costs. This encourages very high consumption, to thedetriment of exports, and therefore of vital foreign currency earnings. These concepts onlychanged at the end of the 1980s, with the fall of the Berlin Wall and the collapse ofcommunism.
Box 1.3 Nationalisations.
• To set up an information system on the international oil market, as well as consultationswith the oil companies.
• To cooperate with producing countries and other oil-consuming countries in stabilisinginternational energy markets to ensure that the world’s energy resources are managedand used rationally, in the interests of all countries.
• To create a plan which would prepare countries for a possible major disruption ofsupplies 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 inDecember 1973 to $12.70 in December 1978 for Arab Light, then the reference for pricingall crudes). Prices were fixed by OPEC at periodical meetings. The prices of other crudeswere derived from that for Arab light as a function of their quality (°API, sulphur content)and location.
The second large price rise, or second oil shock, was associated with the Iranian crisis. Atthe end of 1978 political and social discontent in Iran (Fig. 1.28) led to strikes in most sectorsof the economy and particularly in the oil sector. Iranian production fell from 6 Mbbl/d inSeptember 1978 to 2.4 Mbbl/d in December and to 0.4 Mbbl/d in January 1979 when theShah departed, to be replaced by the Ayatollah Khomeini.
At first other counties increased their production to make good the Iranian shortfall. ButSaudi Arabia subsequently decided to place a ceiling on its production significantly lowerthan its level of December 1978. The free market, still relatively undeveloped, spiralled outof control. Demand far exceeded supply, exacerbated by the scramble by operators to
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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 theofficial price close to the spot price.
In October 1980 the commencement of hostilities between Iraq and Iran led to a largereduction in the output of these two countries, provoking a new, although brief, upsurge inprices. In fact energy conservation measures taken by consumer countries were beginningto show their effectiveness: world consumption fell from 3.1 Gt in 1979 to about 2.8 Gt afew 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 and1.30) in the region of the Gulf of Guinea. Other zones were also the object of extensivedevelopment, 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 oilcompanies had chosen their supply sources essentially on commercial considerations. Theexpectations of governments played little part. The world was one in which crude oil wascheap and abundant, rarely costing more than $1.50/bbl to produce. Outside of the communistblock the growth in production, which extended from 1950 to 1970, therefore took place inzones with low production costs, that is basically the countries which founded OPEC in 1960or which joined subsequently. Even countries such as India and Brazil, which were activelycommitted to an independent, state-controlled approach to development, preferred to importgrowing quantities of petroleum products produced cheaply by the multinationals rather thandevelop their own production. It was regarded there as elsewhere as the antithesis of soundeconomics to use scarce financial resources to encourage an uncompetitive nationalproduction.
The attractiveness of OPEC oil (and particularly that from the Gulf states) was consid-erably reduced as a result of its policy of high prices. There were also doubts as to the reli-ability of OPEC supplies. Political instability in the region made Western countriesincreasingly wary of Middle Eastern oil. Most oil-importing countries were pursuing apolicy of diversifying supplies. The sharp oil price rises greatly facilitated the emergence ofnew producing regions. An oil price of $30/bbl enhanced petroleum-producing potentialthroughout the world, benefiting new producing countries, Western oil companies andgovernments of importing countries. For new producers, any domestic production which
substituted (costly) foreign imports or could be exported (lucratively) handsomely justifiedthe attraction of foreign capital. Nationalisation’s in OPEC countries led to a split betweenthe upstream and downstream activities of the international oil companies, which had lostmost of the reserves which they managed. Their primary commercial motive was thereforeto replace these reserves elsewhere so as not to be unduly dependent for the crude purchases
so vital to their refining activities on any single producer. They also sought to avoid losingthe benefit of their production know-how, even though this meant redirecting investmenttowards regions where production costs were higher than in the Arabian-Persian gulf.
Western states found in these developments a very effective means of revitalising compe-tition between producers, thus exercising a downward pressure on prices and restoring abalance of advantage in their dealings with exporting countries.
High prices and the fear of scarcity led to increased R&D efforts which allowedproduction from fields with high exploitation costs, especially offshore. New productionfacilities were established not only in Europe (the North Sea, see Fig. 1.31) but also in NorthAmerica (Fig. 1.32) and developing countries: Argentina, Brazil, Colombia, Ecuador,Angola, Egypt, Gabon, Syria, India, Malaysia. All of these countries became middle-rankingproducers, between 20th and 30th in the world rankings. Only Mexico, Norway and theUnited Kingdom joined the ranks of the major producers. During this time there was a signif-icant 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 alreadymentioned, between 1979 and 1985 total world demand for oil fell by about 300 Mt eachyear. The price increases led to fuel substitution (a return to coal in some industries, the useof nuclear energy for power generation, etc.) and energy conservation measures (insulationof buildings, more efficient engines, etc.). Since there was also a rapid increase in non-OPECproduction, that part of total demand met by OPEC (Fig. 1.33) fell by almost 50%, from1500 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 SaudiArabia 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.
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20%
30%
40%
50%
60%
20052000199519901980 19851960 1965 1970 1975
First oil shock 1973
Second oil shock1979
Oil counter-shock1986
Figure 1.33 Reduction and recovery in OPEC shareof world production.
To cope with this weakness in demand, the OPEC countries decided to place limits, orquotas, on their production. These quotas totalled 17.5 Mbbl/d (compared with a productionof 30 Mbbl/d two years earlier). They were only able to retard the fall in oil prices, whichfell from $34/bbl in 1981 to $29 in 1983 and $28 in 1985.
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 adesperate plight. The revenues of the latter had fallen by 75% in five years. For the first timein history Saudi Arabia abandoned its defence of oil prices and sought to recapture “its fairmarket 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 verylow. Riyadh therefore made the following proposal to the purchasers of crude: the refinerwould take delivery of the crude, would transport it and transform it into finished productswhich he would sell at the current price on the international market. The proceeds wouldthen 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 fromits processing after deduction of the costs of processing and transport. This was referred toas the netback contract.
This arrangement certainly allowed Saudi Arabia to regain market share, but it led to acollapse in the oil price. Refiners were encouraged to maximise their throughput, since theirmargin per barrel was guaranteed. This resulted in a glut of products on the market, andprices fell. In consequence the price of crude fell also. In January 1986 the price of ArabLight 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 returnto a system of official prices. They set a target (desired) price for Arab Light of $18/bbl. Butin practice the price of crude fluctuated widely, depending on variations in supply anddemand. Producing countries paid a heavy price in terms of their oil revenues. These fellfrom their 1981 peak of $261 billion to $77 billion in 1986, recovering to $180 billion in2002.
1.2.5.4 The situation in the late 1980s
The reason behind the desire of importing countries to increase the production of non-OPEC oil was less the supposed instability of the OPEC members than the political weightwhich this cartel was able to wield. Experience in countries such as Angola, Algeria andNigeria shows that internal political instability and even civil war rarely interferes with oilproduction. Both sides are usually careful to ensure that the petroleum infrastructure, thesource of great wealth and sometimes even the object of the conflict, is not damaged. Thesame does not apply to confrontations between different states, when the oil infrastructurebecomes a military target and may suffer, as was the case in the Iran-Iraq war and the Gulfwar.
The diversification of supply was achieved not only because of the voluntary policy putin place but also because, as we saw, higher prices drove the international companies todevelop their activities in non-OPEC countries.
By the end of the 1980s, the industrialised countries were less dependent on oil than theyhad been at the time of the first oil shock in 1973. Only the transport sector remained acaptive market for oil products.
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1.2.6 The 1990s: market forces
Since 1986 oil prices have been subject to rapid and large fluctuations. Over the next15 years it fell on several occasions to around $10/bbl, and rallied at other times to amaximum of about $40. Remarkably small variations in the supply/demand balance canproduce very large price swings.
Between mid-1986 and mid-1991 prices remained within the range $10-20/bbl, dependingon the production quotas agreed by OPEC. The Iraqi invasion of Kuwait in 1990 resultedin 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 ArabEmirates were rapidly able to increase production to make good the shortfall in productionby Iraq and Kuwait.
Even more interesting is that throughout the occupation of Kuwait by the Iraqi forces, thefutures markets indicated a return to normal prices (i.e. around $20/bbl) within severalmonths. In fact, most observers were betting on the rapid intervention of the U.S. and herallies and a normalisation of the situation within a reasonable period. Another lesson learnedin the Gulf was that when hostilities commenced on 17 January 1991 (Fig. 1.34), althoughthe experts expected a brief upsurge in the price of crude, it actually fell: the markets werediscounting a short, sharp military action, and the actual price aligned itself with price onthe futures market.
The oil price subsequently stabilised within the range $15 – 20/bbl. This was the resulteither of modifications in OPEC production levels or by actions such as that of Americanpension funds in the spring of 1994: taking the view that the oil price was abnormally lowthey purchased oil on the forward market.
The end of the century was marked by a further demonstration of the sensitivity of pricesto fluctuations in the equilibrium between supply and demand and the importance of the roleof 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. Itbecame increasingly clear that the volumes of stocks of crude and of oil products were key
parameters determining short-term price movements. Most observers therefore attachedconsiderable importance to the regular publication of data on stocks.
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 productionquotas (from 25 to 27.5 million barrels per day). This was equivalent to less than 4% of totalworld production. Yet the Asian crisis of 1997, followed by a Russian crisis in 1998 andsubsequent problems in Latin America, dampened the increase in demand, so that the priceof crude fell to about $10/bbl, notwithstanding a progressive reduction in the OPEC quotaswhich 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 theycould no longer meet their financial needs. OPEC countries’ debt was growing. A return todiscipline among the OPEC countries was needed to increase prices. How could it beachieved?
The election of Hugo Chavez as President of Venezuela at the end of 1998 was the firstsign of change. While the previous governmental had favored maximizing production, thenew President favored a policy of solidarity with third-world countries in general and withother 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-OPECcountry) to limit production. This agreement would be strengthened by an improvement inrelations between Saudi Arabia and Iran, the main Arabian Gulf producing-countries. Thecommitments to reduce OPEC production, supported by clear signs of solidarity from themain non-OPEC producers, finally appeared credible to operators. In March 1999, the priceof oil started an upward trend that would lead it to a peak level in 2000. The OPEC coun-tries then decided to set an objective for the average price of a basket of crude oil of $25per barrel, and a range of $22 – $28 within which the price should remain: if the price wentabove $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 thefirst 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 Americansgreatly reducing their personal travel. But prices gradually recovered. Until 2003, $25/bblwas 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 theaddition of a “risk premium”, which different experts estimated at $5, $10 or $15/bbl. Thistheory was confirmed by the fall in the price of oil on March 20, 2003, the day on whichPresident George W. Bush announced that the US rejected Saddam Hussein’s response tothe US ultimatum, and that the US-led coalition would attack Iraq. In London, the price ofBrent crude fell from $35 to $25. Operators were not worried about the immediate conse-quences 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 Iraqwould once again become possible (plans were made to raise production capacity from 3 to6 Mb/d), so a return to “normal” oil prices therefore seemed probable.
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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 $147per barrel (Brent price) on July 11, 2008. There were many reasons for this. The situationin Iraq – and the Middle East – was not as had been expected. Iraqi production remainedfar below its level under Saddam Hussein.
Attacks in Saudi Arabia were worrying. Some countries could not stop their productiondeclining. Oil consumption rose strongly while the surplus production capacity that hadresulted from the fall in demand and increased non-OPEC production after the second oilshock, had disappeared. There was no shortage of oil on the markets, but the balance ofsupply and demand was precarious. Costs – particularly capital costs – were rising steeply.Arguments regarding levels of oil reserves added to the concern. These arguments weremisdirected since the immediate problem was not the reserves underground, these were stillsufficient for several years. It was rather above the ground, particularly the lack of sufficientcapital investment for geopolitical reasons: producing-countries were reluctant to investmassively to produce more oil for a market that did not seem guaranteed. Why invest tosupply Western consuming countries who wanted to reduce their oil consumption becauseof their supply security concerns and to reduce greenhouse gas emissions? There was greatconcern about forecasts of an oil production ceiling of 95-100 Mb/d, while the needs of Chinaand other emerging countries seemed unlimited. The market was preoccupied by its desperateattempts to balance future supply and demand.
Many specialists did not understand why the price increases did not reduce the increasein demand. The explanation is simple. The income effect – when revenues double, gasolineconsumption increases by 70% – is more important than the price effect – when pricesincrease by 100%, gasoline consumption only decreases by 7%. Economic growth was
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Weekly averageAnnual average
65.1
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1996 1999 2002 2005 2008 2011
$/b
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12.7
17.7
28.4 24.5
24.5 28.8
72.5
54.5
38.1
97.6
61.1
79.6
Figure 1.35 Brent Oil Spot fob Price – January 1996 to July 2011(Source: US DOE, BP Statistical Review).
extremely strong (4% per year from 2003 to 2007), while the fuel price increases seen byconsumers were “tempered” by the significance of taxes in consuming countries and by pricecontrols in emerging countries.
A comment should be made on the impact of speculation. When it seems probable thateconomic 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 toincrease. They of course make the trend in price increases more pronounced, but they do notcreate the increase, they follow it.
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Although supply and demand has had a basic role in the oil price setting mechanism since1986, at least until 2003 it was OPEC’s position that was decisive. Without OPEC, oil priceswould have been much lower – probably of the order of $10 to $15 per barrel – over theperiod 1986-2003.
However, in periods of significant potential oversupply, OPEC cannot – and does not wishto – assume the sole responsibility for supporting prices. Thus in 2001, OPEC reduced itsproduction 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 itsproduction further and see its market share decline dramatically and non-OPEC producersprofit from higher prices without participating in the loss of production, or maintain its exportvolume and inevitably experience a fall in the crude oil price. In fact, at the start of 2002, themajor non-OPEC producers (Mexico, Norway, and most importantly Russia) joined OPECin their efforts to maintain prices.
Between 2003 to mid-2006, there was no longer any need for this debate. Globallyproduction 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 politicalsituation and mild weather, a tighter quota policy once again made sense. OPEC instigatedmassive production cuts in reaction to prices collapsing by a third, which stopped the decreasein prices and restored the organization’s credibility. Angola and Ecuador joined OPEC in 2007and, despite Indonesia leaving in 2008 (which was logical as Indonesia had become an oilimporter) 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 againmade the cartel’s pricing policy a central issue. OPEC decided to reduce its quotas by 4 Mb/dover 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 reductionsince, during winter, Russian exports are reduced anyway because weather conditions limittanker loading at the Novorossiysk and Primorsk terminals.
OPEC may decide to invite new members to join. Although countries like Brazil and Kaza-khstan have envisaged joining, there are no guarantees that a larger OPEC could maintain itsunity. Would Brazil with its bio-fuels really be welcomed within the cartel? Would thecomplexity of relationships between the states surrounding the Caspian Sea allow countriessuch as Kazakhstan or Azerbaijan to join the cartel, without adversely affecting OPEC’s rela-tionship with Russia? Would Russia be ready to compromise its foreign policy goals, partic-ularly with respect to Iran, by participating in OPEC? Given their relations with Europe andthe US, is it conceivable that Norway and Mexico could join OPEC? Wouldn’t the integrationof Sudan within OPEC carry the risk of dragging the organization into regional Africanconflicts? A more reasonable solution to a massive and continuing fall in demand seems tobe OPEC working with “associate” members.
Box 1.4 The Role of OPEC.
1.2.7.3 The fall in demand and collapse in prices, from $147/barrelon July 11, 2008 to $40 at the end of 2008
Economic growth tumbled while oil production remained strong. Even the conflict in Georgiain August 2008 failed to slow the fall (however, the Russians bombed both sides of the Baku-Tbilisi-Ceyhan pipeline, the only outlet route outside the control of Moscow, to show thatif they wished, they could stop exports from the Caspian).
The fact that oil was abundant and consumption was stagnant or even declining, wasfinally recognized. OPEC reduced its production quotas by 0.5 Mb/d in September, 1.5 inOctober, and 2 in December. This stabilized prices in the $40-$50 range. Investment fundswithdrew from the oil markets (and those for other raw materials) en masse. This seemedlogical 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 everyrespect similar to what occurred in 1986 at the time of the oil counter shock, when SaudiArabia launched a price war to recover market share and prices fell from $28 to $8 betweenJanuary and July. The reasons in both cases were the same: an oversupply of crude oil. Themarket forgets long-term considerations (anticipation of increasing and strong demandconfronting 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 OPECquotas, the price of oil started to increase again and rose to $70 per barrel in mid-2009. Thiswas close to $75 considered at this moment by King Abdullah of Saudi Arabia to be the rightprice for oil and the price needed to ensure the production of marginal supplies, i.e. syntheticoil from Canadian oil sands, the most costly liquid (obtained from non conventional oil) overthe next few years. Economists were satisfied: the price of oil was close to the “long termmarginal cost of production” or the cost of the most expensive barrel to produce in a fewyears to meet demand.
This situation did not last and quickly the price increased again, flirting with $100/b atthe 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 largeexcess capacities and could meet the lack of Libyan production, even if the quality ofthe crude was a problem (most of the excess capacity was for medium, sour crude, whilethe Libyan one is light, low sulfur).
By mid 2011 the oil price remains “high” and the short term direction is difficult topredict. A price close to $100/b is the most likely forecast even if geopolitical events canprovoke 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 increasein the price of a barrel from $10 to more than $100 between 1999 and 2008 had effects ondemand that were slower and more limited. Several explanations for this have been advanced:
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• The weight of oil in the economy is less than it was 20 years ago and so the importanceof the energy bill is also less. France spent nearly 6% of its GDP on its oil at the beginningof the 1980s but only slightly above 3% in 2007. More efficient use of oil, and anincrease 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 remainsvery significant for the poorest developing countries: in 2007 Senegal spent more than8% 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 crudeoil price variations in a number of countries. Generally in Europe, if the price of crudeoil quadruples from $25 to $100 per barrel, the price of fuel at a service station onlyincreases 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 minimumwage in 1981, but only less than 15 minutes in 2011 (when the price of oil is $100/b).
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 inparticular) and West Africa. Only OPEC countries - and in particular the countries of theMiddle East – seem to be able to increase their production significantly. Saudi Arabia hasan actual production capacity of more than 12 Mb/d.
Who will make the necessary investments in exploration and production? The five largestinternational oil companies (Exxon Mobil, Shell, BP, Chevron and Total) have jointly earned
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While it is difficult to answer this question, there are several possible benchmarks that canbe considered:
– Production costs (excluding costs of capital) are less than about $5/barrel in the MiddleEast, and $10 to $15 in other producing countries. However they are $60 or more for thehighest cost oil from difficult zones of the North Sea and synthetic oil obtained from the veryheavy 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 oilprice of $20-$25/bbl. For example Algeria used $19/bbl for many years. Any revenue fromhigher prices was then used for exceptional expenditure (debt repayment, new equipmentprojects, etc.). This situation has changed and many producing countries now “need” a muchhigher price to balance their budgets. The price “needed” varies considerably from oneproducing country to another, but often exceeds $50/bbl.
A new factor that must now be taken into account is the considerable increase that willapply to future total production costs arising from the substantial increase in capital costs. Inrecent years, these costs have increased by a factor of 2 or 3. Taking this increase intoaccount, experts agree on a total production cost (including capital costs) of $60 to $80 forthe 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 levelsof crude oil and products, geopolitical events can at some time play an important role.
Box 1.5 What is the “Right Price” for Oil?
more than $110 billion in profits every year from 2005 until 2008. In 2009 that total fell tounder $70 billion. Results in 2010 were distorted by BP taking a pre-tax charge of $32 billionin relation to their Deep Water Horizon disaster, had it not been for that the total profit wouldhave shown a substantial increase over 2009. Over the total period some of these profits wereused to reduce their debt, which is now very low, and to reward shareholders. These companieshave 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 reservesto exploit. However, since the nationalizations of the 1970s, and notwithstanding the fewexceptions which are discussed later, these countries overall remain reluctant to re-opentheir oil and gas industries to major international companies. Saudi Arabia and Kuwaitare completely closed. Iran has opened itself to only a limited extent. Outside the MiddleEast, Venezuela has only opened marginal fields and reserves of extra-heavy crude oil toforeign companies. Outside OPEC, Mexico remains totally closed to non-Mexicancompanies and Russia has shown that it wishes to keep tight control over its reserves. Thisleads 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 pricesincrease, leaving the foreign companies’ portion broadly constant (in dollars per barrel).This policy is consistent with a dominating political approach which sees mineral resourcesas an asset belonging to the nation and its people whose benefits (and sometimes theexploitation – 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 thefull benefit of the increase in crude oil prices. Their government only returns a portion ofthe oil revenues to them and retains the rest to finance their budgets. Of course, the highrevenues of recent years have allowed major producing states to balance their budgets - oreven achieve surpluses – in contrast to the difficult years of the 1990s. Nonetheless, in manycases the amounts left for the national oil companies have been insufficient for them tomaintain and develop their oil production capacities. Since mid-2008, this position has beeneven more pronounced.
1.2.7.7 New oil nationalism
The high oil prices of the period up to 2008 had important consequences for the principaloil producing countries’ policies. Their revenues have given them (temporarily?) far moreindependence from the major International Oil Companies (IOCs). Of course, for more than30 years now, some countries – Saudi Arabia, Kuwait and Mexico – have operated a systemin 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 thispresence even further through nationalization by legislation (Bolivia) or de facto national-ization (Venezuela decided to increase the national oil company PDVSA’s share in theproject for exploitation of the extra-heavy oils of Orinoco, to 60%, leading to the withdrawalof 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 consumingcountries will drastically decrease their oil consumption has made producing countries veryprudent when considering any increase in production. Producing countries have blamedspeculation for much of the increase in prices, have always insisted that the markets are well-supplied and that they need security of demand in response to the security of supply calledfor by consuming countries. Why should they invest tens of billions of dollars in new
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capacity, which will probably result in a decrease – or even collapse – in prices, if demandfalls 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. Theforecast in the early 1980s that the price would exceed $100/bbl before 2000, promoted afall in demand and an increase in supply. Similarly, the low prices of the 1990s discouragedinvestment 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 forincreased 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, Chinawill need the equivalent of the current worldwide consumption of oil, for “only” one-fifth
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A few figures will help put the significance of oil price movements into context. If the priceof oil were to remain at $75 for one year, the value of oil traded internationally would begreater than $2 trillion. This is approximately the value of French GDP. It is significant, butsmall when compared with 2007-2009 stock market “losses” amounting to $25 trillion, or theamounts available in investment funds (these funds include in particular the pension fundswhich receive contributions from American employees to fund their retirement), whichamount to tens of trillions of dollars.
Variations in the price of oil result in a significant shifts of resources from producing coun-tries to consuming countries.
Impact of prices for the major consuming-countries: the price of oil was only $61/bbl in2009 compared with an average of about $100 in 2008 ($97 to be precise). France’s oil billtherefore 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 concernto European authorities since it brought inflation to a level of nearly 4% While this was stillreasonable compared with the level of the 1980s (more than 10%), it was far above that ofmore recent years. The decrease in the price of oil – and of many raw materials at the end of2008 – decreased inflation to a level of nearly zero.
Impact of prices for poor countries: although emerging countries found it relatively easyto tolerate a significantly higher energy bill, the same was not true for less-advanced coun-tries for whom the increase in prices was stifling. Their oil bill, for example in West Africancountries, frequently exceeded 10% of GDP, a level far greater than the few percentagepoints of GDP covered by governmental and privately funded aid. The bill remains high withcurrent 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 toanother. It is the relatively low population Gulf countries that have accumulated significantfinancial reserves and whose sovereign funds have access to hundreds of billions of dollars: $40per barrel is sufficient for the UAE, Kuwait, etc. It is much higher in countries like Iran andVenezuela, which have difficulties when the price drops below $80. Russia also depends signif-icantly on its exports of oil and gas, since the price of gas is indexed to the price of oil. Thefall in the value of the ruble at the beginning of 2009 reflected the importance of oil for Russia.
Box 1.6 The Impact of Oil Prices on the World Economy
of the world’s population. In addition, reserves of oil – although very large– currently showconstraints that were not apparent in 1970 or 1980.
The oil market remains subject to basic economic laws: all periods of high prices carrythe potential for future prices to fall, since they tend to stimulate supply and moderatedemand. Nonetheless, it seems probable that future price movements will continue to be bothsignificant and unpredictable, while prices themselves will stay at a considerably higher levelthan 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 1973were followed by a worldwide economic recession. Seen from our perspective at thebeginning of the 21st century, movements in the oil price are likely to have less impact oneconomic growth. But the strategic nature of oil remains, even if less pronounced than inthe 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 relateto 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 byblending the outputs of numerous small deposits (sand lenses). In the latter case the blendmust 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 lightcrude will yield a lot of gasoline, jet-fuel and diesel oil, while a heavy crude will yield morefuel oil, particularly heavy fuel oil. The prices of gasoline and diesel oil are considerablyhigher than that of fuel oil.
The most commonly used unit for indicating the specific gravity of a crude oil is degreesAPI. This is a unit adopted by the American Petroleum Institute, and defined as follows:
°API = 141.5/sg – 131.5where 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 contentthe more costly it is to process because the sulphur content of the different products is limitedby their quality specifications. The latter are become increasingly severe due to environ-mental concerns. Generally speaking, light crudes have a low sulphur content while someheavy crudes may contain up to 5 or 6% sulphur, or even more. This is not a hard and fastrule however.
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1.3.1.2 Location
The most commonly quoted price for crude is the FOB (free on board) price. This is the priceof the crude on board the vessel which will transport it at the port of origin (Ras Tanura inSaudi Arabia for Arab Light, Sullom Voe in the Shetland Islands for Brent, etc.). Prices arealso 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 givencrude 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 qualityare produced from different oil fields, the price differential between them should representthe difference in transport costs. Suppose that two crude oils with the same characteristicsare 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) andRotterdam 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 sellat $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 growingrapidly while supply fluctuated depending on discoveries made: the arrival of substantialvolumes of new oil on the market could result in a collapse in prices. Prices fluctuatedbetween up to about $20 and several tens of cents per barrel. In the very early yearsexchanges were set up in which oil was freely traded.
The Rockefeller era saw greater stability in prices. Standard Oil controlled most of therefining capacity and distribution infrastructure in the United States, and sought to preventlarge variations in price so as to foster demand. This was the time when the system of “postedprices” was developed. Faced with a very wide range of different crudes, the refiners, andspecifically John Rockefeller’s Standard Oil, posted the price at which they were willing topurchase crude at the refinery gate.
Posted prices were introduced in other areas by the oil companies, after World War II asthe price at which they were prepared to sell the crude. Posted prices were used as a referencefor 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 thenumber of oil companies suddenly rose sharply. During and immediately after the war the priceof crude climbed (from $1.20/bbl in 1916 to $8/bbl in 1920). However the nature of the Americanmarket was significantly modified by a large number of discoveries of oil, in California (SignalHill 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. Thefact that in the U.S. landowners also own the mineral rights means that when oil is discoveredon someone’s land, all his neighbours will have an incentive to also drill and produce oilthemselves. This fact can result in gluts of oil on the market, and also to the inefficientexploitation of oilfields, which are rapidly depleted (Fig. 1.36).
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The fall in prices in the early 1930s provoked social unrest and riots. The authorities wereforced to intervene to control production. This meant putting a stop to anarchical oilextraction activities, which proved to be hugely wasteful, and matching production todemand. An inter-state committee was set up to distribute production quotas set by theBureau 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 timeabsorbed almost half the world’s production of crude) from the rest of the world, where themajors were in cut-throat competition with each other. When prices again fell, in 1928, themain leaders of the oil industry (in particular Henry Deterding, Chairman of Royal DutchShell, Walter Teagle, President of Standard Oil of New Jersey and John Cadman, Presidentof Anglo-Persian) got together in a castle in Achnacarry in Scotland. The objective, apartfrom shooting grouse, was to coordinate the actions of the main oil groups so as to curtailthe 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 competitionin acquiring new markets.
As far as prices outside the U.S. were concerned, the rule since the end of the nineteenthcentury had been: any product, whatever its origin, is sold throughout the world as if it hadoriginated from New York. This practice was justified by the American dominance, and inparticular the dominant position of the East coast. The Achnacarry agreement perpetuatedthis principle in a slightly modified form: since Texas had now become the centre of world
1. Your well is running mine dry.2. I got here first.3. As soon as an oilwell starts producing, other people start drilling nextdoor to benefit from the oil field! When wells start interfering with eachother’s production, litigation follows.
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production, the system was based on the “Gulf plus” pricing agreement. All oil productswould 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 desti-nation. After the major discoveries at the end of the 1930s, this system favoured andcontinued to favour Middle Eastern oil because of the low production costs applying there.
This formula was first challenged during the war. The American and British naviesdiscovered that it increased their refuelling costs considerably. The oil companies thereforeaccepted that a second point of reference for pricing should be established in the ArabianGulf. 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 crudefrom the Middle East. The European Cooperation Administration (ECA), whose job it wasto manage the aid provided by the U.S. under the Marshall Plan, sought to reduce the costof oil imports, which was absorbing a large part of the American aid. Furthermore it was inthe interests of the oil companies to develop their production in the Middle East: per barrelcosts were low there and could be reduced even further if the volumes produced and exportedcould be increased. After the war there was a growth in oil imports to the East coast of theU.S. which involved the adoption of a new system of so-called “posted” prices (1949): theFOB price of a crude was set at a level such that its price in New York would be the sameas 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 oilshould 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 wouldaccrue to the company and half to the producing country. This principle spread to other coun-tries, particularly in the Middle East. It should be noted that if the international and partic-ularly the American companies accepted this regime relatively easily, this was because theircosts were fairly limited: taxes paid to the local authorities would be deductible from thetaxes paid in the United States. And if the U.S. government did not object, this was becausethe 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 pricessystem spread to all large producing countries. Before then the prices of crudes at thewellhead 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, significantreductions in costs were possible. It became general practice to apply reductions, and theposted prices were periodically revised downwards.
There were other changes: royalties began to be regarded as a cost rather than as anadvance on tax. This amounted to increasing the taxation of companies by one-half of theroyalties. After the large price increases of 1973, producing countries replaced the postedprice by the Government Official Selling Price, which was taken as the basis for the calcu-lation 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%, andlater 80 or 85%. The objective of producing countries was clear: to retain for themselves thelion’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 ratesfell to ensure that the operating companies still had a financial incentive to explore andproduce.
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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 tolandowners. An operator who suspects there is a deposit of oil on his land must seekpermission 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 beenthe most common. In exchange for the payment of a sum of money known as a bonusand the acceptance of a number of obligations, the operator obtains the right to explorefor 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 mineralrights) for each barrel produced. This royalty compensates the state for the removal of anon-renewable resource. The amount varies considerably, but is frequently of the orderof 10-15% of the price of the crude. In addition, producing companies pay a tax on theirprofits to the state. The cost of obtaining the crude is therefore the production costs plusthe 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 longerperiods of price stability. These were the prices posted by the majors from the end of thewar until 1973, or the official prices set by governments between 1973 and 1985. Before1985, free market mechanisms, where cargoes of crude or of products were traded outsidethe control of the major producers played very little part.
The second oil shock transformed this situation. At the end of 1978 and for many monthsthereafter the prices on the free market were in excess of the official prices. This led to anunderstandable tendency on the part of certain producers to dispose of increasing volumes ofcrude on these markets. But on these free markets, the prices are also free, being fixed on aday-to-day basis, cargo by cargo. This is the “spot” market. It should be mentioned that after1981 the reverse situation applied, with the spot prices being lower than the official prices, asituation 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 supportinga spot market. The prices set in a market can only be accepted by the parties concerned ifthere are many buyers and sellers. In most of the large exporting countries the number ofsellers remains very small. This is why the spot markets concentrate particularly on severalNorth Sea crudes (Brent in particular), on West Texas Intermediate in the U.S. and onDubai in the Middle East.
From that time on, spot prices began to drive the physical markets. The major exportersbegan to fix the FOB price of their crude by reference to the spot price of Brent (for crudes
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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. equalto the price of Brent less a differential reflecting both the difference in quality and thedifference in transport costs.
Spot markets developed relatively rapidly. Before 1973 when the producing countries tookcontrol of their petroleum resources the international companies were highly integrated andalmost all trade took place within the framework of long-term contracts. Spot markets werealmost non-existent. In 1973 only 1% of transactions were effected on the spot markets, butby 1980 spot transactions accounted for 20% and by the end of the 1990s the proportion wasabout one-third. In most contracts for the delivery of crude oil or refined products, whether shortor 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 refinedproducts (see Box 1.8) to deal with the financial risks associated with the volatility of pricesresulting from the development of spot prices. The new markets had a considerable impact
Box 1.8 Futures and derivatives markets.
Futures (contracts)
Because spot prices are very volatile, the need arose for an effective means of hedgingagainst loss due to unfavourable price movements. Various exchanges have opened upmarkets for futures contracts in crude oil and refined products.
These are financial markets. They do not involve exchanges of physical goods, but arestandardised 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 monthm + 1, m + 2,….., the term being stipulated in the contract. The price is determined atthe time the contract is made.
In most cases operators never actually get as far as a physical exchange, but sell theircontract before it matures (close their position).
Derivatives
These are a range of financial products of varying degrees of sophistication associatedwith other types of asset or commodity, also suited for use with crude oil and petroleumproducts. 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 thecase of a futures contract) to buy or sell a standard quantity at a given fixed price. A rightto buy is referred to as a call option and the right to sell is a put option. An option is char-acterised 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 afixed price. An airline wishing to know what it will pay for kerosene can effect a swapcontract with a trading company. The airline will buy the kerosene at the price applyingon the day of purchase, but will receive the difference between that price and the referenceprice if this difference is positive, or will pay this difference if it is negative.
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in making for a more flexible market. The relatively low transport costs and the differencesin 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 withwhich prices regained their pre-war levels) at the outbreak of the Gulf war in 1990-1991 tothe existence of futures markets rather than the announcement by the IEA that strategic stockswould be used. The ability to purchase oil forward has effectively made it pointless to accu-mulate stocks speculatively, a practice which is thought to have contributed to the secondoil shock. But speculative behaviour on these “paper” markets can also amplify the pricemovements caused by uncertainties related to the weather, stock levels, etc. In general, asmall mismatch between supply and demand can strongly influence price. The influencewhich market developments have on price volatility remains a matter of debate.
4. Arbitrage consists of exploiting differences between two markets for a given product. If, for example, theprice difference is greater than the transport and transaction costs then arbitrage consists of buying theproduct at the lower price and selling it at the higher price.
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. Spot price (in red) and future price (in blue) from July 2008
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 beenoverlooked during the previous decades, when large discoveries were being made in theMiddle 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 non-renewable resource increases at a rate equal to the discount rate (when operating costs arenegligible). 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 consistentwith a model based on Hotelling’s rule that incorporates the latest assumptions for eachperiod 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 haveto be replaced when they are exhausted either by some other good or by an alternative tech-nology (backstop technology) at a higher cost. Until the mid-1980s, the resource in questioncould be considered to correspond to “conventional” oil. Available backstop technologies(non-conventional hydrocarbons, biomass and other renewable energy sources, nuclearenergy, liquid fuels obtained from coal) appeared to be accessible only at a cost that wasconsiderably greater than oil prices could support. At least this was the case for “white”products, fuels and petrochemical feedstock.
Harold Hotelling, a prolific economist active in the nineteen twenties and thirties, isgenerally considered to be the founder of the theory of exhaustible resources, followinga pioneer article by L. C. Gray (1914). His work was rediscovered in the 1970s andbrought 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, haddiscovered “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 ofan exhaustible resource increases at a rate equal to the real rate of interest (or, using a morecontemporary approach, to the discount rate). If the cost of production is not negligible, itis 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 beexplained very simply. If the price of the resource is stable (or increases at a rate less thanthe discount rate), it would be in the interest of producers to produce goods as quickly aspossible, 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. Theonly change that would allow for market equilibrium is, therefore, the one that makes thediscounted value of future unit revenues stable, thus an increase at a rate equal to thediscount rate.
Box 1.10 Hotelling’s Rule of exhaustible resources.
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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The situation has changed since then. The belief, up until 1985, in an ineluctable growthin prices stimulated significant research and development efforts. The resulting techno-logical progress has led to the discovery of hard-to-find deposits, to noticeable improvementsin rates of recovery, and to the development of “non-OPEC” oil, especially offshore. Afterthe 1986 price drop, these efforts were continued and led to a sharp decrease in explorationand production costs in non-OPEC countries, especially for deep-sea oil. The frontierbetween conventional and non-conventional oil (deep-sea oil, extra-heavy oil, tar sand) isregularly being pushed back. Producers can now access offshore deposits at increasinglygreater depths using technologies that are constantly being improved. Figure 1.37 illustratesthe progress made in this field. The difference between the production costs of offshore andon-shore oil is decreasing. As indicated above, the extra-heavy oil in the Orinoco Basin inVenezuela was, until the 1990s, considered to be practical to produce only at a relatively highprice per barrel of crude (at the time, $40 or more). This oil is now produced for a relativelylow price, and large-scale production has begun. We’ll discuss the technological costs in thefollowing 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, extra-heavy oil, tar sand, oil shale, and so on. The traditional distinction between conventional andnon-conventional oil makes little sense today. Moreover, this continuum is not limited to oil-based hydrocarbons. Considerable research has been done on the development of tech-nologies for producing liquid fuel from natural gas (gas-to-liquid, or GTL, technologies usingthe Fischer-Tropsch process) and coal (coal-to-liquid, or CTL, technologies using directliquefaction or indirect liquefaction after gasification). These technologies will be discussedbelow. This continuum extends to biomass fuels that make use of available products orprocesses (ethanol, ETBE, vegetable oils, methyl esters of vegetable oils) or those that arecurrently being researched (ligno-cellulose or biomass-to-liquid, BTL). In the more distantfuture, we may be able to develop technologies for the “carbonation” of hydrogen produced
Figure 1.38 Oil cost curve, including technological progress:availability of oil resources as a function of economic price(Source: IEA).
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 limi-tation, but there is and will be a need to make use of more complex and more costly tech-nologies (as currently perceived) as conventional deposits are exhausted.
1.3.3.2 Production costs
The average and marginal costs of production are the first elements used to analyze priceformations. Average production costs, for conventional crude oils, are between a few dollarsper barrel for the largest and easiest fields to develop (Middle East), up to $60/b in the mostdifficult areas.
To complete this study, we need to provide some idea of the costs of non-conventionaloil, 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 abarrel, 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 ratesof recovery (8 – 10%). The injection of steam would increase costs but would result in appre-ciably better rates of recovery.
The cost of oil extracted from the Athabasca tar sands —oil sands— fell to low levelsbefore the rise in gas prices, to which production costs are highly sensitive. Production can
be made by use of mining technologies or petroleum technologies with steam injection(steam assisted gravity drainage, SAGD). The latter technologies consume natural gas forthe 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 hori-zontal wells situated at a lower level).
In addition to extraction costs, we should take into account so-called “upgrading” facil-ities, 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 veryhigh 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 unlikelythat 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 “shaleoil”, a good quality oil located in the source rock and which can be produced by fracturingtechniques.
B. Synthetic hydrocarbons obtained from coal and gas
There are two methods for producing synthetic hydrocarbons from coal (coal-to-liquid). Oneentails direct conversion through the hydrogenation of coal, the other makes use of indirectconversion, coal gasification initially producing a synthesis gas (CO + H2), which is then trans-formed 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 cetanenumber). During World War II, Germany made use of both types of processes. Currently theonly factory of industrial capacity still using the Fischer-Tropsch process is the Sasol plant inSegunda in South Africa. Several facilities are currently under project in China. As for the directhydrogenation process, a large-scale project is currently underway in China, with the partici-pation 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 technologieswere considered profitable for per-barrel prices of $50 and above (excluding costs associatedwith CO2 emissions) for production units located near low-cost mines. Since then, estimatesof breakeven points have been revised upwards to around $70 – 80 a barrel. Recall that coalreserves represent on the order of 100 years of production at the current rate (with consid-erable uncertainty however). The limitations of CTL will most likely arise not fromconstraints on raw materials but from the costs associated with CO2 emissions.
The production of liquid hydrocarbons from natural gas (gas-to-liquid) also makes useof the Fischer-Tropsch process. The first plant of this type was built in 1991 by Mossgas (nowPetro SA) in South Africa. Shell then brought on line a 14,500 barrels-per-day (b/d) facilityin Malaysia. The rise in oil prices that began in 2000 has promoted studies for several newprojects. 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 atotal capacity of 140,000 b/d). The first started operation in 2007, the second in 2011. Theannounced costs should be on the order of $25 per barrel when the gas is produced at lowcost and supplied at low price ($0.5 – 1/MBTU) to produce high-quality diesel fuel. Thehigher cost of raw materials and services seen since 2004 has raised the stakes. With unitinvestment costs that are three times greater and a higher gas price, the Shell project wouldonly be profitable with high crude prices. The success of these initial projects will have a
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7. “Les pics mondiaux du pétrole et du gaz” [Global Peaks in Oil and Gas], presentation to the Conseild’Analyse Stratégique, Paris, Oct. 28, 2006.
decisive effect on developments in this field. Different projects are being studied but devel-opments will probably remain limited to niche production activities. Another drawback: costsdo not include the cost of CO2 emissions, and GTL like CTL involves a significantconsumption of energy. Additionally, opportunities could be limited by the appearance of theglobal 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, theuncertainties concerning peak gas are stronger than those for peak oil. In particular, in thedistant future shale gas reserves are large and we cannot exclude the development ofproduction technologies that make use of methane hydrates (clathrates). These resources arepoorly understood at present but could become highly significant.
C. Biofuels
The biofuels used today, so-called first-generation fuels, consist primarily of ethanol forgasoline engines and the methyl esters of vegetable oils for diesel engines. In 2010 worldwideproduction 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 fortraditional 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. Theirsubstitution potential for oil-based fuels is limited to a few percent because of competitionwith food production.
To go further it will be necessary to develop second-generation systems, which makeuse of ligno-cellulose biomass (wood and straw). Optimistic estimates indicate a substitutionpotential of 30% by 2030. Biomass-to-liquid (BTL) systems involve gasification of thebiomass followed by the production of kerosene and diesel fuel using the Fisher-Tropschprocess. The second method is comparable to the production of ethanol by fermentation.These approaches are subject to considerable research in an attempt to reduce productioncosts, 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 continuummentioned above could be classified today by increasing cost. It is therefore likely that withthe exhaustion of deposits that are easy to access, costs and prices will increase. This is notcertain, however. Recall that in the early 1980s all the published scenarios for the devel-opment of oil prices pointed upward and technological progress played a determining rolein proving those assumptions wrong. But if there is one field in which forecasting is an espe-cially difficult art, it is that of technological change. There are many examples of this. Inthe energy sector, aside from the spectacular drop in production costs for extra-heavy oilalready discussed, there have been improvements in the yield of combined cycle electricalproduction plants. Progress is often faster than anticipated, although it does not alwaysoccur when we expect it, as the case of nuclear fusion illustrates. Fifty years ago, it wasbelieved that it could be controlled for applications to produce electricity within 35 to 50years. We are still talking about a fifty-year horizon today, with little certainty aboutcommercial prospects.
1.3.3.3 External costs and greenhouse gases
Available options in the energy sector must take into account concerns about climatechange. Greenhouse gas emissions, associated with the use of fossil fuels, increase thetemperature of our atmosphere. By the end of the century, the change could amount to asmuch as 1.5 to 6 degrees Celsius on average, according to experts from the Intergovern-mental Panel on Climate Change (IPCC). Although there are considerable uncertaintiesabout the scope and consequences of such emissions, there appears to be little doubt thatit 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 aEuropean market for CO2 emissions permits has been in place since January 1, 2005. Thedifferent steps that will need to be taken to limit emissions will entail costs that will haveto be tied to hydrocarbon use. Many analysts feel that constraints on greenhouse gases willhave a greater effect on limiting the use of fossil fuels, and oil in particular, than resourcescarcity.
Steam-assisted recovery, the processing of extra-heavy fuel, the use of tar sand or oilshale, and the conversion of gas or coal into liquid hydrocarbons all require high energyconsumption and result in significant CO2 emissions. The internalization of the corre-sponding external costs or the use of Carbon Capture and Storage (CCS) can modify the hier-archy of direct costs. This may restrain the development of non-conventional oil and assistedrecovery processes intended to increase recovery rates. In this area technological progressplays a key role. To limit CO2 emissions, the heat needed for assisted recovery projects andthe production of non-conventional oil can be provided by nuclear reactors. The carboncapture and storage provide a number of alternatives, but the development of the corre-sponding costs is difficult to predict. Reduced CCS costs could promote new developmentsin 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 globalreserves of conventional crude are located in the Middle East and 80% of proven globalreserves are owned by national companies. We all know how oil has influenced politicalevents and the repercussions political events have had on the oil market. Oil market is aglobal market to the extent that transport costs are low and much lower than those associatedwith other energy sources. Geopolitical issues, therefore, are considerably different for oiland natural gas, which are related energy sources. Events that have had a major impactinclude 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 thehistory of the price of crude in relation to some of these events. Although of more limitedimpact, the uncertainty in Venezuela concerning the policies of President Chavez, orEurope’s fears concerning Russian supplies, in particular issues related to energy transportthrough gas and oil pipelines, are important. OPEC’s decisions also play a significant rolein geopolitical events. However, although the 1973 conflict was a factor in triggering the firstoil crisis, the price rise was inevitable given the increased demand (7 – 8% annually), whichrose at a considerably faster pace than the increase in production capacity.
Finally, in the producing countries the willingness to allow international companiesto 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
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8. More specifically, it is a dominant oligopoly with a competing fringe. The Arab countries with smallpopulations and extensive reserves (Saudi Arabia, Kuwait, the Emirates), whose cash flow needs are lesspressing and can more easily limit production, constitute the core of the oligopoly (see, for example, P. N.Giraud [1995]).
respectively, which are national companies. In Iran, foreign companies have limited accessto 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 principlesembodied in the Iranian constitution, according to which the state has a monopoly on thedevelopment of petroleum resources. Such complex contractual arrangements represent asignificant limitation for the host country and for international firms. For the past severalyears, we have seen how the Russian government has reasserted control over the oil and gassectors; and more recently Latin America (Venezuela, Bolivia) has followed suit.
A. The cartel
Ever since the first oil crisis, increases in crude oil prices have been considered the result ofbehavior by the OPEC cartel8, with Saudi Arabia playing a dominant role. Outside periodsof 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 increaseddemand 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 from1981 to 1985. This situation is atypical, however. The Persian Gulf reserves, which are veryinexpensive, should be sold before those with a higher marginal cost, assuming the existenceof centralized global economic management or the presence of a competitive environment.The result was just the opposite, however. When demand contracted following the intro-duction of alternative energy sources and energy saving policies, non-OPEC production, asa result of the technological progress mentioned above, continued to grow while OPECproduction fell, especially in Saudi Arabia. In 1985 it hit bottom (2.5 mb/d compared with11 in 1980). The decline in revenues led to tensions within the organization. Saudi Arabiadecided to regain its market share. This was the start of the “counter shock” and the drop inoil prices (figure 1.26).
What is the role of the market when Saudi Arabia has the will and ability to regulateactivity? R. Mabro once quipped that Saudi Arabia and the market divide the work of deter-mining crude oil prices: Saudi Arabia gets to determine the first two figures before thedecimal point, while the market gets to determine the two figures following the decimal. Notethat 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 partnersas well as non-OPEC producers (Norway, Mexico, Russia) explains the lag before pricesfound a level that was considered satisfactory by the producing countries. In the interval, thelow 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 demon-strated 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 inad-equate, as was the case in 1979 and from 2004 to 2009.
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 difficultto 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, notwith-standing inertia, become effective: alternative sources, energy savings, investment in non-OPEC regions. Moreover, among the members of the cartel, the temptation to ignore quotasincreases whenever prices are high. As Sadek Boussena9 remarked, “OPEC is strong whenprices are weak, but weak when prices are strong.” The temptation becomes even greaterwhen there is significant overcapacity. Thus, it is even more difficult to conclude agreementsdesigned to distribute additional limits on capacity among the members of the oligopoly.
On the other hand, when prices are low, investments by exploration and productioncompanies are scaled back because of the reduced profit potential of new projects as wellas a limitation on financing ability. Low prices also promote increased consumption, whichcan increase more rapidly than the growth in production capacity. This was the situationobserved between 1998 and 2000. Moreover, considerable degradation in revenue could, insome countries, result in the growth of social movements and political instability that allparticipants seek to avoid.
We could summarize this by noting that in the petroleum industry, as in the majority ofother industries, production capacities are sometimes excessive, sometimes saturated. Whenthere is excess capacity, as always prices trend downward. It is primarily in such circum-stances that OPEC can intervene. When production capacities are saturated, the priceincreases until capacities are restored. Since 2004 not only has excess production capacitybeen strongly reduced but refinery processing capacity has been saturated. The initialquestion was whether, following a transitional “squeeze” between supply and demand, pricescould return to an equilibrium not very different from that of the 1990s, or if the rise seenin recent years reflects a structural modification, the increase in demand necessitating thesearch for production sources at higher marginal cost. Since 2005 many economists andpoliticians have come to believe that the latter is the correct view, and speak of a “paradigmshift” in the price of oil and other energy sources.
For the restoring force to be effective, several conditions are needed. For decisions to bemade, actions to be taken, and investments made, it is not enough for prices to be high, onemust assume they will remain high.
C. Expectations
Investment decisions are naturally based on assumptions about demand and medium- andlong-term prices. But price forecasts are always difficult and, it is worth pointing out, in thepetroleum market, often self-destructive. One especially relevant example relates to the1985 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 Commis-sariat 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 Frenchnuclear program, were made for reasons of energy independence ––these immediately
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9. Associate professor at the University of Grenoble, former Algerian Energy Minister, former president ofOPEC.
followed the first oil crisis. But significant energy savings, the use of alternative energysources, 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 highbut 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 ofproduction and refining capacity in 2004. The rate of growth of demand, especially in Chinasince 2003, had not been anticipated. And, until the summer of 2003, nearly all analystsassumed Iraq would again participate in the market, with the development of new productioncapacities 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 otherOPEC countries, primarily Saudi Arabia. Such a consensus was obviously unfavorable toinvestment in those countries. Coupled with the slowdown in demand observed after theevents of September 11, 2001, this led to a reduction in worldwide exploration and devel-opment expenditures in 2002 and 2003, on top of that of 1998 – 1999. In short, the prevailingconsensus until mid-2003 on the existence of excess capacity contributed to the disap-pearance of that excess.
Following IFP Energies nouvelles studies on investments projects and production potentialregion by region, Y. Mathieu proposed two scenarios regarding oil production (Fig. 1.40). Itis clear that hydrocarbon reserves are finite and therefore exhaustible. But little is knownregarding the level of ultimate (i.e. total existing) reserves. The Association for the Study ofPeak 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.
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0
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1972 1976 1980 1984 1988 1992 1996 2000 2004 2008
1984*
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Figure 1.39 Changes in crude oil price forecasts.
1.4 CONCLUSION
A future without oil crises is quite unlikely, even if we retain optimistic hypotheses of tech-nological 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 technologiesare available, timely investments must be made in energy management and alternative fueltechnologies, and in the development of oil production capacity. This last point wouldassume a continuous pro-active effort on the part of OPEC countries to make investmentswith a certain amount of foresight. The investments in question are often considerable andjust-in-time management is not favorable to the existence of excess capacity. Moreover, itis 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 theelements of a much larger problem ––the ability to ensure the sustainable development ofhuman societies. Water and agriculture are the major factors, along with health, and willrequire increasingly greater amounts of energy. The real question is not about hydrocarbonsbut about all energy sources. The twenty-first century will only be able to resolve theseproblems if we make a concerted effort to rid ourselves of our addiction to the use ofenergy. We will also need to make use of synergistic effects in promoting the use of differentforms of energy: upstream and downstream cooperation between oil and nuclear energy,cooperation between renewable energy and nuclear energy.
* including part of the oil sands of Canada and extra heavy oils of Venezuela
Figure 1.40 Production scenarios (Source: Yves Mathieu (2006)).
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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 sedimentaryrock, which forms the reservoir. They therefore occur in sedimentary basins, that is, indepressions 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 thesedepressions (clays, sands), by bio-chemical activity (calcareous rock) or by evaporationfrom lagoons (salt, gypsum). These sediments formed in successive layers, millions of yearsago, older layers being buried by more recent layers. Once buried, these layers becamecompressed, the water was driven out and the density increased according to the phenomenonof compaction. A process of subsidence then occurs in which the thickness of the layersdecreases over time and there is a natural packing of the rock. Furthermore variations inpressure, temperature and the ionic balance due to the process of sedimentation cause themineral salts dissolved in the interstitial water to precipitate, leading to the formation ofcement. The cumulative effect of compaction and cementation eventually results in a trans-formation in which the sediments, initially loose, become solid rock.
Sedimentary rocks settle first into horizontal layers known as strata, but can be deformedby geological processes related to tectonics, that is, movements in the earth’s crust. Thelargest such movement of this type is continental drift, known as plate tectonics. The slidingmotion of oceanic and continental plates produces folding which can lead to the formationof mountain ranges and the major ocean trenches (Fig. 2.2). They lead to the formation ofanticlines (folds), synclines (basins) and faults (fractures) if the strata are brittle. Whenthese structures undergo erosion for thousands of years and are then covered by more recentlayers the process is known as discordance.
2Oil and gas exploration and production
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HOLOCENEPLEISTOCENE
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Homo sapiens;Glaciations;
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Subduction of Indiaunder Asia;
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Emergence of mammals;
Disappearance ofdinausaurus and
ammonites; Primate; Formation of North
Atlantic,
Flowering plants;
Formation of South Atlantic;
Birds;
First mammals;
Breakup of Pangea;
First dinausaurs
Glaciation
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Reptiles
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oxygenatedatmosphere
Development of aerobic
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First sedimentary rocks
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CENOZOIC
Period
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Formation of the Earth
Formation of the Sun
Formation of the Universe
ERA PERIOD
EOCENE
Figure 2.1 Stratigraphic scale.
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, isdeposited in aquatic environments low in oxygen —on the beds of inland seas, lagoons, lakesor deltas— and is therefore protected from the action of aerobic bacteria. These residues aremixed with sediments (sand, clay, salt, etc.), accumulate, are compressed, and undergo a firsttransformation under the action of anaerobic micro-organisms. This first stage in the decom-position of the organic matter gives rise to kerogen, solid organic molecules entrappedwithin a rock known as the source rock.
The mechanism of subsidence causes sediments to be entrained to great depths, where theyare exposed to high temperatures and pressures. The kerogen is then transformed into hydro-carbons by thermal cracking: the long molecular chains are broken down, expelling theoxygen and nitrogen, leaving molecules made up only of carbon and hydrogen. Whentemperatures exceed around 60°C (140°F), kerogen is transformed into petroleum (alsoreferred 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 resultingmolecules, and therefore the lighter the hydrocarbons. In some cases, all the hydrocarbonsare broken down into the lightest hydrocarbon component, methane (CH4).
During their primary migration, due mainly to the effect of pressure, the oil and gasgenerated from the kerogen are expelled from the fine-grained source rock in which theyformed. Lighter than water, they tend to rise towards the earth’s surface, making their wayupwards along permeable conduits and fractures during secondary migration. Unless stoppedthey escape and seep away at the surface or lose their volatile components and solidify intobitumen. If on their path they encounter an impermeable layer, referred to as a seal, theycannot migrate further. In order for a deposit to form, the hydrocarbons also need to be trappedunder this seal, in the pores and fissures of a rock reservoir where they can accumulate.
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Figure 2.2 Mountain folds and faults.
There are two main types of trap: structural traps and stratigraphic traps (Fig. 2.4). Struc-tural traps are created by folds and fractures in the earth’s crust. The most common are anti-clinal 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 lyingadjacent to the reservoir rock. A trap is referred to as stratigraphic, on the other hand, if atleast one of its boundaries comprises a change of physical properties, i.e. a significantchange in porosity or permeability within the rock.
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Figure 2.3 Formation of hydrocarbons. Oil window, gas window.
Oil
Gas
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Hydrocarbons formed
Dep
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Figure 2.4 Structural (A, B) and stratigraphic (C, D) traps. A. Anticlinaltrap. B. Fault trap. C. Sand lens and wedge deposit under discordance.D. Reef.
A B
C D
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 reservoirof fair quality has a porosity in the range 10–20%. Moreover, it must be permeable, i.e. thepores must be connected in such a manner that the fluids can flow through the pores, so thatthey can be extracted. Most reservoir rocks are composed of sandstone or carbonates. Sand-stone reservoirs account for some 80% of all reservoirs and 60% of oil reserves. Within thereservoirs the fluids arrange themselves in layers from the lightest to the heaviest, the gaslying above the oil, which itself lies above the water.
A field comprises one or more reservoirs superposed over one another or in close lateralproximity. Some formations may contain many tens or hundreds of reservoirs: they are thendescribed as being multilayered.
2.1.3 Petroleum system
The term petroleum system refers to the combination of the main geological attributes whichhave led to the accumulation of hydrocarbons (Fig. 2.5). Firstly, there has to be a source rockfor hydrocarbons to be generated. A porous and permeable reservoir rock is needed tocontain the hydrocarbons and allow them to accumulate. The reservoir must be surmountedby 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. Andfinally, 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 like-lihood of occurrence of each of these events in order to estimate the chance of finding anaccumulation 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 hydro-carbons, 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 thousandsof metres below ground, so quite indiscernible visually or otherwise. Furthermore, theseaccumulations themselves only occur under very precise and restrictive conjunctions ofgeological circumstances. An exploration programme involves formulating a certain numberof hypotheses which are either more or less rapidly confirmed or have to be rejected giventhe indicators commonly adopted. Chance plays a non-negligible role, even though spec-tacular advances in prospecting methodology have taken place since oil exploration began150 years ago. At one time the most effective method of finding oil consisted of drilling closeto surface indicators. Hydrocarbon resources are now becoming increasingly difficult todiscover because they are found at depths of up to 5000 or even 6000 m (16000–20000 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 presenceor absence of hydrocarbons in a given subsurface formation. Furthermore it allows thepressure of a reservoir to be measured and allows samples of rock to be brought to the surface
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for analysis. Because drilling is costly, however, it is essential that geological, geochemicaland geophysical studies are carried out beforehand.
In the first place it is up to the geologists to identify general areas which, on the basis ofgeological criteria, are likely to conceal accumulations of hydrocarbons. They work withgeophysicists who study the physical properties of the subsoil, in particular with the help ofseismic reflection. For offshore exploration since general ground reconnaissance is simplynot 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
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Figure 2.5 Petroleum system.
50-100 μm
Rock pores
Salt water
Oil
33
33
11
11
11
1122
22
22
10 km
50-1
00 m
taken to drill an exploration well. Whether or not the drilling is successful, it provides thegeologist with valuable information in the form of core samples, cuttings and electricalrecords from the wellbore. By examining, cross-correlating and interpreting these data,prospectors are able to pinpoint subsurface structures which could contain economicallyviable quantities of hydrocarbons. Exploration is an iterative process, each round of resultsobtained permitting more targeted exploration to be conducted.
If exploration drilling produces positive results, the next task is to delineate the reservoirdiscovered and appraise it by drilling additional wells and making further measurements. Atthis 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 howmuch is already known about the area. In hitherto unexplored territory the first stage is tonarrow down the area of study and identify zones where more detailed exploration is appro-priate. For onshore zones this involves studying satellite images, aerial photographs and radarimagery in order to determine the main features of the sedimentary basin concerned. The nextstage is to conduct geographical studies of the surface in order to verify that the threenecessary components, i.e. source rock, reservoir rock and impermeable seal are present. Ifthey 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 theproximity of an accumulation. Geologists drill small boreholes which allow them to take coresamples for chemical analysis by a laboratory. The results provide useful information onwhether there are traces of hydrocarbons present. In a mature, more familiar region, existingsources of information in libraries and company databases, public agencies, etc. can beconsulted. Particular efforts are made to gain a better understanding of the porosity andpermeability of potential reservoirs. Most large traps have already been discovered, so thatless 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 mostcommon 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 subsurfacemaps. These successive elaborations require a stratigraphic correlation which involves iden-tifying rocks of a similar age by comparing fossils and the electrical analysis from an explo-ration well or from an outcrop with the data from another well or outcrop in the light of theseismic results. A major variation in thickness or in the type of rock may provide an inter-esting geological clue.
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2.2.3 Geophysics
It is not possible to obtain an adequate picture of the subsurface properties by extrapolatingfrom surface characteristics. And the underground formations are not visible. It is thereforenecessary to resort to geophysical exploration methods. These consist of making measure-ments of fundamental physical data —the gravitational field, magnetic fields, electrical resis-tance— in function of depth, and interpreting these results in geological terms.
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Figure 2.6 Principle of seismic exploration (A), 2D seismic image (B). 3D seismic image (C).
GaultclaysAlbo-Aptian
Barremian
Wealdean
Sequanian
Rauracian
Kimme-ridgian
Portlandian
A
B
C
Geophysical methods fall into three categories:
• Magnetometry, which involves measuring, usually from an aircraft, variations in theearth’s magnetic field. This provides an indication of the subsurface distribution ofcrystalline formations, which have no chance of containing oil, and more promising sedi-mentary formations.
• Gravimetry, which involves measuring variations in gravitational fields which occur asa result of the different densities of rock close to the surface, and gives indications ofthe nature and depth of layers.
• Seismic methods, which involve making an ultrasound image of the subsoil by studyingthe way waves are propagated, thereby providing prospectors with information on thesubsurface structures and stratigraphy.
The first two categories are in fact not used very often; seismic methods, and seismicreflection in particular, represent some 90% of geophysical operations, however.
Seismic reflection involves transmitting sound waves into the subsoil which are propa-gated through the rock mass, undergoing reflection and refraction at certain geologicaldiscontinuities, referred to as reflectors. Like echoes, the reflected waves return to the surfaceand are recorded by sensors which convert the vibrations in the ground into electricalvoltages (Fig. 2.6). There are two types of acquisition: two dimensional (2D) and threedimensional (3D) seismic acquisition. Traditional 2D acquisition is used for extensive explo-ration and in zones where access is difficult, whereas 3D seismic methods are used for finerprospecting and offshore programmes.
On land the seismic waves comprise tremors on the ground surface generated artificiallyby buried explosives or “thumper trucks” (Fig. 2.7). The receivers or geophones aredistributed at the surface in different possible configurations: in a straight line, along severalparallel lines, in a star or rectangular shape or any other geometric configuration. They areconnected to a recording truck which logs the data acquired.
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Figure 2.7 Thumper trucks.
Offshore exploration depends almost exclusively on seismic measurements made onboard a vessel equipped with two crews, one to carry out the normal navigational operationsand the other to perform the seismic measurements. The vessel generates waves by meansof air guns and tows a tube called a streamer behind it which contains hydrophones. It iseasier to collect seismic data at sea than on land because of the facility with which a boatcan move in any direction. The geophysicist is therefore able to acquire more data than onland, and can produce, after processing the data, a more detailed 3-dimensional image at alower cost (Fig. 2.8).
The signals received by each sensor at the surface are then plotted graphically as afunction of the interval until the signal is returned. Isochrones —i.e. lines joining subsurfacepoints of equal return times—, can then be plotted. In order to obtain a depth section whichrepresents a vertical cross-section of the subsurface, the durations need to be converted todepths using formation velocities obtained during drilling.
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Seabed
SourceHydrophones
Figure 2.8 Seismic exploration at sea.
Seismic records collected by the geophysicists are then processed by powerful computerswhich seek to increase the signal to noise ratio. Advances in data processing achieved inrecent years make it possible to discover new petroleum structures using old data usinghigher-performance imaging techniques.
Once the seismic data have been acquired and processed, they have to be transformed intoutilisable data in the form of isobath or isopach maps and interpreted geological cross-sections showing the faults and the main reservoir layers. In order to provide the mostaccurate possible description of the subterranean structures the velocity of propagation of thewaves 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 cali-bration 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, theinclination of the strata, their continuity and folds, thereby indicating the presence of possibletraps which would be the target of drilling. They also allow gas reservoirs to be located incertain cases, or oil-water or gas-water contacts (oil-water contact: OWC, gas-water contact:GWC) to be identified.
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 ofthe subsoil acquired through geological and geophysical surveys allows the potential of aprospect to be broadly evaluated, but cannot definitely confirm the presence of suspectedhydrocarbon resources. Certainty can only be obtained by gaining direct access to thesubsurface through drilling. Drilling also provides prospectors with a range of valuable dataon the lithology and fluids present.
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Figure 2.9 Drill bits.
Drilling an exploration well can take several (2 to 6) months, but the precise duration isdifficult to predict because of geological uncertainties at this level. Important doubts willalways remain about the depths, the hardness of the rocks and interstitial pressures in theformation, which can only be swept away by drilling. On average one drilling in five resultsin the discovery of an economically feasible hydrocarbon reservoir. This falls to 1 in between7 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 bypenetrating the various geological strata down to a depth of up to ten kilometres (35000 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 onthe rock, its rotation and the removal of the cuttings using a circulating fluid (the drilling mud).
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Figure 2.10 Main components of a rig.
Crownblock
Drillingcable
Travellingblock
Hook
Injectionhead
Rotarytable
Drill pipe
Drillingwinch
Mudpumps
The drilling bit is attached to a drillstring made up of tubular elements which are screwedon as the drilling advances: drill-pipes and drill-collars close to the bit. This assembly issuspended and manipulated from a derrick (Fig. 2.10). Depending on the type of well therotary 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).
In addition to cleaning the bottom of the well, drilling mud helps to cool and lubricatethe drilling bit, to consolidate the walls of the wellbore and exercise pressure such as tocontain 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 adrill-collar and a drill-pipe. When drilling has reached a certain depth a new drill-pipe isadded to the drillstring. This procedure is repeated each time the increase in drilled depthreaches 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 intothe wellbore one at a time, and cemented in place so as to protect the groundwater and controlfluids emitted from the well. Several items of equipment are fitted to the upper extremity ofthe casing to insure suspension and seal the opening. Safety devices known as blow-outpreventers are also fitted at the wellhead, fitted with high pressure valves which allow thewell 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 therequisite safety requirements are all met the next drilling stage can begin. A new drilling bitof smaller diameter is lowered into the hole inside the surface casing, and operations proceedin the same manner as before. When a certain depth has been reached the hole is again casedusing smaller casing which matches the diameter of the new hole. The size of the drillingbit is again reduced, the procedure is repeated, and so on. As drilling progresses, successivelysmaller 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 increasingdepth, punctuated by difficulties and the need to regularly replace the drilling bit, whichinvolves withdrawing the entire drillstring As drilling advances a drilling log is maintainedin which information is entered regarding the drilled depth, the nature of the rock and thefluids encountered, the drilling durations and any noteworthy events. This document is ofgreat 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 facil-ities to the site and the availability of the derrick. Offshore there is the additional constraintof 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 whichthe rig is supported. Offshore operations are conducted from platforms which either float orare fixed to the sea bed, and which are capable of performing all the functions normallycarried out at an onshore drilling site as well as certain other services such as diver supportand a meteorology station. The platforms may be either fixed platforms resting on the seabed, floating structures or semi-submersibles. Self-raising or jackup rigs are generally usedin shallow waters. Barges and semi-submersibles with dynamic positioning tend to be keptfor deeper waters. These mobile units only remain stationary during drilling, which can lastbetween several weeks and several months (Fig. 2.12).
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250
Dep
th (
m)
750
3 600
2 500
3 300
Surface casing
Technical casing 1
Technical casing 2
Concrete
Production casing
Liner hanger
Liner
26" (660 mm)
20" (508 mm)
17 1/2" (444 mm)
13 3/8" (340 mm)
12 1/4" (311 mm)
9 5/8" (244 mm)
8 1/2" (216 mm)
7" (178 mm)
5 3/4" (146 mm)
5" (127 mm)
Figure 2.11 Cased wellbore.
Figure 2.12 Mobile platforms for offshore drilling.
3000
2500
2000
Wat
er d
epth
(m
)
1500
1000
500
Jack-uprig
Jack-up rigsemi-submersible
Dynamically positioneddrill vessel
2.2.4.4 Logging
During drilling, prospectors keep records of a number of physical parameters of the rock andthe fluids encountered, known as logs, which they represent graphically as a function of depthor time.
The mud log comprises the various measurements provided by the mud circuit. Theseinclude the penetration rate, the characteristics of the drilling mud and the cuttings and coresdescription. 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 acore 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 datesthem), porosity, permeability, and fluids saturation.
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Figure 2.13 Core samples.
Wireline logging, also commonly known as electrical logging, is carried out during inter-ruptions to the drilling. It uses a tool known as a sonde lowered into the wellbore at the endof an electric cable or wireline. Logging while drilling, on the other hand, is carried out withthe 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 todelineate the reservoir and evaluate its potential. This appraisal stage essentially involvescarrying out the following tasks iteratively:
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Figure 2.14 Log plots.
Logs Logs
GR RH0830 140 170
55
270
NPH -5
23602370
23802390
24002410
24202430
24402450
24602470
24802490
– Mapping (making a more accurate evaluation of the size and position of) reservoirsusing 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.
When these tasks have been completed, a decision will be taken, based on the availableinformation, whether to develop the field and put it into production or to shut it in untileconomic prospects become more favourable or whether to abandon it.
The appraisal stage is a period of high economic risk. On one hand, a precise appraisalprogramme needs to be undertaken and targeted studies need to be conducted so that suffi-cient information is obtained to take the right decision, which takes time and requiresinvestment. 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 thedevelopment of the field and production as quickly as possible in order to ensure the projectremains 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? Shouldit be developed? If so, what should be the development scheme? Answering these questionsinvolves understanding the interplay of geology, geophysics and reservoir engineering. Thetotal recoverable resources will depend on how recovery is to be effected: the production
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Box 2.1 The most common forms of wireline logging.
The spontaneous potential (SP) measures the electrical current which flows in theformations adjacent to the hole resulting from differences in salinity between the drillingmud and the water in the formation. The SP can be plotted on a graph against depth, andinterpreted visually in order to demarcate reservoirs and clay overlays.
Resistivity logging is essentially used to calculate saturation levels of water, oil andgas. Depending on the type of mud used and the radius of investigation, different toolsare used to measure the resistivity of formations: induction, conventional resistivity or thelaterolog. 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 highernatural 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 allowgas, oil and water zones to be distinguished.
Sonic logging provides another means of evaluating porosity. It makes use of thedifferences in propagation time of a sound wave across the strata of a formation, this prop-agation being faster through dense than through porous rock. These data also allow thegeophysicist to establish a correspondence between the geological strata and seismicmarkers.
rate, the drainage methods adopted, the number and positioning of the wells, etc. The overalleconomic context (prices, taxes, etc.) and the circumstances of the company itself (financialresources) 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 arestudied by multidisciplinary teams comprising geologists, geophysicists, petroleum architects,drillers, producers and reservoir engineers. They also take account of the thinking of econ-omists 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 scenariosto be considered and tested with the help of simulation models, and their value in economicterms evaluated.
2.3 DEVELOPMENT AND PRODUCTION
If the appraisal stage demonstrates that the characteristics of the reservoir are sufficient tojustify production then the development stage begins. This involves drilling the futureproduction 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 thereservoir 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 thereservoir, its internal structure and the distribution of the fluids.
Petrophysical analyses based on logs and core analysis provide information on the capacityof the reservoir rock, i.e. its porosity and the possibility for the movement of the fluidsthrough 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 anestimate to be made of the total hydrocarbons present.
Studies of the fluids, referred to as PVT (pressure, volume, temperature) tests, are made inorder to characterise the physical and thermodynamic properties of the effluents, based onwhich the most appropriate production methods are determined.
Finally, well tests are carried out by measuring downhole pressure at the level of thereservoir before and during production. These provide information on the nature of thefluids, the drainage area of the well and the permeability of the formation. They also provideindications of the quality of the producing formation and the impact of the drilling on wellproductivity (skin effect). The producers deduce the optimum oil or gas production rate fromthese data.
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The downhole thermodynamic conditions and the composition of the hydrocarbons presentallow the reservoir to be classified according to the way the fluids will behave duringproduction. 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 initiallysingle phase liquids: the natural gas present in solution is released at the surface when theoil is produced. On the other hand if the oilfield originally contains both liquid and gaseousphases, the oil is described as being saturated and the free gas which is not dissolved in theoil resides in a gas cap (Fig. 2.15).
In the case of a single-phase gas field, the wet gases will generate, at the surface, conden-sates and dry gases comprising light fractions such as methane and ethane. In gas fieldssubject to retrograde condensation, liquid hydrocarbons will be deposited in the reservoirduring 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 wereformed from sediments which settled in or close to the sea. Part of the water will have beendisplaced during the migration of the oil, but some remains in the form of interstitial wateradsorbed as a film onto the rock around the pores. Water is also often found in reservoirsbelow the oil or gas, forming an aquifer.
Geologists and geophysicists begin by evaluating the volume of rock impregnated byhydrocarbons, the percentage of this volume effectively occupied by hydrocarbons and thedistribution between hydrocarbon types, in order to estimate the total tonnage. The reservoirengineer then estimates the reserves. Capillary forces within the reservoir make it impossibleto 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.
2.3.1.2 Recovery mechanisms
The reservoir engineer studies possible production levels, field life duration and the numberand types of wells, based on the characteristics of the field and its effluents, and draws upa development plan in collaboration with the petroleum architect.
At the outset of the development phase the information needed to define the functionalsub-systems is not always known sufficiently accurately for all the options to be determinedat 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 atthe surface. They flow from the reservoir into the well under the effect of the pressuregradient between the reservoir and the well bottom (Fig. 2.16). As production proceeds thepressure in the reservoir falls, thus reducing the natural flow rates of the hydrocarbons, andthe oil in particular.
In the case of gas fields natural flow through single phase expansion is the most effectiverecovery mechanism, allowing a recovery rate of about 80%.
For oil, primary recovery is less effective and may even prove very limited where thereis no effective source of energy such as the expansion of a gas cap, aquifer activity or theexpansion of dissolved gases. Where an oilfield has a gas cap, as oil is produced and thereis a consequential pressure drop in the oil zone, the gas cap expands, driving the oil into theproduction wells. There is considerable energy in the system, thereby allowing the oilfieldto produce for a long period of time, depending on the size of the gas cap. In addition, whenthere is a sufficient fall in the reservoir pressure, gas which was initially dissolved is freedin the oil mass, and entrains the oil towards the producing well. When a sufficiently largeaquifer lies under the oilfield, the pressure is maintained for as long as the water replacesthe oil in the pores during the production. In this case the wells go on producing until thewater production becomes excessive. Primary recovery typically allows from 5-10% to30-50% of the oil to be recovered.
B. Enhanced recovery
In most cases the volumes of crude oil extracted under primary recovery is not economicallyviable. It is therefore often necessary to resort to mechanisms for enhancing the recovery rateafter a production period which can vary.
A distinction is traditionally made between secondary recovery, which involves main-taining the pressure of the oilfield, and tertiary or enhanced recovery which refers to anumber of advanced methods which improve the displacement characteristics of the oil.
Secondary recovery is effected by means of water injection and gas injection, waterinjection being largely used. It involves either drilling injection wells or convertingproduction wells into injection wells. Water is then introduced into these wells underpressure. This both maintains the pressure in the oilfield by taking the place of the producedoil 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 sameprinciple, the fluid injected into the reservoir in this case being natural gas, nitrogen or fluegases from combustion, under pressure. This can be an attractive technique in desert, remoteor offshore areas where there is no market for natural gas and where flaring is forbidden.
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Well bottompressure (WBP)
Reservoirpressure
Atmosphericpressure
Wellheadpressure
The hydrocarbons are propelled from the reservoir to the surfaceby the pressure differences RP > WBP >WHP > AP
(AP)
(WHP)
(RP)
Figure 2.16 Principle of primary recovery.
Fewer injection wells are needed for gas than for water injection, but heavy compressionequipment is required (Fig. 2.17).
The injection of water or immiscible gas into an oilfield leads to recovery rates which arehigher (40–60%) but still limited because the flushing of the cavities in the reservoir isincomplete (macroscopic sweep efficiency) and because residual oil is trapped by capillaryaction in the flushed areas (microscopic sweep efficiency).
Tertiary recovery processes, known as EOR (enhanced oil recovery), make use ofchemical and thermal techniques, and seek to enhance the spacial sweep efficiency and toreduce the capillary forces by making the fluids miscible or improving their mobility. Theycan improve recovery by a further 5–10% of the total oil resources in the oilfield (Fig. 2.18).
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Waterinjection
Waterinjection
Gasinjection
Gasinjection
OIL PRODUCTION
Figure 2.17 Maintaining pressure by injecting water into the aquifer andgas into the gas cap.
The behaviour of the fluids during the production phase is carefully observed and analysedso as to ensure that production continues to be optimised.
Finally after a period of, typically, 15–30 years, the limits of economic recovery arereached. 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 analysethese data critically because of the large uncertainties attaching to the hypotheses in theexploration phase. The modelling phase proper involves interpreting the data in order toconstruct 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 threedimensions, and may be rectilinear, polar (around a well, for example), or irregular (inorder to show up heterogeneities, etc.). The parameters which characterise the reservoir mustbe defined for each cell (Fig. 2.19).
Equations are then added to this static model which describe the fluid flows betweenadjacent cells, and between cells and the well, in order to obtain a dynamic model. The finalstage consists of simulating the behaviour of the reservoir in time and space according todifferent production scenarios which are subjected to a range of economic calculations.Economic optimisation, using various hypotheses linked to the environment allows the mostappropriate development programme to be chosen.
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Water
WaterWater
Gas
Gas
OilOil
Oil
Oil
Oil-wateremulsion
GOC
WOC
Percentage oilrecovered R = 0% R = 50% R = 65%
OutsetAfter secondary
recovery(water injection)
After tertiaryrecovery(gas lift)
Oil
Figure 2.18 Oilfield at different stages of recovery.
Once the project has been approved, the site prepared, the production wells drilled andcompleted, and the gas collection, production, processing, storage and dispatch equipmenthave been installed and the living quarters built, production can begin.
Numerical simulation models are subject to continual improvement as production proceedsand knowledge about the field increases. Refinements made in the course of production allowmore 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 investmentdecision-making during the different stages of the life of the field.
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Box 2.2 Enhanced oil recovery.
Chemical methods involve adding chemicals to the injection water. There are twomain types: micro-emulsions and polymers. Micro-emulsions consist of mixtures of oil,water and surfactants, stabilised with alcohols. They enhance the displacement action ofthe 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 viscosityby a factor of 50 or more.
Thermal recovery involves increasing the temperature in the reservoir in order toreduce the viscosity of the oil and increase the productivity of the well. This can be doneeither by generating heat at the surface in the form of steam and transmitting it to theformation via an injection well, or by injecting air into the well and inducing in situcombustion or an oxidation front in the formation close to the injection well.
Miscibility methods promote thermodynamic exchanges between the oil in thereservoir and the fluid injected to reduce the capillary forces. The nature of the fluid tobe injected depends on the type of reservoir: carbon dioxide on its own or followed bywater, LPG under pressure, methane enriched with light hydrocarbons, nitrogen underhigh pressure. These methods may increase the recovery factor by 30% to 40%, but areconstrained by practical difficulties in the fields and economic considerations.
Figure 2.19 Grid representation of oilfield using Athos software.
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 aprecisely 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 hori-zontal, 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 evenbe used to access resources under the sea bed from an onshore location, thus avoidingthe need for offshore equipment;
– To enhance productivity, and therefore recovery; by draining a reservoir over a lengthof, sometimes, more than a kilometre, the oil flow rate can be increased, making itfeasible 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 producingwell (known as coning) which occurs with traditional drilling, which results in anexcessive 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 costmeans of delineating a field in unknown areas. The profitability of a production well isassured by the main wellbore drilled into a known reservoir (Fig. 2.21).
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Sidetracking
Offshore Drilling from the coast
Emergencyoperations
Multiple zones
Inaccessiblesite
Figure 2.20 Horizontal and directional drilling.
During production, multidrain systems multiply the number of wellbores and thereforeincrease production while reducing the development costs per barrel. Drilling multidrainsystems in existing wells in the depletion phase slows the rundown of mature fields bytapping into secondary reservoirs and allows a programme of water or gas injection to becarried out for optimal flushing of producing formations.
2.4.2 Completion
Completion involves making the well ready for production. It begins when the drillingphase comes to an end, when the last piece of casing has been cemented into place in theproducing formation. First of all a connection has to be made between the wellbore and thereservoir, by drilling into the reservoir, treating it, equipping the well and putting it intoproduction.
The equipment and methods used in well completion are quite varied, depending on thetype of effluent, the kind of reservoir, the requirements to be met by the well during itslifetime and the economic circumstances at the time of drilling. The completion must at leastensure the integrity of the walls of the hole and the selectivity of the fluid or production levelwhile 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 regulatedand the well to be put back into production.
Wellbore-reservoir connection
There are two types of wellbore-reservoir connection: cased hole completion and openhole completion.
Cased hole completion is the most common. After the reservoir formation has beendrilled the last piece of casing or liner is set and cemented in place. Perforations are thenmade at the level of the production zone to reestablish a connection between the reservoirand the well. These perforations must pass through the casing and the cement sheathingbefore penetrating the formation, which may then be subjected to stimulation treatments.
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Figure 2.21 Multidrain wells.
In open-hole completion the well is simply drilled into the reservoir, which produces inan open hole. A variant of this involves placing a pre-perforated liner against the wall of theformation, so as to maintain its general shape. This type of completion tends to be used whenthere is a single zone only which is either highly consolidated or where sand control by gravelpacking is adopted. In practice this procedure is rare for oil wells, but is sometimes appliedon gas wells.
Tubing
The configuration of the tubing mainly depends on the number of production levels andthe production selectivity sought.
In conventional completion, we generally use a tubing which is totally contained in thecasing string. Completion may be single or multiple. In the latter case production can takeplace at several levels selectively, allowing the field to be developed with fewer wells andtherefore more rapidly, but maintenance costs are higher.
It should be noted that that there is a type of completion where tubing is not used. Thisinvolves cementing and perforating a small length of casing in place at the level of theproduction zone. This is appropriate for small gas fields poor in associated liquids and at lowpressure.
Once the well has been completed, the wellhead is attached to the top so as to control theflow 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.
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Christmas tree
Casinghead
Tubinghead
Figure 2.22 The wellhead.
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 furtherlaboratory testing will reveal whether any treatment is necessary. The well is then put intoservice and evaluated. It will subsequently undergo measurements, maintenance, workoveror abandonment.
2.4.3.1 The drillstem test
The term drillstem test (DST) refers to all the well testing carried out during drilling. TheDST is basically a test intended to establish the production potential of a well and allow itto be characterised.
When a DST is conducted the well is temporarily completed and a special assembly islowered, equipped with various valves allowing the well to be shut off both at the wellbottomand at the surface, as well as pressure gauges. A sequence of periods of production and obser-vation is defined and the test involves continuously monitoring the pressure of the reservoirduring 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 obtainproduction data. This allows certain physical characteristics of the well to be derived, as wellas 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 thepetrophysical characteristics of the well, or because of damage caused by the drilling. Whenthe natural flow rate of the oil is weak, however, it can be improved by stimulation methodssuch as acidising or hydraulic fracturing.
Acidising consists of injecting acid which infiltrates the reservoir and dissolves some ofthe 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 reservoirrock by means of high pressure produced hydraulically. These cracks are then wedged openby 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 treatmentfacilities it is necessary to resort to activation, i.e. either gas injection or pumping. This isnecessary in more than three-quarters by number of wells worldwide, although these wellsprobably account for no more than 20% of world production. When there is an economicalsupply of gas and the quantities of oil justify the expense, a technique known as gas lift isapplied. Gas is injected into the fluid column in a well to lighten it and make it rise as a resultof the expansion of the gas. Depending on the production characteristics of the well and themanner in which the gas injection equipment is deployed, the gas can be injected continu-ously or intermittently.
Various different types of pump are used for conventional pumping:
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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 ofthe 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: wellservicing and workover. These are both intended to maintain or enhance output fromproduction 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 ofcorrosion, waxy hydrocarbons, etc. Well servicing also includes simple operations such ascleaning and sand control.
Workover includes more major repairs such as removal of sand which has intruded intothe 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 acontrol room.
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 andsometimes carbon dioxide, in varying proportions. The water from the well and other impu-rities must be removed before the hydrocarbons are stored, transported and sold. The functionof 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, waterand gas— by passing it through multi-stage separators. These are cylindrical installationsunder 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 theupper 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 whereit can be marketed. Watery emulsions must first of all be broken down with the help of ade-emulsifier which allows the water to coalesce into larger droplets which can be separatedmore easily from the oil. Inhibitors, solvents or heat are used to prevent the waxy hydro-carbons from precipitating out. And finally the oil is desalted by washing it in soft water. Itwill 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 butbecome progressively greater as production proceeds. It is imperative, for reasons at oncetechnical, ecological and economic, that this water is purified before being released into the
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Figure 2.24 Production facility.
environment or used in the production process. Firstly, all traces of oil must be removed andadded to the oil stream. The solids must then be removed so that the injection wells do notbecome plugged. The content of dissolved gases, particularly corrosive oxygen, must alsobe lowered. And finally, the sulphate-reducing bacteria in the water must be removed.
2.5.4 Gas treatment: sweetening and dehydration
The natural gas or associated gas from an oilfield often contains carbon dioxide, hydrogensulphide (H2S) and water. Depending on how the gas is to be used and transported, more orless processing is required, and it must be sweetened and dehydrated. Natural gas may betransported to the area where it is to be consumed by pipeline or may be liquefied and trans-ported in LNG tankers. The propane and butane fractions are known as liquefied petroleumgases, and are transported in special tankers. The natural gas can either be burned to produceelectricity or heat, or it can be reinjected into the oilfield as a means of effecting secondaryrecovery or gas lift.
Hydrogen sulphide is very toxic. If the gas is to be used commercially the hydrogensulphide must be completely eliminated. If it is to be liquefied, the CO2 content needs to bereduced, by chemical absorption, physical absorption or adsorption, in order to preventsubsequent crystallisation. If the gas has to be transported by pipeline for processing atanother 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 mole-cular sieve or by condensation. At high pressure and low temperature the traces of waterpresent in the gas can lead to the formation of hydrates which can accumulate and causeobstructions in the pipelines. But the formation of hydrates can be avoided by injecting ahydrate inhibitor such as methanol or diethylene glycol.
In offshore production these installation have to be located on platforms with a restrictedsurface area (Fig. 2.25).
The concept of hydrocarbon reserves, absolutely fundamental to the oil industry, is a complexone. In broad terms, the reserves are the total resources available to meet present and futureneeds. In order to anticipate demand, the size of these reserves needs to be known. Verybroadly 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:
– 1000 Gbbl of reserves already used;– 1300 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.
The proven reserves of gas remaining are 177 Tm3 (60 years of production at the presentrate), 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
3Hydrocarbon reserves
Figure 3.1 Breakdown of world’s ultimate oil reserves.
1000 Gb
1300 Gb
300 - 900 Gb
300 Gb
Consumed reserves
Reserves proven to consume
Reserves to be discovered
Enhanced recovery
a great deal about the hydrocarbons still in the earth’s crust. And even where we know ofthe existence of an oil- or gasfield, the reserves can rarely be recovered in their totality withpresent technology or given the policy on exploration practised by the states which own themineral rights. Furthermore even where technical and political conditions permit production,costs may be too high under present market conditions to permit their commercialexploitation.
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 affectedby the third. The price of crude greatly influences both the level of exploration activity andthe rate of technological progress. A high price means that it is profitable to recover hydro-carbons with higher production costs. A low price, on the other hand, excludes any possi-bility of investing in programmes whose economic viability is uncertain, such as high-riskexploration programmes or fundamental research. The three questions above behave likefilters, narrowing down the concept from that of hydrocarbons present in the ground to thatof economically recoverable quantities. They illustrate the difficulty of rigorously definingthe concept of reserves. In 1986, for example, the OPEC countries changed their definitionof reserves. Their estimates of proven remaining world reserves were increased artificiallybut considerably from 700 to 900 Gbbl without there being any real change in the globalstock of hydrocarbons.
In this chapter we shall begin (Section 3.1) by reviewing the definitions used by theindustry. We shall then go on, in Section 3.2, to specify the various types of hydrocarbonsextant and will look particularly at those referred to as “non-conventional”. Unlike so-calledconventional hydrocarbons (broadly, those that are easy to produce and market in today’sconditions) non-conventional hydrocarbons are at present unprofitable to produce, but couldbecome profitable in the future. This category includes, for example, ultra-deep offshoreresources, extra-heavy oils and synthetic petroleum. These resources, even though they maybe 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-conventionalhydrocarbons exist in quantities incomparably greater than the proven reserves of conven-tional hydrocarbons, and could therefore have a major impact on the oil industry in the futureproviding 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 willshow that hydrocarbon production curves are linked to the reserves in the relevantgeographical zones and allow the impact of technological progress in terms of creating newreserves to be shown. The study of production profiles has led many writers to try to forecastthe ultimate reserves and production rates by simple extrapolation. These theories can in factlead to two radically opposed visions of the future of hydrocarbons, corresponding to an opti-mistic and a pessimistic view. Energy experts armed with the same data disagree about theshort-term future of the oil industry. This debate rages on, and will be considered inSection 3.4 of this chapter.
And finally, in Section 3.5 we chart the main hydrocarbon-producing sedimentary basinsin the world, continent by continent, giving the reserves and production volumes for the mainproducing countries.
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3.1 DEFINITIONS
There are many different definitions of hydrocarbon reserves. The first point to note is thatthe term reserves denotes a technico-economic rather than a geological concept. A distinctionis 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 isidentical 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 andunder present economic conditions”. The widely used term “recoverable reserves” istherefore a pleonasm because broadly speaking the term “reserves” refers to hydrocarbonswhich 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 theyhave 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 geographicalzones are only partially open to exploration by the states which control them. The second istechnical: there are zones where the geological or geophysical exploration methods describedin Chapter 2 are not yet sufficient (for example ultra-deep offshore).
But there is a third barrier to resources becoming reserves: a technico-economic constrainton production. There are in fact many accumulations of hydrocarbons for which the tech-nology 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 crudeswhich are difficult to recover because their viscosity is too high, for example.
Technology is not the only obstacle to transforming resources into reserves. There areresources for which the extraction technology exists, but where the recovery cost wouldexceed the proceeds from selling the hydrocarbons extracted. Or, which boils down to thesame thing, the energy required to produce the hydrocarbons exceeds the energy content ofthe products. These resources would not be economically feasible, and would therefore notbe 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 andthe producing countries. Estimates of reserves may be intended to have a certain impact, andshould be viewed with caution. In fact estimates are beset by a lack of precision which isintrinsic 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 intoproduction within the short and medium term. Reserves are therefore hypothetical volumes
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because they are prone to various uncertainties and depend on variables such as technologicalchange, the economic climate, etc. The only reserves known with certainty, i.e. determinis-tically, are the reserves already produced. It is often said that the reserves present in a fieldare not known until production finally ceases. A deterministic approach assumes that thevalue of each parameter needed for the calculation is certain. It obtains an estimate whichis assumed to be totally reliable, not subject to an error margin. Any other approach tomeasuring the reserves in which there are uncertain parameters is necessarily speculative. Itprovides probabilistic estimates in the form of a range, or in statistical terms, confidenceintervals or, more precisely, prediction intervals.
Chapter 2 described the different stages in exploring and appraising an oil- or gasfield andthe uncertainties to which the results are subject. This approach produces a probability thata particular prospect does indeed contain hydrocarbons. This is a probability because the esti-mates of the uncertainties involved are themselves formulated by experts in the light of theirown experience, based on their own hypotheses. The probability estimates are thereforedescribed as subjective, or as a priori probabilities.
Once a formation has been declared to contain hydrocarbons, the total quantities ofhydrocarbons physically present (these figures are rarely published) are evaluated, and theassociated reserves are estimated. To do this it is necessary to evaluate the ratio of the recov-erable hydrocarbons to the total quantity of hydrocarbons in the reservoir. This quantity isknown 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 distrib-ution function. Because of the uncertainties in the measured values it is meaningless to saythat the reserves in a field are 100 million barrels (Mbbl). What can be said is that there isa certain probability that its size exceeds 100 Mbbl. The size distribution of a particular fieldis generally reasonably well represented by a lognormal distribution (see Fig. 3.2)1. Inpractice the reserves are represented by providing a number of the parameters of thelognormal distribution (the mean or a number of percentiles: 10%, 50%, 90%, etc.) whichis supposed to represent the size of the field.
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Tableau 3.1 From resources to reserves (by kind permission of Jean-Noël Boulard).
R Accessibleto exploration
Identified Production technically
feasible
Economically RES ERVESE viable
S O
viableUProduction notR
technically feasibleCNot identifiedE
SNot accessible
to exploration
➀
②
➂
④
Not economically
1. There is however a debate on this matter. The main weakness of the lognormal distribution is that it doesnot represent small fields well, and in some cases completely misrepresents them.
3.1.3 P90, P50, P10, etc.
Px is defined as a number such that there is an x% likelihood that the true reserves exceedPx. For example if the P10 of a field is 100 Mbbl, there is a 10% probability that the actualsize 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 andP95 respectively, or P10 and P90. These are misleading terms, because the true minimumand maximum of the lognormal distribution are 0 and +∞. The mode is the theoretically mostlikely value of the distribution. The mean (or expected value) would be the average valueobserved for a large number of fields whose size is characterised by precisely the same apriori probability distribution. Figure 3.2 shows a typical lognormal distribution for a fieldfor which the P50 is 500 Mbbl. The curve shows, for any x, the size for which the proba-bility 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 thepercentile approach, and which also provide a probabilistic evaluation of the reserves in afield. These values correspond with the Px in a manner depending on the company or writerconcerned:
– 1P is generally equal to the P90 or P95 described above;
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Figure 3.2 Lognormal distribution function modelling the size of anoilfield.
– 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 orig-inates 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 aremany exceptions, to the values 1P, (2P – 1P) and (3P – 2P). Or putting this the other wayround:
It should be noted that these definitions were formulated and officially adopted in 1997by 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 nomeans universally accepted, and are contested by some in the oil community. When figuresare quoted, they usually refer to the proven reserves. However does that mean P95, P90 orsomething else? It is almost impossible to answer this question properly, and often thevagueness is intentional on the part of the users. Examples can still be found where figuresgiven for “proven reserves” may mean an unspecified value between P50 to P98. Cautionis 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 morewidespread. 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 arriveat the reserves for an entire basin or country. This is because the figure obtained by summingtogether the Px (or the modes) of the reserves for a number of fields is not generally equalto 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 tendsto 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 reserves3P of the entire basin. In the case of 2P the error can go either way. Furthermore whetherthey are an overestimate or an underestimate is a random process.
The only estimates which can legitimately (in mathematical terms) be summed togetherare 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 aforecast to be made. However it is important to realise that the mean only proves to beeffective when used a large number of times: taking Fig. 3.2 as an example, the expectedvalue of the distribution will only be achieved in 15% of cases. In concrete terms this meansthat if several fields have this distribution, only 15% of them will turn out to have reservesgreater than the mean of the distribution! But it should be noted that the sum of the actualreserves of the fields will be close to the number of fields multiplied by the expected value
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of the distribution. This apparent paradox results from the law of large numbers, which statesthat deviations from the mean will tend to cancel one another out, i.e. that the mean of thedeviations will tend to zero. It is therefore just as crucial to know the standard deviation (thequadratic mean of deviations from the expected value). This information allows predictionintervals to be constructed. But it should be borne in mind that the size distributions of hydro-carbon fields are characterised by large standard deviations, giving extremely wide predictionintervals.
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 obtainorder of magnitude estimates of the reserves at a more macro level (region, country, fieldsowned by an oil company). Usually only the proven reserves are published. These thereforeprovide the only data available for statistical studies. Although summing them arithmeticallymay 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 non-conventional hydrocarbons. We will not deal with the case of condensates —light liquidssometimes associated with natural gas— because these reserves are generally included in thefigures for the gas reserves, except, usually, in the U.S. and Canada. It should be notedhowever that condensates account for up to 20%, in terms of energy content, of the reservesof 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 conven-tional 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 ofsulphur 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 (whichaccount for two-thirds of present world gas reserves). Whether a particular gas deposit isconsidered conventional or not depends on how difficult it is to extract and put intoproduction.
Colin Campbell, Alain Perrodon and Jean Laherrère (1998) regard conventional hydro-carbons as being hydrocarbons which can be produced in the technical and economic condi-tions of the present and the foreseeable future. This definition, which is very close toMcKelvey’s definition of proven reserves (see Section 3.1), allows however for technologicalprogress and future economic circumstances. Non-conventional hydrocarbons thereforebecome, 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 bein the future. The impact of a new technology on the extraction of hydrocarbons can bemeasured 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 offshorehydrocarbons situated in water at a depth greater than 200 metres were considered non-conventional (and therefore not included in estimates of proven reserves). The technologyof the time was simply not able to put these resources into production profitably. Nowadays
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we commonly envisage producing from reservoirs in depths of water 5 or 10 times as great,i.e. at depths of 2000 metres. The boundary between conventional and non-conventionalhydrocarbons has retreated considerably over time.
Heavy and extra-heavy hydrocarbons furnish another example. The Orinoco basin inVenezuela, 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 of693 Gbbl (i.e. equivalent to more than half of the world’s proven reserves of conventionaloil). The position in 1967 was therefore: resources = 693 Gbbl, reserves = 0! A new evalu-ation in 1983, however, estimated the resources to be 1200 Gbbl and the reserves (these werestrictly 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-conventionaltends to be pushed back over time in the direction of hydrocarbons which are more and moredifficult to produce in terms of production conditions, situation, quality and overall, in termsof extraction costs. However geopolitical factors also come into play, modifying this picturesomewhat. 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 andcommercial production of less accessible petroleum throughout the world. The oil which ischeapest to produce is therefore no longer necessarily the only or even the first resources tobe exploited.
Non-conventional hydrocarbons are therefore the reserves of the future. This shifting ofthe boundary is referred to by some authors as the fossil carbon continuum. When thereserves of a certain type of hydrocarbon which can be produced are exhausted, other typesare sought, including non-conventional hydrocarbons. Gradually, and with the help of tech-nological progress and political exhortation, the production of these new hydrocarbonsbecomes the norm, becomes conventional or “conventionalised”. We have therefore grad-uated from oils in the U.S., Algeria and the Middle East which are easy to produce, tooffshore, 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-sectionsbelow.
3.2.2 Deep and ultra-deep offshore
A distinction is generally made between deep offshore (between 400 meters and 1500 meterswater depth) and ultra-deep offshore (up to 1500 meters). The former can nowadays be easilyaccessed, 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 andUnited States. Today, most of the production comes from the Gulf of Mexico but the growthis 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 itis referred to as extra-heavy. Many of these deposits are referred to as oil sands. These
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2. Term referring to large and abrupt changes of price, see Chapter 1.
substances are genuine petroleum, having passed through the entire cycle which characterisesthe formation of petroleum. They originate from hydrocarbons expelled from a source rockinto a reservoir (generally sand), often very large in size. Long oxidation and the gradualdisappearance 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 WesternCanada and the Orinoco belt in Venezuela.
The total resources of these oils are considerable: of the order of 4700 Gbbl, i.e. four timesthe proven reserves of conventional oils! More than one-third (1700 Gbbl) of these resourcesare found in Canada, with 870 Gbbl in Athabasca alone. Russia may have 1500 Gbbl ofheavy oil resources, although the official statistics do not indicate the densities involved,which makes classification risky. After Russia, Venezuela possesses 1 200 Gbbl in theOrinoco belt. The U.S. and Indonesia also have large resources.
Oil sands have so far remained within the domain of non-conventional oils, despite thevast resources involved. Today, only 5% of these resources appear to be economicallyviable. By 2025–2035 the recovery ratio may have reached a threshold of 15–20%, wherebyoil sands could be regarded as a conventional hydrocarbon.
3.2.4 Oil shales
Oil shales are not oils in the same way as the aforementioned hydrocarbons. They do notoriginate from the migration of oil from source rock to a reservoir, but remain in the sourcerock. The source rock is usually a clayey sedimentary rock which can produce oil after under-going crushing and pyrolysis at a temperature of about 500°C. The production of oil fromshale requires heavy industrial installations. Shale can claim a first in petroleum history: atthe beginning of the 20th century there were numerous sites where shale was quarriedthroughout the world. These shales produced surface outcrops which were of courseexploited. At a time when petroleum geology was virtually non-existent, no exploration wasneeded to find these deposits.
Shale can be found on all five continents, as can be seen from Table 3.2, but the largestdeposits 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 additionalenvironmental 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 usethe entire flow of the Colorado river in order to produce commercially from the Green RiverCanyon shales.
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Table 3.2 World resources of oil shales (Gbbl).
US South Australia Africa Former USSR AsiaAmerica (unofficial) (unofficial)
200Resources 2200 800 (of which 20 of 115 1400 2800
Stuart shale oil)
3.2.5 Synthetic oils (Fig. 3.3)
The Fischer-Tropsch process for converting gas or coal into synthetic oil was developed inGermany during the second world war (see Chapter 1), where it was the only source of motorfuel. The process remains a difficult one. The market for synthetic oil produced from gas couldgrow. Until recently, there were only a few units which convert gas into oil —a productioncapacity of 100 kbbl/d from 30 Mm3/d of gas— notably in Malaysia (Shell experiment) andSouth Africa (a remnant from a boycott by producing countries provoked by the policy ofapartheid. Things have changed with the new market conditions based on a higher crude oilprice. New projects are now under consideration. In the Pearl Gas to Liquids project, Shell andQatar Petroleum are investing hugely to build two 70 kbbl/d trains dedicated to convert gas intooil. China has turned its attention to coal liquefaction technology. In 2004, Shenhua Group, thecountry’s largest coal producer, was assigned a project to build a coal liquefaction plant innorthern China. The first phase is intented to bring on stream annual production capacity of 1Mtoe 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 inChina (feasibility studies are conducted for two 80 kboe/d plants) and in the US (in Montana,Illinois and Wyoming).
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3.2.6 Non-conventional gas
The resources of non-conventional gas are thought to be considerable, but are not yet wellcharted. Reservoirs of non-conventional gas are characterised by low recovery rates: of theorder of 10–20%, against about 80% for conventional gasfields. These are reservoirs in whichthe 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 USresources 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
Figure 3.3 Possible applications of the Fischer-Tropsch process.
as to the uncertainty attaching to the estimates. Production remains limited but is growingsignificantly in the US —where 45 Bcm were extracted in 2004— and in China where10 Bcm could be produced in 2010.
Tight gas sand reserves figures remain unknown. Canada estimates vary in the range2.5–42 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 isprobably 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 (forexample 17 m3 per m3 of water at a depth of 6000 m and up to 170 m3 at 10000 m). Becauseof the sensitivity of the calculation to the conditions within the trap, estimating the resourcespresent can be a perilous undertaking, and the figures which follow are of a highly specu-lative nature. Russia has estimated that its resources are 1000 Tm3, and U.S. estimates varyin the range 30–200 Tm3 (including 150 Tm3 for the Gulf of Mexico alone). In the early1980s an estimate of 1000 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..
3.2.7 The polar zones
Several fruitful exploration programmes have been carried out in the Arctic, and these haveidentified some 10 basins with real potential. Most of these basins are in Alaska, Greenlandand Russia, the latter looking the most promising. In the Arctic as a whole, resources of8 700 Gbbl of oil and up to 20 Tm3 of gas have been discovered. However the fieldsconcerned probably contain much more gas than has been announced. It should not beforgotten when considering these figures that production of these resources will be particu-larly difficult given the very harsh climate, the ice cover, the lack of infrastructure and theremoteness of the site from existing markets.
The Antarctic, on the other hand, looks very much like being the poor relation of itsNorthern counterpart. The geology of Antarctica seems unpropitious for the discovery ofsignificant deposits of oil. Furthermore, quite apart from the difficulties associated with theextreme climate and inaccessibility, all industrial activities on this continent have beenforbidden 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 verymany such fields. But their small size makes them difficult to find. Furthermore thereneeds to be pre-existing infrastructure nearby. Development costs must be kept low if verysmall fields are to be remotely profitable.
• Oils won by assisted recovery techniques are themselves sometimes treated as beingnon-conventional products, although most of these techniques are becoming standard.
• High-pressure, high-temperature (HP-HT) reservoirs are subject to the same kind ofinconsistencies because the various record-keeping agencies do not use the same pressureand temperature criteria (these vary around 700 bar and 150°C) for classification. This
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means that fields with the same pressure and temperature characteristics may sometimesbe classified as conventional and sometimes as non-conventional.
• Gas hydrates are very important potential sources, and some authors consider that these mayexceed in magnitude the total known reserves of hydrocarbons. These are gases in a solidform which occur in the form of crystalline hydrates. It is impossible to say now whetherwe will one day be able to transform these resources into reserves. Two hurdles will haveto be overcome to make the production of these substances viable: their low energy densityand 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 hydro-carbons produced. This self-evident statement illustrates the extent to which the concept ofreserves is economic in nature.
However the circumstances for gas are rather different from those of oil. At present andallowing for existing rates of consumption the reserves of gas will outlast those of oil (about65 years, against 40 years for oil). Furthermore it is generally agreed that gas production willpeak (point at which production begins to decline) later than oil production. The demand forgas, although real and considerable, is therefore less sustained than that for oil products, orto put it another way, in consuming energy we tend to give priority to the most economicoption (at present oil), with their wide variation in energy content. It should be rememberedin this connection that gas is 5 times as costly to transport as oil. The oil market is rathermore 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 coalmarket. In practice there are very many extremely large known gasfields which will probablynever be put into production.
At the present rate of production, coal reserves will last more than 160 years. This statisticis difficult to interpret, however, because it seems very likely that two centuries from nowcoal will have all but disappeared as a source of energy. This means that some of thesereserves will deliberately not be exploited. This being the case, these latter should be clas-sified 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 marketfor it.
In the two succeeding sections we will consider how reserves are estimated, andproduction 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 plottedagainst time. A production profile can be prepared in the same way for a well, a field or acomplete geographical zone by the same process as that applying to a petroleum system, abasin or a country. The profile can be descriptive (i.e. historical data) or predictive. Predictiveprofiles are usually constructed for a well or a field once the production tests have beencompleted. Two theoretical examples are given below which are typical of productionprofiles for an oil —or gasfield. The field reserves are represented by the area under the curve
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which defines the production profile. The preparation of a predictive production profiletherefore 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 smalland large fields. Small fields (Fig. 3.4) exhibit a very steep rise in production and are rapidlyexhausted, so as to reduce the production costs by concentrating them over as short a periodas possible. Conversely, the production profile of a large field (Fig. 3.5) tends to be morespread out in time. After an initial testing period it climbs steeply to reach a productionplateau which is maintained for a number of years, depending on the size of the field. Thedecline in production as the field becomes depleted is generally slow.
It can be seen that production profiles tend to be very asymmetric around their productionpeak (or maximum). When, however, production profiles are summed to give estimates foran entire basin or country, the aggregated curve is often symmetrical about its peak, with arather bell-like shape. This fact was first applied by King Hubbert at the end of the 1950sto forecast the peak and decline of oil production in the U.S. But is this forecasting methodof universal applicability?
Around 1960, King Hubbert, then an engineer at Shell, forecast, by fitting a normal curveto 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 forecastof the peak proved correct to within a year. This success won its author great acclaim andrecognition from his peers. There are various Internet sites which promote the work ofHubbert and his disciples. However the fact that his theory was vindicated for one particularexample does not mean that his model has been validated generally. An entire school of fore-casting has been erected on this solecism.
The object of this section is not to refute Hubbert’s conclusions or methodology but ratherto 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 ofa method of forecasting production (and therefore also the ultimate reserves). As we arguein Box 3.1, it is legitimate to make some criticisms of the tendency to force everything intoa normal distribution; there are many regions in the world, including the U.S., where aggre-gated production profiles are not distributed normally, or even symmetrically.
A model of this kind makes time the only explanatory variable for the production of aregion. 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.
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Box 3.1 Hubbert and mathematics.
Even if, in several regions of the world, production profiles are found to be distributednormally, 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 “math-ematically”. One such attempt, tenacious and false, appeals to one of the most celebratedtheorems of probability theory: the central limit theorem. This states that under certainregularity hypotheses the sum of a large number of independent random phenomena(even if highly asymmetric or multimodal) tends to produce a random variable with anormal distribution, that is, symmetrical with a bell-shaped distribution, like that used inthe Hubbert approach: the distribution function of the sum of the processes is close tobeing normally distributed. But the probability density of the sum is not equal to the sumof the probability density (in this case the production profiles of the fields). Furthermorethe Hubbert phenomenon does not fall within the scope of this theorem. In the first placethe production profiles summed are obviously not independent of one another, particu-larly when they relate to the same geographical zone, and secondly the theorem relatesto 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 appealingit may seem on the basis of a few examples, has no scientific basis. If certain aggregatedprofiles exhibit the characteristics of the normal distribution, these are curiosities, the realreason for which it would be very interesting to explore, rather than a phenomenon ofgeneral applicability as claimed by Hubbert and his numerous followers. Hubbert himselfended up by repudiating the normal curve in favour of the logistic curve which unfortu-nately is no more justified than the normal curve.
3.3.4 The impact of technical progress on the production profile
A profile is usually constructed when production commences, once the production tests havebeen completed. Post mortem profiles, i.e. those which can be drawn when productioncomes to an end, are often very different from those initially envisaged, however. Thisdifference is usually caused by technological progress, which may increase the reserves(Fig. 3.7) or permit their accelerated production (Fig. 3.8).
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Figure 3.7 Effect on initial production profile(mauve) of the creation of reserves due to tech-nological progress (grey).
Figure 3.8 Effect on initial production profile(mauve then white) of the acceleratedextraction of reserves due to technologicalprogress (grey).
The two scenarios presented below show the impact of an assisted recovery technique putinto 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 increasein 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 corre-sponding to the original production profile), but simply an acceleration in the extraction ofthe existing reserves. Production comes to an end 10 years earlier, without any loss in thetotal reserves extracted. Although there is no increase in the reserves, the acceleration is defi-nitely economically advantageous for the producer as it allows him to avoid a long periodof run-down and to receive the revenues earlier.
There are many examples of both cases. The Alwyn field in the North Sea is a textbookexample of the first scenario. A variety of measures were taken resulting in a succession ofsignificant increases in the reserves. A number of writers have identified numerous examplesof the second scenario.
The second model of technological progress takes a pessimistic view about reserves. Inrelation to conventional oil, technology simply accelerates depletion and therefore hastensthe onset of scarcity.
As already mentioned earlier, there are two schools of thought in relation to ultimatereserves. The object of the next section is to present both sets of arguments so that the debatecan be properly understood.
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There are many indicators commonly used in the petroleum industry, either at companylevel or for the entire sector. These may have a warning function, may be for generalmanagement purposes or to signal scarcity.
R/P
The first and most widely used indicates the outstanding life of the reserves at the presentrate of production assuming that no further discoveries are made: it is the ratioreserves/production, often indicated by R/P. It is expressed as a number of years. The ratio hasfluctuated considerably over the years, as the following table shows:
Since 1970, when it appeared that oil would be exhausted by 2000, the outstandinglife 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 thecompanies, 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 thatthis ratio is very sensitive to the definition of reserves adopted. In 1986 the method usedin the Middle East to evaluate reserves changed, leading to a substantial rise in the R/Pratio.
Success rate
This indicator, used by the upstream petroleum industry, is the ratio of non-dry wellsto the total number of wells drilled. It is therefore, at the company level, a measure of itssuccess in exploration. However this index must be interpreted cautiously. A non-dry wellwhich discovers reserves of 1 million barrels is obviously not equal in value to onewhich discovers reserves of 1 billion barrels. The ratio should therefore reflect the sizeof the reserves involved; a high success rate in a region where the reservoirs are small isof no great interest to the company. The success rate nevertheless provides a measure ofthe effectiveness of exploration. Its value has climbed over the last 30 years, from 1/10to 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 inthe field. It varies with time, along with the estimates of reserves and resources. Averagerecovery factors for conventional hydrocarbons are at the moment 30–40% for oil and80% for gas. One of the ways of increasing reserves —the other being exploration— isto increase this percentage by taking advantage of technological advances. This is some-times referred to as field growth. The recovery factor is often used as a criterion to distin-guish between conventional and non-conventional hydrocarbons, particularly for gas. Asfar as heavy oils are concerned, recovery factors are of the order of 10% or less. Thereis obviously great scope for improving these rates, and nowadays reserves are mainlycreated by increasing the recovery factor from deposits of non-conventional hydrocarbons.
Box 3.2 Indicators used in the upstream petroleum industry.
50′ 70′ 80′ 90′ 00′
Oil 150 30 35 40 40Gas 50 55 60 63
3.4 OPTIMISTS AND PESSIMISTS
It was seen in the previous section that the forecasting of reserves is particularly importantfor the petroleum industry. There are several theories in this area, and these lead to schoolsof 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 pessimistsinto a debate between the defenders of the validity of this or that index (see Box 3.2). Never-theless linking the various views with the behaviour of the indices allows ideas to be putinto perspective.
The R/P ratio is increasing over time, which appears to indicate that the point in time whenstocks will become depleted, already distant, is receding still further. Furthermore the successrates announced by the industry tend to increase over time, indicating that explorers arefinding 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, whoargue that these indicators are biased: the R/P ratio does not represent the actual number ofyears of reserves because production is increasing regularly by 2–3% per year, while oilfielddiscoveries are becoming less frequent. R/P is therefore an over-optimistic indicator. Thisindex continues to enjoy very wide use in the petroleum industry, however, and will continueto be used regardless. It is incumbent on the analyst to be aware of the bias inherent in thisratio and interpret the figures accordingly. Similar remarks apply to the “success rate” forexploration, which by definition only allows for numbers of successes, and is not weightedby the size of the finds. It therefore also remains a relative and biased indicator of explo-ration performance (see Box 3.2).
But the optimistic and pessimistic theories, the main arguments for which are summarisedabove, draw on two opposing economic theories.
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Figure 3.9 In a closed market falling pricesstimulate demand until signs of scarcity begin toappear, when prices rise again, thereby reducingdemand.
Figure 3.10 In an open market three types ofenergy are competing. Prices fall as the currentenergy type is progressively substituted by lesscostly alternatives (here NRJ 1 is substituted byNRJ 2 and then NRJ 3). This process is knownas economic reproduction.
Price
Price
Time
There are several theories of exhaustible resources, particularly Hotelling’s theory, forwhich the reader is referred to Chapter 1. The following comments appeal to the law ofsupply and demand.
Let us assume that the oil market is a closed market, that is, we only have to consider theresource itself; there are no interactions, for example substitutions with other types ofresource. The depletion of the resource due to its consumption will lead inexorably toincreases in its price (Fig. 3.9), in accordance with the law of supply and demand. Converselywhen a market is open, other types of resource which are potential substitutes offer compe-tition. This competition ensures that as a resource is gradually depleted there will be a tran-sition, over time, to new sources of energy. This progressive substitution serves to stabiliseor even reduce the market price over time (Fig. 3.10). This phenomenon is sometimesreferred to as economic reproduction. Resources are depleted in physical terms, but thereserves reproduce themselves in an economic sense.
These are the two sets of ideas which oppose one another, corresponding to the views ofthe pessimists and the optimists.
The pessimists
Given that the quantities of sub-surface hydrocarbons are finite, each quantum consumedbrings the exhaustion of reserves closer. In fact, production and consumption are growingover time (in particular because of demographic growth). The pessimists regard this devel-opment as unsustainable, being liable to lead to shortages, and therefore sharp increases inprice.
Many scientists, industrialists and ecologists fervently espouse the pessimistic view, regu-larly predicting the peaking and decline in the production of hydrocarbons, because for anumber 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 shortagesand an artificial reduction in supply. During the 1970s the economies of the industrialisedcountries were very dependent on oil. A reduction in the reserves therefore contributed tothe very large increase in the prices of hydrocarbons, in accordance with the law of supplyand 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&Defforts in order to devise new techniques which would render feasible certain activitieswhich had hitherto been marginal, such as nuclear energy or the extraction of certain non-conventional oils.
Despite these efforts, economies remain largely dependent on the production of existingconventional hydrocarbons. The pessimists tell us that despite the technological advancesmade 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 ofthe expected increase in prices to materialise. There is of course no denying the fact that thereserves of conventional hydrocarbons, finite in quantity, are being consumed. However oilprices remain stable over the long term. The vaunted price rises have not happened. This can
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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 forhydrocarbons in hitherto unexploited zones in the world.
be interpreted as a refusal by the markets to accept that the shortages proclaimed by thepessimists are imminent. As described in Section 3.2.1, there has been a gradual substitutionof conventional by non-conventional oils which can now be commercially produced, inaccordance with the concept of the fossil carbon continuum mentioned earlier (inSection 3.2.1). Furthermore the two oil price shocks in the 1970s encouraged the emergenceof new energies (particularly nuclear energy) and new technologies which allowed certainnon-conventional oils to be made commercial. To the proponents of this view, petroleumappears to be characterised by the open market model (Fig. 3.10) in which the process ofeconomic reproduction is taking place, rather than the closed market model. Furthermore thismodel is in keeping with the present trend towards economic liberalism.
However economic reproduction will only occur if technology is successful in developingnew types of energy. We saw in Section 3.3.4 that technological progress can be an agentfor accelerating depletion rather than a catalyst for economic reproduction. But the risk ofdepletion should be reflected in a perceptible increase in prices, whereas no such increasecan yet be detected.
The argument between the two camps appears to reduce to a confrontation between acommon sense, “naturalistic” view that if an exhaustible resource is consumed it will becomescarcer, and the partisans of progress and economic liberalism, the openness of markets andthe theory of economic reproduction which stems from it. Does this mean that naturalistsare essentially pessimists, and economists optimists?
3.4.2 Naturalists or economists?
Whatever one’s point of view, the conclusion for the long term remains the same: energypolicy 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 exploitedbecause they were not economically feasible (e.g. non-conventional). In both cases there mustbe energy substitution, economic reproduction. The vision of the pessimists differs from thatof the optimists, however, in that it assumes that a very active posture, and the building ofpublic awareness of the impending shortages and risk of sharp price rises, are needed to nego-tiate the transition to the new energies. The optimists, on the other hand, believe that the tran-sition to the new energies will occur naturally (as implied by the concept of the fossilcarbon continuum) as a result of technological progress and market forces such as thecompetition 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 industryis supported by many concrete and incontrovertible examples. On the other hand the opti-mists can also produce evidence suggesting that the petroleum industry has been able to adaptto change through revolutionary technologies which have made it possible to commercialisehydrocarbons which were previously ignored or whose existence we were unaware of. Thishas 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), areclose to 2500 Gbbl. This figure is very different from the estimate of several tens of thou-sands of Gbbl of non-conventional resources mentioned in Section 3.2. Furthermore these
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speculations may rage, but as we saw, in the medium to long term both camps ultimatelyagree 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 tran-sition will come about: through an abrupt increase in prices for the pessimists or as an orderlyand 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 mapshowing the most important producing sedimentary basins. All the data quoted are taken fromthe BP Statistical Review 2007. The maps are adapted from the USGS World PetroleumAssessment.
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Table 3.3 Proven reserves and annual production worldwide.
Table 3.4 Proven reserves and annual production, North America.
Proven Annual R/Preserves production
(Gbbl) (Tm3) (Mbbl) (Gm3) (years)
United States Oil 29.4 2511 11.7Gas 6.0 545.9 11.0
Canada Oil 27.7 1208 22.9Gas 1.6 183.7 8.9
Mexico Oil 12.2 1269 9.6
Gas 0.4 46.2 8.0
Total Oil 69.3 4988 13.9
Gas 8.0 775.8 10.3
C A N A D A
U N I T E D S TAT E S
M E X I C O
Offshore sedimentary basin
Onshore sedimentary basin
Figure 3.11 Main sedimentary basins in North America (excluding U.S.).
3.5.2 South America
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Table 3.5 Proven reserves and annual production, South America.
Proven Annual R/Preserves production
(Gbbl) (Tm3) (Mbbl) (Gm3) (years)
Argentina Oil 2.6 255 10.2Gas 0.44 44.8 9.8
Brazil Oil 12.6 669 18.8Gas 0.36 11.3 31.9
Trinidad Oil 0.8 56 14.2& Tobago Gas 0.48 39.0 12.3
Venezuela Oil 87.0 954 91.2Gas 5.15 28.5 > 99
Other Oil 8.2 487 16.8Gas 1.33 27.2 48.9
Total Oil 111.2 2421 45.9
Gas 7.76 150.8 51.5
Figure 3.12 Main sedimentary basins and hydrocarbon producing countriesin South America.
Offshore sedimentary basinOnshore sedimentary basinMain producing countryOther countries
3.5.3 Europe
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Table 3.6 Proven reserves and annual production, Europe.
Proven Annual R/Preserves production
(Gbbl) (Tm3) (Mbbl) (Gm3) (years)
Norway Oil 8.2 933 8.8Gas 3.0 89.7 33.0
Netherlands Oil – – –Gas 1.2 64.5 19.4
United Kingdom Oil 3.6 597 6.0Gas 0.4 72.4 5.7
Other Oil 4.5 363 12.4Gas 1.1 48.3 22.6
Total Oil 16.3 1893 8.6Gas 5.7 274.9 20.8
Figure 3.13 Main sedimentary basins and hydrocarbon producing countriesin Europe.
Offshore sedimentary basinOnshore sedimentary basinMain producing countryOther countries
NORWAY
UNITEDKINGDOM Netherlands
3.5.4 Africa
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Table 3.7 Proven reserves and annual production, Africa.
Proven Annual R/Preserves production
(Gbbl) (Tm3) (Mbbl) (Gm3) (years)
Algeria Oil 12.3 730 16.8Gas 4.5 83.0 54.5
Angola Oil 9.0 629 14.3Gas – – –
Egypt Oil 4.1 259 15.8Gas 2.1 46.5 44.3
Libya Oil 41.5 675 61.5Gas 1.5 15.2 99
Nigeria Oil 36.2 860 42.1Gas 5.3 35.0 > 99
Other Oil 14.4 613 23.5Gas 1.2 10.7 > 99
Total Oil 117.5 3766 31.2Gas 14.6 190.4 76.6
Offshore sedimentary basinOnshore sedimentary basinMain producing countryOther countries
Angola
Nigeria
Algeria LibyaEgypt
Figure 3.14 Main sedimentary basins and hydrocarbon producing countriesin Africa.
3.5.5 Middle East
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Table 3.8 Proven reserves and annual production, Middle East.
Proven Annual R/Preserves production
(Gbbl) (Tm3) (Mbbl) (Gm3) (years)
Iran Oil 138.4 1606 86.2Gas 27.8 111.9 > 99
Iraq Oil 115.0 783 > 99Gas 3.2 – > 99
Kuwait Oil 101.5 958 > 99Gas 1.8 12.6 > 99
Qatar Oil 27.4 437 62.7Gas 25.6 59.8 > 99
Saudi Oil 264.2 3801 69.5Arabia Gas 7.2 75.9 94
United Arab Oil 97.8 1 064 92Emirates Gas 6.1 49.2 > 99
Other Oil 11.0 540 20.4Gas 1.6 45.6 35.1
Total Oil 755.3 9190 82.2Gas 78.2 355.0 > 99
Offshore sedimentary basinOnshore sedimentary basinMain producing countryOther countries
I r a nI r a q
Kuwait
Qatar
United ArabEmirates
S a u d iA r a b i a
Figure 3.15 Main sedimentary basins and hydrocarbon producing countriesin the Middle East
3.5.6 Former USSR
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Table 3.9 Proven reserves and annual production, former USSR.
Proven Annual R/Preserves production
(Gbbl) (Tm3) (Mbbl) (Gm3) (years)
Azerbaijan Oil 7.0 317 22.1Gas 1.3 10.3 124,3
Kazakhstan Oil 39.8 544 73.2Gas 1.9 27.3 69,6
Russian Oil 79.4 3642 21.8Federation Gas 44.6 607.4 73.5
Turkmenistan Oil 0.6 72 8.3Gas 2.7 67.4 39.6
Uzbekistan Oil 0.6 42 14.4Gas 1.7 58.5 29.7
Others Oil 2.1 166 12.6Gas 0.4 11.0 39.1
Total Oil 129.5 4783 27.1Gas 52.7 781.9 67.4
Offshore sedimentary basinOnshore sedimentary basinMain producing countryOther countries
R U S S I A N F E D E R A T I O N
Figure 3.16 Main sedimentary basins and hydrocarbon producing countriesin former USSR.
3.5.7 Asia–Oceania
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Table 3.10 Proven reserves and annual production, Asia-Oceania.
Proven Annual R/Preserves production
(Gbbl) (Tm3) (Mbbl) (Gm3) (years)
Australia Oil 4.2 205 20.5Gas 2.5 40.0 62.8
China Oil 15.5 1366 11.3Gas 1.9 69.3 27.1
India Oil 5.5 292 18.8Gas 1.1 30.2 35.1
Indonesia Oil 4.4 354 12.4Gas 3.0 66.7 45.0
Malaysia Oil 5.4 276 19.6Gas 2.5 60.5 41.0
Others Oil 5.8 393 14.8Gas 3.5 124.8 28.3
Total Oil 40.8 2886 14.1Gas 14.5 391.5 36.9
Offshore sedimentary basinOnshore sedimentary basinMain producing countryOther countries
Australia
India
China
Malaysia
Indonesia
Figure 3.17 Main sedimentary basins and hydrocarbon producing countriesin Asia-Oceania.
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4.1 INTRODUCTION
Due to the role of energy in the global economy, oil is a crucial global commodity, with aworld market of more than $2.0 trillion per year. Investment in oil and gas exploration andproduction is very high, amounting every year to more than $300 billion. The oil and gassector is the biggest consumer of steel through its oil and gas pipelines. The total fleet of oiltankers amounts to more than 10,000 vessels (with around 500 very large carriers of morethan 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 elec-tronics or telecoms. However each oil and gas field has a limited lifespan: around 15 to 20years for an oil field and 20 to 30 years for a gas field. Furthermore, this is the conventionalview as some new fields, especially offshore in the North Sea, Gulf of Mexico and evenAfrica have much shorter lifespans. Thus there is a strong rate of decline of production whichvaries from less than 3% per year (putting the lifespan over 30 years) in some Middle Eastcountries, 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 oilcompany, to keep its market share, the annual rate of growth is over 7% per year, so thereis a real challenge for the industry to find and put into production enough oil and gas toprovide for the next generation.
The oil and gas upstream sector is therefore a very capital intensive sector. Globally, theratio of investment to revenue is around 8% for the whole sector. For the upstream segmentof 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 USand Europe.
Today more than 150 oil and gas projects with a capital expenditure over $1 billion arein development. Deciding to develop new E&P projects is the main task of the executive
4Investments and costs
committee of major oil and gas companies and capital discipline is a necessity to balancetechnological, geological, financial and geopolitical risks.
The decision on capital is very important because of the uncertain nature of oil and gasproduction. When oil or gas is discovered, analyses of the drainage mechanisms allowreservoir engineers to determine the nature of investments required and to establishproduction profiles. Using cost estimates, oil and gas price assumptions and fiscal andcontractual 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 technologicalprogress. Discovering and producing new resources is a very challenging process, withphysical, environmental, technological conditions becoming even more difficult. Duringexploration activity, despite constant progress in our understanding of the subsurface, apercentage of an oil and gas exploration investment will vanish in dry wells. Over the lastten years, globally, the rate of success in exploration activity has been around 25% (successis measured by the ratio of discoveries with respect to exploration wells drilled, and this indi-cator gives an optimistic view as it includes discoveries that are not yet commercial, undertoday’s price and technology).
When new oil is discovered, choosing the best development concept is a key decision foran oil company, because re-engineering is very costly, as it often completely defines the oper-ating conditions of the field. Although the initial investment is of fundamental importance,there is a very strong technological evolution which constantly brings marginal projects intodevelopment. The frontiers of offshore depth, reservoir temperature, and pressure andviscosity (i.e. heavy oils) are constantly being increased. In order to bring challenging newresources 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 technologicalimprovements and strong competition in the service sector. Since 2004, with the strong surgein oil demand, the pattern of costs has changed. With the higher oil prices, oil companieshave raced to develop new resources as quickly as possible leading to a tense situation inthe oil services sector. As demand has grown very quickly, resources like oil rigs, technicalcapacities and skilled labour are in short supply. The long-term trend of decreasing costs hasbeen replaced by a strong increase in many of the service sectors. After a peak in 2008, theeconomic crisis has provoked a small reduction. However costs will remain now muchhigher than at the beginning of the century.
4.2 COSTS CLASSIFICATION
Economic evaluations of petroleum projects include, in addition to assumptions about thevalue of hydrocarbons, three types of data:
– Production profiles, constructed by reservoir engineers from analyses of the drainagemechanisms;
– Capital and operating costs, evaluated by cost estimators and managed by the projectmanager and the field manager respectively;
– Contractual and fiscal conditions, which can have a decisive role (they can prevent anexcellent project from ever seeing the light of day, for example).
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The relevant importance of these three elements can of course vary depending on theproject context.
In the evaluation process these three types of data have to be analysed independently ofone another, but also subjected to an overall optimisation cycle such as to maximise valueadded. This optimisation process almost always leads to a choice being made between alter-native development options in which the minimisation of capital and operating costs is afundamental and ongoing requirement. The company’s profitability and competitivenessdepend on this. This imperative applies at all stages of the project.
Choosing the right development architecture, accurate costing and controlling expen-diture across the board are the keys to success.
4.2.1 Types of costs
Normally speaking there are four types of costs involved in a project in the upstreampetroleum 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 gainknowledge 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 dependingon the environment, the nature of the reservoir and its fluids, the export conditions and, ina very different vein, any contractual constraints which may apply.
The exploration costs can vary enormously. They may be limited to a seismic programmeand 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 thedevelopment cost when the discovery is clearly established and well defined. In other casesthese costs may make the economics of the project problematical when considerable appraisalwork 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. 4.1and 4.2.
These examples show, and many projects exhibit a similar pattern, that the developmentcosts are fairly evenly divided between drilling operations, the production installations andtransport 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 courseapplies to the operating costs. The total operating costs over the life of a field are of a similar
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magnitude to the investments, although for the decision-maker their weight is lessened bythe effects of discounting over a long period1.
The object of this chapter is to give a general overview of the orders of magnitude of eachof the main items of expenditure, to present some of the methods currently used by estimatorsand project managers and, finally, to suggest a number of routes by which costs can ulti-mately be reduced.
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Drilling and completion
Production installations
Transport system
38%30%
32%
Figure 4.2 Example of the cost breakdown for an onshore development(South America).
24%
44%
21%
11%
Drilling and completion
Surface installations
Subsea installations
Gas export pipeline
17%
22%
41%
20%
Figure 4.1 Example of the cost breakdown for an offshore development(North Sea, water depth 300 m).
1. A decision-maker does not place the same value on a given receipt or expenditure in a number of years ason the same sum now. Discounting consists of applying a given annual rate (this rate is specific to thecompany) to future receipts and expenditures to estimate their present value. Discounting tends to reducethe impact of future cash flows (see Chapter 6).
4.3 EXPLORATION COSTS
Exploration costs are generally less important than other items of expenditure (see Section4.2.2). On the other hand they incur before the discovery of hydrocarbons, and will thereforehave a direct impact on the accounts of the company, the recovery of these costs being linkedto 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 ofactivity and the investment costs. We will therefore confine ourselves in the present sectionto considering the costs of seismic methods, since only marginal amounts are invested inother 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 partic-ularly 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 extremeenvironments (high mountains, swamps, the Arctic, etc.) (Fig. 4.3). However the cost ofseismic methods is very dependent on the environment: 3D seismic exploration costs arearound $5000/km2 offshore, but can reach $50000/km2 in onshore difficult areas.
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Figure 4.3 Two examples of harsh environments. A. Borneo swamplands.B. The Bolivian sierra.
A B
Marine seismic is the least costly by virtue of a technique known as 3D multiflute, whichpermits 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 gridneeds to be reduced.
Figure 4.4 shows a comparison of the expected costs of 2D and 3D seismic explorationin different environments.
It can be seen that offshore there is not a great difference in costs between a 2D seismic500 × 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 deepoffshore) compared with drilling exploration wells: the exploration costs for an area of100 km2 would be around $0.5 million for 3D seismic, whereas the cost of drilling anoffshore exploration well can be more than $100 million.
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 $100 million). Service providers’ fleets are tendingto move towards larger vessels capable of sophisticated automated manoeuvring.
The movement of seismic equipment onshore cannot however yet be automated. Thismeans that personnel costs are significant, and depend on the cost of local labour. When theterrain is difficult, costs may be increased substantially by the need to use a helicopter orspecialised equipment such as thumper trucks where access allows, or floating machineryfor swampy terrain. Because of the major investments required to maintain seismic teams,the 1980s saw the oil companies abandoning their own activities in this area, to the advantageof specialised companies such as CGGVeritas and Schlumberger.
4.3.1.2 Data processing costs
In the same way as data acquisition, the processing of the seismic data is also subcontractedto service companies, apart from a number of specialised processes and studies which arestill carried out by the large oil companies.
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0123456789
1011121314
Co
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($ m
illio
n/10
0 km
2 )
Offshore Desert Jungle Marshland Mountainous
3Dseismic mini
3Dseismic maxi
2D seismic(500 x 500 m grid)
Cost ofdrilling well
Agricultural Urbanarea
Figure 4.4 Effect of terrain type on seismic 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 standarddata (a 3D programme for deep offshore will involve several terabytes2 of data). When thedata require certain advanced or detailed processes which are time-consuming and labour-intensive the processing costs may be considerably higher. This applies, for example, to a“depth migration before addition of 3D” which allows three-dimensional subsurface imagesto be obtained as close as possible to reality from series of images over time created fromthe seismic records. This process can cost several thousand dollars per km2.
4.3.1.3 Analysis of data
Once the seismic data have been acquired and processed, they have to be transformed intodata 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 allowsthe seismic data to be transformed directly into data which can be used to locate where awell is to be drilled or draw up a development plan. The processing and interpretation ofthe 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 inter-pretation of the seismic data can be a task of between a few months and several years. Thiswork will involve personnel and data processing costs which may be in the range $100000to $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 considerablysince the late 1970s when the technique was first introduced.
This reduction in costs has been achieved through technological progress in the followingareas:
– 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 achievedthanks to the fall in the cost of information technology. However, as the projects that the oilcompanies are working on today are increasingly difficult, part of these savings are de factoabsorbed 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 aresubject 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.
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2. 1 Terabyte = 1012 bytes; 1 byte = 8 bits.
Furthermore in mature exploration zones (North Sea, U.S., etc.) the oil companies oftenaward 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 pre-investment, are often offered at a cost as low as one-tenth of the price which an operatingoil company would pay for an exclusive customised survey.
For these reasons the mean costs per km2 indicated above must be adjusted to allow fortemporal and geographic factors, which can produce variations of a factor of 5 or 10 relativeto the mean value.
4.3.2 Exploration drilling
Most of the costs of an exploration programme are accounted for by the drilling. Onshoreand offshore drilling each has its own technical peculiarities; they differ particularly interms of cost if not duration. An offshore well typically costs between $20 and $100 millionand 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 costsmay be much higher, occasionally exceeding $200 million.
The main components of the cost of drilling an onshore exploration well are indicated inFig. 4.5.
The duration of drilling is difficult to predict due to geological uncertainties regarding thedrillability 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. cancause 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 theworks (operating company personnel or prime contractor). Only 25–30% of the drilling costscan therefore be estimated with a reasonable degree of precision. These are the costs whichdepend on the depth drilled (essentially the casing), the cost of the wellhead, etc. For thisreason it is a difficult exercise for the technicians to set a budget for an exploration well.
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Consumables
Logistics
Managementand supervision
Hire ofdrilling rig
Petroleum services
Petroleum services29.5%
Consumables32.8%
Logistics12.5%
Managementand supervision
5.1%
Hire ofdrilling rig
20.1%
Figure 4.5 Breakdown of costs of onshore exploration drilling.
The hire of the drilling rig alone can represent between 20% (for the above example) and35% of the total drilling costs. The daily cost depends on its power, which in turn dependson the depth of the well and, for offshore drilling, the water depth involved. It will alsodepend on the current availability of drilling rigs on the market, that is the relationshipbetween 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 several100 thousand dollars if the market is tight. For the drilling contractor, the capital costinvolved can be between $10 and $16 million for onshore equipment, between $120 and $180million for a jackup platform and between $300 and $380 million for a semi-submersible ordrillship with deep water capability.
Figure 4.6 illustrates the evolution of daily hire cost of offshore platforms.
4.3.2.1 Logging and geological parameters
The acquisition of petrophysical and petrochemical data involves logging3, core sampling andinitial production testing from the reservoir strata. The duration of this work varies from caseto case.
The monitoring and interpretation of the geological results from the drilling makes useof two techniques practised by specialised service companies. The first of these is mudlogging, i.e. the acquisition and surface interpretation of samples, data and informationcarried via the mud circuit. The second technique involves recording physical parameterswhich allow the nature of the formations, their pressure regimes and the fluids which saturatethem to be characterised. These records are gathered either during drilling by means ofsensors incorporated in the drill string (in which case it is referred to as logging while
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150
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200
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Dai
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(tho
usan
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per
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)
Jack-upGulf ofMexico Semi-submersible
North Sea
Figure 4.6 Daily hire cost of offshore platforms expressed in thousands US$ per day.
3. Logging: The recording of various electrical, acoustic and radioactive characteristics of the formationspenetrated, as a function of depth.
drilling, or LWD), or after drilling by means of sensors lowered into the wellbore at the endof 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 connectedto a central data processing unit located in the mud logging room which also includes a smallgeological laboratory used for sample calcimetry, UV analyses, etc. (Fig. 4.7).
The costs relate to the provision of equipment and specialised personnel during drillingoperations. The magnitude of these costs depends of course on the local logistics, butpredominantly on the extent and complexity of the required measurements. For example thecharacterisation of gaseous indices by gas chromatography with flame ionisation detectionrequires the hire of specific equipment costing several hundred dollars.
Competition between mud logging contractors over the last decade has kept costs rela-tively low, of the order of $1500–3500/d. The costs of surface geological records represent2–3% of the total cost of the well.
4.3.2.3 Logging
Whatever the actual contractual terms negotiated for logging, the effective costs of theseservices 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 (explo-ration, appraisal or development), each of these different types of well requiring more or less
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Figure 4.7 Geological records (surface).
Analyser Extractor Well:ML-1
Data processing
Gas logs
Interpretation
sophisticated measurements. They are often expressed as a cost per metre drilled, whichallows 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 theindirect costs of $50–$80 per metre drilled.
4.4 DEVELOPMENT COSTS
The development costs include the costs of drilling the development wells, the costs of theproduction installations and any systems required for the transport of the effluent. Theseinvestments are directly linked to the initial definition of the project. In fact the costs ofconstructing the chosen system have to be met at this stage, which is why the various oppor-tunities to appraise the project before it is authorised are so important. This subject isconsidered 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, eachphase of which is intended to define more precisely the project and its associated investmentand operating costs. Starting with exploratory studies the work proceeds through preliminarystudy, the conceptual study and ending up with the preliminary design, the final stage beforethe project is authorised. The process is illustrated in Fig. 4.8.
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Studies Project Operat ions
Pre l im ina rydes ign
Basicengineering
Engineering,procurement,construction
(EPC)
S t a r t - u p Opera t ion
S e l e c t i o no f c o n t r a c t o r
C o m p l e t i o n o fc o n s t r u c t i o n
a n dc o m m i s s i o n i n g
Go-ahead formore in-depth
studiesor explorat ion
Go-aheadto start
prel iminarydesign
Go-aheadto proceed with project
Prel iminarystudies
Conceptualstudies
(screening,feasibi l i ty)
Provisionalacceptance
of theinstallation
Productionand final
acceptance ofthe 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 exploredhas commercial potential. It includes a geological stage which will define the potentialhydrocarbon resources present, evaluate the probability that an exploration well will besuccessful, and estimate the development costs in the event of a discovery. By referring tothree geological scenarios, i.e. “mini”, “mode” and “maxi” scenarios, and often by drawinganalogies with other similar fields, the researchers will seek to define a development archi-tecture and the capital and operating costs involved. These data will help a decision to bemade on whether the proposed exploration programme should proceed. How relevant theanalogies and extrapolations made in this type of approach are will depend on the reliability
of available databases. Furthermore the usefulness of analogies may be limited when newtechnologies are involved.
4.4.1.2 Preliminary studies
The preliminary study is intended to present a first economic evaluation of a discovery sothat 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 toimmediate development. The purpose of these studies is not necessarily to identify theoptimum development but to estimate, on the basis of the development concept most appro-priate in the light of the available data and experience, the capital cost accurate to within30–40%.
4.4.1.3 Conceptual studies
This is a key phase in defining the development architecture. It is impossible to overem-phasise that the largest reductions in investment costs are made by getting the final conceptright. The purpose of conceptual studies is to define the “final concept”. This necessarilyinvolves:
– 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 watercooling, 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 stageshould 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 engi-neering, if applicable.
Its essential objective is to allow the investors to decide whether or not to go ahead witha development, that is, to authorise the project. This is a major decision. The decision-makerneeds not only production forecasts but also coherent, validated technical picture coveringall 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 complexityof the subject matter, such that the uncertainties are reduced to an acceptable level. It shouldbe noted that the preliminary design is the last stage at which there is still an opportunity tomake major changes in the definition.
The preliminary design usually lasts two to six months, and as a rule provides estimatesof the capital costs accurate to within 20%. In order to maximise the likelihood that theproject will be successful, the preliminary design is usually confirmed in an agreementbetween the party responsible for the project conception, the party who will in future be incharge of the project and the future operator. This agreement will set forth the parametersand fundamental choices, as well as detailing the optimisation studies remaining to becarried out.
In summary, therefore, the sequence of studies out lined above allows the uncertaintiesin the costs to be reduced and the risks inherent in the project to be identified, as shown inFig. 4.9 and Table 4.1.
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These studies require the participation of many engineers and specialists, and are thereforenot without costs. There are no hard and fast rules for determining the costs but, as apercentage 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%;
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P r e l i m i n a r ystudies
C o n c e p t u a ls tud ies d e s i g n
P r e l i m i n a r y Basicengineering
Detailedengineering
0
+ 10
+ 20+ 30
+ 40
1 0
2 0
3
4 0
A c c u r a c y o f t h e e s t i m a t e( a s % o f t o t a l p r o j e c t c o s t )
Pro jec tgo-ahead
––
––
Figure 4.9 Reducing uncertainty in costs as project proceeds.
Table 4.1 Different study phases before a project is authorised.
Development Objective Risk evaluationstudies
ExploratoryEstablish broad feasibility Identify the risks (qualitative).studies
First economic evaluation Identify the risks and estimate Preliminary of a development project the degree of uncertainty
studies Basic data, attached to the economic results.
no optimisation of operating concept
Analysis of the risks associated Choice of a development concept with the solutions studied.
Conceptual from set of alternatives studied:studies => Choice of concept
cost, planning, economics, risk Feasibility demonstrated, subjectto clearly described uncertainties.
Technical and economic definition sufficiently accurate for: Analysis of risks
Preliminary • a decision to be taken on whether design to go ahead with the project, => Helps in defining objectives
• a “project action plan” and “project action plan”.to be drawn up.
– 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 decision-making 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 theproject. This timetable should show the estimated percentage of the investments to bedisbursed 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 post-ponement of an item of expenditure to a later year can significantly enhance the economicsof the project when the decision is made. Furthermore, optimising the timing of investmentsoften 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, inconstructing 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 ofexpenditure (studies, equipment, contracted activities), the country involved, the billingbasis 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.
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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 thelead times involved are easier to plan and the costs are often easier to control. The timerequired for the actual drilling has to be increased to allow for the time needed for wellcompletion, which varies according to the complexity of the completion.
In any particular environment, the development wells are generally drilled more rapidlythan 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 forthe technological parameters to be optimised on successive wells so that the drilling timecan be reduced. Figure 4.12 illustrates this “learning curve” effect. In a recent offshore devel-opment the time taken to drill a development well (2700 m in depth, with horizontal drainsof 1000 m at the bottom) was reduced from 26 days for well no. 1 to 13 days for well no. 7.
Tables 4.2 and 4.3 and Fig. 4.13 illustrate a typical breakdown of offshore developmentdrilling costs.
Special conditions can heavily influence the costs of a development well, as shown bythe 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 horizontalwell is 20–30% higher than those of a vertical well (but their productivity may be 3 timesas great).
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0 10 20 30 40 50 60 70
Drilling
Geology
Production Testing
Completion
Abandonment
Exploration or appraisal drilling
Development drilling
Duration (days)
drilling geology completion
drilling geology testing abandonment
Figure 4.11 Typical timings for drilling operations.
Figure 4.12 “Learning curve” for development drilling.
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Consumables
Logistics
Managementand supervision
Hire ofdrilling rig
Petroleum services
Petroleum services13.8%
Consumables34.2%
Logistics7.9%
Managementand supervision
3.4%
Hire ofdrilling rig
40.7%
Figure 4.13 Cost breakdown for offshore development well.
Table 4.3 Duration for drilling an offshore development well (same project as in Table 4.2).
Erection and removal Drilling Geology Completion Total
Duration (days) 1 33 5 16 55
Table 4.2 Cost breakdown for offshore development well. Oil-producing well – South-East Asia – water depth 70 m.
Phase % of total cost
Consumables 34Wellhead, piping, drilling bits and core barrels, mud and cement products, accessories, energy, water.
Logistics 8Fixed price (trucks, aircraft, removal of drilling rig…).
Management and supervision 3Studies and project management, supervisory arrangements, geology and reservoir.
Hire of drilling rig 41Drilling contract, mobilisation/demobilisation of drilling rig.
Petroleum services 14Mud, 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
Another example is a high pressure, high temperature (HP/HT) well: more sophisticatedwell and completion equipment is required, so that the consumables required are morecostly, increasing the costs by up to 20%. The same applies to exploration wells where theconditions are difficult. A well producing corrosive fluids requires completion equipmentmade of more sophisticated metallurgical materials, which can also increase costs by up to20%.
Furthermore an oil producing well where subsea pumping is necessary will requiremultiple workovers in order to maintain the pumps.
Environmental constraints can equally affect drilling costs. These are increased if drillingwaste such as rubble or liquid wastes have to be treated in order to comply with nationallegislation. 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 ecologicallysensitive zones such as the Paris basin; the reduction which can be achieved in this way isof the order of 10–15%.
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 ofequipment currently used in development drilling. Instead we describe below some typicalonshore and offshore project configurations and review some of the methods traditionallyused to cost these installations. We then present a set of unit costs and ratios which can beused for very preliminary evaluations. More detailed descriptions will then be given for twospecific cases: a deep offshore development programme and an example of an LNG project.
Whether onshore or offshore, the principles of production, gathering, separation, treatmentand transport of the products remain the same. The structures and equipment will varyaccording to the composition of the effluents, the product specifications applying to transportand 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 intoclusters, are linked by a network of gathering lines to a production and processing facilityfrom which one or more transmission lines run (Fig. 4.14). Some remarks follow on thedifferent 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 sophis-ticated alloys (Inox or Duplex steel) or composite materials. They are subject to attack bothexternal and internal, in the form of corrosion and erosion. They can also undergo processessuch as blocking, scaling, the deposition of minerals (sand, sulphur) or hydrocarbons(paraffins, asphaltenes) through settlement or the formation of hydrates. They are thereforeequipped with cathodic protection or systems which inject protective or preventive chem-icals, heating and insulation systems, systems for scraping and detection “pigs”.
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C. Production and processing facility
The effluent from a well is made up of gaseous and liquid hydrocarbons, usually water andsometimes salt, sand and solid hydrocarbons. The different phases present, which sometimesalso include emulsions and foams, have to be separated. This is traditionally done insuccessive phases through pressure drops, the effluent waste (water and sediments) beingseparated from the oil and gas and treated, before being discharged. The specifications ofthe separation and treatment units touched on above will depend on the types of effluent,their quality and the specifications which need to be met.
• Oils are treated mainly by removing the water, salt and excess gas so that they can bestored, transported and handled by normal methods. Desalters and stabilisers are the mostcommon 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 andcondensing the heavy fractions: molecular sieves, adsorbent beds, chemical or physicalabsorption, traps with cooling coils or self-refrigeration by expansion and recompression.The gaseous fractions are compressed for transportation or reinjection into the reservoiror, very occasionally, for storage.
• The water treatment usually involves a treatment plant and pumping facilities whichreinject the water back into the reservoir.
• The production facility may also supply the utilities required (electricity, water and otherservices).
• The effluents are transported to a terminal, factory, etc. by pipeline.
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The processing plant:SeparationHeatingStoragePumpingPower generation
➂
The pipeline④
The loading terminal⑤
The field:well clusters and gathering system
➁
Well cluster➀
Figure 4.14 Onshore development concept.
4.4.3.2 Offshore development
In an offshore installation the wellhead may either be on the platform or underwater.Combined surface and subsurface production facilities are becoming increasingly commonin offshore development.
The production support, which may be a fixed platform or a floating vessel, houses theutilities needed for production (particularly power) and all the safety installations. Forreasons of weight, installation cost and maintenance, the offshore processing equipment isoften 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 ontotankers. The remaining processing needed to ensure that the products comply with thedelivery specifications are carried out on arrival. Accommodation for personnel, the controlroom and offices and the amenities needed for life on board are situated either on theproduction platform itself or on a dedicated accommodation platform.
Two common types of development are illustrated below: concepts based on fixed plat-forms and on a floating vessel.
A. Development based on fixed platforms
The well, processing and accommodation platforms are linked together by walkways to forma 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 OffloadingVessel) linked to the underwater wellheads by means of flexible lines (Fig. 4.16).
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ACCOMMODATIONPLATFORM
UTILITIES/PROCESSINGPLATFORM
FLARE
WELL PLATFORMS
Pipeline
32” - 82 km
PROCESSING PLANT
Figure 4.15 Offshore development configuration with fixed plat-forms.
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 iscrucial that the key parameters are identified and evaluated so that the project can be properlydefined and its viability assessed, because some of these parameters strongly influence thecosts.
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 waterdepth, which may be conventional (to 300 m), deep (to 1500 m) or ultra-deep (over 1500 m).
B. Oceano-meteorological conditions
Producing oil and gas in a hostile environment means costly production installations: plat-forms must be able to withstand extreme climatic conditions, for example storms in the NorthSea, 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 orgas 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 thecontent 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-dutyequipment 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, butabout $150/m for 300 bar.
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Figure 4.16 Offshore development configuration with FPSO.
4.4.3.4 Development costs summary table
Table 4.4 is an example of a typical summary made by the estimators, in this case for anon-shore gas treatment plant. The methods used to prepare it will be explained later. The tableshows that the technical costs4, although important, are just one element in the overallestimate. They are accompanied by a range of other costs related to the studies, surveys,project management and insurance.
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Table 4.4 Example of structure of cost: onshore gas treatment plant.
Project information
CharacteristicsGas flow: 1000 mm.s.ft3/dOil flow: 90573 bbl/dWeight of equipment: 2245 t
Summary of costs Ratio (%)• Direct costs
Process equipment 42%Utilities 11%Ancillary equipment 2%Infrastructure 3%
Total direct costs 58%
• Indirect costsTechnical facilities 1%Construction-related costs 2%Costs related to transport of equipment
and bulk materials 3%
Total indirect costs 6%
• Technical costs (direct and indirect) 64%Engineering 10%
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) andindirect costs (equipment transport, temporary installations, etc.).
4.4.3.5 Unit costs and standard ratios
Table 4.5 presents various standard cost data for the main elements of the production andtransport 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 rapidoverview of the principal methods used by estimators during the various study phases referredto above. Before doing so we take this opportunity to define a number of terms and abbre-viations 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 beforeall 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 actualcosts ultimately prove lower because the competition between the suppliers and othercompanies turns out to be keener than expected or because dumping is practised by somesuppliers, all well and good. But an estimator may not assume a favourable scenario ofthis kind.
• An estimate is an approximation rather than a precise forecast of costs: an installationcannot be costed by referring to a price catalogue. Quantities such as the weights of struc-tures or piping, dimensions, volumes of concrete, the length of cables, etc., are not yetknown at the preliminary, conceptual or even the preliminary design stage. This is quitedifferent from a contractor bidding for a job, who must begin by calculating the quantitiesof 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 drawnup by a financial department. Other competent departments will then also add on thefinancing expenses, local taxes and customs duties so as to obtain a complete projectcosting in the local currency;
– The accuracy of the costing will depend essentially on the methodology adopted andthe 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 togive the technical costs, other general items and a “reserve for contingencies”. Readers arereminded of the definitions of each of these terms below.
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Main equipment
Carbon steel pressure vessels (less than 5 t) 15–35 $/kg(between 5 and 20 t) 18–20 $/ kg(over 20 t) 5 $/kgMultiplier for inox pressure vessels 3.0
Pipeline project, onshore or offshore 15–20% of technical costsOther project 25–40% of technical costs
Region Onshore construction Engineering
France 60 100
UK ($1 = £0.5) 70 100
Norway ($1 = NOK 5.96) 80 120
Far East (Indonesia) 30 50
Gulf of Mexico 50 80
Region Supply Derrick barge Derrick bargeLay barge
vessel < 2,500 t < 6,600 t
North Sea 20 1,100 1,300 400–1,100
Middle East / 8–10 300 850 500Far East
Gulf of Mexico 5–10 300 850 400
Table 4.5 Production and transport installations: standard costs and ratios (base 1stquarter 2007).
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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 bulkequipment such as pipework, valves and fittings, electric cabling, instrumentation, cladding,etc. Also included are the construction costs including the costs of onshore prefabricationof the elements and modules of the offshore platforms, as well as the on-site constructioncosts (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 Super-vision) cover:
– The engineering, i.e. the basic engineering and the detailed engineering, as well asservices 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. Thiscorresponds to the value of the contract for the construction of the infrastructure, that is, atechnical cost together with the general costs of the contractor responsible for carrying outthe work. In a contractual arrangement of this kind the EPC cost must be increased to allowfor the general costs of the prime contractor, or “company costs”, that is, the costs of thebasic 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 andon how much is known about the environment. Whatever the stage of a project, a provisionfor contingencies is always included in an estimate, in order to allow for uncertainties whichcannot 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. Thecost is estimated by reference to the known (or appropriately updated) cost of an existinginstallation of the same type but a different capacity. It is assumed that the ratio of the costsof the two installations is equal to the ratio of their capacities raised to a power of approx-imately 0.6 (also known as the “scale factor”). This rule of thumb only applies when thecapacities concerned are not too different from one another.
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Define the general characteristics of the installation
and apply general ratios
List in detail the equipment, bulk materials
and specific quantities
List the main equipment and apply specific factors
Global methods Factorisation methods Detailed methods
Preliminary
studies
Conceptual
studies
+30%
–30%
+25%+20%
+10%
–10%–15%–20%
Preliminary
design
Final
costing
Figure 4.17 Main costing methods.
B. Factoring methods
These methods are widely used, particularly for preliminary and conceptual studies, andsometimes even preliminary designs. They are based on the observation that there is a fairlyconstant relationship between the direct installed cost of an item of processing plant or autility, including auxiliary equipment and construction, and the costs of the main items ofequipment. The latter are generally evaluated using small computational programmes or anequipment database. A multiplier specific to the type of equipment involved is then appliedto obtain the direct installed cost.
To these equipment costs have to be added the site preparation costs, ancillary or offsiteinstallations (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 esti-mated using percentages.
C. Detailed or semi-detailed methods
This method involves estimating each item analytically. Since the quantities of bulk mate-rials cannot be calculated at this stage of the study, they are estimated as a proportion of themain equipment. For example the tonnage of the supporting structure or piping associatedwith a particular item of equipment is estimated by applying a specific ratio to the tonnageof the equipment. The hours of labour spent on manufacture or construction on-site are also
evaluated using ratios. It is estimated, for example, that the labour required for the manu-facture of substructures for fixed platforms is between 60 and 80 h/t, or about 300 h/t forordinary steel piping. Finally these hours are converted into costs by using a labour cost perhour and assumptions with regard to productivity.
The general costs will be estimated at the most detailed level possible by evaluating, forexample, 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 contractualstrategy 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 factoringmethod based on the costs of the main items of equipment; we therefore have two require-ments:
– A database, as complete as possible and regularly updated, of the main items ofequipment;
– Feedback from projects on the quantities of secondary equipment associated with eachof the main items of equipment, on numbers of hours spent on manufacture andconstruction as well as costs, broken down by subject area and by structure type. Thiswill 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 isbecause, firstly, we rarely have access to data on the cost of equipment, often purchased bythe contractor, particularly secondary equipment. And secondly, although the overall valueof 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 eventswhich 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 willoccur. It includes, for example, uncertainties relating to “slight” modifications in the tech-nical specification, modifications in the regulations, specific building problems, supplierdelays, 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 ultra-deep offshore development project and a LNG (liquefied natural gas) supply system (entirecycle including liquefaction, transport and regasification).
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These two examples will give readers a better understanding of the orders of magnitudeof the overall costs of projects in the petroleum industry and, in particular, the technical costsexpressed per barrel of oil or per unit calorific value of gas, as appropriate.
4.4.5.1 Deep and ultra-deep offshore
This is a very topical theme: many companies are currently interested in exploration in waterdepths in excess of 1000 m and even occasionally 2000 m.
Advances in subsea technologies mean that it now appears feasible to produce hydro-carbons discovered at such depths at a competitive cost.
At more familiar water depths up to 300–400 metres technological progress has led tosignificant reductions in costs. The cost of producing a barrel of oil (exploration, developmentand exploitation) at such depths had fallen from $13–15 in the 1980s to $5–7 in 2000 andgrew again over $20.
Extrapolating these results suggests that the development of offshore resources in deeperwaters should be economically feasible. There are many production concepts of provenviability at moderate depths which could realistically be assumed to constitute the startingpoint for evaluating deep or ultra-deep offshore development projects (Fig. 4.18).
The petroleum industry is currently focusing its efforts on very deep waters (>2000 m),with the objective of getting to 3000 m.
A. Costing methodology
A possible development programme can be evaluated on the basis of two major categoriesof parameters, those which describe the reservoir itself and those which describe itsgeographical location.
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Figure 4.18 Deep offshore production concepts.
Parameters associated with the reservoir are usually obtained from a “speculative” seismicexploration survey and by interpreting local geological phenomena. These parameters allowthe size of the target object to be estimated, that is the reserves and the extent of thereservoir, as well as its potential, i.e. the density of the reserves, reservoir productivity andthe 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 existingpetroleum infrastructure and the extent to which it would be available, the market prospectsfor the production, local regulations, tax regime, etc.
The values of these parameters will point the evaluator towards the most appropriatedevelopment plan.
B. Example of estimation of capital costs
By way of illustration the investment costs are estimated for two prospects of contrastingsize 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 hydrocarbondeposits, of centred morphology, extend over an area of 90 km2. They consist of multilayerreservoirs lying at depths of between 900 and 1700 m below the sea bed. The reserves areestimated to be 750 Mbbl of oil, and the field would have a life of about 20–25 years. Theproduction will plateau at 200000 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 productionnetwork (Fig. 4.19).
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430 m
Cluster of 10 subsea wells
Gathering lines (length ~ 3 km)• production 2 x 12”• test 1 x 6”
Figure 4.19 Example of development concept, deep offshore (Gulf ofGuinea).
The FPSO, tethered in a fixed position by 16 mooring lines, will comprise a hull 300 mlong and 60 m wide with the capacity to store 2 Mbbl of oil. The treatment plant and util-ities will be situated in one or more independent modules on the upper deck. Their net weight(empty) is estimated at 20000 t.
The production wells will be connected to production manifolds which are joined to thegathering lines. Each production line is made up of two pipes thermally insulated by meansof a layer of foam in a metallic case. The water injection wells are connected in twos to theinjection manifolds. Three water injection wells are connected to the FPSO by three inde-pendent 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 eachproduction 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 theFPSO. 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 recov-erable reserves per well, two cases are considered, in which there are 48 and 63 productionand water and gas injection wells respectively.
The capital costs were estimated by reference to projects similar to the one in questionin the Gulf of Guinea and Brazil (see Table 4.6).
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b. Prospect in the Gulf of Mexico
This prospect is situated in 1500 m of water in the Gulf of Mexico. The reservoir, with anelongated morphology, has an area of 22 km2. It is multilayered, at depths of between 1800and 3000 m below the sea-bed. The reserves are estimated to be 180 Mboe, and the fieldwould have a life of about 15–20 years. The production will plateau at 60000 bbl/d of oiland 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 adeep draft (Fig. 4.20) with wellhead at the surface and the production being dispatched toexisting installations. In contrast with a subsea development, this design has the advantageof carrying out the drilling and production from the same platform, allowing servicing to becarried out on a well without having to mobilise a drilling rig. This system also overcomesthe problem of having to transport a multiphase effluent over a long distance. The spar
Table 4.6 Gulf of Guinea prospect: development investments ($M). Waterdepth: 1500 m – Reserves: 750 Mbbl.
Case 1 Case 248 wells 63 wells
Production vessel 1700 1700Subsea equipment & control system 1000 1300Gathering lines 1700 1900Company costs1 600 700Provisions 500 600Drilling – Wells 2000 2600
Total capital cost ($M) 7500 8800Capital cost ($/boe) 9.9 11.7
1. Project management and supervision, studies, preliminary work, insurance.
comprises a floating structure with a circular cross-section at water surface level and alongthe 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 cavityof 18 m square in the middle containing the risers. The spar is anchored by means of 12 semi-taut catenary cables. The risers connecting the seabed to the wellhead at the surface are main-tained under tension independently by means of flotation modules inside the cavity in theshell. The riser contains a special joint at the level of the spar keel in order to accommodatemovements of the riser relative to the platform.
The drilling and production module, including the living quarters for 110 persons, is madeup of 3 decks 55 m in length, providing a total surface area of the order of 9000 m2. Theempty weight of this module is approximately 9000 t. All the wells are pre-drilled as far asthe surface casing. Four of the wells are drilled into the target formation so that productioncan commence shortly after the installations are erected and connected. The remaining wellsare drilled from the spar.
After separation, the products are exported to pre-existing installations situated in shal-lower water by means of two independent pipelines, i.e. a 10" line, 60 km in length for gasand a 16", 70 km line for oil.
The capital costs were estimated from available data as indicated in Table 4.7.
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Figure 4.20 Artist’s impression of a spar.
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These two examples of deep offshore prospects show that, depending on location, the unittechnical 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 stabili-sation plants, the following subsystems (Fig. 4.21):
– The liquefaction plant, which provides for the treatment, refrigeration and liquefactionof 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.
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, totalsulphur approximately 3 ppm moles). Gas treatment units upstream of the liquefaction are
Table 4.7 Prospect in Gulf of Mexico: capital cost of development ($ millions).Water depth: 1500 m – Reserves: 180 Mbbl.
Production platform 1 900Subsea equipment & control system –Collection network –Export system 100Company costs 2 180Provisions 120Drilling – Wells 300
Total capital cost ($M) 1600Capital cost ($/boe) 8.9
1. Including the drilling function\equipment and the production and export risers.2. Project management and supervision, studies, preliminary work, insurance.
Pre-processing Liquefaction LNG
GPL
Feedgas
Salesgas
Temperature = – 160°C
LNGplant
Regasification
Losses: 2% 8% 2% 1% =+ + + 13%
Refrigeration
LGN
Precooling
Figure 4.21 The LNG cycle.
more expensive than traditional liquids removal units. Any mercury in the feed gas is treatedat 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 firstcycle, which usually produces pure propane, cools the feed gas (usually to –20/30°C) andthe refrigerant for the second cycle. The second cycle, which uses a mixture of nitrogen andlight hydrocarbons, allows the gas to be condensed and cooled to –160°C. These units makeuse 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 exchangesurface. They are usually spiral tube exchangers 4 metres in diameter and some 60 metresin height.
Depending on the nitrogen content of the feed gas, the liquefied gas will be passed to adenitrification 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 gasrich in ethane which is routed back into the LNG stream. It also produces a propane/butanestream which can be reinjected into the LNG or sold as a separate product and finally, aheavier product with the characteristics of a light condensate.
The liquefied gas is then stored in cryogenic tanks at atmospheric pressure fitted withloading pumps. The gas resulting from the evaporation of the LNG (“boil-off”) is returnedto the fuel gas stream by means of dedicated compressors.
The LNG is transferred from the loading bay onto LNG tankers by means of cryogenicloading arms. In view of the size and draft (approximately 14 m) of these vessels, and theprecautions which must be taken during product transfer, a dedicated jetty and associatedport facilities are needed. A large LNG factory may have several jetties. The LNG plant atBontang in Indonesia, for example, has three jetties.
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N2Fuel gas
Feedgas
NGL
Preprocessing
ReceptionAmine
treatment DryerMercury
trap
Sour gases (CO2, H2S, mercaptans)
Precooling
Propane
MCR™
Liquidsremoval
Cryogenicexchanger
(MHE)
Denitrification
Fractionation
LPG
LNGMCR: Multi Component Refrigerant
Figure 4.22 Simplified flowchart of a LNG plant.
The liquefaction plant requires the following facilities: a cooling circuit (generally seawater), 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 liquideffluents 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.
b. Transport
The LNG market is characterised by long-term contracts, and a dedicated fleet of LNGtankers is normally used to transport the product. The number and size of the tankers formingthe 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 TBtuper 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 Eastto Japan) are approximately 6,300 nautical miles and the shortest (Algeria to Spain) about350 nautical miles.
c. Regasification
On arrival at the reception terminal the LNG is transferred to storage tanks, and subsequentlyvaporised, after cryogenic pumping, and made available to the end-user. The gases whichform due to the natural evaporation of LNG in the terminal installations are reincorporatedinto the liquefied gas before pumping. The vaporisation is effected either in trickle evapo-rators or in submerged flame vaporisers. If the calorific value of the gas is too high, nitrogenor 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 theunit 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 plantdepends on the size of the reserves which it will process and the market for which it willproduce.
Only one plant, in Kenai, Alaska, operates with a single liquefaction train; all the otherplants 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 mechanicaldrives. The liquefaction trains are sized on the basis of the markets at which the plant isaimed, but also on the optimum production rate associated with the power of the refriger-ation 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 mostappropriate turbine with a power which meets the requirements is therefore chosen. Whenchoosing the rated capacity of the turbine, it should be borne in mind that the power actuallyavailable depends on the temperature of the air (there is a 0.7% variation in output powerper °C): the capacity of the train will therefore be a function of temperature.
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It should also be noted that most liquefaction plants have been debottlenecked at somestage in their lifetime, leading to an increase compared with the initial (“design” or “name-plate”) 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 plusa certain number of days” production for the plant when operating at full capacity. Thisnumber of days will depend on the particular circumstances of the case, particularly the avail-ability of tanker capacity (which may be disrupted by weather conditions, for example). Asa first approximation, 4–5 days should be taken.
The number and sizes of the tanks will depend on the chosen capacity, but also on theunit cost, given that these are lower for a large than a small tank. LNG storage tanks arelarge: up to 250000 m3 for an above-ground tank.
d. Size of LNG tankers
The size of a LNG tanker can reach 250000 m3, but smaller vessels might be chosen for shortroutes 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 supplycycle; this parameter is indispensable for any technico-economic analysis.
The liquefaction plant requires around 10–12% of the feed gas for its own use. Theprecise figure depends on the pre-treatment necessary, the installations used to load the LNGonto the tankers, the source of power (gas or steam turbine) and the intrinsic efficiency ofthe liquefaction process.
There is some evaporative loss of LNG during transportation, and this will be burned in thevessel’s boilers. In addition, some LNG will be used to keep the storage areas cold for the returnjourney. The loss of saleable product is estimated at between 1 and 3%, according to the distanceinvolved. 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 specificproject 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 defi-nition, 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, theremoteness of the site and the logistics. These costs also depend on the market conditionsat the time the construction contract is signed. For a preliminary estimate of the cost of theLNG 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 6000 nautical miles.By applying the data in Table 4.8 and by making a few simplifying assumptions, we arriveat a production cost CIF5 including regasification but excluding feedgas for LNG of approx-imately $3/MBtu. These costs are broken down in Fig. 4.23.
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5. Cost, Insurance and Freight: the price including the cost of the merchandise, insurance and maritimefreight as far as the destination port.
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Table 4.8 Estimation of the cost of an LNG cycle using standard factors.
Plant (capacity Proposed cost % Cost range5 Mt/y, 2 trains) ($M) of total cost ($M)
Figure 4.23 Cost structure for the LNG cycle ($/MBtu feedgas excluded).
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 sometimessomewhat 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 givingrise to operating rather than capital costs.
About two-thirds of the operating costs consist of four major items, i.e. general supportprovided 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 firstinstance, on the level of subcontracting. The balance includes contracts, purchases andservices.
The remaining one-third of expenditure comprises various items which account forbetween 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) orby their purpose (production, maintenance, security, etc.).
Where items are classified by their nature, they should generally conform to theaccounting conventions, which may have a statutory character in the particular countryconcerned. They will include, in particular:
such as piping, drill strings, joints, catalysts, molecular sieves, cladding, laboratorysupplies, individual items of security equipment, spare parts, household supplies, food);
– Telecommunications costs, miscellaneous hire charges, service and maintenancecontracts.
The classification by purpose allows the costs to be analysed in a manner which corre-sponds more closely to the objectives of the operator. The following breakdown is anexample:
– The direct costs comprise downhole (well services) and surface production, maintenanceof 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 moni-tored throughout the life of the field, compared between installations, and so that the costsof planned installations can be estimated.
Conditions and circumstances can vary enormously. We can only give orders ofmagnitude here: operating costs are subject to a very wide spread, ranging from $0.5 and$6/boe (1 boe = 6.119 GJ), depending on:
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– The ease with which the gas, oil, heavy oil, etc. can be extracted;
– 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, foran offshore and an onshore field respectively.
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 operatingphilosophy are chosen. This is the stage at which the overall optimisation, and in particularthe trade-off between Capex and Opex is virtually fixed. Optimisation is achieved throughthe engineering studies (detailed installation design, choice of equipment) and the prepara-tions made (policies on recruitment and subcontracting, organisation of logistics).
Particular consideration needs to be given to the operating philosophy, because this hasa direct impact on personnel costs, preponderant in the field. It is vital to optimise the work-force when the units are being conceived. It would be illusory to think that savings can bemade through antiquated methods such as using operators for remote monitoring for example.This would have the effect of inflating the production workforce, decentralising maintenanceoperations and ultimately straining budgets. A single operator costs in excess of $100000/y,not allowing for various extras, i.e. $1 million over 10 years, far in excess of the capital costneeded to avoid this labour cost.
During the operating phase, the steps taken to control operating costs are as describedbelow:
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0
1
2
3
4
5
6
7
Ope
ratin
g co
sts
($/b
oe)
Head office supportHead office managementTechnical supportProduction lineSecurityLogisticNew worksMaintenanceSurface productionDownhole production
Figure 4.24 Examples of breakdown of operating 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 forrecording expenditure, often using automated procedures, for the same elements in this hier-archical breakdown. By calculating costs at each hierarchical level, analyses and compar-isons can be made.
4.5.2.2 Optimisation
An analysis of the expenditure, beginning with the largest items, will allow areas to be iden-tified where economies are possible by reviewing current practices and technical specifica-tions. 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,
At one site, for example, the frequency with which the 24 gas turbines present were recon-ditioned (unit cost between $200000 and $800000) was challenged. By considering thehistory of these machines it proved possible to increase the interval between reconditioningfrom 3 to 5 years on average. This led to a reduction of 5% in the total maintenance costsfor the site.
Account must also be taken of future production dynamics such as the run-down of thereservoir, 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 (ageingequipment, obsolescence, extensions) and changes in the economic climate.
The scope for optimising operations may be inhibited by poor development prospects orwhen there is an economic downturn, or may conversely be enhanced by organisationalchanges, or a modernisation of the installations when there is a major extension to theproject, for example.
4.6 MASTERING COSTS
It can be a major challenge for the team charged with designing and implementing a projectto ensure that the installation is operational, secure, reliable and effective. Moreover if apetroleum project is to be successful, these objectives have to be realised at the minimumcost. In the past this consideration was paramount when the price of crude oil or gas waslow. For a number of years now, considerations of cost minimisation have become apermanent feature for developers.
As a direct consequence, there have been significant reductions in technical costs inthe petroleum industry over the nineties. Fig. 4.25 shows that overall the technical costs havelost almost 50%, from $11/bbl in 1990 to $8/bbl or less in 2000. This reduction has affectedessentially exploration and operating costs.
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Since 2000, this trend has changed: technical costs are rising and they have increased bymore than 100% between 2000 and 2008. The increase finds its explanation first in theeconomic cycle, with higher price of commodities like steel and other metals. Second thehigh level of investment drove to strong constraint in the oil services sector. Explorationequipments 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 petroleumindustry to reduce its technical costs. A number of technological advances helped to makethis achievement possible.
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0
2
4
6
8
10
12
14
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DepreciationExploration costsOperating costs
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008
Dol
lars
/bar
rel
3.4 3.5 3.9 4.7 5.66.9 7.80.8 0.8
0.90.9
1.2
1.71.9
4.4 4.75.2
6.0
7.0
8.1
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Dol
lars
/bar
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2002 2003 2004 2005 2006 2007 2008
DepreciationExploration costsOperating costs
Figure 4.25 Technical costs in upstream petroleumindustry (Source: Total).
Major strides forward have been made in geoscience as a result of the processing capa-bilities of modern information technology. The systematic use of 3D, for example, has madeit possible to reduce the number of exploration wells needed to uncover economically viabledeposits of hydrocarbons. It has also allowed the wells to be positioned optimally, therebylimiting the need for further delineation.
Advances in drilling have also helped to cut costs: deviated wells, horizontal and evenmultiple borehole drilling, to name but a few, have increased the number of objectiveswhich could be reached from a single site (a platform, for example), as well as allowingmultiple pay zone access from a single well. These techniques have had a radical impact onthe productivity of wells by reducing the number required and, in consequence, significantlysimplifying the linking infrastructure needed.
Another notable advance has been the simplification in gathering systems made possiblenot only by reductions in the numbers of wells, but also to a great extent by advances inmultiphase transport. Because the liquid and gas phases no longer have to be separated, ithas been possible in some cases to halve the number of pipelines. In addition, separation unitshave been considerably simplified or even eliminated altogether, particularly in places wherethese are undesirable, such as in the vicinity of the wellhead. Of course some of theseeffects are offset by developments at the reception facilities, which have necessarily becomemore complex. But the overall net effect is substantially positive, a saving of the order of10–15% of the total cost of a project.
Technological advances have also led to remarkable improvements in productionequipment (power generation, instrumentation, piping, rotary drives, etc.), in terms of reli-ability, availability, and ease-of-use. Other examples include the development and wide-spread use of digital process control systems, the advent of high-performance privatetelecommunications networks, the emergence at last of really reliable, powerful, light gasturbines, a spin-off from ongoing progress in the aero industry. Other important develop-ments include the advent of the variable-speed electric drive, the contribution made bypowerful electronics and technological advances in rail transport.
It is difficult to quantify the effect on costs of all these improvements, but it is certainlyconsiderable.
We have got to the point where diminishing returns are beginning to set in. But furtherprogress is always possible, and there are still many opportunities for making savings in allareas. 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 threemain difficulties: the delicate matter of adjusting the weight of the mud, the low tempera-tures which create problems related to the rheology of the mud, and finally the presence ofa rigid drilling riser, heavy, cumbersome and fragile. We now have a good understandingof these problems and are reasonably able to deal with them during exploration drilling. Theynow need to become routine, so that the costs of development drilling can be brought backto an acceptable level, particularly in deep water (in excess of 1500 m). This process isalready taking place, and there is no doubt that the petroleum industry will soon devise tech-nically 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) unlesscertain technological breakthroughs are made, such as drilling without a riser and drillingwith casing.
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4.6.1.2 Mastering the costs of surface installations
It is impossible to over-emphasise the fact that 90% of the costs are determined in the defi-nition of the object to be built. This underscores the enormous importance of the conceptualstudies and the preliminary design, during which potential areas in which the costs can bereduced should be identified (Fig. 4.26). Sufficient time and resources and the best possibleskills therefore need to be devoted to these studies to ensure an optimum project definition.Traditional methods need to be constantly questioned and new ideas systematicallyconsidered.
A second way of reducing capital costs is to seek to simplify and standardise theequipment. 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% forstructures and 25% for construction and supervision— not counting savings in time, whichmay be as much as 3–5 months. Even if two installations are not completely identical, it isworth checking whether some of the units in the first installation cannot also be used withoutmodification in the second.
A third way adopted by some companies is to put the contractual arrangements withsubcontractors on a different footing. The objective is to harness the skills of bothmanagement and workforce as a whole towards common objectives in terms of costs, dead-lines and even production. This approach has spawned alliances, the concept of the targetprice, ventures involving profit-sharing. There is no doubt that service providers have takenon a broader role, becoming in the process more partners than subcontractors. Many haverestructured, growing in the process, and with their technical competence considerably rein-forced. The oil companies have relinquished entire areas which were hitherto very much theirpreserve. This new modus operandi is undoubtedly acting as a mechanism for the dissemi-nation, spread and acceleration of technological progress, and has led to a division of workpropitious to these advances, the service providers building expertise in new areas, and theoil companies taking on the coordinating role in relation to the complex set of tasks requiringinputs from a range of different specialities.
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Conceptualstudies
Preliminarydesign Basic
engineering
Cost reduction potential
Time
Detailed engineering
Screeningstudies
Figure 4.26 Cost reduction potential during the various study phases.
Quite separate from this antithesis between service providers and oil companies, it is clearthat the growing complexity of projects, together with the shortening of the developmentcycle in the face of economic pressures means that there is an increasing interdependencebetween the disciplines involved at an increasingly early stage. In other words, the need fora cross-disciplinary approach is making itself keenly felt; this is certainly the case in the fieldof R&D, where efforts are being directed towards technological innovation which can beused commercially, with attractive economics.
4.6.1.3 Mastering operating costs
Opportunities to reduce the operating costs present themselves in both the design and oper-ating 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 machinescorresponding to availability requirements and acceptable risk level, need for multiplebypasses, etc.);
– Select equipment based on criteria of maintainability, reliability, ease of diagnosis, andquality.
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 impacton project economics because of the effects of tax and the effect of discounting future cashflows. In the operating phase, however, cost reduction has a permanent effect, and becomesincreasingly necessary as declining production results in a rapid increase in the costs perbarrel. This trend can make the venture uneconomic, even while there are still substantialreserves remaining. It is therefore important to keep operating costs under close reviewthroughout 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 cutcosts. They use all the means at their disposal, although some are bolder than others in thisregard. The petroleum industry long had a reputation for conservatism in its technicalchoices, preferring methods which were tried and tested. Broadly this continues to be thecase. However some companies are increasingly demonstrating their capacity to innovate,
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particularly where this leads to significant rewards or where the technical parameters are suchthat innovation is needed to reach new reserves. Innovation obviously involves risk ofgreater 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 tradi-tional system of compression pumping is an example of the industrial application of an inno-vation resulting from prolonged R&D.
Risk used to be essentially of a geoscientific or geopolitical nature, and if considerabletechnical risks were sometimes taken, for example in the North Sea in the 1970s, these werenot seeking to establish or strengthen the position or competitiveness of a particular companyin a given context.
Times have greatly changed in this regard. The oil companies differentiate themselves andpromote themselves to the competent authorities in host countries in terms of their capacityto take technological risks and to bear the financial consequences which ensue. There aremany reasons for this. For example there is no doubt that the technological “levellingupwards” requires the ability not only to realise an activity at a particular point in time butalso to be able to bet on future performance in the short or medium term so as to retaincompetitiveness. Specifically the willingness is required to take risks at the moment whenagreements or contracts are signed, i.e. well before the realisation stage, and to manage theserisks subsequently.
In other words, in the past when development opportunities were technology-limited, risk-taking remained fairly low. At present the reverse applies, and technological risk-taking hasbecome a consequence of commercial decisions taken on the basis of considerations of adifferent nature. The perils are increased further still by the sheer physical size and thereforefinancial implications of the stakes involved.
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 thelevel of economic activity at the moment when the main contracts are awarded can provideuseful guidance on the mean price levels likely to apply.
Since the lead times involved in decision-making and the realisation of petroleum projectsare long (3 to 5 years) investment decisions are taken on the basis of long-term economiccalculations, and there is no direct correlation between the costs of platforms underconstruction and the price of crude. The costs of platforms are more sensitive to the costsof raw materials (particularly steel), the order books of the companies concerned and theavailability of large construction yards.
Since 2003, the petroleum services sector has entered the high phase of an economic cyclewith 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%, dependingon the state of the market. The firm awarded the contract may just be seeking to cover itsoperating costs to avoid closure. Or alternatively in overheated economic conditions the firmmay have won the contract without any real competition, since the order books of itscompetitors were full. This is illustrated by the example of Korea, which dropped its
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construction prices by 35–40% in 1998/1999 in order to maintain an acceptable level ofactivity, 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 alsotends 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 hasbeen observed in 2009 and 2010.
Once the project has been defined, the final capital cost can still be affected by variousfactors and circumstances, in particular the contractual strategy adopted when the maincontracts 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 contractualstrategy 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 fordistributing these various activities between different contractors should be the subject of ageneral study by the company managing the project, so that the overall project costs andtimetable can be optimised. It should be noted that this process induces a delay betweenservices price rises and impacts in the cost of oil companies. This contractual arrangementhas limited the increase in the technical costs: projects decided in the last 5 years have stillan effect on these costs due to the long development phase. This strategic study, carried outat the start of the project, is usually referred to as the Project Execution Plan (PEP). The finalcost 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 ofthe PEP can affect the ultimate capital costs. The first of these parameters is the method bywhich the various contracts are remunerated. The second is the maintenance of competitionbetween contractors in all the project stages.
A. Different methods of contractual remuneration
The various contracts will be awarded within a framework which includes remunerationterms 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 minimumcost because this is of no advantage to him. There is therefore a tendency for costs to mountand timings to slip relative to the initial estimates.
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This contractual basis is appropriate to phases of the study in which the basis of theproject, 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 overallproject, and it is vital that the necessary resources are made available and that the work doesnot suffer as a result of relentless cost-cutting. This is the time when the installations to beconstructed are being defined technically, and the quality of this work provides the best guar-antee that the project will be completed within budget and on time. For large constructionprojects, on the other hand, day-rate contracts should be avoided, as overruns on multi-million dollar projects can be extremely costly.
In a foot-rate contract the contractor is remunerated according to measurable quantitiesof work carried out (volumes of earthworks, tons of piping installed, etc.) based on a unitprice schedule appended to the contract. This form of remuneration may be appropriate inthe initial phases of construction when the works have still not been fully defined and a fixedprice cannot yet be set.
This form of contract only passes part of the financial risk to the contractor. It alsopresents similar risk of overruns to the day-rate contracts.
Unlike a day-rate contract, a turnkey contract remunerates the contractor for the supplyof a complete installation (where appropriate with performance guarantees) without referenceto the time spent and materials used. Only the result counts. The contractor has to estimatethe cost of the proposed works on the basis of a call for tenders prepared by the petroleumcompany, and prepare a fixed-price bid for carrying out all the work, including an elementwhich compensates him for his risk, and his profit.
For the oil company, this formula has the merit of constituting a formal commitment onthe part of the contractor to complete the work on time and at minimum cost. The fact thatthe contractor has to bear the cost of an overrun gives him every incentive to keep to theinitial estimates.
The oil company needs to be aware of the fact that if a turnkey contract is to be effectivethe work to be carried out must be defined in a precise, complete and definitive manner. Anywork not covered by the contract is likely to be billed at a rate which reflects the fact thecontractor will be the only one able to carry out the work required.
Turnkey contracts are therefore suitable during the construction phase when the designand technical studies have been completed and the project definition has been “frozen”. Inpractice it is often necessary, in order to stick to the timetable, to award contracts before thedefinitional studies have been fully completed. In such cases it is up to the oil companymanaging the project to ensure that the timing is such as to ensure an optimum trade-offbetween cost and time.
In the foregoing we have presented a simplified picture of the various contractual optionsopen to oil companies in implementing development projects. In reality it is up to them toadapt, mix and coordinate these various possibilities depending on the realities of the situ-ation, so as to optimise the overall economics. Particular attention is needed to ensuring thatthe various contractual interfaces between the petroleum company managing the project andits main subcontractors are clear and well coordinated. Special care needs to be taken thatresponsibilities are well delineated, and that there are no overlaps or gaps.
B. Maintaining competition between contractors
The other vital measure in reducing the final cost of a project is to maintain competitionbetween contractors when contracts are awarded.
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The price of executing a project can vary significantly (i.e. by 20–30%) depending onwhether or not there is genuine competition between contractors or the price was imposedby a contractor acting monopolistically. If it is not careful, such a situation may be of theoil 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 tominimise the need to link up separate modules was in itself a good idea. However this ideawas taken to extreme lengths, so that modules became so large that there remained only onecontractor with the necessary equipment or a lifting barge of sufficient capacity, with theresult that prices became prohibitive.
b. LNG plants
Over the years petroleum companies have got into the habit, for reasons of technicalconformity, of using the same proprietary liquefaction process and the same contractors forthe construction of LNG plants. A quasi-monopoly has therefore arisen between a fewcontractors, and this has pushed prices artificially high. This situation has in turn tended toreduce 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 proprietaryprocesses 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 erecthigh-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 otherongoing requirements are met, such as workplace safety, environmental protection, plantsecurity, quality and reliability.
The project organisation must have regard to these different constraints, but will beheavily influenced by the contractual strategy adopted. The project manager will in any casemonitor the critical activities directly, as far as management is concerned, by keeping tabson the costs and planning, and in the key technical areas, which are often metallurgy, instru-mentation and power.
Costs will be controlled particularly tightly. This will be achieved by using specialistsoftware which allows rigorous budgetary monitoring and an ongoing exchange of data withthe different groups involved with the project, whether from the client organisation or thefinancial department of the company.
The measures to control project costs will be accompanied by a series of reviews orinternal or external audits aimed at optimising the safety and the quality of the installationsunder construction. Given the magnitude of the investments involved in petroleum devel-opments, all oil companies have developed strict and planned control procedures in theseareas.
In some countries, local content policy means that much of the investment is made in thelocal market. In that case, international service companies need to establish a permanent localpresence to get fully involved. However, questions exist around the ability of the supplysector to meet demand in term of local equipment and local human resources with theadequate skill sets.
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4.7 THE PETROLEUM SERVICES SECTOR
The petroleum services sector, or more fully the upstream oil and gas supply and serviceindustry, is not easy to define as it embraces activities of a very heterogeneous nature. Itincludes geophysical activities (the acquisition, processing and interpretation of seismicdata), drilling and associated services, engineering and design, subsea engineering (pipelinelaying) and the construction of platforms (shipyards). In addition there are hosts of manu-facturers of tools (for geophysics and drilling), metal construction and mechanical engi-neering firms. What all these companies, whether large, medium-sized or small, have incommon 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 countryto develop national hydrocarbon resources. The U.S. has long set the pace for the petroleumindustry worldwide; it has developed a powerful petroleum services industry which includesmany companies which are global players.
In the United Kingdom, although drilling began in the 1960s, it was the first oil shock in1973 which really rendered exploration and production projects profitable and permitted theemergence of a national petroleum services industry which, on the back of its success in thedomestic market, rapidly took on an international dimension.
In Norway the first seismic profiles date back to the 1963. At that time the Norwegiangovernment decided it would control exploration and production on its continental shelf. Thepetroleum services industry has developed in three stages: in the 1970s service companiescooperated with other countries with petroleum experience. In the early 1980s, nurtured byheavy protectionism and the publicly owned national oil companies (Norsk Hydro andStatoil) the large petroleum industry players emerged. Since the late 1980s these companieshave been established themselves on the international market.
In France the state played a role in helping the home-grown petroleum services industryto develop, despite the lack of a domestic market for these activities. But the Frenchcompanies, which cover almost the entire spectrum of activities in this sector, have becomemajor players in markets such as the North Sea and the Gulf of Guinea, and have therebysucceeded in gaining access to the international market.
Apart from these main actors, China and South Korea, have significant petroleum servicesindustries.
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 ofthree 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 ofexisting installations, only part of which benefits the petroleum services industry. Thismarket is worth roughly $50 billion/y.
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• The balance comprises the sums invested by the petroleum services companies themselvesin new equipment (construction or renovation of drilling rigs, seismic, pipe-laying orsupport vessels) and data acquisition systems (seismic, logging while drilling, etc.). Theseexpenditures are difficult to evaluate, but vary between $10 and 15 billion/y.
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0
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Figure 4.27 Total investment in exploration and production in differentareas (Source: IFP Energies nouvelles).
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Figure 4.28 Number of active seismic teams, onshore and offshore(Source: IFP Energies nouvelles).
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Over the last two decades the petroleum industry has undergone a transformation as aresult of factors which affect the level of investment in the upstream industry: oil shocks andcounter-shocks, major technological advances, large gains in productivity and radical restruc-turing.
In the first half of the 1980s upstream investments by oil and gas companies were rela-tively 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 ininvestment, 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 capitalflows in the upstream sector. In 1997 investments broke through the $100 billion barrier, anall-time high in current dollars. During the period 1994–1997 there was therefore stronggrowth 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 oilprices, but also, and especially, by increasing costs.
In 2009 the trend was reversed, with investments falling by an average of 16% (dropping37% in North America but only 8% elsewhere in the world). The total of G$406 was G$80less than in 2008, due to an economic environment that hardly encouraged companies toinvest in developing new production capacity.
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, buteven the biggest failed to emerge unscathed. Early in 2009 for example, Schlumberger andBaker Hughes were obliged to implement extensive redundancy plans.
Depending on the sector concerned, this fall made itself felt in different ways.
0
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Figure 4.29 Number of drilled wells (Source: IFP Energies nouvelles).
In the geophysical market, seismic business continued to expand, increasing by 8% overthe 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 offshoreactivity. Nevertheless, geophysics firms saw falls in their sales and profits figures due to rene-gotiation of contracts for lower prices.
The leader in this sector continues to be CGG-Veritas (CGGV), followed by two othersector 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 itsmarket. Nabors, Helmerich & Payne and Ensign, sector leaders, registered substantial reduc-tions in their annual sales.
Conversely, rigs at sea withstood the trend well, increasing slightly by 2.5%. Transoceanremained the leader with 25% market share, ahead of Diamond Offshore and Noble Drilling.
Offshore construction has continued to progress, expanding by 7%. The projects breakdown 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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2004 2005 2006 2007 2008 2009
North America
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Figure 4.30 Number of offshore wells (Source: IFP Energies nouvelles).
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5.1 THE KEY ISSUES
5.1.1 Ownership of hydrocarbons and the sovereigntyof the State over natural resources
Two questions arise regarding the ownership of hydrocarbons. Firstly, who owns theseresources while they are in the ground, either before or after their discovery, but before theirextraction? And secondly, who owns them after their extraction from the subsoil, and at whatpoint 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 includeshydrocarbons) are the property of the State. The State monitors petroleum activities and inter-venes as custodian of the public interest, in particular when it licences individuals or orga -nisations 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 consid-erable 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, andhydrocarbons belong to the owner of the land by accession. This is the system applying inthe United States on private land, i.e. excluding federal or state-owned lands. The owner cangrant leases to any person he chooses, and in return receives a royalty. But even under thisregime the right of ownership is limited by the powers exercised by the State in the generalinterest to guarantee security and the preservation of these resources.
In all other countries, on the other hand, landowners have no rights or claims on thesubsoil resources, these being the property of the State.
5Legal, fiscal and contractualframework
B. Ownership by occupation
Under this regime, the mineral rights belong to the first occupant of the land or to theperson 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 Statedetermines, by virtue of its power of patronage, the conditions under which the explorationfor and production of hydrocarbons, which constitute part of the national wealth, will takeplace. The State grants mineral rights (leases or concessions) to the companies it chooses atits discretion, a process which may involve competitive bidding. The companies chosen arerequired 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 ownershipare also laid down by the State. This is the system which applies in most industrialised coun-tries.
D. State ownership
In this approach, which has its roots in the feudal system, hydrocarbon resources are ownedby the State (the sovereign) and form part of its estate. Hydrocarbon exploration andproduction are governed by agreements or contracts made between the State and the companyit chooses. This was the system which applied in the Middle East and Latin America, andinvolved applying application of the rule of the “inalienable and imprescriptible property ofthe State”.
The principle of State ownership results in a State monopoly, companies acting as merecontractors with the task of developing the assets of the State. This is exemplified by thesystem 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 theprinciples of State discretion or State ownership, the State exercising its sovereign rights overthe 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 ofownership; 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 istempting to assume that State ownership is analogous to the relationship between an indi-vidual and his private property, including all the prerogatives which this confers on anowner over his assets.
English-speaking countries use an expression difficult to render in other languages “vestedin the Crown/State”. This expression seems to convey a concept of management rather thanthe complexity of ownership.
Other national legislations classify mines, including hydrocarbon deposits, as belongingto the State without being too specific about it. However mineral resources do not fall easily
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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 thebenefit of all citizens, but nor are mines subject to the rules of private property. Someauthors consider that mineral resources constitute a category sui generis of State assets,referring to them as “national property, intermediate between the two traditional forms ofState patrimony”, or even, in the view of some South American jurists, as an “eminentdomain” or “special domain” of the State.
B. State sovereignty
Developments in the way the international community interprets the concept of the sover-eignty of the State are particularly important in practice. Since 1952 the United NationsGeneral Assembly (Resolution 626) and then the United Nations Conference for Trade andDevelopment (UNCTAD) have repeatedly reaffirmed “the inalienable right of all States todispose of their wealth and natural resources in accordance with their national interests andbased on respect for their economic independence” (1960). Resolution 1803 of 1962, restatedin the third general principle adopted by UNCTAD at its first session in 1964, calls on Statesto exercise this sovereignty “in the interests of national development and the well-being oftheir peoples”.
Subsequent declarations have been more radical, and the Resolutions adopted on 1 May1974 by an extraordinary session of the UN General Assembly on raw materials introducedthe 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 sovereigntygives states the right to safeguard their mineral resources by exercising effective control overthem.
This principle was not to apply to mineral resources in the high seas. The United Nationsdesignated (Resolution 2749-XXV of 1970) these as a “common patrimony of man” underthe stewardship of sovereign states.
The State exercises sovereignty over its national territory, the continental shelf and the 200mile exclusive economic zone in the case of coastal nations. The UN Convention on the Lawof the Sea (UNCLOS) of 1982, signed by 135 countries, sets forth the relevant principles inthis regard. The interpretation of these principles can sometimes pose severe difficulties, asin the case of the Caspian Sea, where the determination of sovereignty has been a matter ofdispute 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 isacknowledged 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 requirethat a public interest is demonstrated and that fair and prior compensation is paid. Nationali-sation without or with inadequate compensation discourages new petroleum exploration.
The basis on which compensation is determined remains a moot point. In equity it couldbe 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 installationsor the present value of future profits derived from producing the known reserves. Such a basisis contested, however, because the reserves are the property of the State. The most commoncriterion adopted is that of the accounting value of the installations, as determined by an
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expert, with the possibility of resorting to international arbitration, although the latter is notaccepted by all countries.
It should be noted that problems of a similar order occur where the State, while stoppingshort 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 ofcourse more acceptable to the investors than nationalisation.
In contrast, the 1990s have seen a growing tendency in many countries towards the totalor 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 canbe 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, somecountries 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 actionor indirect action.
5.1.2.1 Direct action by the owner
The owner of the mineral rights can carry out exploration and production activities forhydrocarbons himself/itself:
– As the owner of the land (U.S.), whether a private individual, a state or the federalgovernment;
– In its capacity as the State, through the intermediary of public bodies (former USSRand Eastern European countries until 1990), or through national companies holding afull or partial monopoly (Latin America, Middle East) and where necessary calling onthe 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 propri-etary 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: firstan exploration license and, in the event of the discovery of commercial hydrocarbonresources, an exploitation license usually called “concession”. The license holder has the soleexploration and production rights for a certain area and for a certain period. Furthermore hehas the beneficial use of the products extracted subject to fulfilling certain obligationstowards 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 impartingmineral 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 thiscompany as representative of the State. The contractor is simply the exclusive provider ofservices to the State, and bears the technical and financial risks of exploration. In the event
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of a discovery he has the exclusive right to develop and exploit the resources, and will receivea remuneration equal to a proportion of the production (whence the name). The State receivesthe remaining proportion of the production.
In either case, certain countries stipulate that, in addition, the State may participatedirectly in the operations as a partner of the license holder or contractor, taking on the samerights 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 offerthe State a number of advantages. Until the late 1980s such arrangements were to be foundin many countries, the participation rate reaching 50% or more, but they are tending to bereduced or even disappear completely. However since 2005, some producing countries havere-introduced participation rates higher than 50% (Algeria, Venezuela).
5.1.3 Regulatory options
The foregoing shows that there are two opposite approaches to establishing a legal frameworkfor 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, Australiaand Latin America, the legal framework is defined in detail and in a non-discriminatorymanner by legislation and regulations;
– In the contractual approach the relations between the State and the companies are essen-tially defined contractually, and are often discretionary. This is the system applying inmany 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 refiningand 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 majoramendment, 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 shortterm and, in the medium term, protect the State if major discoveries are made. Modern legis-lation provides a flexible framework, confining itself to laying down the principles, leavingthe details, modalities and economic parameters to be dealt with in implementing regulationsand contracts. The delicate balance which needs to be achieved is often the subject of majordiscussions between the legislature and the executive.
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However legislation can be more or less flexible, depending on the constitution of thecountry 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 amatter for the legislature, which means that taxes are set in the law without leaving anymargin for negotiation. Under this regime, petroleum taxes can be amended periodically byfinance acts, and apply equally to all operators.
Other countries adopt a more flexible approach, and make use of contracts which leavea 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 oper-ations 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 natureof 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 mostappropriate approach. Over the last 30 years many countries have adopted a petroleumlegislation 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 aspecific regime for the taxation of the profits from petroleum exploration and productionactivities.
• 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, andparticularly with negotiating and signing petroleum contracts. This body will also, eitherdirectly or by delegation, supervise petroleum operations and monitor compliance with theapplicable legislation.
Some or all of these powers may be delegated to a national oil company. This can leadto conflicts of interest because the latter then has two theoretically separate roles: the repre-sentative of the State in its capacity as regulator but also a partner associated with othercompanies in joint petroleum ventures.
In order to avoid this kind of conflicts, several countries have established separate bodiesto 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 lawand implementing regulations. This fairly inflexible approach is what happens in the indus-
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trialised countries and older legislation inspired by the French model in Africa. An alternativeapproach is to define the broad principles, particularly in relation to taxation, by referenceto a model contract prepared by the competent authority. This is a more flexible solutionwhich allows the regime to be established in the contract. This model contract, which doesnot form part of the law, can be adapted to allow for the nature of the potential discoveriesof hydrocarbons and the petroleum context.
5.1.4.6 Implementing regulations
The petroleum law establishes the legal framework. The regulatory detail is spelt out inimplementing regulations enacted in the form of decrees and regulations. These deal withadministrative procedures, the technical aspects of operations, the environment, workplacehealth and safety as well as abandonment procedures when production comes to an end. Theycan be very detailed in countries such as the U.S., Canada, the United Kingdom and Norwayin 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 tech-
nical or economic reasons;
• To maximise the revenues of the State while securing, if possible, returns to investorscommensurate with the risks run during exploration;
• To establish an attractive, fair and stable fiscal and contractual regime, capable of adaptingto conditions as they evolve over the long term, thereby maintaining a satisfactory activitylevel;
• To supervise and monitor operations in consultation with the companies, while ensuringthat 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 onmany factors, both for the State and for oil companies, and can also change over time inresponse to circumstances, e.g. developments in international hydrocarbons markets, thepotential and position of the country (producer or not, exporter or not, etc.), the importanceof oil in the national economy and the company’s own particular strategy.
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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 andcontractual 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 (thisnotion has already been considered in Chapter 4). Depending on the parameters mentionedabove, 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 bywhich 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 oilindustry.
A contract for petroleum exploration or production deals with the relationship betweenthe State (or the national oil company representing the State) and the license holder orcontractor (which may comprise a consortium of companies formed exclusively for thispurpose). This is the type of contract considered further here.
When the license holder or contractor comprises a number of partners, the associationbetween these partners is formalised by means of a Joint Operating Agreement (JOA) whichspells out their relationship in regard to decisions and the conduct of operations, based ontheir stake in the partnership, under the responsibility of an operator chosen from amongstthe partners.
5.1.8 Breakdown of petroleum contracts by type
Tables 5.1 and 5.2 show the incidence and breakdown of petroleum exploration andproduction contracts according to:
– The different countries;– Geographical region.
It should be noted that several regimes may coexist in the same country. An estimateshows that most of the volume of hydrocarbon production is still governed by concessionregimes. This is due to the fact that this type of contract predated the production-sharingarrangements 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 previoussection, i.e. which confers exclusive rights on the beneficiary) generally consists of adocument of, typically, about a hundred pages, with several sections: the preamble, the maintext, and appendices which form an integral part of the contract.
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Type of contract
Concession (with possible participation bythe State or by joint companies)
Production sharing contract
Risk service contract
Production by the national oil company or alocal company (in countries already opento foreign investment)
National oil company with absolutemonopoly
Main producing countries
Most OECD countries (Australia, Canada,US, UK, Norway, etc.)
Abu Dhabi, Angola, Argentina, Colombia,Brazil, Brunei, Gabon, Nigeria, Russia,etc.
Angola, Algeria, Azerbaijan, China, Congo,Egypt, Gabon, Indonesia, Kazakhstan,Libya, Malaysia, Nigeria, Peru, Qatar,Russia, Turkmenistan, Trinidad andTobago, etc.
Algeria, Iraq, Iran, Kuwait, Qatar,Venezuela, etc.
Algeria, Brazil, Iraq, Iran, Russia,Venezuela, etc.
Saudi Arabia, Mexico
Table 5.1 Types of exploration and production contract and countries in which prac-tised.
Concession Production sharing Service Absolute contract contract monopoly
Exporting Colombia Bolivia Ecuador Mexico
countries Peru VenezuelaTrinidad and Tobago Trinidad and Tobago
Producing
Argentina Chile
countries
Brazil CubaBarbados GuatemalaCanada SurinamUS
Non-producing
Bahamas Antigua Honduras
countries
Belize Aruba JamaicaCosta Rica Dominican PanamaParaguay Republic Puerto Rico
Guyana SalvadorHaiti
Table 5.2 Geographical distribution of different types of contractual basis (OPECcountries shown in italics).
1. America
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2. Western Europe
Concession and Production Service contract joint companies sharing contract or absolute monopoly
Exporting
Russia Russia Most production is
countries
Other CIS Republics: presently carried out Azerbaijan, Kazakhstan, by State enterprisesUzbekistan,Turkmenistan
Concession regime in all countries (apart from production sharing contracts in Cyprus,Greece, Malta).
3. Central and Eastern Europe, CIS countries
Production Service AbsoluteConcession sharing contract contract (or partial)
monopoly
Exporting
Abu Dhabi, Dubai, Sharjah Bahrain Oman Iran Saudi
countries
(United Arab Emirates) China Qatar Qatar ArabiaBrunei Indonesia Syria IraqOman Iraq YemenPapua New Guinea Malaysia Vietnam KuwaitVietnam
Producing
Australia Bangladesh
countries
New Zealand Burma (Myanmar)Pakistan IndiaThailand PhilippinesTurkey Thailand
Non-producing Fiji Cambodia Nepalcountries South Korea Laos Sri Lanka
Mongolia
4. Asia
The preamble enunciates a number of general statements (customarily beginning with theword “Whereas”) whose purpose is to set the detailed provisions of the contract in theirbroader context, both legal (for example references to existing legislation which provides forthe type of contract in question to be concluded) and political (for example references to therole 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, termof validity and the rights and obligations of the respective parties. Broadly speaking theprovisions fall into four categories:
– Technical, operational and administrative provisions, which deal with practical aspectsrelated to the conduct of operations during the different phases;
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5. Africa
Concession Production Service Absolute sharing contract contract monopoly
– Economic, taxation, financial and commercial provisions, which deal with how theprofits 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 contractualrelationships 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 aboveheadings. Most of these are to be found in any petroleum contract, but some are specific tocertain 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 mayapply to different phases. The first is the exploration phase, during which the contract holdercarries out geological and geophysical surveys and drilling operations with a view to iden-tifying 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, whichoccurs when hydrocarbons are found which are judged to be commercially viable. This phasecomprises a period of development followed by a period of production. As long as he hasfulfilled his contractual obligations, the contract holder can withdraw at any time during orat 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 opentheir industries up. Increasing numbers of contracts cover zones already explored and whichalready contain hydrocarbons. These might be discoveries which are not yet exploitedbecause there is a need for technologies or funding beyond the capabilities of local oper-ators (typically national oil companies). Or they may have been already subjected toexploitation activities, and now be considerably depleted and in need of rehabilitation orenhanced recovery which has not been carried out for the same reasons. In these cases thecontract will take account of this specific situation by omitting the exploration phase andcommencing the development phase immediately. When no exploration is necessary the risksare lower, and the State may require that this fact is reflected in the financial arrangementsagreed.
The situation can be even more complex where a contract is for further exploitation froman existing field but when further exploration is authorised, for example at greater depthscorresponding to horizons not yet explored.
These considerations demonstrate the need to define very clearly the terms used in acontract and the effective operations to which they relate, so as to avoid subsequent misin-terpretations of the contract or disputes.
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5.2.2.2 Exploration phase
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 theexploration zone and to discover hydrocarbons;
– It should be short enough discourage the contract holder from proceeding undulyslowly, thereby occupying for too long a large area which might be of interest to othercompanies.
In order to reconcile these two criteria, the normal practice is to provide for a relativelylong total exploration period (generally 5–10 years), but to subdivide this period up into anumber of subperiods. The contract holder therefore has an initial period, renewable for oneor two succeeding periods. At the end of each subperiod he may renew his entitlement fora 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 thecontract 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 explo-ration work still in progress.
Up until 1986 the general trend was for a reduction in the duration and the size of theexploration area. Since then this trend has been reversed as a result of the changed petroleumenvironment, particularly in deep offshore locations.
The initial exploration period begins when the contract takes effect. Because this isgenerally the longest of the exploration sub-periods, and in order not to quarantine a largearea without any exploration taking place, it is normally stipulated that the contract holdermust begin work within a certain period (typically 3–6 months) from the effective date ofthe contract.
B. Contract area and relinquishment
The initial area covered by the licence or the contract zone is specified by means of a mapshowing the boundaries and indicating the coordinates of reference points. It is often definedby the State before blocks are created, rather than by the applicant, particularly where thereis an international call for tenders. Sometimes the size of a licence or a zone available forgranting is limited by legislation. This area varies considerably depending on the particularcircumstances applying.
Although in some cases large areas are still granted to contract holders, authoritiesgenerally tend to allocate zones of medium size (of the order of 1000 to 5000 km2). If thearea is too large there is a risk the holder will only explore a small part of it. The rest willtherefore be “frozen”, thereby excluding other companies which might want to invest in thatzone. It is important that the State adopts a policy which ensures the coherency of explo-ration programmes.
Usually the contract holder cannot hold on to the entire area indefinitely. It is customaryfor a minimum reduction to be made in the area of the contract zone when an application ismade to renew the exploration term. In most contracts which provide for an initial periodand two additional exploration periods, the first and second renewals are accompanied by
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the mandatory relinquishment of up to 25–50% of the initial area, except where specialcircumstances justify a smaller or no relinquishment.
The contract holder is usually free to choose the zones to be relinquished. To prevent himfrom relinquishing a large number of fragmented pieces, constraints can be imposed on theshape 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 explo-ration sub-periods (initial period and additional periods) which the contract holder must carryout if he wishes to renew his rights. This programme is normally subdivided by type of oper-ation: 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 or3D surfaces.
The minimum drilling programme is defined in terms of a minimum number of wells tobe drilled; this number will depend on the duration of the exploration period and on the areacovered by the contract. Minimum depths for the drilling (or specific objectives to beattained) will also be specified. And finally the contract needs to state whether delineationand 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 eachcontract holder will undertake sufficient exploration work obligations to ensure that thepetroleum potential of the zones granted will be properly studied.
The contract usually provides that if during one of the exploration periods the contractholder exceeds the specified minimum exploration work obligations for that period, theadditional work can be carried forward to the following period, thereby reducing the oblig-ation in that period.
Sometimes the obligation imposed on the contract holder is defined in terms of theminimum expenditure on exploration work, either as a total or broken down by the varioustypes of work.
The contract needs to specify whether the contract holder must comply with both workand expenditure obligations or only one of these, and what the priority is. Usually work oblig-ations take priority over expenditure obligations. In that case the only expenditure stipulatedin the contract relates to the penalties applying in the event of failure to complete the spec-ified work.
In order to ensure that the contract holder can discharge his obligations to invest or carryout 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 explo-ration period. The contract provides that where there is a partial relinquishment of the area thereis no diminution of the obligations in the current period, and that of the area is totally relin-quished, 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 requiredto notify the competent authority of this fact. If he considers that the discovery is worth an
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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 theresults obtained from the appraisal and his conclusions, and specifically, whether he regardsthe find as commercial and whether he plans to develop it.
Where the contract holder concludes that the discovery is economically marginal or non-commercial, some contracts may provide that he can propose to the State modifications tosome of the provisions of the contract so that the contract holder is able to exploit thediscovery. These proposals must be accompanied by economic studies performed by thecontract holder which demonstrate the effect of the proposed changes on the projecteconomics. 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 topropose and implement a development programme.
Some contracts provide that if a discovery is considered non-commercial the contractholder must hand the discovery over to the State if the authorities wish to exploit it beforethe normal expiry of the contract. Special clauses may apply to gas discoveries (seeSection 5.2.5).
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 isa matter for the contract holder: it is the investor who will bear the risk and who is in aposition 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 discoveryon the basis of which a contract holder can be obliged to undertake a developmentprogramme. This is based on certain objective criteria related to the volume of hydrocarbonsdiscovered or a certain productivity per well achieved over a certain period. This approachhas not really caught on, however.
When the contract holder declares a discovery to be commercial, he prepares a devel-opment 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 ashort period. The development plan is an important document which deals with all the tech-nical and economic aspects: reserve estimation and future production profiles; developmentschedule, wells and production installations, storage and transport, timetable for completionand commencement of production, estimates of capital and operating costs; economic eval-uation establishing the commercial viability of production; the environment and safety; theabandonment plan when production ends.
B. Production period
After a development plan has been adopted, the holder of the exploration rights is entitledto exclusive rights to exploit the resources discovered. The duration of the production periodis variable, depending on the agreement. Production is usually authorised for an initialperiod, typically 20–25 years, which may be renewable for 10 years or more if furtherproduction is economically viable.
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The grant of a production licence involves an obligation on the part of the contract holderto develop the field in question in accordance with the development plan. He is expected toproduce 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 tothe authorities details of the precise configuration of the field which emerges from the delin-eation. The production zone corresponds to the extent of the field. Within a given explorationzone 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 declaredcommercial. It can occur that the improved knowledge gained after several years ofproduction means that the production zone needs to be enlarged.
To cater for this possibility, a provision can be included allowing the production zone tobe enlarged so that it corresponds with the new area of the zone which has now been foundto be exploitable, providing that the additional area lies within the area of the explorationzone still held by the contract holder.
D. Unitisation
When an oilfield is discovered which straddles several different exploration zones grantedto different contract holders, the contract needs to contain a clause which ensures that therecoverable reserves are exploited in a coherent manner (for example by appointing a singleoperator, adopting a joint development and production plan, etc.).
Such a clause, known as a unitisation clause, has to be common to all the agreements madebetween the State and the contract holders, since in the event that such a clause has to beinvoked, the rules must be identical for all.
The special case of oil and gas fields which straddle national frontiers has to be dealt withby means of international agreements, as in the North Sea between the British and Norwegiansectors. When a dispute arises between several countries, this can be resolved by creatingjoint development zones governed by ad hoc statutory and fiscal arrangements, as in the cele-brated Neutral Zone between Saudi Arabia and Kuwait, the Timor Gap between Australiaand 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 spec-ified. These may involve transferring all installations to the State without charge or decom-missioning the wells and the disposal of the installations at its own cost. Contractsincreasingly specify an abandonment plan, submitted to the authorities in advance, containingspecial fiscal provisions if appropriate, and providing for cost allowances to be set aside inadvance to fund the abandonment costs. This may be a costly operation in offshore zonessubject 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 ornot there are detailed technical regulations in force. This requirement relates particularly to
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resource conservation (optimum production) and safety. Nowadays environmental protectionhas also become a very important issue, and new standards are being formulated, includingthe requirement to carry out an environmental impact assessment and to monitor continu-ously in ecologically sensitive areas.
B. Annual work programmes and budgets
Before the start of each year the contract holder must submit to government a workprogramme together with a budget for the coming year, broken down by type of activity orexpenditure (exploration, evaluation, development, production). The programme is provi-sional; and changes may be proved necessary as work proceeds. These are permissibleprovided the objectives of the work programme remain the same.
C. Administrative supervision
Petroleum operations are monitored by the State, acting through the department responsiblefor mining or hydrocarbons within the relevant ministry. The contract holder must informthis 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 arepresentative to the site. The department can also ask the contract holder to carry out anywork 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 holdermust submit, at specified intervals, activity reports detailing the work carried out, supportedby technical data where necessary.
He must also submit to the State a copy of all the data obtained during operations as wellas any information describing the subsoil: geological and geophysical data, logs, results ofanalyses, measurements made in production wells, pressure trends, studies of secondaryrecovery, estimates of the reserves in place and recoverable. It must also submit all the dataon the production itself: quantities produced from the field, hydrocarbon sales, quantities ofproduct shipped, including data on the purchasers, countries of destination, price of eachcargo, 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 holderfor a period specified in the agreement. This period varies considerably, ranging from3–5 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 expen-diture. These reports also allow the State to monitor the development of local employmentin the petroleum sector.
E. Training and employment of local personnel
The contract holder may be required to give priority to the employment of local personnelfor its petroleum operations. By their very nature, petroleum operations need experienced,highly qualified personnel, not always available locally. For this reason, this clause is alwaysaccompanied by provisions for the training of local personnel, and this involves setting upa minimum annual budget for various programmes. In some countries employment objec-
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tives are also set, expressed as the percentage of the workforce at a given level of qualifi-cation 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 thatlocal goods and services are used. Use is often made of international calls for tender inawarding contracts, with local businesses being consulted.
Local development becomes a growing requirement in many producing countries. InOctober 2009, Nigeria adopted the concept of “Local Content Bill” to develop the localindustry. Venezuela introduced the concept of “Desarollo endogeno”. In Canada, the oilproducing 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. Explorationcosts are funded by means of equity capital. Development costs can be funded to a largeextent by loan capital. The contract may specify a maximum percentage to be financed byloan capital, as well as other conditions for approval, the conditions relating to the taxdeductibility 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 aredealt 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 toitself participate directly in petroleum operations as a partner of the contract holder, takingon the same rights and obligations in proportion to the level of its participation. The mainpurposes of these provisions are to give it access to petroleum resources, to increase its netrevenues (i.e. after meeting its share of the capital and operating costs) and to increase itsinvolvement in petroleum operations, particularly in terms of increased control, closer super-vision and the transfer of skills.
The State participation usually involves an incorporeal association. The State, usuallythrough the intermediary of a national company, becomes a partner in the contract with adefined share. The relationship between the partners is governed by a participation agreement.The State may enjoy certain specific advantages, for example a “carried interest” wherebyits share of the capital cost is borne by the other partners during the exploration phase, tobe reimbursed later from its share of any production.
The other form of participation is implemented through a joint company. Such anarrangement is less common and can give rise to practical difficulties relating particularlyto the financing the State’s share of the capital, the ownership of the reserves and of theproduction, the payment of dividends and the taxation basis applicable. However Venezuelaadopted 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%.
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Depending on the detailed arrangements, the participation of the State can have a majoreconomic impact because the State does not share the initial exploration risk. And Stateparticipation reduces the shares of the other investors in the production. The State share canbe 50% or even higher in some countries, but has generally declined considerably over the1990s, in some cases to nil. As already mentioned, the opposite trend can be now observedin some major producing countries (Algeria, Bolivia, Venezuela).
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 apoint of delivery agreed by the parties. The price normally used is the FOB price at the exportport by tanker. Where sales are based on the CIF price (cost, insurance and freight) this pricehas to be adjusted to obtain the FOB price.
Sales between affiliated companies should be valued at the weighted mean price for salesto third parties, for the same oil and during the same period, if it is possible to calculate thisprice. If there were no sales to third parties during the period considered, the real market priceis established by considering the mean market price during the same period of crudes ofcomparable quality sold in the country or in neighbouring geographical zones. This price istherefore submitted for discussion and approval by the parties according to a procedure tobe 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 independentexpert 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, butwith effect from 16 October 1973 the OPEC countries decided to set their posted pricesunilaterally. The purpose of this reference price was to avoid discussions about the deter-mination of the real sale price, the posted price being a fiscal reference price used to calculateState 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 gasbecause 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 compet-itive market exists in the United States with a spot price. The price to be taken into accountfor the purpose of the contract is therefore the real sale price to third parties or, for directsales to the government or an affiliated company, the price fixed by agreement between theparties. Sometimes the price of a substitute fuel such as fuel oil is referred to. The pricesfixed in long-term gas sale contracts may be the subject of complex formulae based on theindexed price of a basket of crudes and petroleum products.
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5.2.3.5 Marketing
The contract holder is responsible for the marketing of all the products extracted or of hisshare of those products, depending on the type of contract applying, and is obliged to obtainthe best possible price. There is often a requirement that the domestic market should havea first call on national production. In this case the sale price is either the market price or areduced 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 separateaccounts in accordance with accounting procedures appended to the contract. These proce-dures are set up in accordance with the rules applying in the country concerned, but may besubjected to slight changes to allow them to cater for specific petroleum mechanisms, forexample depreciation procedures, the period of carry-forward of losses and the definition ofpetroleum costs.
The clause in the main agreement relating to the accounts of the contract holder cantherefore be quite short because it will refer to the accounting procedure in which all the prac-tical 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 accountsaudited.
5.2.3.7 Customs regime
Because of their particular nature, petroleum operations enjoy certain customs privileges oradministrative facilities. These relate particularly to the right to import goods and servicesusually free of any import duties or taxes. The import of equipment which will eventuallybe re-exported is often treated as a temporary import only. The contract holder also has theright 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 andproduction, 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 loansraised in other countries.
In other respects, and with the exception of any other provisions in the petroleum legis-lation, holders are subject to the normal tax regime. The taxation of service companies andforeign suppliers presents a difficulty in determining the profit resulting from one-off oper-ations 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 opera-tions, 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;
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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 thecountry, i.e. the operating costs, taxes, etc.;
– Foreign currencies to be converted and bought in the host country.
Some exporting countries have in the past obliged companies to reinvest part of theprofits in the country, in the petroleum or in other sectors. Very often the local tax legis-lation in a country which is already a hydrocarbon producer provides incentives for rein-vesting, for example by making new exploration expenditure immediately tax deductiblethrough 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, representedby one or more ministers, the minister responsible for petroleum affairs or the national oilcompany.
As far as the company is concerned (or companies in the case of a consortium), theagreement is most often signed by a new subsidiary of the parent petroleum companycreated under local law. The latter will therefore guarantee that the contractual obligationsof the signatory company are properly carried out.
In some countries a local joint company with the involvement of the State is set up whena discovery has been made. This company is established to manage the operations but doesnot 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 areacovered by the agreement to other persons provided he observes the conditions imposedunder this clause.
5.2.4.3 Force majeure
In the event of force majeure (an unpredictable event or act beyond the control of theparties, such as a natural disaster, civil unrest, sabotage, war, etc.), the contracting partiesare temporarily relieved of their obligations where these are affected. Once normal opera-tions 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 tobe resolved by referring to technical experts, given the protracted nature of arbitration. Inother cases recourse to the national courts or international arbitration can be considered.
For agreements between developing countries and foreign investors a dispute wouldnormally be referred to international arbitration using procedures established by the inter-national organisations.
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5.2.4.5 Applicable law
The applicable law is usually that of the host country. Where this national legislation isincomplete the contract can provide for the application of the more complete legislation ofanother jurisdiction, for example that of the state of Alberta in Canada (often referred to inpetroleum contracts).
5.2.4.6 Responsibility
The contract holder is responsible, with or without limitation, for any damage (includingenvironmental damage) resulting from his petroleum operations, whether or not due to negli-gence or gross misconduct. The government and third parties have to be compensated forsuch damage. Where a consortium of companies is involved, these companies bear joint andseveral, 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 beenignored, to the revocation of the contract and the forfeiture or withdrawal of the mineralrights (exploration licence or lease). Penalties may be specified for some infringements.Where such forfeiture is challenged the provisions relating to the settlement of disputes willapply.
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 fromexisting 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 ownright as dry or wet gas (non-associated gas).
The production of natural gas has a number of specific characteristics: considerable andtherefore costly infrastructure needed, the fact that it cannot be stored, special transport anddistribution requirements, the need for a long-term and stable market. Special provisions aretherefore included in contracts designed to facilitate gasfield development and production.
As far as associated gas from a commercial oilfield is concerned, the usual procedure isas follows:
• The natural gas is first used by the production facility for its own internal needs (as energysource, re-injected for purposes of enhanced recovery, etc.).
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• If the gas cannot be used by the production facility or marketed it can be flared once theauthorities have been informed and, if necessary, have approved it. But flaring is moreand 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 usuallytaken 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 andthe marketing of the production must be submitted to the authorities. These should demon-strate the commercial potential of the discovery. The deadline can often be extended by3 to 5 years.
• Either the authorities or the contract holder can decide at any time during this additionalperiod to develop the gasfield, the other party being free to participate in this developmentif it so wishes.
• Economic and fiscal incentives may also be put in place in order to lower the commercialthreshold. Such measures have allowed small projects for supplying gas to local powerstations 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 onlyflared in certain conditions defined clearly in the agreement, and where there is no prospectof 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 thediscovery and identify potential markets.
5.3 CONCESSION REGIMES
5.3.1 General framework
Under a concession arrangement the State grants the contract holder exclusive explorationrights (exploration licence), as well as an exclusive development and production right (leaseor concession) for each commercial discovery.
A contract established under a concession regime will contain the provisions describedabove. This may involve an actual petroleum agreement or simply the application of generaland special conditions associated with the grant of an exploration licence or a lease withinthe framework of current petroleum legislation and accompanied by a schedule of conditionsspecific to the licence.
The features which distinguish a concession agreement are the ownership of the hydro-carbons produced, the ownership of the production installations and the items of revenue tothe 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 inSection 5.1.3 is taken, a concession comprises a contract in law, and this offers someprotection to the holder in the event of subsequent changes in the petroleum law.
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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. ThisState ownership of the subsoil and of the mineral resources is very common, and applies inmost 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, subjectto the payment of a royalty in kind (oil and natural gas) or in cash, from the time they areextracted 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. Whenit expires the fixed installations usually revert to the State without compensation for theholder; the State is free to use them at its convenience if it considers this would be econom-ically attractive. Alternatively the State can require the holder to remove at the latter’sexpense some or all of the installations if it does not wish to use them. The holder is entitledto 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 revenuecategories 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 contractualnature of a concession, so that the latter affords protection to the holder in the event of achange in the petroleum tax law. In most countries therefore, even where there is not actuallya 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 fromtime to time. There have, for example, been a series of reductions in tax rates in the 1990sin the UK, Norway and the Netherlands, and the petroleum industry has also benefited fromthese reductions. However, the UK has again introduced a specific petroleum tax whichresults 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 contractis signed or the exploration licence is granted. This bonus is paid to the State in one or moreinstalments, and its amount varies depending on the contract, but can amount to severalmillion or even hundreds of millions of dollars. This represents a major financial commitmentfor the holder, particularly since it is payable before production commences, and it willtherefore have a fundamental impact on the profitability of the project. From the country’sperspective 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 explorationlicences on the basis of a bidding procedure. The payment made by the eventual holder
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following this procedure is analogous to a signature bonus, however. This procedure has beenadopted 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 beendeclining, indeed has largely disappeared except in countries formerly closed to the directinvolvement of the international oil companies, but which are now opening their borders.Representative examples are Venezuela, where very high bonuses were achieved in the firstround of bidding for exploration blocks, organised in 1998, Brazil in 1999-2000, the JDZbetween Nigeria and Sao Tome and Principe in 2004, Libya after 2000.
5.3.2.5 Exploration surface fees
The holder may be required to pay annual surface fees to the State or other specified organ-isation proportional to the area to which the exploration licence applies. These fees usuallyremain fixed during each exploration period. Each time the exploration period is renewedthese fees usually rise in proportion to the mandatory relinquishment. If, for example, theminimum mandatory relinquishment at the first renewal is 50%, the fees per unit area forthe 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 peryear), and do not impose a significant burden on the holder unless the area covered by thelicence is very large.
5.3.2.6 Production bonus
Production bonuses are one or more sums paid to the State which are triggered when certainproduction thresholds are reached on a field. The contract sets forth the sums to be paid whenproduction first reaches certain levels (usually expressed in bbl/day) for a stated period. Itcan also provide for a “discovery bonus” to be paid.
These production bonuses are very variable in magnitude, and depend on the oil potentialof the country in question. Like the signature bonus, these bonuses can represent acommitment 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 taxpurposes. Some treat these bonuses as being deductible while others do not consider themto 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 surfacefee on the holder proportional to the area over which the concession extends. This paymentis analogous to the fees paid during the exploration phase. Since the area over which theconcession extends is much smaller than that covered by exploration, the fees per unit areaare 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 holderto the State in cash or in kind. It is effectively a tax directly proportional to the value ofproduction, 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 anumber of other parameters which must be carefully specified.
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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 slidingscale is sometimes specified in the contract, depending on the production level. There arevarious options, including:
– A variable percentage which depends on the daily or annual production (per well, perreservoir, per concession, etc.). In order to prevent abrupt changes in the calculatedamount for small changes in production, the percentages apply to incrementalproduction rather than the whole amount;
– A variable percentage which depends on cumulative production since productionbegan;
– A variable percentage which depends on economic criteria such as the R-ratio betweencumulative cash flow and cumulative investment.
C. Ring-fencing or consolidation
In cases where the holder produces from several concessions both resulting from the sameexploration 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 totalproduction from all the concessions.
Where the percentage used to calculate royalties increases with increasing production itis obviously more attractive for the State to aggregate the concessions for the purpose of theroyalty 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 quar-terly or monthly. Where payment is made in cash, the calculated amount of the royalty willdepend on the value placed on production, on the point at which the royalty is calculatedand 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 thepoint 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 purposeof profit tax, i.e. whether as a tax credit (practised historically, but now rare), or as a chargedeductible from the holder’s taxable profit.
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H. Recent trend
The royalty is independent of profit, and becomes increasingly onerous for the investor asthe technical costs rise or the oil price falls. The 1990s have seen a tendency for royaltiesto be reduced or even dispensed with entirely in order to encourage new investment. Thepercentage which was once typically 20% is nowadays more likely to be in the range 0 to12%.
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 isusually calculated separately for exploration and production when the holder is also activein 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 aggre-gating all his exploration and production activities in the country or each concession can bekept separate (the latter case is referred to as ring-fencing). It is financially beneficial to theholder to consolidate together as many activities as possible as this allows him to set off hisexploration 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 hydrocarbonssold and any other revenues to be counted (e.g. the hire of installations to third parties, saleof by-products such as sulphur, etc.).
On the cost side, deductible costs need to be defined very precisely: operating costs, depre-ciation, financial charges, specific provisions and other permitted deductions. Certain costsare shared with operating companies within the group but in other countries, e.g. head officecosts which have to be shared between all its subsidiary oil-producing companies. Thesecosts may also include the cost of technical assistance and non-resident personnel attributableto 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 depreciationbased on the unit of production. A list indicating the categories and depreciation terms foreach type of equipment can be specified in the accounting procedure appended to thecontract.
Some countries allow the holder, by way of tax relief, to write off more than 100% ofthe 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 thoseapplying 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 basedon provisional amounts, a balancing payment being made when the accounts are closed.
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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 petroleumactivities. Historically, the rate was typically at least 50%, and could reach up to 85%. Overthe 1990s there has been a trend for the rate to fall to a figure of about 30–40%. As alreadymentioned this trend has been reverted in some countries, tipically the UK with a figure of50%. Some countries have introduced in the past, and still retain, a special additional taxwhich 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 traditionalconcession, involving the payment of a royalty on production and a tax on profits, no longermet 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 oilrevenues accruing to the State after the two price shocks, which took account of the oil priceand/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 thetax regime applying to oil companies in order to encourage investment, as described inSection 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).
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RoyaltyProfit taxNet profit to companyDepreciationOperating costsDevelopment costsExploration costs
$
Years
Figure 5.1 Typical breakdown of oil revenues under a concessionagreement.
5.4 PRODUCTION SHARING CONTRACTS
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 inde-pendent, and a similar contract was developed in Peru in 1971.
Since then very many countries have adopted this basis. Some are oil exporters: Indonesiaand 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 approachhas also been adopted in countries which export little or no oil, such as Tanzania, the IvoryCost, Mauritania, Kenya, Ethiopia and Jamaica. Several countries in Eastern Europe and theCIS countries have also adopted this system (see Section 5.1.8).
The success of this formula in developing countries and the transition economies is dueto several original features. Of interest, for example, are the nature of the contractual rela-tionship (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 theoryexercise over the activities of the oil company, which acts merely as a service-provider orcontractor to the State.
We shall see, however, that in practice the State can exercise as much control through amodern concession arrangement as in a production sharing contract. In both regimes the oilcompany bears the financial risk, and is generally responsible for running and performingoperations under the supervision of the State. Some concessions may even be consideredmore restrictive than production sharing contracts, in terms both of operating the facility andthe 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 thefollowing 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 andproduction. The oil companies act merely as service-providers or contractors.
• Although the State or national oil company draws on the technical skills and financialresources of the oil company (which lends or prefinances the necessary capital), it retainsownership of a large proportion of the production. The contractor may only receive thelesser share of production to meet his costs and remunerate him for his services. It shouldbe noted that it is this share of the production which appears in the annual company reportsand not the total reserves.
This system is therefore based on the principle of production being shared between theState or national oil company, which owns the mining title, and the oil company (orconsortium). The latter is the operator, responsible for funding and running operations, andit is remunerated, in kind, only where a commercial discovery is developed.
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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 givencountry between contracts and depending on the date of signature of the contract. Only thegeneral principles will be discussed here.
In a production sharing contract the contractor has the right to recover his costs by appro-priating a proportion, not exceeding a certain percentage, of the annual production in thecontract zone. This proportion is known as the cost oil. The balance not yet recovered iscarried forward for recovery in the following year(s) on the same principle. The cost oil isvalued using the market price of crude oil before being compared with the recoverablecosts.
The maximum limit on the cost oil is known as the cost stop, and varies, depending oncountry and the particular contract concerned, but is typically between 30 and 60%, althoughit can be as high as 100%. The value of the cost stop has a profound effect on the economicsof the project. The higher it is, the faster the contractor can recover his costs and the betterthe 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 formercase, 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 basedon nominal value, without indexation).
• Spreading the recovery of development costs over time: equivalent to a system of straightline depreciation over a period of 4 to 5 years (Angola) or a double declining balancesystem (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 onproduction, but where a royalty is paid, the cost oil is calculated on the production remainingafter 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. Theway the profit oil is shared between the State and the contractor has changed substantiallyover the last 35 years.
Originally production was split on a fixed basis, negotiated per contract, independent ofthe characteristics of the discovery. In Indonesia, for example, the 65–35% split betweengovernment 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.
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Later, progressive sliding scales were introduced which depended on the daily productionrate, for example progressive sharing rates increasing from 50–50% for low productionrates to 85–15% for the top tier of production. In 1979 Angola introduced a progressive scalebased on the accumulated production from an oilfield. These scales depend on the charac-teristics of the discovery and in particular, the environment (onshore, shallow or deepoffshore).
Some countries have adopted adjustment mechanisms which allow for changes in the priceof crude (price capping). The government share for that part of the price which exceeds theprice cap, which is indexed, may be as high as 100% (for example Angola, Malaysia, Peruand Indonesia before 1978).
In 1983 a number of countries introduced new production sharing mechanisms, based noton the daily or accumulated production but on the rate of return (or some other measure ofprofitability) to the contractor on a given date. The countries involved were: EquatorialGuinea, Liberia (sharing according to the rate of return), India, Libya, Tunisia, the IvoryCoast and Azerbaijan (sharing according to the R-ratio, which seems to be a more acceptablebasis, see definition in Section 5.6).
There are quite large variations in the profit oil split between different countries andcontracts. These reflect differences in the perceived petroleum potential and costs, the latterbeing directly linked to the characteristics and the location of the discoveries.
The possibility of adapting the terms of a production sharing contract to the potentialexhibited by a discovery is one of the advantages, and therefore explains the success, ofproduction sharing contracts compared with concession, where there is less flexibility duringnegotiations.
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Profit oil (State)Profit oil (Company)Cost oil (recovery of capital costs)Cost oil (recovery of operating costs)Development costsExploration costs
$
Years
Figure 5.2 Typical breakdown of oil revenues under a production sharingcontract.
5.4.2.4 Taxation of profits
To compare different production sharing contracts the treatment of taxation of profits needsto be considered. In production sharing contracts concluded up until 1976 the profit oil splitwas deemed to be calculated after tax, so that the contractor was not subject to an explicittax on profit. His share was net of tax, the latter being assumed to be included in thegovernment’s share. The contractor nevertheless received a tax return corresponding to thisfraction. He was therefore able to deduct this sum from his tax liability in his country oforigin thereby avoiding double taxation.
In 1976 the U.S. Internal Revenue Service (IRS) stopped allowing the notional taxpayment to the State as a tax credit. This led, at the request of the American companies, toa change in the simple form of the original production sharing contract. This involved theintroduction of a separate procedure for determining the tax on profit, using the general rulesfor the taxation of commercial and industrial companies in the host country. This proceduredid 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-taxprofit oil split of 70–30% between State and contractor. The 70% received by the State isdeemed to include 30% representing taxes on the contractor’s profit, because the 30% thelatter receives is free of tax. The corresponding before-tax split is therefore 40–60% betweenState and contractor. The contractor then has to pay tax on his 60%, i.e. 30%, so that his netremuneration 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 thesame as that adopted for the recovery of the petroleum costs, which is not always the casein contracts. There are therefore some differences between the two sharing systems in termsof 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 canopt 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 theproduction equal to the cost oil plus his share of the profit oil. Furthermore the State is freeif it wishes to take its share of the profit oil and market it. This is an advantage when thereis 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 oilcompanies 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 isnot widespread. Two categories of service contract exist, depending on the degree of riskborne by the oil company:
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– Risk service contracts (or agency contracts) in which the contractor only recovers hisinvestment costs where a project proceeds to production;
– Technical assistance or cooperation contracts, which are non-risk-bearing, carrying outworks on the basis of an agreed remuneration.
The terms and conditions of service contracts are very variable. The main provisions aresummarised below.
5.5.1.1 Risk service contracts
These are a time-honoured form of contract between producing country and oil company forexploration and production, originating in countries where oil was nationalised or where thenational oil company was granted a monopoly, such as Argentina, Brazil, Indonesia, Iraq andIran.
This form of contract could enjoy a renaissance in those Gulf OPEC countries wishingto increase their production capacity, which may turn to the oil companies for their technicalknow-how and financial resources. It is the case of Iraq with the signature at the end of 2009of 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 hydro-carbons at his own risk and expense on behalf of a national oil company, and by which heis reimbursed for the costs he incurs and remunerated in cash depending on the success ofthe exploration. All production accrues to the national oil company, although the contractormay 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 maybecome the operator when development or production commences. The national oil companyowns the installations, but the foreign company has the right to use this infrastructure.
The fundamental difference between the risk service contract and the production sharingcontract is that the contractor is paid in cash rather than in kind. The contractor is thereforenot 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. TheIranian 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 whichpermits contracts to be concluded between the Ministry of Petroleum, national companiesand local or foreign companies or persons. Conoco concluded the first agreement in March1995, relating to the development of the Sirri A and Sirri E oilfields. Following the cancel-lation 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, recoversthe costs incurred during production and receives a fixed remuneration, negotiated before thecontract is signed and independent of any fluctuations in the price.
The duration of the contract is limited to two short phases: a development phase followedby 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 planappended to the contract. The operations are supervised by a joint management committee
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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 allo-cated to local sub-contractors.
These contracts present investors with a number of specific constraints: they are short-termcontracts, fairly inflexible during the development phase, in which the plan must be followedvery closely. The share devolving to the contractor is relatively small, and they do little tobolster his reserves. In addition the fact that the remuneration and the cost of the investmentare fixed at the moment the contract is signed introduces an element of risk which has to bemanaged. 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 projectdirectly. He receives a fee for services rendered. This fee can be related more or less closelyto the results. Technical assistance contracts relate mainly to the resumption of productionfrom fields under depletion, and sometimes to development activities. The funding isprovided 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 nation-
alised their petroleum industry in the 1970s, such as Saudi Arabia, Kuwait, Qatar andVenezuela;
– Contracts by which countries of the former Soviet Union and Eastern Europe providedassistance 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 oilcompany, for example in Abu Dhabi, India and Benin.
It should be noted that some technical assistance contracts give the contractor the rightto 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 EXPLORATIONAND 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 thepart of the signatories to seek to develop the hydrocarbon resources in a given geographicalzone having specific characteristics.
Many provisions in a contract are independent of the characteristics of the zone to beexplored. These include, for example standard legal provisions, matters relating to theconduct 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 specificcharacteristics of the zone to be explored: exploration risk, type of hydrocarbons, location,
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existing infrastructure, level of costs, etc. These clauses will also have regard to the inter-national oil market, both at the date of signature of the contract and in terms of anticipateddevelopments during future production. They relate to the following aspects:
– The duration of the exploration programme, the area to which the licence applies andthe 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.
These issues will be the main focus of attention in the negotiations and the decisions takenby oil companies when entering into a contract or licensing arrangement.
Fiscal and contractual provisions designed for a particular zone or in particular marketconditions 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 suffi-ciently flexible to accommodate expected and unexpected changes.
Incentives can also be introduced to foster investment in special zones such as unexploredbasins, deep offshore, remote onshore locations, the Arctic, rain forest or the desert. Incen-tives 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 fixedroyalty rate and a tax on profits or a production sharing contract with a fixed rate of profitoil split.
In both these cases the return to the oil company and the State’s oil revenues vary consid-erably depending on the characteristics of the field which directly affect costs (location, sizeof reserves, well productivity), and hydrocarbon prices. The commercial viability of adiscovery of hydrocarbons is very sensitive to parameters of this kind.
Simple economic simulations show that there is a gearing effect associated with the tradi-tional 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 caseof a “marginal” discovery the unit technical costs are usually high, and the expected returnmay be adjudged too low. And conversely, in the case of larger discoveries with lower unittechnical costs, the expected return may appear high, or very high where the reserves exceedcertain levels. This can lead to an imbalance in the sharing of the profits between State andoperator, making subsequent negotiations necessary to find a fairer basis.
Producing countries realised that contractual and fiscal regimes needed to be devisedwhich properly addressed these different scenarios. Most countries have gradually adaptedtheir 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 inimplementation, computational methods and audit which were not foreseen when they wereconceived, but which have often necessitated adjustments to the new contracts. The mech-anisms 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 economicrent need to be able to deal with two contrasting scenarios.
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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 anddevelop. This involves the State being willing to assume part of the risk and give up somepotential 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. Thistrade-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 gobeyond the limit of acceptability. In this case the State share of the revenues needs to beincreased. But at the same time the regime must be careful not to discourage investors byremoving 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 mostcountries, both industrialised and developing, towards the second objective. This period sawthe introduction of excess profit taxes on petroleum additional to normal taxes or profit oilsplits moving in favour of the State. But circumstances have moved on since that time. Therewere two subsequent new developments, already referred to earlier: a steady decline inprices during the period 1981–1986 followed by a period when prices were volatile but fluc-tuated widely around a fairly moderate price until the end of 1998; and increased opportu-nities in countries formerly closed to the international oil companies, particularly since 1990in 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 ofexceptional profits, and conversely host countries are conceding that they need to reduce theirtake 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 exceptionalprofits, so that a growing number of producing countries have claimed a higher state takeand 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 considerableeconomic impact, even if progressive in structure, because it is a tax on turnover. Some coun-tries have therefore taken the radical decision to dispense with royalties altogether in certainconditions. For example for oilfields where the annual production is below a certain thresholdor, as in Norway, for all fields declared commercial on or after 1 January 1986, whatevertheir production turns out to be. This measure was taken when a rather pessimistic view wasbeing taken about the prospects for crude prices, and was intended to revive activity inNorway by encouraging the development of marginal oilfields and satellites of existingoilfields.
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B. Investment incentives
These can take the form of investment credits, depreciation uplifts or a variety of otherdevices which reduce the tax burden falling on the companies. This category includes theconsolidation for tax purposes of all the exploration and production activities in a particularcountry rather than ring fencing each concession. This allows the holder to offset his explo-ration costs at one location against his revenues arising from production at another. Thisamounts to an indirect subsidy by the State, and the higher the tax rate the greater the valueof this tax relaxation.
C. Progressive profits tax rate
This mechanism is fairly rare. It was introduced in Tunisia in 1985, for example, where aprogressive tax rate applies depending on a profitability ratio recalculated each year, like theroyalty. The complication lies in the fact that the scale is not the same as that establishedfor 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 thefirst 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 sametypes 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 variousguises in the 1980s: the “Special Tax” in Norway, the “Petroleum Revenue Tax” in theUnited Kingdom, the “Windfall Profit Tax” in the U.S. and the “Exceptional Levy” inFrance. The adoption by OPEC countries of higher rates of taxes on profits —up to 85% insome countries— can also be regarded as an excess profit tax.
These instruments have an impact on the profitability of the holder, but experience showsthat they are not sufficiently selective in achieving the necessary objectives. They are in factbased either on the excess of the oil price over an indexed base price (in the case of thewindfall profit tax) or on a pseudo-profitability criterion calculated on a purely accountingapproach (the petroleum revenue tax) rather than being based on the true economic prof-itability of the operations in question.
Because of these considerations, some countries —Papua New Guinea (1976), Mada-gascar (1981), Somalia (1984), Guinea-Bissau (1984), Senegal (1986), Australia (1988) andNamibia (1991)— have introduced a “resource rent tax”, calculated directly from theeffective profitability of an exploration and production project.
Most of these instruments ceased to operate after prices fell to levels well below thoseapplying in the 1980s. However with the increase in oil price, they may be automaticallyreactivated.
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 productionsharing contract than those of a concession. This can be achieved by modifying the cost
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recovery mechanisms and defining a sliding scale for the profit oil split, because the para-meters 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 whereoperating costs remain practically constant. Using the same concept as mentioned earlier, thisparameter could be based on a sliding scale which increases with the annual production orthe cumulative production from an oilfield. This mechanism would represent a worthwhileimprovement, provided a significant relationship can be established between the productionlevel and the potential return to the contractor, which is not always possible. This systemdoes 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 priceof oil rises beyond a certain threshold, indexed to allow for inflation: this device is found incertain contracts in Angola and Malaysia.
There are various types of mechanism which allow a linkage to be established between theshare 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 contractorpays in cash on his share of the profit oil, the latter being determined using the same rulesas 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 yearsall 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 forconcession. This device has been adopted by two countries, i.e. Liberia and EquatorialGuinea, but did not achieve the success hoped for because of difficulties in putting intoeffect the necessary calculations.
• The profit oil split can be made a function of a profitability ratio, or “R-factor”, calculatedeach year as the ratio of the contractor’s cumulative net revenue to his cumulative invest-ments. The amounts are calculated each year, and accumulated from the first year of thecontract. The contractor’s share of the profit oil reduces as the R-factor increases accordingto a scale set forth in the contract. Unlike the device described previously, and even if thecalculation and auditing procedures need to be defined precisely, the latter is far less difficultto implement. This instrument has therefore enjoyed increasing success and has beenadopted, 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, involvingseveral difficulties. In particular, the economic calculations which underpin them are often
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made on a stand-alone basis, with no allowance for the possibility of consolidation with otheractivities in the country or region. Furthermore the technical conditions prevailing in onecountry may not be reproduced in another. And finally, the fact that the contracts tend to bestrictly confidential does not make it any easier to get data; those obtained from indirectsources may not be reliable.
While bearing in mind the reservations described in the foregoing, it is possible to rankthe relative severity (from the investors’ point-of-view) of the economic rent sharing systemsthroughout the world by reference to the simple criteria of the total Government take. Thisparameter 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 investmentcosts 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 Stateand harsh for the investors. Obviously whether or not a system is harsh depends on thepetroleum potential of the country. However activity levels are not necessarily inhibited bya severe system as long as the country in question has a well demonstrated potential or isvery prospective. On the other hand countries with little or no production, or whereproduction is declining and which are not able to renew their reserves, have no choice inthe current very competitive environment but to try to entice inward investment into thecountry by offering an attractive package.
To illustrate this, a number of countries with diverse backgrounds are classified belowaccording to the State take. The classification is approximate, and more careful analysis mightlead to some changes.
• Between 30 and 50%: Argentina, Colombia, US (Gulf of Mexico), Ireland, Morocco, NewZealand, 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), Libyaand Venezuela are around 90%.
Some countries appear in different categories because they offer different terms fordifferent zones. The countries in the first category are largely industrialised countries whichare producers and consumers, and whose economies are not greatly dependent on theirupstream oil activities. The second category is the most numerous, and comprises a hetero-geneous group of countries with modest or moderate production, with petroleum policieswhich depend on their level of development. The countries in the third category areproducing, and in many cases exporting, countries whose economies are highly dependenton these activities.
There is increasing competition between countries to attract investors and to offerattractive conditions. A token of this is the periodic revisions which countries make in theirlegislation, tax regimes and contractual arrangements. This was exemplified by Cameroonand Morocco, which made major changes in their systems in 2000. Morocco introduced taxincentives, and is hoping to be able to attract deep offshore activity to its shores. Cameroonmade sweeping changes to its systems, and also provided incentives to attract renewedexploration so as to reverse the downward trend in its production.
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Conservely, producing countries with expected additional upsides, have recently intro-duced 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 ofthe legislative, fiscal and contractual framework alongside the technical side and results ofappraisal of the petroleum potential. These aspects lie at the heart of the relationship betweenpetroleum-producing countries and investors, and play a crucial part in determining how theeconomic 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 inter-national community and of a number of systems usually adopted by countries, this chapterhas 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 explorationand production have become quite competitive. New regions once closed to internationalinvestors or inaccessible within the technological constraints then applying have been openedup, thereby considerably increasing the choice of countries for possible investment. The oilcompanies have then become more selective because of budgetary constraints when pricesare low, and there has at the same time been a reduction in the number of oil industry partic-ipants as a result of mergers and acquisitions. These large corporations apply differentcriteria with regard to the required return on investment from those used by the smaller inde-pendent companies. One consequence of the increase of the prices is a trend followed bythe independent companies to invest in risky new areas when they made significant discov-eries 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 potentialhydrocarbon-producing countries will continue, resulting in still more flexible tax regimesand contracts. This tendency is particularly discernible in regard to exploration andproduction in more challenging environments. However competition also exists between oilcompanies which need to secure and renew their reserves. In parallel, established producingcountries wish to benefit from the sustained increase in oil price, so that they have introducednew contractual and fiscal provisions to increase the global State take. Not all countries arein the same boat, however, or carry the same weight on the international scene. It is to beexpected 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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The petroleum sector is a capitalistic industry par excellence, and investment decisions inthe industry are absolutely crucial. This chapter therefore deals with the evaluation of capitalprojects. 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, whilerecalling a number of more general principles.
We shall begin by introducing the concept of strategic analysis which will help to establishthe main constraints within which the project evaluation will be performed. We shall thentouch briefly on questions which arise in connection with short-term decision-making, beforeturning to the techniques for estimating the return on capital. In this connection we shall firstdiscuss deterministic methods before addressing, in the last section, the topic of risk analysisand 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 seniormanagement. Most large oil companies, however, use systematic procedures to determinethe broad lines of their strategic orientation, and to illuminate the context in which decisionsare taken on large investment projects. In so doing, use is made of a range of well estab-lished 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 ofmethodologies used in the upstream oil industry, before going on to consider briefly how oilcompanies 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 understandingof the environment in which the company is operating. One of the missions of the department
6Decision-making onexploration and production
in charge of strategy is therefore to monitor constantly and analyse the markets for crudeprice behaviour, the relationships between the participants, the political risks, etc. Theseelements were touched on in Chapter 1, and we will not dwell on them further here. Visionsof the medium and long-term future are often expressed in the form of scenarios. Shell hasestablished a reputation in this area which goes back many years. Where a comprehensivescenario is not available, it is necessary to specify a number of reference hypotheses so asto ensure the consistency of the analyses carried out by the different sectors of the company.
Particularly important amongst these assumptions are those relating to technologicaldevelopment. While forecasts are difficult in this area, they have a major impact on a certainnumber of options. A decision to develop interests in natural gas inevitably involves makingforecasts of future demand and the way the market will evolve. But it will also depend onthe anticipated reduction in the costs of liquefaction and transport. Similarly, companiesinvolved in producing extra-heavy oil in the Orinoco Belt were not simply betting on theeventual scarcity of “conventional” oil. They were undoubtedly also banking on futureprocessing improvements, and therefore on better recovery rates and reduced production costsfor resources of this kind in the future.
6.1.2 Strengths and weaknesses
Opportunities are usually identified by comparing the proposals of the operating companiesin the group with analyses of the external environment. A “strengths and weakness” analysisis then carried out, both for the competitors and for the company itself. It is usually carriedout for each separate business, and relates to all the factors which affect competitiveness:technology, finance, human resources, organizational aspects and political factors. In lookingat 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 patentsapplied for may be an indication of technological preoccupations, while acquisitions, divest-ments and changes in shareholdings may provide indications of orientations, a refocusingon core activities or geographical diversification. Presentations made at road shows may alsobe a source of information.
“Know thyself” enjoined Socrates. It is difficult to be objective about one’s own strongand weak points. A team which has proven its worth in one country may not necessarily bethe most effective in another country or environment. This notwithstanding, it is obviouslyof 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 criterionthan market share. In seeking a balanced portfolio a company may follow the BostonConsulting Group in seeking balance not between products but between sectors of activityor project types. To preserve viability in the long term, the portfolio needs to include activ-ities which may not justify themselves on the basis of present profitability only, but whichmay become profitable in the future as a result of changes in technology, markets, regula-tions, etc. Deep offshore may therefore be regarded as a “star”, certain high-risk countriesmay be viewed as “question marks” or even as “dogs”, while the “cash cows” are wellknown: these are the projects which allow the company to participate in pioneering projectswithout putting it in financial jeopardy.
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In this connection, the fact (actually self-evident) is that that it may be necessary toventure beyond the confines of exploration and production activities to take full advantageof foreseeable developments. The acquisition of refining and even distribution interests maymake it possible to gain a foothold in a producing country about to open up its upstreamactivities to international companies. It was undoubtedly this desire ultimately to gain accessto the upstream oil industry that explained why so many companies expressed interest in thegas projects announced by Mexico and Saudi Arabia in 2000 and 2001.
The desire for a balanced portfolio is also based on considerations of risk, one of theobjectives being to reduce the overall risk associated with the portfolio through diversifi-cation. This is one of the reasons why oil companies have long collaborated with one anotheron projects. Generally speaking it can be assumed that there is no correlation between thetechnical/geological risks, or more generally the risks related to the size of the reserves, fordifferent projects. By increasing the number of projects we therefore reduce the risks for theportfolio as a whole.
It should be noted, however, that increasing the number of projects does not entirelyreduce 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 pricefluctuations. But this sensitivity can vary significantly between zones, depending on the cush-ioning effect of the tax regimes in place.
The practice of sharing capital costs between competitors is characteristic of the upstreamoil 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 mostlarge projects, political motivations should also be mentioned. The inclusion of certainpartners can sometimes provide an “insurance policy”, contributing decisively to thesuccessful realisation of the project. Total’s choice of partners in Iran was probably not basedpurely on economic considerations, but also on a desire to reduce the political risk. Ingeneral terms, and quite apart from mergers and acquisitions, strategic alliances provide away of acquiring new skills and can provide an entry ticket into new activity sectors or coun-tries. A particular focus in recent years has been the alliances between international corpo-rations 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, andwe confine ourselves to a number of observations.
Responsiveness is a very important attribute for success. A significant proportion of theopportunities in the upstream oil sector need to be grasped fairly quickly, either for politicalor 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 newzones or activity sectors. The latter are analyzed by a central group (which may, as in thecase 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 beregarded as inconsistent with flexibility. The plan for the group is obtained by aggregatingtogether and synthesizing the plans prepared by the different subsidiaries or operating units.
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The preparation of these plans creates a channel of communication between head office andthe other companies in the group. The latter enter into commitments in some areas and, inother areas, propose options for possible changes.
The selection criteria and project analysis tools are determined by the Strategy Departmentin 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 setsof 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 determiningthis rate for the company is therefore of particular importance. Its value cannot be derivedby 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. Itreduces the likelihood that projects will turn out post hoc to be unprofitable, but leads toopportunities being rejected which may be grasped by the competition. On the other handsetting the discount rate to the lowest possible value consistent with the data on the cost ofcapital will tend to foster development and increase market share. This can be compared withthe 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 buyback 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 orien-tations. This is true at the level of a single company, but also for each sector of activitieswithin a group. The petroleum sector therefore often uses different discount rates for differentcategories of activity, even within the exploration/production sector. These discrepancies maybe due to differences in the financial methods applying, to differences in the risk profile, butmay also be an expression of strategic decisions: setting a high discount rate acts to limitinvestment budgets. On the other hand, setting a relatively low discount rate can be a wayof 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 orderto promote the development of the refining sector and distribution networks. This wasjustified not in terms of the profitability of these activities but in terms of the access it gaveto outlets for crude production. More generally, adjustments in the discount rate can be usedas 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 someof the analytical principles of short term decision-making. Decisions during the operatingphase usually only have a short-term effect (one year, for example), and therefore generallydo not involve complicated methodological issues. They may involve risk analysis andprobabilistic calculations, but questions of this kind are considered in Section 6.4. We shallconfine ourselves here to deterministic calculations, that is we either assume that the conse-quences of a particular decision are perfectly known or we make use of one or more definedscenarios representing possible futures.
This being the case, the economic analysis is, broadly speaking, limited to making acomparison of the expenditures and revenues involved for the different possible options. But
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many of the decisions which need to be taken correspond to modifications which may bemade “at the margin” of a production programme. These decisions can be usefully analyzedby a “marginal analysis”, a practice we all use, whether or not we realize it! This can beexemplified by considering a problem of secondary recovery by polymer injection during thelast year or years of production of a reservoir. The problem is to decide on the quantity offluid to be injected. Table 6.1 shows the quantity Q of crude oil which can be recovered asa function of the quantity of fluid injected, and therefore of the corresponding cost C duringthe year studied. The operation involves a declining marginal yield and increasing marginalcosts.
There is no further increase in the production of crude once the quantity injected reaches73000 m3.
Quantity of oil produced (103bbl) 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 ($/bbl) 13.8 14.8 14.6 13.9 12.9 13.8 14.2
Cm ($/bbl) 19.2 13.7 10 10.4 17.9 40
Table 6.1 Polymer injection.
These data can be used to construct the graphs in Figure 6.1 which show how the totalcost, average cost and marginal cost of the crude produced by secondary recovery vary asa function of the additional quantities recovered.
• Marginal cost
• Average cost CC
QM =
CC
Qm
d
d=
Assume the wellhead price of crude, P, is $15/bbl. If P is independent of the volume ofproduction 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 thevolume injected, so increasing production. This can be increased as long as the marginal costCm 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 theaverage cost is less than the sale price. In accordance with the theory1, we note that theaverage cost CM is a minimum when Cm = CM.
If the wellhead price of crude is $15/bbl, then profits are optimised for an additionalproduction of crude of about 57000 bbl/y, obtained by injecting a volume of approximately62000 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 themarginal cost is less than the average cost, i.e. Cm < CM, the cost of a small increment in production willresult in a reduction in the average cost. On the other hand when Cm > CM the average cost increases.
the sale price, so that injection is worthwhile. It should be noted, however, that this cost isclose to the sale price. It may be, therefore, that the decision will be taken on the basis ofother considerations and criteria: uncertainty as to the behaviour of the reservoir, a desire togain experience with injection, etc.
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Box 6.1 Marginal analysis.
For a production facility which manufactures a single product, the optimum productionlevel is generally not that which minimises average costs.
Over a short period, and for a given set of equipment, the level which maximises profitsis that for which the marginal cost (cost of the last unit of production) is equal to themarginal receipts (receipts procured for the last unit of production) (subject to appro-priate assumptions regarding continuity, differentiability, increasing marginal cost beingsatisfied).
If the sale price is independent of the level of production, production is optimised whenthe marginal cost is equal to the sale price. This can readily be proved mathematicallyby 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 shownin microeconomics textbooks. This is rarely the case in the refining and petrochemicalsectors, where the cost function is often best represented by considering the cost C as thesum of a fixed term and a term proportional to the volume processed, at least as long as thecapacity of the plant is not exceeded.
300
400
500
600
700
800
900
Additional production
20 30 40 50 60 70
Annual cost
5
10
15
20
25
30
Additional production
20 30 40 50 60 70
Mean / marginal cost
Cm
CM
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 onexploration are dealt with before decisions on development. But the former are based on
probabilistic calculations and on risk analysis techniques, which cannot be carried out untilwe have quantified the value created (or destroyed) for the various outcomes of the decisionbeing studied. It is this quantification, based on “deterministic” calculations specific to aparticular assumption, which is the subject of the present section. In Section 6.4 we shalllook 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 forevaluating investment projects. The basic principles will be reviewed in boxes incorporatedinto the text.
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 cashflows received and disbursed at different dates. The technique by which this is done is knownas discounted cash flow: this technique involves applying coefficients to cash flows occurringin different years which make them comparable (see Box 6.2). The discount rate is generallydefined as the average cost of capital. The most common method outside the upstreampetroleum industry involves using a weighted average cost of capital after tax (WACCstandard method). The cost of debt is therefore calculated after tax, i.e. (1 – t)d, in nominalterms, where d is the cost of debt in current prices before tax and t is the tax rate. Sinceinterest is usually deductible from profits before the calculation of tax, the payment of O 1of gross interest generates a tax saving of O t.
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If we suppose that there is no uncertainty about the future, and that there is a perfectcapital market (i.e. a market in which any economic agent can lend or borrow any sumof money at a unique rate of interest i), then a sum S0 in year 0 is precisely equivalent toa sum S0(1 + i)n in year n, since either can be exchanged for the other. On this basis, asum Sn available in year n is equivalent in year 0 to its “present value” (or “discountedvalue”):
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 ofall its capital. This is generally a weighted average, equal to the marginal cost of financeassuming the proportions of the different types of capital remain the same. The discountrate can be regarded as the price at which the financial department is willing to providecapital funds to the department(s) responsible for the study and for implementing theinvestment project.
It should be pointed out that the above theory does not depend on the assumption thatthe rates of interest applying to money lent and borrowed are equal. In practice if acompany has funds available at a given time, these funds will generally not be lent outat 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 themoney were invested at a rate i.
Box 6.2 Discounted cash flow.
In costing equity capital, the most commonly used approach is the Capital Asset PricingModel (CAPM), based on financial theory (see Box 6.3). This was the method adopted byElf Aquitaine in 1998 when it revised its discount rate. The parameter β is obtained by econo-metric methods. Various studies have obtained values of less than 1 for the oil industry: ofthe order of 0.9. Where an oil company is active in a number of different sectors, the coef-ficient β can vary significantly between sectors. Moving downstream from traditionalpetroleum activities, values for β of between 0.4 and 0,5 are observed in the pharmaceuticalsand cosmetics industries.
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This model gives a method of quantifying the cost of equity capital as the returnexpected by the shareholders, which can be considered to be equal to the return on risk-free investments, increased by a risk premium. This risk premium relates only tosystematic risks affecting the share market as a whole. In practice, non-systematic orspecific 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’sreturn on capital and the average return for the market as a whole to the variance of thelatter. It can be calculated from stock market statistics.
Box 6.3 The Capital Assets Pricing Model (CAPM).
6.3.1.2 Different discount rates
As indicated in Section 6.1, it is quite common for oil companies to use different discountrates for different sectors, and sometimes for different geographical zones. Leaving asidestrategic 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 areexposed, can vary between one activity and another. The same is true of debt ratios, withthe permissible debt ratio being a function of the risk involved: exploration is practicallynever funded by debt, while most development projects are funded in part by debt, andindeed the latter may exceed the equity element. This reduces the average cost of capital. Itshould also be mentioned that specific risk premiums are sometimes added to the cost ofcapital calculated in the manner described. Remember that this calculated cost of capitalalready includes, in the estimate of the cost of equity, a systematic risk premium. Thispractice 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 inflowsminus cash outflows.
The cash flows are defined relative to the situation in which the project is not imple-mented: only those future flows related to the decision being evaluated should be broughtinto the calculation. A cash flow usually involves (with a few exceptions, such as the residualvalue of an item of equipment remaining at the end of the period studied) a real movementof funds, and not a mere accounting concept. An important difference between cash flowsand profit and loss accounting relates to the treatment of depreciation. Depreciation does notinvolve the physical movement of funds in or out. Depreciation only has an indirect impacton cash flow insofar as it affects tax payments: depreciation can be a deductible expense incalculating 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 enteredin terms of the money of the day. Real terms (constant money) are notional monetary unitsin which the purchasing power remains constant and equal to that in a reference year. If year0 is the reference year and we assume a constant annual rate of inflation of d, the value F
–k
in real terms for year 0 of a flow Fk in year k defined in nominal terms, is given by:
F–
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, thusensuring that the monetary units used in economic evaluations and accounting and tax docu-ments are the same.
In the first place we shall confine ourselves to looking at “operating cash flows”; thesedo not bring into the calculations any debt-related flows, corresponding to calculations ofthe 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
F
d
kk
1+( )
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The net present value (NPV) is the algebraic sum of the present values of all cash flowsFk associated with the project:
where:
Fk : cash flows in nominal terms,
F–
k : 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 ).
NPV =+( )
=+( )= =
∑ ∑F
i
F
i
kk
k
Nk
kk
n
1 10 0
Box 6.4 Net present value.
The net present value is an absolutely fundamental concept in economic evaluation. It is ameasure of the value created by an investment and is equal to the maximum sum which canbe borrowed in year 0 (by the project department from the finance department), in additionto the capital cost of the investment, such that the revenues generated by the project willrepay 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 berealized if the NPV is positive. In choosing between a number of mutually exclusive projects,the project with the highest NPV will be chosen.
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 theproject’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 themaximum rate at which the project revenues can remunerate the capital invested without theproject becoming loss-making (Fig. 6.2).
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Figure 6.2 Graphical representation of internal rate of return.
F
Discount rate
0
Pre
sent
val
ue
r
This is equivalent to checking whether the rate of return on the project is greater than thediscount rate or whether its NPV is positive. In choosing between two exclusive projects Aand 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 returnof B with respect to A is higher than the discount rate (the incremental rate of return is therate 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 nominalterms, r, and in real terms, r-, are related as follows:
1 + r = (1 + r-) (1 + d )r ≅ r- + d
6.3.3.3 Early production, multiple rates of return
When studying the development of a reservoir it is usually appropriate to compare differentproduction alternatives (for example relating to the number and locations of wells). One ofthese variants may be the option to deploy an early production system. Such a situation oftenleads to multiple rates of return, a phenomenon uncommon in other sectors.
Multiple rates of return cannot occur unless forecast net cash flows display severalchanges of sign over time. This is the case, however, when we are looking at a project whichinvolves accelerated production. What happens is that the capital expenditure (negativecashflows) leads to an accelerated or increased production in the early years (positive cash-flows), 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 valueof a project involving early production will be positive between these two values. Obviouslyin a case such as this great caution is necessary in using the criterion of rate of return asdefined in the previous section.
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Figure 6.3 A multiple rate of return.
10 20 30 40 50 60 70
I (%)
– 230
NPV
6.3.4 Equivalent cost
When studying an investment project, the sale price of the hydrocarbons produced may besubject to uncertainty. It can then be very useful to determine the minimum sale priceneeded to ensure that the project is profitable, or in other words to calculate the equivalentcost of production.
Determining the equivalent cost allowing for tax and recalculated to a before tax basis issimplified when calculating an equivalent cost after tax is relevant, particularly in cases wherethe project accounts are consolidated with those of other activities, the total being in profitbecause 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 notto be the case, with some projects giving rise to losses which are carried forward. These
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 preciseequivalent cost it is then necessary to proceed iteratively to arrive at the sale price such thatthe present net value is equal to zero.
When the main uncertainties relate to the price of crude, the difference between this priceand the equivalent cost throws light on the acceptable degree of fluctuation in the price ofcrude, and is often more informative than the value of the NPV or the difference betweenthe 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 thediscussions between the partners, the calculations are generally carried out using operatingcash flows as defined above, without bringing in elements related to the loans required tofinance the project. These calculations relate to the WACC method. The data relating to thefinance are implicit in the discount rate, the internal price at which the finance departmentis willing to allocate funds. This allows financing decisions to be kept separate frominvestment decisions. For small projects this overall approach (WACC method) is generallythe only one used: projects are assumed to be financed from a common pot of capitalavailable. For large projects this WACC method is also adopted when the debt ratio αdefined by the company for all its projects is strictly fixed. In such a case, if the debt ratioexceeds α on a particular project, the debt component on other projects needs to be reducedto a lower level. It is then appropriate to maintain a separation between the sources offunding and their application.
For large exploration/production projects a flexible approach is often taken with regardto debt. When the studies reach a sufficiently advanced stage and the financing arrangementshave been defined it may be desirable to look at their impact. To this effect, most companiesadvocate supplementing the calculations of the overall return on capital (possibly making useof the method of Arditti, which we shall look at presently) by a calculation of the return onequity (see Box 6.6). This will in fact be the main criterion in a case where the project finance
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The equivalent cost, in annual or unit form, is an (annual or unit) equivalent of the totalcosts associated with a project. It includes both the operating costs and an investmentequivalent cost. We consider here only the case where it is appropriate to regard it asconstant over time, when it can be assumed that the annual receipts or the sale price ofthe products will remain stable during the study period. When an annual equivalent costis determined, it is a constant annuity equivalent to the sum of the present values of thecapital 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 valueof production.
A project has a positive net present value if and only if the annual (or unit) equivalentcost 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 andrecalculated to a before tax basis , is equal to the sale price (or annual receipt) such thatthe net present value is zero.
Box 6.5 Equivalent cost.
has no impact on the debt ratio applying to the company’s other investments (in the case ofnon-recourse financing, for example). When the project is financed on the same basis as theoverall portfolio of investments, the two approaches, i.e. WACC and equity residual shouldlead to the same decision2.
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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). Thediscount rate is defined as the after tax weighted average cost of financing. Thestandard WACC method reflects the viewpoint of the department responsible forinvestment projects.
Equity residual method (return on equity)
A calculation of the return on equity, on the other hand, reflects the viewpoint of theshareholders. Payments made to service debt and the associated tax shields are thereforeincluded in the calculation. The discount rate used is therefore that appropriate to the share-holders, the cost of equity.
If the tax rate on company revenue, t, is stable, the relationship between the overall returnon 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 lifeof the project. If this is not the case, the relationship is approximate only. This can be inter-preted very simply: the overall return on capital is the weighted average of the cost of debtand the return on equity.
Box 6.6 Standard WACC method and Equity Residual method.
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 samesector, the various different methods of evaluation —overall return on capital, return onequity but also Arditti’s method— all tend to indicate the same decision. In other words, theNPV for the different methods all tend to have the same sign. But they will not have thesame value and indeed may diverge considerably. The problem of putting a value on a largeproject crops up frequently in the upstream petroleum industry, where development ofteninvolves consortia, and where companies seeking to optimize the return on their portfoliosmay seek to buy into a project, or divest their interests, at any stage during development andexploitation. Investors need to be able not just to know its net present value, but to be ableto calculate its value in any year. Based on the criterion of overall return on capital, the valueof the project in any year k in the future is the sum of the values of future cash flowsdiscounted to that year:
2. We only have to set the equation in the Box 6.6, assuming it holds precisely, with α′ = α, beside theformula for the discount rate i = α(1 – t)b + (1 – α)ke, to realise that re ≥ ke if and only if ro ≥ i.
In particular, once an investment I has been made in year 0, the value of the project atthe end of year 0 is:
Before an investment is made the value of the project (i.e. of the right to invest) is equalto the NPV.
But if the equity residual method produces a very different value, how can a companydetermine the maximum price it is willing to pay for an interest in the project, or for thatmatter, 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 equalnot 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 deter-mined not by the capital cost of the investments but by the capacity of the company to servicethe loan, that is, by its expected revenues. Suppose there is a third party with the same expec-tations as to return and the same financial structure, and therefore the same discount rate, asthe company we are considering. He is considering purchasing the right to carry out theproject. The maximum sum he is prepared to pay is equal to the NPV of the project. If weadd the capital cost of the project, the total acquisition costs including the construction ofthe plant amount to I + NPV, a fraction α of which he can finance by debt. The companyitself would only be able to borrow αI, so it would benefit from a lower gearing than theimaginary 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 projectis financed. If debt is limited by considerations of risks specific to the project, if it has noimpact on the debt ratio for other projects, it is the NPV on equity which should be used. Ifon the other hand taking a smaller loan in connection with this project would result inincreased capacity to borrow elsewhere, the objective of complying with the reference ratiofor the totality of investments means that the WACC method using the relevant discount rateshould be used: the assumption that the debt ratio remains stable, and is defined by referenceto the value of projects, is implicit. It is therefore the overall NPV on capital which is therelevant 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 asthe after tax weighted average cost of capital. But in the upstream petroleum industry, deter-mining the after tax cost of debt can be problematic.
VF
iIn
nn
N
0
1 1=
+( )= +
=∑ NPV
VF
ik
nn k
n k
N
=+( ) −
= +∑
11
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The problem is that the operating companies involved in exploration and production arenot always in profit, for example when they commence operations in a new zone. In suchcircumstances they are not able to deduct any accounting loss from profits associated withother activities. These losses must be carried forward to future years. Furthermore thepractice adopted in some countries of ring fencing the exploration licence can prevent fiscalconsolidation, even within a given country. Tax regimes are often complex, and generallyvary between different licences. The tax rate may depend on the rate of production, etc. Allthis means that it is not possible to express the taxation of petroleum revenues (and its impacton financing costs) in terms of a single parameter. It is therefore not generally possible todetermine by simple calculation the cost of debt after tax. This makes the standard WACCmethod an inappropriate method of evaluating a project. Even assuming the average cost ofcapital after tax can be calculated, the company would have to use as many different discountrates as there are petroleum tax treatments to consider.
Furthermore the return on equity, a parameter very sensitive to the assumptions regardingfinancing, is usually only used in the final study phases. These various considerations haveled the oil industry to make fairly widespread use of another method, known as the Arditti-Levy 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 para-meter is easier to calculate than the cost after tax, and its value is independent of the taxregime. The method therefore allows the number of discount rates to be limited, possibly tojust a single rate, remembering that the cost of capital before tax varies little from onegeographical zone to another.
The cash flows to be considered therefore (hereafter referred to as the A-L flows) willinclude tax allowances earned relative to interest on loans, but will not include the loandrawings or redemptions, or interest payments. In other words, the deductibility of interestis not allowed for in determining the discount rate (as happens in the standardWACC method), but in calculating the cash flows in each year, by using the tax rate for theyear.
In practice the taxable profit and therefore the tax in each year are calculated by deductingthe interest from the project operating revenue. Account is taken of all the specifics of thetax regime for the project (carry forward of losses, variable tax rates depending on one ormore 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 ofthe equity) and lenders. The A-L flows effectively include the sums received or disbursedby everyone, while the cost of capital reflects the average minimum return sought by thevarious 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 WACCmethod (when this can be used) and the equity residual method when the financing proposed
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for the project is consistent with that for the firm as a whole3. In other words, there is aconvergence of the viewpoints for the different methods: between that of all the variousinvestors (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 isneeded in its application, however. The pitfalls are known to the specialists, but they makeit difficult for decision-making to be decentralized. It is not enough to simply provide a userwith the value of the discount rate. The first step must of course be to check that thefinancing assumptions made in determining the discount rate are compatible with the assump-tions made in calculating the financing costs and the corresponding tax savings. In practicethe method in its original version is only appropriate for the study of projects where the debtcomponent of the financing is consistent with the overall debt ratio objective set by thecompany. 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, ceterisparibus, the higher the internal rate of return on the project. This may come as a surpriseto 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 casethe assumption of a constant debt-to-capital ratio over the entire study period is clearlynot satisfied, and can lead to an underestimation, sometimes substantial, of the profitabilityof the project.
• Economic value of a project: consider a project for which the debt-to-capital ratio is equalto the debt ratio α set by the company, i.e. B0 = αI0. In this case the NPVs calculated bythe traditional method and the Arditti-Levy method (as well as the equity NPV) shouldhave the same sign, but be different in magnitude4. If the object is to decide whether ornot 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 acquireor dispose of an interest in the project, it is the economic value of the project (Vn in yearn) which should serve as the reference value. The fact that the two methods may givedifferent results can also give rise to the problem referred to in Section 6.3.5.
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3. More precisely, convergence is ensured when the debt-to-capital ratio α′ for the project remains constantover its life and is equal to the debt ratio α fixed by the company for projects of this type. Thedemonstration is similar to that for the convergence between return on capital and return on equity. TheA-L rate of return rs is a weighted average of the cost b of debt before tax (return to lenders) and the rateof 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, theformula becomes approximate rather than precisely correct. The A-L discount rate s is a weighted averageof 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 isgreater than ke.
4. The relationships between NPVs obtained in this case by the different methods are given by Babusiaux[1990].
6.3.8 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 theTotal group. It is described in detail by Babusiaux and Pierru [2001]. It is a generalization ofthe classical return on capital method, and caters for the case where profits arising from theproject studied will be subject to a different tax rate from that considered in calculating thediscount 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 shallrevisit 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 adifferent tax regime or, more generally, where revenue will be taxed at one or more ratesdifferent from t. We will confine ourselves to the case where there is no consolidation ofaccounts for tax purposes, or to similar cases5 which are quite common in the upstreampetroleum industry. We assume further that the project can be financed partially by loancapital 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 whateverthe debt ratio set by the company, the loan can be considered to be taking the place of a loanL put up by the central services of the company. The loan L, equal in amount to L′, wouldhave been repaid over the same term and by the same method of repayment. In other wordsthe redemption timetable would have been the same. This assumption, though it may appearsomewhat theoretical, can be seen as a way of satisfying the requirement that the loan L mustresult in the same overall debt ratio each year as the loan L′ (the assumption currentlyadopted for project evaluation of a debt ratio fixed ex ante).
The principle underlying the method is very simple: the difference in the after-tax costof interest payments is assigned to the project. If the interest rates are the same in the hostcountry and the home country this has the effect of assigning to the project the differencein tax allowances which arises when the interest is accounted for in the host country ratherthan in the company’s home country.
Remarks
• The procedure proposed is a generalization of that proposed by Babusiaux [1990] foranalyzing the profitability of a project in order to apply for a loan at a subsidized interestrate.
• There are, on the face of it, no particular difficulties in adapting the method to cater forcontractual conditions specific to the upstream oil industry. In the case, for example, of
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5. When for example local taxes are higher than taxes in the company’s home country, where profitsworldwide can be consolidated.
a production-sharing contract, in which the financial costs are recovered in the form ofcost oil, the cost oil simply reduces by an equivalent amount the quantity of profit oilwhich 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 thatapplying to the company generally. An international oil company in fact has to contend witha large number of different tax regimes. How can the rate t be determined? In theory thecompany should take up loans in increasing order of after-tax cost (this would involve, forexample, 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 isthis last loan which has to serve as the reference in defining the loan λ which would be substi-tuted by the loan L′ for a project under study, as well as the tax rate applied to the revenuesfrom which the appropriate interest can be deducted. The gain to be credited to the projectis calculated by reference to the cost of this marginal loan (if it can be determined by thecompany’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, Furthermoreit 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 therevenues 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 proposedmethod therefore allows a unified criterion to be adopted for all the activities of an oilcompany, a traditional criterion which is easier to use and whose use is more widespreadthan 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 fordebt. 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 returnon capital employed (ROCE). The accounting revenues used in this exercise exclude bothinterest charges and the corresponding tax savings. The ROCE is therefore analogous toa cost of capital after tax. Similarly, the economic value added (EVA) method defines thevalue added in a year as the annual accounting revenues (excluding financing items) lessthe cost of servicing the capital. The latter therefore also requires an after tax average costof capital. In each of these different cases the explicit or implicit method of reference isthe classical cost of capital method rather than the Arditti-Levy method. One of theadvantages 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 presentedin Pierru and Babusiaux [2000]. Although not proposing to go into detail, we present the
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main formula which lies at the heart of the method, because it provides additional justifi-cation 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 byreference 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 assump-tions, 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 economicvalue in any year, calculated using the generalized ATWACC method, is equal to the valuecalculated by discounting the operating cash flows at a rate equal to the average cost aftertax 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 inthe country of origin. The parameter t can therefore take any arbitrary value. Each of thetraditional methods (standard WACC, Arditti-Levy, equity residual) corresponds to aparticular value of t, providing a very simple proof of their consistency7.
6.3.9 A first step in dealing with uncertainty: sensitivity analysis
Sensitivity analyses are usually indispensable in economic evaluation. They involve analyzinghow the profitability of a project varies in response to changes in the assumptions regardingthe different components of the cash flow calculation, such as, in the case of the developmentof a hydrocarbon reservoir: the cost of capital, the price of crude and/or gas, the size of therecoverable reserves, tax rules, etc.
The spider diagram
In presenting the results of a sensitivity analysis a graph, the spider diagram, often conveysmore than tables of numerical values.
This is constructed by representing along the x-axis the variations in the different para-meters to which the profitability of a project may be sensitive. They are usually representedby variations relative to a base case defined beforehand. The y-axis comprises the value ofthe criterion in terms of which the results are expressed: net present value, rate of return orequivalent cost. In each analysis just one parameter is varied, the other parameters being keptconstant 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 foran investment project. The criterion used is NPV. The variations studied relate to the priceof 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 theparameters to which the profitability of the project is most sensitive. It also allows sensitivityanalysis to more than one independent parameter at a time to be studied The possible vari-ation due to two independent parameters, for example, can be estimated by taking the linesegments representing the possible variations in these two parameters singly and completingthe spider’s web as shown, or more accurately, by summing the two vectors represented bythese line segments.
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6. Pierru and Babusiaux [2000].7. See also Pierru and Feuillet-Midrier [2002].
The same procedure can be used to consider the simultaneous variation of any numberof parameters, as long as they are independent. In the general case the curves are not neces-sarily straight lines, and the “parallelograms” to be constructed are therefore curvilinear. Itshould also be noted that when the chosen criterion is the rate of return, the method can onlybe approximate, but can provide order of magnitude estimates.
The graph makes it easier to characterize the set of favourable cases for which the netpresent value is positive, and the set of unfavourable cases (corresponding to the shaded half-plane 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 bequickly used to determine what change would be required in another variable (sale price, forexample) to lead to a negative NPV.
In the case of a project to develop a field for production, the price of crude or the priceof gas is usually the parameter to which the profitability of the project is particularlysensitive. The equivalent cost, as we saw earlier, is the threshold price which determineswhether or not a project is economically viable. This criterion, which itself embodies infor-mation on sensitivity to price, is in its turn particularly well suited to be the subject of a sensi-tivity 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 possiblelosses do not comprise a major risk for the company. Very often the sensitivity analysis isregarded as dealing sufficiently with the question of uncertainty to present a firm proposalto the relevant senior management.
However it also often happens that the sensitivity analysis throws up a mix of favourableand unfavourable cases, each with their associated gains and losses, such that a decisioncannot be made. For projects of a certain size, the analysis can be carried further byattaching probabilities to each of the various outcomes. This approach will be consideredin Section 6.4.
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NPV
Capital cost
Crude
pric
e
Reserves
Variation (%)
Figure 6.4 Spider diagram showing results of sensitivity analysis.
6.3.10 An empirical criterion: payback period (duration of financial exposure)
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, tech-nological risk (a technical advance may be of short duration), etc. It is defined in variousways, and can be calculated from the start of exploitation or from when capital expenditurestarts (in the latter case we refer to the duration of financial exposure). Payback time maybe defined in terms of discounted or non-discounted values. In any case this criterion is agood way of formalizing the desire not to carry out projects whose profitability depends oncash 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 revenuesbeyond the desired payback period is to assume that they will be nil, which is generally notrealistic. There are many projects of long duration in the petroleum industry (and in theenergy sector generally).
Despite these drawbacks, payback time is a criterion, albeit secondary, which manydecision-makers find of interest. The maximum financial exposure (accumulated expen-diture) 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 introducenotions of probability. In decision-making with regard to exploration it is almost indis-pensable, particularly when drawing up an exploration drilling programme. The decision-maker has to contend not only with uncertainty about the volume of reserves, which applieswhen a discovery is made, but also with whether or not hydrocarbons are present at all. Oncethe preliminary geological and geophysical studies have been completed, the decision to drillis generally taken on the basis of an «exploration» data sheet. Companies ask geologists tomake probabilistic estimates: probability of success and probabilities related to the reservesallowing 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 aresubjective probabilities. They convey the degree of likelihood estimated by an expert, basedon 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 netpresent value, i.e. the weighted average of the possible values of the NPV, the weights corre-sponding to their probabilities. This is the value to which the average would tend if thecompany 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 oftimes. The criterion of expected value is also justified by the law of large numbers if the
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company carries out a sufficient number of similar, mutually independent projects. This istherefore the basic criterion used for all the “small” projects.
Remark: It is possible to calculate the expected value of a revenue, a discounted cost oran annual equivalent cost. It is not in general possible, on the other hand, to calculate theexpected 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 maybe 250 Mbbl. This prospect could require a development with a NPV of $320 million. Theprobability of finding an oilfield of this size is 10%. There is also a 5% probability offinding a larger oilfield. The NPV in this case would be $400 million. The probability ofdiscovering a smaller oilfield is 5% and the NPV in this case would be $200 million. Theprobability 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 bythe probabilities, i.e.:
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 charac-teristics such as the variance, we need to have an estimate of the probability distributionfunction associated with the net present value. But the latter is a function of a certain numberof parameters; it is usually easier to associate probability distribution functions with theseother parameters.
In the case of the capital costs, it may be possible to refer to historical data to estimatethe probability distribution function. It should be observed that this function is usuallyasymmetric (Fig. 6.5). The probability that the cost will be substantially less than the costingof 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 probabil-ities will generally have to be used. Often a broad-brush approach is taken to representingprobability distribution functions. A uniform distribution represents a range of values withinwhich it is difficult to define a most likely value. Conversely, however, when a most likelyvalue (the mode) can be estimated, a triangular distribution function may be adopted.Frequent use is also made of the lognormal distribution.
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Probability
Capital cost
Figure 6.5 Capital cost.
In the development of oil or gas fields, the parameters crucial to profitability are thevolume of the reserves and the productivity of the wells. The latter depends on a number ofvariables which can be considered random: the area of the reservoir, the thickness of thereservoir bed, the porosity and permeability of the rock, the viscosity of the fluids, etc. Theseare the fundamental parameters which can be estimated and described in terms of probabilityfunctions by the geologists and geophysicists. Often an estimate has already been made ofthe minimum recoverable reserves required to make the development viable. The questionthen 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 distrib-ution function for the net present value (or equivalent cost), the problem is to derive thisfunction from assumptions about the probabilities of the fundamental parameters.
6.4.2.3 Simulation
The technique most commonly used consists of performing a simulation using Monte Carlomethods8, and computer processing is normally required. A sample is drawn at random foreach variable considered stochastic using the appropriate distribution function. These valuesare then used to calculate the corresponding possible value of the net present value (or thevolume of the reserves, as the case may be). This operation is repeated a large number oftimes (several hundred), a sample set of notional values of the NPV is obtained. Statisticaloperations can then be carried out on this sample: construction of a histogram, calculationof mean, standard deviation, etc. If the sample is large enough, the method allows a proba-bility distribution function to be derived for the NPV. In particular, the mean of the sampleis an estimate of its expected value. This method has been in use by the oil industry sincethe early 1960s.
One of the disadvantages of simulation methods is they behave like a “black box”. Theprobability distribution function of the target criterion is derived from probabilistic data forthe different parameters. But, unlike what happens in a sensitivity analysis, the effect of indi-vidual factors is not apparent. In practice, the uncertainties attaching to the different para-meters 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 ona large number of cases studied by the company, and on the experience of specialists. It ismuch more difficult, on the other hand, to obtain probabilistic data, even subjective, for theeconomic parameters (price of crude, tax rules). This is one of the reasons why simulationtends to be mainly used for evaluating the volume of the recoverable reserves. It allows theimpact of uncertainties of a technical nature to be represented, while those relating to theprice 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 moresubjective in nature than the other parameters. Analogous to what was said in discussingsensitivity analysis earlier, simulation can be used just to determine the equivalent cost. Thisallows uncertainties related to the sale price to be kept distinct from all the other uncertaintieswhich affect the net present value.
Finally, the use of simulation, always a major exercise, can be avoided by using approx-imate formulae to determine the expected value and the variance of the net present value fora project.
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8. These methods were popularised by D.B. Hertz [1964], and are sometimes referred to as the Hertz method.
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 areoften distributed asymmetrically. This led R. Charreton and J.-M. Bourdaire [1985] tosuggest representing the distribution of each parameter by a lognormal distribution, withlower bound zero, and characterized by its mode, a “mini” value and a “maxi” value. Themini and maxi values correspond to the 5 and 95 percentile points on the probability distri-bution function.
This approach is particularly appropriate in the case mentioned above where we areseeking to determine the probability distribution function applying to the volume of recov-erable reserves of oil as a function of the physical parameters. The formulae used to calculatevolumes are largely based on products of variables. We can therefore apply the central limittheorem to the logarithm of the volume. Furthermore the lognormal distribution generallycorresponds 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 tobe calculated for a product of variables. The mean and the variance are therefore given bythe approximate formulae:
m = 1 (mini + mode + maxi)3
σ ≈ 1 (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 haveto 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. Thedecision as to whether to develop, if successful, or to continue exploration, will depend onthe 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 isusually read from left to right, or sometimes from top to bottom. The connecting lines ofthe graph represent either possible decisions (continuous lines) or random outcomes of deci-sions taken (broken lines). The nodes therefore correspond either to a state of affairs or toinformation obtained. The nodes corresponding to decisions are represented by a square(decision points), while the probabilistic nodes, associated with random events, are repre-sented 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 relatesto a neighbouring, smaller structure. The geologists consider that there is a 30% likelihoodof 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 amedium-sized field) if A is “dry”.
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45
A
B C6
4
(0.2
)O
il d
isco
very
E 320
45
Exp
lore
pros
pect
BDev
elop
A31
0
H
(0.7
)
Sm
all f
ield
(0.1
) Med
ium
-siz
ed f
ield
(0.2
)5
5
No
disc
over
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.8)
D
F
Aba
ndon
Exp
lore
pro
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t B G
(0.8
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(0.0
5)S
mal
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0
I J
L
Aba
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M
Unf
avou
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ndit
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Favo
urab
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)
Favo
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itio
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(0.6
)
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220
(0.8
)
Dev
elop
110
610
50
(0.1
0)E
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re
pro
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Aba
ndon
– 50
0
Fail
ure
Fail
ure
Fig
ure
6.6
Dec
isio
n tr
ees.
The diagram does not show the lower part of the decision tree, corresponding to prospectB if A is successful. The section after node H in the lower part of the tree will be identicalto the section in the upper part after node G. It should be noted that it is possible, insteadof 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 dynamicprogramming 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. InFig. 6.6 we therefore move from right to left.
A value is associated with each node (“value”, “score” or “potential”) which correspondsto the expected value of subsequent revenues. The evaluation starts at the nodes at the finalstage (M and N). The score assigned to node M, for example, is the expected value ofrevenues from the development of a small field. The probabilities are indicated in bracketson 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 ofthe 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 correspondsto the highest expected value. At node J “abandon” has an expected value of 0 while devel-opment, 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 precedingstage until we arrive back at the initial node A.
In practice, the number of possible decisions is often large, and the number of possibleconsequences is even greater. The size of decision trees can escalate rapidly, and thisimposes 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 meansof 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 conditionsbecome favourable: a rise in the price of crude, a technical development which improves therecovery rate, changes in the tax regime, etc. The corresponding parameters can be regardedas random events or variables.
The value of a production licence can be determined by means of a decision treeconstructed as described above; this also allows the optimum strategy and the timetable tobe 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 thepossibility of using real options theory.
An option (see Box 6.7) is a conditional asset, the value of which depends on the exerciseof a right. The investment opportunity offered by undeveloped petroleum reserves can becompared with a call option. Proceeding with development is analogous to exercising theoption. The capital required corresponds to the call price. The value of the field whendeveloped (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 dateof expiry in the case of a limited-term lease.
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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 takenin the future. Apart from opportunities to develop oilfields, there are in theory many situa-tions in the upstream petroleum industry which meet these conditions: the acquisition of anexploration licence, special contractual clauses, etc.
Options theory is well adapted to evaluating asset market values, and does not requireknowledge of a discount rate. It should be emphasized that models for valuing optionsassume the existence of a liquid market in the underlying asset, and that there are no oppor-tunities for arbitrage. This may be true for the price of oil, but is less so for petroleumprojects.
The value of a given asset is the sum of two components: the intrinsic value and the timevalue. The intrinsic value is the value if the option were exercised immediately and can bedetermined by traditional NPV methods. The time value corresponds to the potential forappreciation 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 theunderlying asset, its volatility, the exercise price, the term and the risk-free interest rate. Thegreater 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 oilprice is more volatile. By holding back with the development of certain gasfields in the NorthSea, gas companies were able to change the nature of the competition in that area. As a resultprices became more volatile, which in turn increased the value of the licences held by thesecompanies.
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A call option gives its owner the right to purchase an asset at a given date or for a prede-termined period at a fixed price (the call price). The standard method for evaluating an optionis the Black and Scholes model.
If we assume that the changes in the market price of the underlying share follow anormal distribution, the value of a European call option (i.e. a call option exercised on a fixeddate) is
where:
S price of underlying share,
X call price,
t time remaining before expiry,
r0 risk-free interest rate,
σ standard deviation of the return on the share (volatility),
N(d) probability that a standardised normal random variable is less than or equal to d.
d
S
Xr t
t
d d t
1
02
2 1
1
2=
+ +⎛⎝⎜
⎞⎠⎟
=
Log σ
σσ
,
– ,
S N d Xe N dr t( ) – ( )–1 2
0
Box 6.7 Value of an option
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 affectthe 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 outa 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. Thecost of the exploration programme is $50 million. The probability of finding a field ofmedium size is 10%. The corresponding NPV would be $320 million (excluding explorationcosts). 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.
Now consider another exploration opportunity in a zone where access is more difficultand less familiar. The cost of exploration there is higher: $ 160 million, but the sizes of thepossible fields are considerably larger. The values of the probabilities and the discountedrevenues (excluding exploration costs) for different possible discoveries are indicated inTable 6.8.
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Discovery Probability (%) NPV ($ millions)
Small 5 100
Large 10 1000
Very large 5 1500
Table 6.8 Characteristics of a possible discovery.
Assume that the two opportunities studied only differ in terms of their costs and revenuesas indicated, and that a choice has to be made between them. A large company wouldconsider both to be small projects, and it would prefer the second to the first because theexpected revenues are higher. For a small independent company, on the other hand, this maynot be the best decision. It has to allow for the fact that the likelihood of losing money ishigher for the second project, and that the maximum possible loss is also higher. In otherwords it is a riskier project. Generally speaking, companies are averse to risk.
Before examining possible responses to the question posed, let us take yet anotherexample. Let us look at two development projects whose NPVs can be considered to becontinuous random variables. Suppose the expected values of the NPVs for the two projectsare the same. A risk-averse decision-maker will prefer the project with the smaller dispersionof NPVs, i.e., project A in Fig. 6.7, which presents the probability distribution functions forthese two projects.
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Probability
NPV
A
B
Figure 6.7 Comparison of projects.
The risk is generally characterized by the standard deviation9 (or the variance) of thediscounted revenue.
If two projects have the same expected revenue, a risk-averse decision-maker would optfor the project with the smaller standard deviation. A problem which can arise is that oneproject has a higher expected value but also greater risk. The decision-maker is then facedwith 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 isalso necessary that the risk should not be too high.
In practice both of these criteria (expected value and variance) are commonly used withouttheir being universal agreement about the trade-off. As indicated earlier, in the oil productionsector simulation methods are often used. These methods allow the expected value andvariance of the volume of recoverable reserves, or going further, of the NPV for the devel-opment project, to be calculated.
Nor do we necessarily rely on just the expected value and the variance, since the distri-bution 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, possiblysupplemented by considerations of a more strategic nature, without having to seek to quantifythe weights to be attached to each element, in particular to the expected value and thevariance (mean value and risk).
9. The standard deviation of a variable is the root mean square of the deviations of the variable from itsmean. It is a measure of the dispersion of the variable. The variance is equal to the square of the standarddeviation.
Different approaches are used to deal specifically with risk. One of these involves usingan 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 whicha 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 calculatingthe cost of equity by incorporating a risk premium. The theory links in with the practiceadopted by many companies of incorporating a risk premium in their discount rate. Anumber 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 systematicrisk. In order to apply it to take account of the risks attaching to individual projects, it wouldbe necessary to calculate the coefficient β associated with each project. But in any case, themodel seeks to maximize the utility of a shareholder who can diversify his portfolio. Theshareholder is therefore assumed to be indifferent to the risk specific to any given asset. Thisis not true for a shareholder who does not hold a very diversified portfolio, and in particularfor someone holding a large proportion of the capital (as in a family business). And afortiori it is clearly impossible for the head of a business to ignore specific risk. Whenreference is made in a company to the capital asset pricing model, it is usually in order todetermine the cost of capital for the company as a whole and not project by project. Thiscost of capital is usually increased more or less explicitly by a premium which factors in thespecific risk. This method will be analyzed briefly below.
We shall use the term “specific risk premium” to refer to the safety margin which has tobe added to the cost of capital to arrive at a discount rate. The adjective “specific” is usedbecause the systematic risk is generally allowed for in the definition of cost of capital, butin practice the premium in question is often defined in a pragmatic manner, without therebeing a real distinction between specific and systematic risk.
An increase in the discount rate reduces the impact of future cash flows, this reductionbeing greater the further they are in the future. Some writers justify this by arguing that thevalue of a future cash inflow is subject to uncertainties which become greater the further intothe future we look. But this is not always true. When we seek modern equipment for an ultra-deep offshore development, for example, the capital cost, which will have to be borne overthe 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 arisk 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 equiv-alent to applying certain probability factors. If i0 is the discount rate not including anyspecific risk premium and pr is the specific risk premium, then the present value of a cashflow Fn in year n is:
A risk premium of 10%, for example, involves applying a factor of approximately 0.6 inyear 5. This is equivalent to assuming that there is a 60% probability that the given flow willtake place, and a 40% probability that it will be nil (e.g. complete expropriation withoutcompensation). This would be a very high assumed risk.
F
i p
nn
rn
1 10+( ) +( )
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When this method is adopted the safety margin used may vary between different divisionswithin a company, as a function of the risks to which the different activities are subject. Aproblem 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 strictapplication of the method may therefore lead to inconsistent decision-making.
The use of a specific risk premium has another disadvantage. We saw earlier that theconcept 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 areinterdependent). 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 theproject, 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 presentthe oil industry appears to be using this device less than it has in the past. Where it is stillbeing 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 anyproject. In some cases a sensitivity analysis will suffice while in others, probabilistic calcu-lations may be needed. There are techniques based on decision theory which permit theanalyst to go beyond the multicriterion approach mentioned earlier.
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 modifiedwhen account was taken of risk aversion, and which show that the satisfaction created byan inflow of money is not proportional to its value. Decision theory permits this satisfactionto be quantified by means of a utility function. But translating theory into applications runsinto 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 criterionconsistent with decision theory, but simple, appealing and therefore easy to put into practice.For independent projects it consists of replacing the NPV by:
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 whichrepresents the maximum acceptable loss which will not jeopardize the survival of thecompany; this sum can be estimated (relatively) easily by general management.
mP
− σ2
2Ch
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1. Charreton R, Bourdaire JM (1985) La décision économique. Que sais-je ?, PUF, Paris, France.
CONCLUSION
Economic evaluations of investment projects using discounted cash flow are the rule in oilcompanies, 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 forgetthe 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 choosingbetween 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 sophisticatedtechniques for analyzing risk, capital budgeting techniques are intended to summarise in asingle or a small number of numerical values a large set of data. They are a tool for ensuringcoherence between the assumptions used by different sectors in the company. Of course theeconomic evaluation is only one of the factors to be taken into account when making adecision, because it is never possible to quantify all the consequences of a decision. But theobject 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 betweenspecialists with different backgrounds: a genuine common language.
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In this Chapter we shall examine the issue of information on exploration and productionactivities, and how oil companies deal with this information in the context of their financialaccounting.
Management in this sector, like any other, relies on an information system so that theycan steer the enterprise on a sound course, optimise its choice of projects and provide allthe information needed for:
– Investors who monitor the fortunes of the companies they intend to invest in, and whomake 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 (forexample a building bought several years ago appears in the balance sheet at its cost of acqui-sition 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 qual-itative information regarding non-quantifiable aspects.
There are specific accounting issues which arise in relation to the oil and gas explo-ration/production sector, and it is vital to understand these so that all the information providedby 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 canbe very loose. A company may have invested $1 500 million (historical costs) in an oilfield
7Information, accounting andcompetition analysis
of 100 Mb, the value of which could collapse when production starts if the price of oil fallsto $50/barrel or, conversely, soar if the price rises to $ 150/barrel. Furthermore the costsare incurred early on in the process, possibly extending over a period of 5–10 years, whilethe receipts which follow may be spread over a period of 10–20 years, or even more in somecases. The oil company will be required to provide information both in the short term (quar-terly, yearly) and the long term (throughout the productive life of the oilfield).
• The intrinsic value of a petroleum exploration/production company depends largely on thesize of its reserves. And yet when the company makes a discovery, this does not affectthe assets in the balance sheet.
• The sale price of hydrocarbons does not depend in any way on the seller. It is thereforedifficult for him to estimate the value of an oil or gas field, and yet he is required to carryout such an exercise to comply with various legal obligations.
• Oil companies conduct their activities in association with other oil companies, and thecontracts that bind them to the host country are often specific, imposing particularconstraints on data structures and the management of projects. This factor influences theway the company organises its internal accounting system.
These difficulties make it an extremely complex matter for a financial analyst to carry outevaluations or comparative studies of the companies in the sector. However the history ofthe oil industry shows what a major role has been played by American companies, whoseleading position is to reflect in the hegemony of United States of America GenerallyAccepted Accounting Standards ("US GAAP"') internationally.
This situation has evolved due to the introduction of International Financial ReportingStandards ("IFRS") since 2005. Indeed, European listed companies have had to prepare theirfinancial statements in compliance with IFRS since the beginning 2005. Many other coun-tries are also choosing to adopt IFRS as their national regulatory bodies move to convergewith the standards. The IFRS are becoming widespread and the oil and gas companies inEurope need to comply with these new standards.
Furthermore, the leading international oil companies are all quoted on the New York StockExchange and are therefore bound by the requirements of the Securities and ExchangeCommission (SEC).
In this context, the knowledge of both US GAAP and IFRS is therefore essential, whenexamining 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 whichallows comparative studies of oil companies to be carried out. We shall begin with the infor-mation provided by oil companies in annexes to their annual reports, and will then define a
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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 thebalance 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 andintangible assets, etc.) and, for oil companies, information prescribed by SFAS 69.
Box 7.1 SEC (Securities and Exchange Commission).
number of indicators which can be constructed from these data. And finally we shall describethe many difficulties involved in using these data.
For readers not familiar with accounting practices, an introduction to financial accountingis 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 duringthe exploration and development phase and the term “operating costs” during the productionphase. These capital and operating costs relate to many different operations, as can be seenin Table 7.1.
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Oil and gas activities are dealt with by specific publications based on recommenda-tions of the FASB. Their objective is to be able to measure the repercussions on thefinancial position of a company of the cost of exploration and development of oil and gasresources, and of the revenues from their sale.
In 1977 the FASB published for the first time a SFAS (no. 19) requiring the oilindustry to publish information about their oil and gas production activities. The termproduction 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 theAccounting Series Release (ASR). This document requires that reserve data are publishedin the company’s financial statement, with an indication of forecast future production andassociated expenses, accompanied by a very detailed description of past performance.
This resulted in a financial statement not subject to standards, which led the FASB topropose a new standard in 1982, the SFAS 69, which defines the way in which the reservesand 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 ofproven reserves in this document is largely based on the requirements of the U.S.Department of Energy.
The International Accounting Standards Board was formed in 2001 and is an independent, private-sector body that develops and approves International FinancialReporting Standards (IFRS). The IASB operates under the oversight of the InternationalAccounting Standards Committee Foundation.
Concerning the European Oil and Gas companies, the IASB did not have time to developa comprehensive standard on extractive industries in time for the entities converting to IFRSin 2005. Therefore, the IASB issued IFRS 6 in December 2004 and provided an interimsolution by allowing entities to continue applying their accounting policy in respect of explo-ration 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 suchas SFAS No. 19 and SFAS No.69 as they did not conflict with IFRS.
Box 7.3 IASB (International Accounting Standards Board).
The distinction between an investment and an operating cost for the purpose of the accountsmay 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 ofthe 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 explo-ration 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 fortheir 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 aninvestment 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, thepayment of an exploration bonus, broking costs and legal costs are considered as capitalcosts. If the investments made do not result in a commercial discovery, they are written offfrom 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 infor-mation, they do not contribute directly to the discovery of oil and gas.
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Table 7.1 Costs in the upstream petroleum industry.
Development drillingConstruction/installation platforms
Enhanced recovery:• wells• pumping equipment• other
(Flowline connectors)
Production installations:• separation/processing• discharge• storage facilities
Production
Operating costs related to pumping, gathering,processing and storage systems
Transport costs
The treatment of drilling costs depends on the outcome of the drilling: if the drilling isunsuccessful (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 exploratorydrilling costs are temporarily capitalized pending determination of whether the well has foundproved reserves if both of the following conditions are met:
– The well has found a sufficient volume of “not yet proved” reserves to justify, ifappropriate, its completion as a producing well, assuming that the required capitalexpenditure is made in the course of the field development;
– The company makes sufficient progress assessing the reserves and the economic andoperating 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. Theyinclude seismic 3D analysis, which allows the field to be monitored dynamically, the drillingof production and injection wells, the installation of production and processing plant, gath-ering and storage systems and systems for transporting the product to the point of contractualdelivery. 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 assetsshown in the balance sheet are greater, for this method, than for the successful efforts method.
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Successful efforts Full costs
Cost of acquiring mineral rights Capitalised Capitalised
Geology/geophysics costs Expensed Capitalised
Costs of dry exploration well Expensed Capitalised
Costs of exploration well, Capitalised Capitalisedproductive or ongoing
Development costs Capitalised Capitalised(including dry development well)
Production costs Expensed Expensed
Table 7.2 Comparison of the successful efforts and full costs methods.
Apart from the purely accounting aspects, these two methods lead to differences in the overallresults in terms of the annual profit/loss and the return on capital. When the full costs methodis used, all the costs of an unsuccessful exploration are capitalised. As a result the book profitwill be higher than that obtained using the successful efforts method (in which dry wells aretreated as operating costs), but the return on capital employed will be lower.
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, arenot included in the balance sheet (except for purchases of reserves, which are included attheir purchase value). Since 1982 however, the SFAS 69 specifies how information onreserves should be disclosed in the companies Annual report (booked reserves). The figuresgiven relate to the proven reserves, i.e. the quantities of hydrocarbons the recovery of whichfrom known reservoirs is regarded as “reasonably certain” in present technical and economicconditions.
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. Conver-sions are based on energy equivalence, and every company uses its own ratio, depending onthe quality of its gas. The conversion rates vary between 5300 and 6000 ft3/bbl.
Variations in the amount of the reserves compared with the previous year must be allo-cated between six categories:
1. Changes resulting from an improved knowledge of the reserves (due to the drilling ofa 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 virginzone, 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 offreedom in the choice of category. A further complication is that a distinction has to be madebetween developed proven reserves (quantities which can be produced from existing instal-lations and wells, without any further development) and those not developed.
It should be noted that the SFAS 69 advocates identifying separately those reservescoming from subsidiary companies fully or proportionally consolidated (first category), andsubsidiary companies consolidated by the equity method (second category).
The SEC definition of reserves based on the notion of “reasonably certain” recovery, may giverise to problems of interpretation. Each company will have its own policy on accounting forits reserves. A very cautious company will always retain the most conservative estimate ofits reserves as knowledge develops about the field. Others will post a best estimate , subse-quently 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 thephysical reality of volumes of hydrocarbons discovered.
First of all, he only recognises the existence of proven reserves; the concept of probable orpossible reserves appears too uncertain for him. He therefore takes a strictly deterministic viewof reserves, forgetting that part of the probable and possible reserves may become provenreserves in the future. Furthermore he will take account of the tax system applied to the
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production of the reserves in question in order to determine the amount of the reserves whichwill be disclosed in the financial statements. This means that a company operating under a leasewill 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 ofleasing. The idea is only to take credit for the proportion of the reserves which it effectivelyowns. A leaseholder therefore only takes account of its interest in the field after deductingthe royalty, paid in kind as remuneration to the owner of the site. The reserves in this casetherefore correspond to proven reserves net of royalty.
In certain leasing systems royalties can be considered as a tax on production, and are thereforenot deducted from reserves. In this case the reserves are the gross figure. In this system, ofcourse, in addition to producing the reserves and paying the royalties, the leaseholder also pays
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The Society of Petroleum Engineers (SPE), the American Association of PetroleumGeologists (AAPG) and the American Petroleum Institute (API) have made recommen-dations 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 proposedby the SEC.
Other efforts have been made at the international level to formulate acceptable defin-itions of reserves. In 1987, for example, the SPE published new definitions, including anextended discussion of the concept of “present economic conditions” and the need for thereserves to be “commercially viable”.
At the World Petroleum Congress (WPC) in 1983 a working party drew up a nomen-clature for reserves, confirmed at the 1987 WPC, which resulted in the report “Classifi-cation and Nomenclature Systems for Petroleum and Petroleum Reserves”.
This WPC report, together with the 1987 SPE definitions, is widely used by governmentagencies (Nigeria, Syria, Venezuela) and oil companies (BP, Chevron) which use it as areference point for their own definitions of reserves. None of these definitions permits aprobabilistic calculation of reserves. In 1997 the SPE and the WPC jointly published a setof definitions which refer to both deterministic and probabilistic techniques.
On December 31, 2008, the SEC issued its revised disclosure requirements for oil andgas reserves. The final rule and interpretations was published on January 14, 2009 (FinalRule).
The Final Rule modifies the SEC’ s reporting and disclosure rules for oil and gasreserves by, most notably:
– changing the pricing assumptions from the prior use of single day year-end price tothe use of average prices during the 12-month period prior to the ending date of the periodcovered by the SEC report;
– permitting voluntary disclosure of Probable and Possible reserves;
– expanding the range of acceptable technologies used to reliably estimate acompany’ s reserves;
– requiring disclosure of reserves in each foreign country where more than 15% of acompany’ s global proved reserves, in barrels of oil equivalent, are situated;
– requiring the disclosure of the qualifications of those persons responsible for acompany’ s estimates and audits.
Box 7.4 Historical background to the different definitions.
one or more “petroleum” taxes each year which are charged against income in the profit andloss 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 thissystem the oil company is a contractor, and only owns part of the production; it can thereforeonly bring that part of the reserves into its accounts, i.e. the cost oil (the repayment of allits costs) and its share of the profit oil. The rest of the profit oil accrues to the State, and istherefore 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 companycan then include the total profit oil in its reserves. The reserves announced therefore corre-spond to “access to hydrocarbons”. In order to quantify them, financial modelling of thecontract until the end of the field life is required.
Finally, in the case of a service contract the contractor is reimbursed his expenses andremunerated financially rather than in kind. He never owns the reserves, and does nottherefore include them in his financial statement.
Contracts of mixed type are becoming more and more common, and it is not always easyto decide in which fiscal category a particular set of reserves fall. In order to decide, oilcompanies refer to rules laid down by the SEC to guide them as to what should be accountedfor as reserves.
These rules reiterate the matters which need to be dealt with in an international agreementor contract if proven reserves are to be identified and disclosed. These include the right toextract 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 ofspecific 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 inwhich a clear mining interest is not involved.
The main theme in the foregoing is related to risk and reward: the reward must be linkedto 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 specificto the upstream petroleum sector. More general material on depreciation, and details ofstraight-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 recommendedby the SEC and the FASB for investments in the upstream petroleum industry in consoli-dated 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 andsite 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 thequantity produced by the equipment. In the case of exploration and production activities thisis not the production installation but the quantity of hydrocarbon reserves. The investmentsare amortised at a rate proportional to the consumption (or depletion) of the reserves.
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The depreciation rate is calculated according to the following formula:
production of hydrocarbons from field in year n
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 depre-ciated, a distinction must be made as follows:
– Cost of acquiring licence: depreciation based on developed and undeveloped provenreserves;
– Capitalised exploration drilling and development costs: depreciation based on developedproven reserves.
The depreciable balance or net capitalised assets are multiplied by this rate to find theamount of the depreciation.
Table 7.3 shows the depreciation profile obtained, based on an investment of $100 millionand initial developed proven reserves of 100 Mbbl. It is assumed that the reserves are notre-evaluated during this time.
Depreciation rate =
It can be seen in this example that that the depreciation in terms of its absolute value variestremendously over time, but is constant on a per barrel basis. In practice the exercise issomewhat more complex because the estimated volume of the reserves is subject to constantrevision, and these changes have to be incorporated into the calculation. These variationsresult not only from production but also from successive re-evaluations, due particularly toimproved knowledge of the field as new investments are made. Some of the probable andpossible reserves, for example, will become proven reserves (there is a 90% likelihood thatactual production will exceed proven reserves).
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Table 7.3 Depreciation by the unit-of-production method.
1. The net capitalisation on 31 December in year n is equal to the net capitalisation on 31 December in yearn-1, plus new investment in the year minus depreciation in the year.
These changes can also come about as a result of the impact of changes in the economicenvironment on the profitability of production, either forcing the company to ceaseproduction earlier than anticipated or, conversely, allowing it to continue production. Itshould not be forgotten that reserves are no more than the sum of the quantities producedin 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 esti-mated 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 higherdepreciation 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 wheresome 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 readyto start production, while development wells still remain to be drilled, or a satellite field putinto 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 asto ensure consistency between the amount of the depreciation and the volume of the reservesassociated 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 thenumber expected;
Slot ratio =number of wells drillednumber of wells planned
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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 7 5 3.5 2 100
– Or as the reserve ratio (beginning of the year), i.e. the estimated ratio of developedproven reserves to the total proven reserves:
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 500000 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 theconstruction of production installations for the entire oilfield. However since only part of thereserves 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-of-production 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 andrehabilitating the site less the value of any materials recovered. This work is generallycarried out after production from the field has ceased, and the costs cannot therefore be amor-tised from future production. In accordance with US GAAP (SFAS No.143 Accounting forasset retirement obligations) and IFRS (IAS 37 Provisions, contingent liabilities, andcontingent assets), liabilities for decommissioning costs should be recognised in the balancesheet when a company has an obligation to dismantle and remove a facility or an item ofplant and to restore the site on which it is located, and when a reasonable estimate of thatliability can be made. The estimate of the fair value of the retirement obligation should incor-porate the best information available and should be discounted using a credit adjusted risk-free 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 theprovision is also created. This is subsequently depreciated over the useful life of the facilityor item of plant
The decommissioning provisions are updated at each balance sheet date and any changein the present value of the estimated expenditure is reflected as an adjustment to the provisionand the corresponding property, plant and equipment.
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7.2 COMPETITION ANALYSIS IN THE UPSTREAM PETROLEUM SECTOR
Evaluating performance and benchmarking it against that of other companies in the samesector is one of the basic tools used by management.
A comparative analysis of methods within the different divisions of a company, but alsowith a sample of other comparable enterprises, permits the company to be evaluated and itsweak points identified, so that improvements can be made.
Competition analysis has been in use for many years and was formalised in the 1990s inorder to understand what others are doing and to learn from their experience. In order to carryout 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 ofyears.
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 thecompany and in the public domain are the most appropriate source. This includes annualreports, published by all companies, supplements containing statistical and operationalmaterial, produced by only some companies, and forms 10-K (American companies) or 20-F (non-American companies), only available for companies quoted on Wall Street.
The material of particular interest in these publications is the “supplemental informationon oil and gas producing activities” in accordance with SFAS 69. In this document itemsfrom companies subject to full consolidation are fully included, whereas items fromcompanies subject to consolidation by the equity method are included in proportion to thepercentage interest of that company in the specific area concerned.
The figures are broken down by geographical zone. It should be noted that thegeographical classification is not fixed, and can differ from company to company, dependingon its area of activity and preferred presentation.
Using this information, various indicators of performance can be evaluated for a companyoperating in the upstream petroleum sector.
7.2.1 Supplemental information on oil and gas producing activitiesappended 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.
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4. Reserve quantity information.5. Standardised measure of discounted future net cash flows related to proven oil and gas
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 pastprovisions for depreciation. It begins with a statement of the gross capitalised costs, brokendown between:
– The acquisition of underground reserves, successful exploration (that is the costs of allexploration which led to the discovery of oil or gas) and development. These costsrelate 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 inorder to obtain the net capitalised costs.
This test is not applied systematically. The calculation is only performed when there is adefinite risk of non-recovery of the book value of the investments (reduction in reserves, costoverruns or changes in tax regime). Furthermore companies are allowed a lot of latitudeas to how they perform the calculation (reserves, price of hydrocarbons, discount rate).
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In accordance with US GAAP (SFAS No. 144 Accounting for the Impairment orDisposal of Long Lived Assets) and IFRS (IAS 36 - Impainuent of assets), a companyneeds to review the recoverable amounts of its property plant and equipment in order toensure 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 arecarried at no more than their recoverable amount. An asset is carried at more than itsrecoverable amount if its carrying amount exceeds the amount to be recovered throughuse or sale of the asset. If this is the case, the asset is described as impaired and thestandard requires the entity to recognise an impairment loss.
In order to measure the ùnpairment loss, the company should calculate the economicvalue 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 planof 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 recognisedin the income statement.
Box 7.5 Impairment test (ceiling test).
7.2.1.2 Costs incurred in exploration, property acquisition and development
This category represents past expenditure, whether capitalised or expensed, broken down intothree different categories:
– The acquisition of mineral rights, distinguishing between proven reserves and otherpurchases;
– Exploration costs;– Development costs.
All oil companies present these three categories by geographical zone, but in varyingdegrees of detail.
By aggregating the values given over all the different companies, this category allowsoverall trends in expenditure in the oil and gas exploration and production sector to bemonitored 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 capitalservicing costs and head office overheads. As a result, the operating result thus obtained doesnot necessarily reflect the contribution of these operations to the group’s consolidated resultsfor oil and gas activities. On the other hand it has the advantage of allowing the performanceof 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). Hydro-
carbon 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 theState’s share are included as costs. However the figures are presented, the net valueremains the same. A distinction needs to be made between sales to third parties andtransfers between companies within the group;
– Production costs, which can include not only the technical costs but also sometimesthe committed costs, and taxes on production;
– Depreciation by the unit-of-production method and provisions (after recoveries) for theyear;
– 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
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The most difficult aspect of this calculation is calculating tax. This is purely theoretical, anddoes not correspond to the real tax situation of the company (no account taken of losses inprevious years brought forward to the current exercise, tax-allowable provisions differentfrom book provisions, etc.). The result obtained is therefore a notional value which allowsthe results of different companies to be compared independently of their tax situation andtheir financing method.
7.2.1.4 Reserve quantity information
The definition of reserves adopted here is that of SFAS 69 (see Section 7.1.2.1), consistentwith the SEC standards. It comprises the total of both the developed proven and developedunproven reserves, and a breakdown of the annual variations. This amount will be includedin the following tables in order to calculate the standardised measure of discounted futurenet 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 ofthe 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 forecastof the production profile. This calculation is carried out using the economic conditions atthe 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 basisof posted prices at year-end, except in cases where the existing contracts provide for fixedand determinable revaluations of the prices.
• The estimated production costs (including, where appropriate, transport costs and taxeson production), future development costs and decommissioning costs are deducted fromfuture 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 atthe 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 gasmarkets, for example —particularly in the United States— with prices which are higher inwinter, and therefore on 31 December, the reference date for prices —will produce higherpresent net values.Only the proven reserves are allowed for. This is rather a pessimistic scenario, since theeventual 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 usedby the oil companies. The latter allow for the development and production not only of theproven reserves but also of a part of the probable and possible reserves, producing highervalues for production and costs.The tax calculation is an estimate only; often the actual tax calculation is affected by activ-ities beyond the confines of the field being considered. The methods used for arriving at thisestimate vary between companies, which makes comparison difficult.The use of a single discount rate does not take account of differences in the real cost ofcapital to the companies holding the reserves. On the other hand the use of a standardisedvalue allows inter-company comparisons.
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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 netpresent value in the earlier year, because they no longer form part of the future, there aremany other factors which contribute to the change. These various sources of difference fallinto two main categories.
The first category of changes to the net present value can be regarded as “constantperimeter changes”, i.e. changes which relate to the reserves as they were in the previousyear. 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 reservesas 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 categoryvariation resulting from price changes in oil and gas (which affect the size of the reservesbecause 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 andgas producing activities” in oil companies’ annual reports, so that their exploration andproduction 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 announcedover 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 recoveryand, 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 equalnumber of barrels of future production. It can be said to have replenished its stocks. Whenassessing this parameter at the global level, purchases and sales of reserves have to beexcluded 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 maintainthis rate at 100%.
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7.2.2.2 Depletion rate
This indicator is the ratio of production in the year concerned to the amount of the reservesat the beginning of the year. These reserves are calculated by adding the production in theyear 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 developedresources. In terms of equipment, this ratio comprises the depletion coefficient used incalculating 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 commitregarding its activity in a given period (usually between 3 and 5 years so as to smooth theresult). 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 includingonly 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 abarrel 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 beattributed: 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 andgas producing activities”, was not intended for this calculation. Every company, dependingon 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.
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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 companiesmay occasionally include purchased reserves in the calculation.
Since the purpose of this ratio is to determine how efficient the company is at finding reservesin its exploration activity, it seems illogical to include the purchase of reserves (purchase costin the numerator and number of barrels purchased in the denominator) or enhancedrecovery (cost of enhanced recovery in the numerator and additional number of barrelsrecovered in the denominator).
7.2.2.5 Finding and development costs
This indicator is calculated by dividing the exploration and development costs for a givenperiod by the proven reserves associated with the discoveries, as well as enlargement, revisions and enhanced recovery announced during the same period. This ratio is alsoequal 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 thenumerator and the denominator. Over a period of three to five years we cannot hope to beable to link directly all the expenses in the numerator with all the reserves in the denomi-nator. Certain expenditures now will permit reserves to be found at a later date, andconversely some of the reserves in the denominator are the result of expenditure well beforethe period in question.Finally, these ratios only make sense for fully or proportionally consolidated entities. Whereconsolidation has been carried out by the equity method, the reserves will be included inthe 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 ofbarrels produced (the production is expressed in accordance with the SEC standard, and istherefore net of royalties). In the same way as the reserve-based ratios, these ratios are onlymeaningful when applied to companies subject to full or proportional consolidation.
The following elements can therefore be calculated:
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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 itemsin the profit and loss account and the corresponding per barrel ratios depend heavily on thefiscal and contractual system applying: the results will differ depending on whether thereserves 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 (fordetails 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 thesum 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 theaccounts 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 thereserves which appears in a standard PSC.
– A PSC, cost oil 50%, profit oil 20%, tax on profit oil 50%, State’s profit oil excludedfrom the reserves.
We assume that in the case of the PSCs, the excess cost is shared between the State andthe 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 productiongenerally included, as is royalty)
– depreciation (the SFAS 69 standardadvocates also including exceptionalitems and provision for site rehabili-tation)
– exploration costs (in accordance with thesuccessful efforts method)
± other revenues and costs
= operating profit / loss before tax
– taxes on profits
Net operating profit / loss
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
Under each of the four contractual bases the company’s net profit is the same. But the oper-ating profit and all the per-barrel ratios are totally different. This means that comparisonsof these parameters will not be relevant unless the analyst has a detailed knowledge of thecontractual 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 byapplying these contractual bases to the same field.
CONCLUSION
All these indicators are useful in giving an appreciation of the value of a company, but theygive greater insight into the past than the future. Furthermore they are calculated on the veryconservative basis of proven reserves only.
The most appropriate method would be to calculate expected future cash flows, extendedto 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-relatedfactors, such as the market capitalisation of the company, the market value of its reserves
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0
200
400
600
800
1 000
1 200
1 400
1 600
1 2 3 4
Net profit /Company profit oil
State profit oil
Tax oil
Taxes on profit
Royalties
Depreciation
Production costs
1: Lease
2: Standard PSC
3: PSC (tax oil)
4: PSC with tax
Figure 7.1
as reserves if there is an active market serving as a reference, and indeed the analysis of infor-mation 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 quar-terly results or information on the strategies of the company;
– Specialised publications produced by consulting firms or financial analysts, in theform of inter-company comparisons;
– Computerised databases offered by consulting companies, for example giving thereserves held by the companies.
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Table 7.5 Per-barrel ratios for different contractual bases.
1. Total production less royalty, i.e. 100 – (100 × 20%) = 80 Mbbl.
2. (1500 – 300 – 200 – 400) × 85% = $510 million.
3. Company cost oil + profit oil. Cost oil = production costs + depreciation = $200 + 400 million, whichmust 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 figuresin the company’s accounts.
Financial accounting collects and organises information needed by a business and compilesit according to certain principles, as follows:
• Historical costs: accounting documents are maintained in actual historical costs (currentprices), without correcting for inflation or discounting.
• Methodological consistency: accounting methods must remain constant over successiveaccounting periods. Any change must be justified.
• Continuity: The keeping of accounts is obligatory, even where a company has not had anyactivity during an accounting period.
• Independence of accounting periods: accounts are closed off at the end of each accountingperiod, 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’ssituation in accordance with the chart of accounts or other contractual document (annexesto accounts).
The position with regard to the assets and liabilities of the company is summarised in thebalance sheet which provides information on the overall worth of the company on the dateas at which it was drawn up. The consumption and production of the enterprise are dealt withby accounting for the costs incurred and revenues earned in the accounting period in whichthey occur, the results being shown in the profit and loss account (change in the worth) forthat 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 sheetand the profit and loss account (and the disclosures) is to give a true and fair view of thecompany’s financial position. These accounts are verified by independent auditors.
Annexeto Chapter 7
Basic principles of financial accounting
7A.1 THE BALANCE SHEET
In order to carry out projects a company needs to create wealth and make the necessaryinvestment, allowing it to produce and market.
7A.1.1 Assets
Investment involves creating the means of production. These may be tangible, such aspurchased or constructed equipment, whether replacement, expansion or diversification; orthey 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. Thesefixed assets appear in the balance sheet at their book value, that is, their cost of acqui-sition less depreciation (see profit and loss account). They may include securities, suchas shares in other companies, and goodwill. Goodwill is the excess of an enterprise’s fairvalue over its book value at the date of acquisition.
• Capital used in the company’s operating activities or in short term operations. These areknown as the current assets. They meet various needs (a) to have a certain quantity of rawmaterials, energy and services in hand in order to initiate operating activities, (b) to fundthe requirements resulting from the delay between the time when expenditure is incurredin connection with an operation and the receipt of the corresponding revenue (workingcapital) and (c) the need for liquid funds. These assets fall into the following three cate-gories:– Stocks (non-capitalised), including raw materials, work in progress and finished
products. Stocks are generally either merchandise destined for sale or products whichwill be used to manufacture this merchandise;
– Accounts receivable: these are invoices issued and credited but still unpaid at the dateof the balance sheet. This amount can be considered a credit extended to customerswhich needs to be financed (trade debtors);
– Liquid assets comprising cash balances or equivalent, such as cash accounts, bankdeposits and short-term investments which can be realized rapidly.
All these investments are included as assets in the balance sheet. They represent the totalassets 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 fundssubscribed by investors when the shares were issued and retained earnings, i.e. earningswhich have not been distributed in the form of dividends (reserves). These funds have tobe remunerated, either by dividends or an increase in the value of the shares. Equity capitalis made up of shareholders’ equity and minority interests.
• Long-term debt, made up of loans from banks, financial markets and other companies, aswell 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
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pensions, provisions for restructuring, provisions for site rehabilitation and deferred taxes(see § 7A.4).
• Short-term finance, made up of all the company’s debt with an outstanding term of lessthan 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 inrelation to purchases from suppliers, and therefore comprise a source of finance. Otheroperating debts refer to all non-financial debts of the company such as taxes payable tothe inland revenue authorities, salaries payable, social security outstanding, etc. There arealso short-term debts, including bank overdrafts, those long-term debts which fall duewithin a year, use of credit lines, etc.
The liabilities therefore represent all the funding available on the date at which thebalance 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 short-term components and showing the definitions of working capital, working capital requirementand net liquid assets.
The presentation can vary, for example French companies interchange the positions of theshort- and long term assets, the short-term assets being shown at the bottom of the balancesheet.
ASSETS LIABILITIES
Equity capitalNet fixed assets
Working capitalLong-term debt
Capital em
ployedC
urre
ntas
sets
Working capital requirementOperating capital
Operating debt
Net liquid assetsLiquid assets
Short-term debt
Current
liabilitiesFi
xed
asse
ts
Figure 7A.1 Balance sheet, classical format.
Working capital (WC): the amount by which the permanent funds exceed net fixed assets. It is therefore that part of the mediumand 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
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7A.1.3.2 Simplified presentation
The balance sheet can also be presented with operating items separated from items relatedto 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
Minority interests
Net debt
Fixed assets
Working capital requirementOperating liabilities
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 accountingperiod which increase (profit) or decrease (loss) the overall wealth of the owners. It incor-porates all the revenues and costs during the period, the difference corresponding to theprofit/loss for the period.
The revenues are the events which add to the wealth of the owners. In the case of oilcompanies these arise mainly from the sale of oil and gas. The costs, on the other hand, arethe items which deplete this wealth. The profit and loss account includes cash outflowsresulting 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 associatedwith the “consumption”, that is the wear and tear to the equipment and installations. Theseinstallations are designed to last for a certain period. There is therefore a lag between thetime when their capital cost has to be disbursed, and therefore accounted for (this is donein 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-cashcost.
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 cashin the profit and loss account, i.e. net profit plus depreciation.
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The net profit provides the company with resources to pay a dividend to shareholders andincrease their equity.
7A.2.2 Presentation showing intermediate balances
The profit and loss account can also show various intermediate balances (Fig. 7A.4), and canseparate, as for the balance sheet, operating and purely financial items. Such a presentationis often only given in an annex (analysis of the result by sector of activity).
Operating costs
Financial costs
Taxes
Depreciation
CO
STSSales
RE
VE
NU
E
Financial incomeNet profit / loss
Net C
ash flow
Figure 7A.3 Profit and loss account.
Operatingcosts
Depreciation
Cost of net debt
Operatingrevenue Gross operating
surplus
Net profit / loss
Taxation
Operating
after taxprofit / loss
Operatingprofit / 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 maybe 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 forthe effect of taxation on operating revenue. This tax is before taking credit for reliefsrelating to the servicing of debt. These reliefs are accounted for in the item “cost of netdebt”.
• The net cost of debt is made up of costs and financial credits directly attributable to theitems 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.
7A.2.3 Depreciation
Wear and tear on the working equipment since its commissioning is reflected in the balancesheet item net fixed assets, i.e. the value of the all investments less depreciation. The wear andtear for a given year, on the other hand, appears in the profit and loss account in the form ofa debit: the allowance for depreciation. The term depreciation (instead of allowance for depre-ciation) 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. Threeseparate 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 thecompany 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, eachcalculated using its own amortisation rules, which can be different from those used tocalculate the corporate income tax.
In France (and countries operating on the French model) an investment can only bewritten 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 treatmenthas a considerable effect on project economics in cases where the petroleum assets areaggregated for tax purposes (no ring fence), that is, the calculation can be carried out for themall together.
In the system applying in English-speaking countries a further distinction is madedepending on the nature of the investment expenditure:
– Intangibles (services or assets with no residual value) which are treated as a currentexpense in the operating account. Intangibles are not capitalised and do not appear inthe balance sheet;
– Tangibles (physically recoverable, or having a residual value at the end of life of theinvestment), are capitalised in the balance sheet and are depreciated in the operatingaccount according to the rules laid down in the country concerned.
It should be noted that the distinction between tangibles and intangibles can varydepending on the tax rules. Intangibles, for example, may comprise a specific part of aninvestment: the wellhead or casing in the case of a well. They may alternatively be linkedto the physical position of the investment: platforms being tangible (on the surface) and wellsbeing 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 AccountingStandards Board), which recommend unit-of-production depreciation on the basis of thedeveloped proven reserves for investments in the upstream petroleum industry (SFAS 19).
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This recommendation complies with IFRS (IAS 16 – Property, Plant, and Equipement).Investments shared by several fields (treatment facilities, export pipelines) are amortised onthe basis of developed and undeveloped proven reserves, or even by straight-line depreci-ation (usually over 20 years).
7A.2.3.4 Straight-line depreciation
Equipment wear and tear is assumed to be occur uniformly over its life. It is easy to see thatthis 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 instal-lations, although it does not take account of the specific characteristics of the field. The rateof depreciation in this method is calculated by multiplying the straight-line depreciation rateby a factor determined by the tax or company accounting rules applying; the straight-line depre-ciation rate of course depends on the life of the item being depreciated. A particular case ofthis 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-linemethods for an investment of 100, an asset life of 8 years and a declining balance depreci-ation rate of 25% (so a double declining balance since 25% = 2 × 1/8).
Table 7A.1 Comparison of declining balance and straight-line depreciation.
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.
The funds flow statement, also known as the statement of sources and application of fundsor the statement of changes in financial position, summarises all the capital operations whichhave taken place during an accounting period. It is a dynamic account of what has happenedduring the period, and complements the point-in-time perspective of the balance sheet.
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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 accountand 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 Profit and loss account Funds flow statementTAXABLE REVENUES
= cash flow+ change in working capital requirement
= operating cash flow– investment
= available cash flow+ change in debt
+ change in capital– dividends
+ 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 othercountries: it can simply establish itself or a branch without a separate legal status, it can setup a wholly (100%) or partly owned subsidiary, or it can take a holding in an existingcompany.
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 a50% 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 oper-ating out of the national jurisdiction of the parent company.
The parent company draws up its balance sheet and corporate profit and loss account inthe 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, itis necessary to have access to the consolidated accounts of the group.
The principle of consolidation is that the financial statements of the parent companyshould give a picture of all the items which it effectively controls through its subsidiaries.
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The method chosen depends on the level of control, essentially given by the percentage ofthe voting rights owned (Fig. 7A.6).
As defined in IAS 27 Consolidated and separate financial statements, control is definedas the power to direct the financial and operational policies of an entity in order to obtaineconomic benefits from its activities.
The parent company is presumed to have control when it holds more than 50% of thevoting rights (exclusive control) or when, if it holds 50% or less than 50% of the votingrights, it benefits from:
– Control of more than half the voting rights by virtue of an agreement with otherinvestors;
– The power to direct the fmancial and operational policies of the entity under a statuteor an agreement;
– The power to appoint or remove the majority of the members of the managementbodies;
– The power to cast the majority of the votes at meetings of the Board of Directors orthe equivalent administrative body.
Yes�
Full integration
Integrates the accounts as to 100%of all subsidiaries in which
the parent companyhas effective control
An additional item is introduced intothe 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
Yes
Proportional integration
All items included in proportionto shareholding
No
�
Significant influence on company �
Equity method
Holdings valued in proportion toshare of equity (including profit / loss)
of the companies
Control on company
Figure 7A.6 Choosing the method of consolidation.
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Joint control, as defmed in IAS 31 Interests in joint ventures, is the sharing of control ofan economic activity under a contractual agreement. This only exists if strategic financialand operational decisions in connection with that activity require the unanimous consent ofthe parties who share control (co-venturers). Such a requirement ensures that no singleventurer is in a position to control the activity unilaterally.
Significant influence, as defmed in IAS 28 Investments in affiliated companies, is thepower 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 holdsdirectly or indirectly through subsidiaries 20% or more of the voting rights in the companyheld (including potential voting rights).
The accounts of foreign subsidiaries are drawn up in the most important currency in theparticular economic environment concerned, described as the functional currency. In mostcases the functional currency is the local currency, except for a large number of subsidiariesin 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 onthe day the balance sheet is made, and at the mean annual rate for the profit and lossaccounts, conversion errors resulting being included in the equity capital.
Investments are usually depreciated in consolidated accounts by the straight-line methodover their life, with the notable exception of oil- and gas-producing assets, which are depre-ciated by the unit-of-production method, that is as a function of the production profile of thefield.
The fact that different depreciation bases are used for the tax calculations and in theconsolidated accounts leads to the establishment in the consolidated balance sheet of an itemfor 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 differencebetween the value for tax purposes and the book value of an asset or liability, multiplied bythe most recent tax rate. Of course this difference is one of timing rather than in the totalamount, so that the deferred taxes reduce to nil by the time an asset reaches the end of itslife.
Balance sheet parent P
ASSETS LIABILITIES
Net fixed assets 12000 Capital 10000Shares in S 900 Reserves 2000Other assets 4900 Profit for year 800
Debt 5000
17800 17800
Table 7A.2 Balance sheet and profit and loss account of parent P and subsidiary S.
The consolidated balance sheet and profit and loss account are therefore as follows(Table 7A.3):
The example below shows how the equity method of consolidation works. Company Phas acquired a 25% interest in company C for O 200000.
The initial value of the shares included in the assets of P is replaced by the share of equitycapital (capital + reserves + net profit) which they represent in company C. The differencerelative to the original value of the holding is broken down between the items “consolidated
Consolidated balance sheet
ASSETS LIABILITIES
Net fixed assets 12900 Capital 10000Reserves 2000
Other assets 5800 Profit for year 890Minority holdings 110Debt 5700
An example of full integration is shown in Table 7A.2. Parent company P has a 90% stakein 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% × 1000)= 110.
Extract from balance sheet of company C: • Capital ........................................................................................................ 1000000 O
• Reserves ..................................................................................................... 200000 O
• Net profit.................................................................................................... 40000 O
Extract from balance sheet of company P:
ASSETS:• Equity interest in C ...................................................................................... 310000 O
LIABILITIES:• Consolidation surplus (in consolidated reserves) ......................................... 100000 O
• Share of profits of affiliates ......................................................................... 10000 O
Extract from consolidated profit and loss account of company P:
• Share of profits of affiliates ......................................................................... 10000 O
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8.1 RISK IN THE INDUSTRY
Oil is often regarded by the public as a dangerous and polluting industry. This somewhatdramatic view relates particularly to the operations traditionally perceived as the mostcritical, such as drilling and transport by tanker and pipeline, which the public associates withspectacular accidents such as oilwell blowouts and “black tides” which result from majoroil spills. In addition there have been several occasions when routine operations involvinglong-term installations have proven to be a source of danger. Events in the North Sea suchas the capsize of the Alexander Kielland and the fire on Piper Alpha were major contrib-utors to this perception.
Exploration and production activities involve the manipulation of flammable substancesat high temperature and pressure which sometimes contain very toxic gases. The main risksare essentially associated with uncontrolled escapes of hydrocarbons and other hazardoussubstances, which can cause fire, explosions and contamination. There are other dangersinherent in the very nature of the means and processes deployed, such as flares which cancause high levels of thermal radiation, or heavy, bulky objects which are difficult tomanoeuvre. These effects can be amplified by the working environment, which often involvesworking in a constrained space in remote locations, particularly offshore.
Apart from problems occurring during operations, often due to human error, shortcomingsin the design of the structures is another major cause of loss of control in installations. Inorder to prevent this, an assessment of risk must be fully integrated into the design of a devel-opment project and all stages of the engineering.
Exploration and production induce also various effects on the environment, soil, water orair. As all human activities, it contributes to greenhouse gas emissions, which means thatspecific efforts must be taken to limit these effects.
8Health, safety,the environment, ethics
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 Seain 1988 called into question established offshore safety practices. This platform, situated110 miles North-East of Aberdeen in Scotland, was destroyed in several hours following aseries of explosions, killing 167 persons. It led to production being stopped immediately, forseveral months, at five other fields, with a total loss of production of 300000 bbl/d, repre-senting 12% of the production of the North Sea. It was estimated at the time that the loss ofexports amounted to £550 million in 1988 and £800 million in 1989, with a loss of taxrevenue to the British government of £250 million in 1988–1989 and £520 million in1989–1990.
The findings of the enquiry conducted by Lord Cullen had a very major impact, leadingto a complete overhaul of the complex and sometimes conflicting British supervisory system,safety thereafter being overseen by a single administrative body, the Offshore Safety Divisionof the HSE. The report also led to changes in the law, with greater emphasis on objectivesto be met. And finally it made clear the need for the development and application of a safetymanagement system (SMS) by all companies, a practise now regarded as standard in theoffshore industry.
This system is based on making a “safety case” demonstrating that the design, constructionand operation of every offshore installation is completely safe. It involves setting up trainingand safety awareness-building programmes for both contracted personnel and others. It alsoestablished a requirement for external safety audits. The safety case must be updated regu-larly 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, theoperator retains full responsibility for the safety of operations.
Legislation varies between countries, but many of the companies operating in the NorthSea have applied the new approach to safety at other fields all over the world, and these prac-tices 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 reducingthe frequency of malfunctions and minimising their consequences. More specifically thismeans:
– 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 preliminarydesign stage into the overall layout, ensuring safe separations are respected, and systemati-cally separating the oil and gas treatment plant from ignition sources. The organisation ofeach 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 firefightingsystems. It is always equipped with an integrated process control system and an emergency
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shutdown (ESD) system. Detectors continuously monitor pressure, temperature, liquid levels,etc. As an anti-fire precaution, gas detectors automatically shut down production and dispatchthe contents of processing units to the flare. If a fire breaks out, fire detectors automaticallytrigger sprinklers in the zone where fire was detected. Reliability calculations are carried outfor all safety systems which depend on sensors and automatic mechanisms (safety integritylevels or SIL).
Other systems not directly related to oil processing have an essential safety function. Theventilation of certain confined areas, for example, ensures that the concentrations of flam-mable 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 notsafety. The accommodation quarters in dangerous areas are designed to withstand explosionand fire, and an overpressure is maintained in order to prevent gas, smoke or toxic substancesfrom penetrating. The gangways and means of escape must be able to maintain their integrityfor a minimum period following fire or an explosion. At each stage of a project safetyreviews are conducted which are intended to ensure that processes in the treatment plant arerobust. They identify the main hazardous events which threaten the installation: blowout, firesand explosions, escapes of hydrocarbons, ship collision, helicopter crash, etc. Estimates aremade of the probability of occurrence of such events. They describe the measures taken tominimise the risks of accidents and identify their impacts: firewalls, fire-extinguishingsystems, additional ventilation or the installation of walls able to withstand explosions,training and simulation exercises, protected shelters for personnel in the event of a seriousaccident. The consequences of every potential failure are evaluated in terms of human casu-alties, pollution and economic loss.
Safety is monitored and controlled throughout the entire lifetime of installations. Safetysystems and emergency procedures are developed by the operators. In the control room allinstallations are continuously monitored; at the same time, rigorous maintenance is carriedout to prevent accidents and pollution. Those working in installations which process toxicgases, for example hydrogen sulphide, are equipped with gas masks ready for immediate useshould there be a release. Gases no longer in their normal operating ranges are immediatelyflared. Finally, all personnel must ensure, particularly offshore, that they are ready for anemergency evacuation, a procedure practised regularly.
8.2.3 Safety management systems
Having looked at matters related to the design of installations, we shall now turn to safetyissues 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 onthose running businesses to take preventive measures, case law apportioning civil liabilityfor 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 industrialdisasters in recent years.
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The EU Seveso II Directive, which took effect on 3 February 1999 and relates to theprevention of major accidents, states clearly that it is the responsibility of all operating enter-prises to practise a policy of prevention.
Management therefore has a clear responsibility to formulate a safety policy and makeorganisational arrangements for safety. This legal requirement alone is sufficient argumentfor 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 byways other than merely punishing the guilty party. This is made very clear by looking at thecauses of errors. It can be seen that in most cases these are the result of underestimating therisk, suggesting inadequate management and an inadequate appreciation of this danger in theorganisation of the work, equipment ergonomics, etc. What is more, as systems become morecomplex, human error rises because it becomes more difficult for the workers concerned fullyto apprehend the danger associated with their decisions. Management studies have shownthat, since the 1960’s, less than 15% of operational problems which arise, including theprevention of accidents, can be dealt with effectively by the individual. The organisation ofwork and training, and the dissemination of information is therefore critical to accidentprevention and to minimising the consequences of error.
This is why safety management is far more than a matter of merely solving technicalproblems and enacting regulations.
8.2.3.3 Trading off cost and risk
Accidents impose considerable costs on the companies which sustain them; these costs aredifficult to quantify precisely because they include not only the direct costs, but also variousindirect costs such as reduced efficiency and the tarnishing of the company’s image.
Accident prevention equally involves costs. And because risk can never be completelyeliminated, these costs are theoretically unlimited. A limit must be imposed, however: thisis done by making use of the concept of “acceptable” risk.
Of course any death is unacceptable at the level of the individual concerned. But societyappears to tolerate, if perhaps not to accept, that almost 10000 die each year on French roads.If that were not the case, regulation and/or public pressure would ensure that vehicles were buildmore solidly with technical speed limitation, that roads would be made safer, that motoristswould be subjected to more public information about the importance of their behaviour. Thussociety 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 agreedor consensual. For this reason, it cannot be left entirely to individual discretion. This is oneof 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 environ-mental problems resulting from their activities, and set clear environmental targets. Theserelate mainly to reducing the flaring of gas, emissions of hydrocarbons and the oil-contentof effluent, minimising the environmental impact of their operations, preserving biological
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diversity and cleaning up the legacy of historical contamination. The companies are highlyaware 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 theneed for their operations to be clean and safe.
The companies have a duty to minimise the risk of oilspills, the economic, ecologicaland, for many, psychological consequences of which can be enormously damaging to theindustry. Over the last 20 years, and particularly since the Exxon Valdez catastrophe in 1989and the high-profile hearing which followed leading to the award of massive compensationpayments, a battery of regulations and a whole range of technical measures have been putin place internationally to contain possible disasters. Since the Kyoto Protocol in 1996greenhouse gases, and combustion gases in particular, are under scrutiny. In response toconcerns about global warming, and driven also by states desirous of making the most oftheir natural resources, the practice of flaring associated gases is declining, these gasesinstead 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 theaim to reduce significantly the emissions of CO2 due to flaring. According to this organi-sation, natural gas flaring represents around 150 billion cubic meters every year, which ismore than the annual gas consumption of France and Germany and around 15% ofcommitted emission reduction by developed countries under the Kyoto protocol for 2008-2012. Flaring takes place all over the world, firstly in Africa (30%), Middle East (25%) andthe 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 associatedgas in the process where the use or reinjection is not easy. The major international oilcompanies are members of this initiative and some of them have indicated that in newprojects 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 internationalcompanies this “Global gas flaring reduction” initiative will mean a very significantreduction of GHG emissions in the next 5 to 10 years. There is surely a need to associatebetter national companies in areas like the Former Soviet Union and Middle East wherethere is also an important flaring of natural gas. It is still difficult to measure globally thesituation but there is a strong commitment of many actors to improve the impact of explo-ration and production in this area.
The main pollutants generated by exploration and production activities are sulphurousgases. Nowadays measures are taken to purify these gases so that they comply with appro-priate standards.
Liquid effluent poses a particular problem. Water is a by-product of oil production, andthe water naturally contains hydrocarbon emulsions. It is vital that the effluent is cleaned upbefore being discharged. Effluent containing up to 40 ppm oil is presently tolerated, but oilcompanies are seeking to impose a more stringent standard of 15 ppm. Production fromdepleted reservoirs present difficulties, because large quantities of water are used in theproduction process.
Site rehabilitation at the end of field life and in particular, the decommissioning ofoffshore installations, are currently the focus of considerable attention. About a hundred plat-forms are dismantled every year in the Gulf of Mexico. International regulations, which areonly indicative, are generally implemented by host governments. They are currently beingtoughened in order to increase the protection offered to the environment.
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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 bemade of the environmental impacts in accordance both with local statutory requirements, ifexisting, 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 asensitive one, an intermediate stage is carried out comprising a preliminary reconnaissanceand 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, hydro-logical, 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 ofthe 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 tobe taken of the lead times involved for the administrative procedures (approval may take4–6 months), which means that the study needs to be carried out as early as possible. Veryoften the impact statement has to be prepared and submitted for approval before the engi-neering 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 recommendationsmade in it represent a long-term undertaking on the part of the company to protect the envi-ronment.
8.4.2 “During”: the operating phase
The approach depends on the type of operation involved, but it will any case be broadlystructured as follows.
8.4.2.1 The management plan
The management plan, which is implemented by each subsidiary, must include, in additionto an organisation with clearly defined responsibilities which pays close attention to regu-latory compliance, the following mechanisms:
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– Impact and risk assessments for modifications or extensions of activities and installa-tions;
– Up-to-date operating procedures (management of waste and chemical products, proce-dures 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.
It should be remembered that the baseline study and the impact assessment comprise initialstudies of the environmental risks.
8.4.2.2 The anti-pollution plan
Each subsidiary company engaged in exploration and production must have a contingencyplan which includes:
– An analysis of the sensitivity of the local environment to the potential risks, the regu-latory framework and the resources available;
– The definition of a strategy and appropriate action, a system of alert levels, listsassigning 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 graduatedresponse according to the seriousness of the incident.
Anticipating crises and responding to them are the two cornerstones of the contingencyplan, 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 tobe adopted and the monitoring frequency (generally monthly). These indicators measureemissions and discharges (emissions to air, liquid effluents, waste, etc.) and environmentalquality parameters (air, surface waters, groundwater, soil, flora and fauna). Some or all ofthis information may be reported to the authorities. Major efforts have been made to reducethe 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 tomanagement issues (“systems” audits) and technical matters. The procedures must be clearlyestablished, 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.
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8.4.3 “After”: the aftercare phase
Abandonment and decommissioning are dealt with by regulations. The rules governingimpact statements also often provide for account to be taken of site rehabilitation afterproduction has finished.
As far as onshore exploration and production are concerned, there are specific regulationsin most countries: a mining code, an oil and gas law or, as in France, an environmental lawfor 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, includingUNCLOS (United Nations Convention on the Law of the Sea), the London DumpingConvention, 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, andinvolve 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 forprior approval.
8.4.3.2 Offshore decommissioning
The IMO has issued guidelines for the decommissioning of platforms which apply to allmaritime regions except the North Sea, unless more restrictive rules apply locally. Theserules provide as follows:
• All platforms of less than 4000 tonnes and at depths of less than 75 m must be entirelyremoved.
• Platforms which are larger or located in deeper waters can be partially dismantled as longas a depth of at least 55 m is left clear.
• Installations erected after 1 January 1998 must be designed such that they can be totallydismantled.
• For the North Sea and North Atlantic sectors, decommissioning is governed by Decision98/3 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 struc-tures, or steel platforms erected before 9 February, 1999 and where the infrastructureor the jacket weighs more than 10000 tonnes. For this last category the base or footingscan be left in place once the decommissioning report has been accepted. In any case thesuperstructure (“topsides”) must be thoroughly cleaned, inerted and dismantled.
To date some 20 platforms have been decommissioned in the North Sea, but more than400 more remain to be dealt with in the coming years.
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8.4.3.3 Site rehabilitation
Some major rehabilitation exercises and, in some cases, site redevelopments, have beencarried out recently, for example:
– The reforestation of the site of an exploration well in the Madidi National Park inBolivia;
– The restoration, re-vegetation and implementation of anti-erosion measures along apipeline route in South-East Asia (Burma);
– The decontamination of groundwater at a field in Argentina by means of vacuumpumping 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 istherefore impossible to stress too strongly the importance of baseline audits, which allow thedivision of responsibilities to be determined when contamination is an issue.
In conclusion, in implementing an environmental management system, identification andprioritisation of the risks is a crucial first step. But the dynamic element in the system whichensures that the approach will be perpetuated and improvement implemented, is the audit.
By adhering to this approach the operating companies should have no difficulty inobtaining certification under ISO 1400 or EMAS.
But apart from the quest for “recognition”, the environmental management system, likethe safety system, must form a permanent part of an integrated approach to the managementof 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. Theinternational 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 oneanother, an approach which tackles these two issues together proves more effective than apiecemeal 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 andprocedures 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 quantifiedrisk assessment. A guide describing best practice in industry and drawing on the principlesof ISO 9000 certification was published and circulated in 1994. Many companies adoptedthese recommendations and developed a sophisticated system for the management of riskwhich they have often validated through ISO 14001 certification.
The Norwegian system is an example: built on the TQM model (Total QualityManagement, developed by the European Foundation for Quality Management), the purpose
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of which is to build awareness amongst managers and analyse the company’s activity, notonly in economic terms but also in terms of safety, personnel satisfaction, environmentalresults and relations with government. The system adopted by American companies, on theother hand, emphasises the importance of motivating the personnel, cultural diversity, costcontrol and the putting into practice, by management, of all the key elements.
Globalisation and technological progress have transformed the oil business, and nowadaysthe public expects more of the multinationals. At present the oil industry has to operate onthe basis of three inseparable imperatives: economic development, social responsibility andenvironmental protection.
The way in which the industry addresses safety and the environment has changed beyondall recognition in the last 20 years. Safety, once considered the exclusive domain of the safetydepartment, has now become a concern of the company as a whole. Investment decisionshave to be based not only on economic feasibility but also have to factor in environmentaland social issues. Safety and environmental management have become an integral part ofthe business. These matters become even more important when companies are operating inharsh 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 themanagement of safety and the environment is probably the fact that commitments made bythe company are now publicised externally. The overall strategy and the objectives to be metin 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 evaluationto measure the effects in terms of emissions. This leads to a limitation of these emissionswith regard to technical and economic conditions.
8.6 OIL AND ETHICS
The oil industry, like other large industries, cannot develop without regard to the socio-political context in the countries in which it operates. This observation may seem a common-place because all large industries have an impact on the environment, on the economy, onsocial development, and even on a political level. What singles out the oil industry in thisregard, however, is the sheer scale of its impact: no other industry produces or transportssuch large volumes of a raw material which is potentially dangerous because it is inflam-mable, and even explosive in certain conditions. Furthermore it is a raw material which canharm the environment, that is, our biosphere and the infinitely complex living world whichwe 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 naturalsurroundings, our health, our safety. This is why public opinion is so sensitive to mattersrelated to the activities of the oil companies.
But it is not only in the areas of safety and the environment that the oil industry impactson 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 wellenough known, we will not repeat here the statistics showing the importance of oil and gasin the budgets and the GNP of the major producing countries or in the trade balances ofimporting countries, or indeed in the private budgets of consumers, particularly those whoown a car.
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The vital economic role of oil and gas has a whole series of consequences which make fora complex and potentially difficult relationship with society. Public acceptability is of courseone of the prerequisites for the harmonious development of any economic sector. An industrycan only find and retain shareholders, employees, scientists and high-calibre managers if thepublic understands its contribution to development, and believes that contribution to bevaluable, well managed, and acceptable on what might be called an “ethical” level.
The term “ethical” is one which everyone seeks to appropriate: both politicians and thosewho make it their job to monitor the behaviour of politicians, both businesses and theircritics. 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 andsupranational 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 “thescience of morality”; it derives from the Greek ηθικοσ, or moral. Knowing what is moraland what is not, is one of the earliest questions to preoccupy man. Aristotle wrote three bookson the subject, which remain reference works to the present day. It should perhaps beremembered that moral codes are not universal, and can change over time. One of the mostvariable areas in this regard, also in terms of its practical consequences, is probably that ofthe 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 toapproach the problem of ethics by looking in practical terms at some real problems encoun-tered by oil companies. We shall therefore attempt to tackle the most important of theseproblems at the confluence between law, morality, commerce, technology and politics. In thisbrief review we shall try to look at the expectations of public opinion and political leadersas a means of shedding light on the difficulties and contradictions which questions of ethicspose for the oil industry.
In fact the oil industry has achieved an almost unique feat: it manages to project anegative image both in the wealthy, developed or consuming countries (“home countries”)and in the often poor and undeveloped oil-producing (“host”) countries. This doublyunfavourable image is due to the fact that, for their part, consumers hold the oil industryresponsible for the prices, often considered excessive, of the fuels they use. People inproducing countries, on the other hand, often perceive oil companies as veritable “stateswithin a state” exploiting their natural wealth, causing pollution and economic and socialimbalances, or even political destabilisation, in their country.
In drawing up a list of the main ethical problems faced by the oil companies, it has beenpossible 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 moretraditional texts dealing with problems of health, safety and the environment (HSE).
Health, safety and the environment have already been dealt with in this book (Sections8.1 to 8.4), and we shall only refer to them again where, because of their social and politicalconsequences, they have a genuinely ethical dimension which transcends purely technicalissues 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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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 areregarded as too specialised and of secondary importance compared with the fundamentalethical issues, or the relations between the oil companies and host countries. Furthermorethey are not generally issues which are specific to the oil industry.
However this category includes quite a few important issues, which are indeed crucial tothe effective functioning of liberal and market economies. We shall consider a number ofexamples.
First of all what should be the rights and duties of the companies in relation to the privacyof their employees? Is it permissible, and to what extent, for a company to control how itsemployees use their working time, their access to the Internet? Has it the right to limit theirpolitical activity if this is judged potentially detrimental to or in conflict with the activities ofthe company? How can it be sure that none of its employees will get involved in insider dealingon the stock exchange, or that they will not be tempted to accept some personal advantage iftheir duties include procurement or the award of contracts? Will a company be able to guar-antee that career progression and promotion to management will be purely merit-based, withoutany form of discrimination based on gender, national or ethnic origin, religion or political affil-iation? These are well and truly ethical issues, as is the issue of equity in dealings with partnersand suppliers. Clear conflicts of interest can arise between practical expediency and ethics. Isit legitimate to favour one particular supplier of goods or services at the expense of others ifrelations with that supplier accord with the logic of industrial strategy, partnership or regionaldevelopment? The oil industry has a symbiotic relationship with the service industries whichsupply it and a number of special factors apply in consequence.
Many more examples could be mentioned, and we see that often there are different view-points, 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 regardedas paramount. Consider, for example, the issue of ethical conduct towards shareholders. Onone hand there is a duty to ensure that information is transparent. On the other hand, thereis a duty to conduct commercial and industrial activities as efficiently as possible. The latterimperative, by its nature, tends to limit the transparency of information. Striking the rightbalance between two ethical but conflicting considerations is not a matter for detailed andprescriptive rules. It has to be achieved by a combination of detailed knowledge and a goodunderstanding of the problem, a good dose of common sense and, ultimately, the moral qual-ities 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 ofsome 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, andwhich involves a number of risks for oil companies, sometimes difficult to deal with.
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Central to this issue is the nature of the contracts which define the terms under which aforeign company —often powerful and usually from a developed country— will invest in acountry which is often relatively undeveloped, and will be rewarded, if successful, for therisks it has taken.
The terms of these contracts reflect the characteristics of oil and gas exploration andproduction, activities in which chance plays a large part, which are highly capitalistic innature, and which, when successful, have a major impact on the host country. These contractsdefine how the proceeds from the production will be split between the investors and the hostcountry. The appropriation and use of these proceeds, often large in amount, are a majorpolitical issue. They rapidly become central to the economic and political life of the hostcountry, and are the root cause of a host of ethical problems which arise. These problemsusually 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 largefinancial flows, and can lead to or exacerbate factionalism, or even fuel armed banditry. Itis not always possible to make a clear distinction between these two types of destabilisationand violent disorder.
There have been many oil-producing countries in recent years where attempts have beenor 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 oilcompanies are considered by the insurgents as natural enemies in so far as they pay taxesto the State, and are often the largest contributors to their budgets. It is of course thesebudgets which provide the State with the funding needed to maintain law and order orexercise 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 oilrevenues. We only mention the most common ones, which are faced both by host countriesand 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 indi-
viduals or “clans”.
In the face of these problems the foreign investor has to manage its own interests, nothaving any real influence over the political choices of the host country. Such an influencewould in any case be unethical, since interference in the political problems of the countrywould 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 andwhat 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. toget involved in local politics, in such situations.
Faced with dilemmas of this kind, the logical attitude on the part of the oil companieswould be to refrain from interfering in local political affairs. But they then run the risk ofbeing held jointly responsible for the injustices and even crimes perpetrated in the name ofthe State or other authorities in the country. Such problems are not new: ethical debates stillcontinue today about the degree of culpability of Pontius Pilate!
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Only someone completely ignorant of the distribution of oil and gas resources throughoutthe world would subscribe to the idealistic argument that oil companies should only investin 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 toparticular authorities, and if so which ones, the task of deciding either to boycott newinvestment or to discontinue activities in countries where investments have already beenmade? It is clear that such authorities would need to have considerable legitimacy andpowers if their action is to be effective:
– Economic powers to provide for compensation mechanisms should activities bestopped;
– 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 hostcountries, we conclude that oil does not necessarily, in itself, lead to economic and socialdevelopment, nor is it necessarily a democratising factor. However it will be appreciated thatthe adverse effects will be less severe where the political system is perceived by its citizensto be legitimate, and that these systems will permit the oil revenues to be distributed in anequitable and balanced way.
Regimes of this kind would not necessarily have to conform to the model of parliamentarydemocracy, although that is probably the model best able to reconcile oil and socio-economicdevelopment 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 constructionof 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 largenumber of environmental problems. To make it possible, it was necessary to bring theWorld Bank into the project.In 1999 the World Bank Chad agreement introduced an innovative scheme designed tomaximize the social use of oil revenues. With this system, all direct oil revenues (royaltiesand dividends) are paid into a sequestered account in the name of the Chad Governmentin 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 theenvironment and water supplies.
– 4.5% is paid over to the oil-producing region of the Southern Chad, as additionalreserve 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 thegovernment to denounce the agreement with the World Bank. Clearly making such asystem sustainable over time is not easy. Nevertheless, this kind of agreements presentpromising solutions to provide a better use of the energy revenues.
• The Extractive industries transparency initiative (EITI) has the objective to provide for adetailed information on energy and commodity revenues, trying therefore to induce a
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better use of these revenues. This initiative is supported by more than 30 countries and25 big oil, gas and mining companies. It is very interesting in that among the countriesthere are some of the more important oil producers in Africa or Central Asia, such asNigeria, Gabon, Chad, Azerbaijan and Kazakhstan, Trinidad and Tobago. All the majorinternational 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 ofcommodity revenues.
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 areinvolved 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’sneeds for energy. Approximately 50% of this energy is generated by the oxidation of thecarbon contained in hydrocarbons (40% or more for natural gas and more than 60% for oilproducts). This results in the formation of carbon dioxide. This is in the nature of theprocess, and technological progress cannot change it. On the other hand technology can helpus to reduce the amount of energy we consume to achieve a certain result, or perhaps evento “sequester” some of the carbon dioxide produced. However this is not in itself what theethical debate is about. The debate arises from the fact that there is a correlation betweenthe temperature in the lower atmosphere and its carbon dioxide content. This carbon dioxidecontent has been rising ever since the industrial revolution, and the question is to knowwhether increasing consumption of fossil energy could lead to major climate change. Suchchanges could be beneficial to some (Siberia, Canada, Nordic countries) but disastrous toothers (countries with semi-arid climates and low-lying coastal regions in particular). Thesedebates of course go far beyond the confines of the petroleum industry, but the latterinevitably occupies centre stage in relation both to the problems and the solutions or remedialmeasures which will need to be taken.
This vast problem, known as the greenhouse effect, is not the only global or local envi-ronmental problem in which the oil industry is directly implicated. The climatic effectcaused by airborne particulate matter and the health effects of urban pollution are due in largemeasure to the consumption of hydrocarbons. A number of ethical questions arise herewhere political leaders have to make trade-offs, of their nature difficult to justify, betweenshort- and long-term effects, between public health and the economy. Although the oilindustry does not itself have to make these trade-offs, it is directly involved, at very least incompiling technical reports which allow the facts to be established and understood beforedeciding how to try to limit the impacts.
The oil industry is in particular heavily involved in transport-related problems. It has toprovide for the transport of large volumes of oil and gas by land and sea. A number of envi-ronmental questions arise in this connection also, both local (oil spills, etc.) and global (emis-sions of methane from urban gas distribution networks). These questions also involvetrade-offs between costs arising from the demands for ever greater safety and the implicitand explicit costs of pollution, either local or global. This again gives rise to questions ofan ethical nature: what value should we attach, what priority should we give, to the survivalof a particular plant or animal species threatened with extinction, what value to the conser-vation of biodiversity? What value should we attach to a human life? There are so manyquestions to which there are no natural and simple answers, whatever moral or philosophicalframe of reference we adopt.
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It is when major failures occur that these questions resurface: failures such as the wreckof the Erika off the coast of Brittany in the last days of 1999. A detailed analysis of thisaccident and its direct and indirect causes reminded all involved that only constantimprovement in international regulations will allow risks of this kind to be diminished. Thisin no way means an abdication or absence of powers for national states. The latter have adouble task: to put their full weight behind ensuring that the international rules are the bestpossible, and to ensure that the regulations are properly applied on their own territory as wellas by the companies under their jurisdiction.
A further point is that the objective of the oil companies is to produce fossil fuels, thereserves 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 forreducing consumption so as to extend the era of oil and gas. Furthermore if they wish toextend their role as energy suppliers into the very long term they will have to get involvedin 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 itsown specific ethical problems.
No discussion, however brief, of the major ethical problems in which the oil industry findsitself a participant can be complete without mentioning the question of human rights. Wehave already observed, in looking at the relationships with producing countries, that althoughthe 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 socialfabric, sometimes with tragic consequences. The oil industry therefore finds itself placed inthe dock, or even declared guilty, by public opinion when dictatorial political regimesprosper, when civil war breaks out, or when cycles of violence and repression develop. Insituations of this kind the oil industry serves as a scapegoat, and has to face a range of conse-quences. In such cases, as for the environmental problems discussed earlier, there are unfor-tunately no simple rules or clear answers as to what constitutes ethical behaviour by oilcompanies.
But there are areas where progress is being made, and these must be explored, in particularthrough codes of conduct evolved between the governments of the countries of origin of thelarge oil companies and the companies themselves. The U.S. Department of State, forexample, published an agreement of this type on 20 December, 2000, signed by the U.S. andthe UK as well as a number of oil and mining companies from these two countries. Agree-ments 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 articulateexplicit rules of conduct for the companies in such contexts. Agreements of this kindcomprise the first steps towards wider agreements which will also ultimately involve thegovernments of producing countries. We may be about to write a new chapter in interna-tional law, which recognises the right on the part of developed countries to interfere in theway large international companies conduct themselves in other countries.
There is a clear movement from the oil industry to take into account the specific situationof the host countries as they are long-term partners in extraction activity. The internationalcompanies 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 conse-quences of economic development. It has to be a balance between the need for direct inter-vention and the need not to interference with the central and local government of hostcountries.
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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 complywith the rules but also to assume an important responsibility in ensuring that these rules arerealistic, effective and ethical. If the oil industry succeeds in setting behavioural standardsfor the rest of industry, it will have fully accepted the responsibilities conferred on it by itseconomic weight and by the technical and human resources which it possesses.
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Campbell C. J. (1997), The Coming Oil Crisis (Essex, England: Multi-Science Publishing).
Capros P, et al. (1999), Energy Scenarios 2020 for European Union. Congress of the WorldEnergy Council reports.
Cossé R (1993), Basics of Reservoir Engineering. Editions Technip, Paris.
European Commission (2007), World Energy Technology Outlook – 2050 – WETO H2(Luxembourg: Office for Official Publications of the European Communities).
European Commission (2003), World Energy, Technology and Climate Poliçy, Outlook(Luxembourg: Office for Official Publications of the European Communities).
Gallun R, Wright C, Nichols L, Stevenson J (2001), Fundamentals of Oil & Gas Accounting.PennWell.
Gorelick S (2009), Oil Panic and the Global Crisis: Predictions and Myths, Wiley-Blackwell.
Gray F (1995) Petroleum Production in non technical language. PennWell.
Heinberg R (2005), The Party’s Over: Oil, War and the fate of industrial societies, ClairviewBooks.
Herz DB (1979), Risk analysis in capital investment. Harvard Business Review 42, 1(janv./fév.) 1964 ; réédité 57, 5, (sept./oct.).
Horsnell P (1997), Oil in Asia. Markets, Trading, Refining and Deregularation. OxfordUniversity Press.
International Energy Agency, Energy Technology Perspectives, Scenarios & Strategies to2050 (Paris: IEA Publications).
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International Energy Agency, World Energy Outlook 2010 (Paris: IEA Publications).
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Johnston D (1994), International Petroleum Fiscal Systems & PSC. PennWell.
Johnston D, Bush J (1998), International Oil Compagny Financial Management in NonTechnical Language. PennWell.
Jones PE (1998), Oil: a Practical Guide to the Economics of World Petroleum. Woodhead-Faulkner.
Karl TL (1997), The Paradox of Plenty: Oil Booms and Petro-States. University Presses ofCalifornia, Columbia and Princeton.
Koller G (1999), Risk Assessment & Decision Making in Business & Industry: a PracticalGuide. CRC Press.
Lerche I, MacKay J (1999), Economic Risk in Hydrocarbon Exploration. Academic Press.
Mac Cray AW (1975), Petroleum evaluations and economic decisions. Prentice Hall,Englewood Cliffs.
Mari JL, Arens G, Chapellier D, Gaudiani P (1999), Geophysics of Reservoir and Civic Engi-neering, Editions Technip, Paris.
Noreng O (2001), Crude Power: Politics and the Oil Market. IB Tauris Publishers.
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Roberts P (2005), The End of Oil: The Decline of the Petroleum Economy and the Rise ofa New Energy Order, Bloomsbury Publishing PLC.
Royal Dutsch Shell (2005), The Shell Global Scenarios to 2025. The Future Business Envi-ronment. Trends, Trade-Offs, and Choices (London: Royal Dutch Shell).
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Arditti FD, Levy H (1997), The weighted average cost of capital as a cutoff rate: a criticalexamination of the classical textbook weighted average. Financial Management 6, 3 (Fall).
Babusiaux D, Pierru A (2001), Capital budgeting, investment project valuation and financingmix: methodological proposals. European Journal of Operational Research 135, 2 (sept.).
Barsky R. and Killian L (2004), Oil and the Macroeconomy since the 1970s, Journal ofEconomic Perspectives 18, no. 4: 115-134.
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Deffeyes K (2001), Hubbert’s Peak: The Impending World of Oil Shortage, PrincetonUniversity Press, 2001, chapter 1. ISBN: 0691116253.
Energy Information Administration, Annual Energy Outlook with Projections to 2035 (Wash-ington D.C.: United States Department of Energy), December, http://www.eia.doe.gov.
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5. WEB sites
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This book is made up of contributions from the following authors:
Nadine Bret-Rouzaut and Jean-Pierre Favennec were the overall coordinators.
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Arbitrage Financial operation which seeks to exploit geographical or temporal pricedifferences. 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 hydrocarbonsis 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 deter-mining 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 Receipts (cash in) less disbursements (cash out).
Casing 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 andsea freight to the destination port.
Club of Rome Think tank in the 1970s renowned for publicising the risks of depletion ofnatural resources due to over – rapid economic growth.
Commercial discovery A discovery of hydrocarbons the commercial potential of whichhas been demonstrated by an operator based on technical, economic, contractual and fiscalparameters. A discovery cannot be developed and exploited until it has been declaredcommercial.
Completion The operation of deploying production equipment in an oil well.
Concession An arrangement by which the state grants the exploration and productionrights 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 appro-priate 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 somecountries, the contract associated with this mineral title.
Glossary
Consolidated profit Accumulated net profit/loss, both national and international, of theparent company and all its branches and subsidiaries in which it holds a significant share ofthe voting rights.
Constant money Notional monetary unit based on the purchasing power of the money ina reference year.
Conventional hydrocarbons Hydrocarbons which can be produced by “conventional”methods and have standard characteristics in terms of viscosity, density, etc. Conventionaloils are supposed to be between 10 and 45° API in gravity.
Coring Operation involving taking a cylindrical sample of rock, carried out by means ofa special tool – a core barrel – in a probe.
Cost oil In a Production Sharing Contract the fraction of the production allocated torecover 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 petroleumindustry service company by which the former controls the operations and the contractorreceives a fixed daily remuneration.
Delineation After preliminary drilling has demonstrated the presence of hydrocarbons ina structure under exploration, the subsequent drilling programme which allows the poten-tially productive formations to be defined and delimited.
Derivatives On futures markets a distinction is made between contracts (firm commitmentsto buy or sell a quantity of crude or a product) and derivatives: options, swaps,… Manyderivatives are OTC (over the counter) transactions —carried out between two parties bymutual agreement, without the intercession of an organised market.
Derrick Tower like lattice structure in the form of a truncated, elongated pyramid. Indrilling equipment a derrick is used for hoisting and lowering.
Development costs Costs associated with the drilling of the production wells (and ifapplicable the injection wells), the construction of the surface facilities (collection network,separation and processing plant, storage tanks, pumping and metering equipment) andtransport 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 themcomparable. The discount factor for year n relative to year 0 is 1/(1 + i)n (where i is thediscount rate).
Discount rate Cost of capital (effective cost or opportunity cost), the internal rate atwhich the financial department requires remuneration from departments responsible forinvestment projects. A company usually defines the effective cost of capital as the weightedaverage 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 ofcapital 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 expen-diture in a number of years as on the same sum now. Discounting consists of applying a given
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annual rate (this rate is specific to the company) to future receipts and expenditures toestimate their present value. Discounting tends to reduce the importance of future cash flows.
Dubai Reference crude for trade East of the Suez Canal.
Economic rent The difference between the value of production (gross revenue) and thetechnical costs (capital and operating costs), before tax.
Equivalent cost When the equivalent cost (annual or unit) can be assumed stable overtime, we have:
• Equivalent annual cost: the annuity equivalent to the discounted capital and operatingexpenditure.
• Equivalent unit cost: the ratio of the total discounted expenditure to the total discountedproduction.
Exploration costs Costs incurred before the discovery of a field, including costs relatedto the seismic/geophysical programme, the geological and geophysical interpretation, theexploration drilling including the test wells.
Extra heavy crude Very heavy crude (specific gravity greater than 1, so API less than10°), found particularly in Venezuela in the Orinoco basin. The Orinoco crude is a nonconventional one since, before use, it needs a special treatment to make it suitable forprocessing in a traditional refinery
Field A field can be defined as a receptacle comprising a permeable rock reservoir sealed bya 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 whichdetermine how the oil profits are shared between the state and the holder of exploration andproduction rights
FOB (free on board) The FOB price is the price of a crude oil or of a product when loadedonto a ship at the port of embarkation. In principle at any given time there is only one FOBprice for a port (Ras Tanura for Arabian Light, Sullom Voe for Brent, Bonny for the Nigeriancrude of that name) whereas there are as many CIF —see CIF— prices as there are desti-nation ports.
Foot rate contract Type of contract signed between a petroleum industry servicecompany and an oil company where the latter controls the operations and the former is remu-nerated according to some measurable unit of activity (for example per metre drilled in thecase of a drilling company).
Full cost method Accounting method defined by SFAS 19 and applying to explorationand production expenditure. All expenditures (exploration and development) are capitalised.
Futures markets Financial markets on which normalised contracts for crude or petroleumproducts are exchanged. They meet the needs of operators to protect themselves or exploit pricefluctuations using hedging, arbitrage and speculation. Physical deliveries account for only asmall part of the transactions effected on futures markets. Orders are transmitted by a brokerand the security of operations is guaranteed by means of deposits to a clearing house. The mainmarkets 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 thetop of the structure.
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Gas lift Production process involving gas injection which serves to emulsify and lightenthe 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 companieswhich 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 thebeginning of the eighties, the prices of the various crude oils —GOSP— were fixed by theOPEC governments. These prices replaced posted prices.
Government take The total revenues accruing to the government including the earningsof the national oil company. It can be expressed as a percentage of the economic rent, andmeasures the severity (from the investor’s point of view) of the fiscal regime.
Heating oil Petroleum product used for space heating in residential and commercialbuildings.
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 assignsexploration rights (exploration licence) or production rights (production licence orconcession) to a party.
IFP (now IFP Energies nouvelles) French Petroleum Institute, a scientific institute devotedto research, training and documentation, founded in 1944, from which has emerged anextensive structure of companies and consultancy services.
Internal rate of return (IRR) Discount rate at which the net present value of a project isnil. When unique, this is the maximum rate for which the project revenues allow the investedcapital to be remunerated without the project going into deficit. In this case a project forwhich the IRR is greater than the discount rate has a positive net present value. On the otherhand in choosing between several competing projects, it is not necessarily that with thehighest 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 wellduring drilling, by means of sensors deployed in the drilling equipment, physical parameterswhich allow the nature of the formations, their pressure regimes and the fluids of which theyare composed to be characterised.
Logging The recording of certain electrical, acoustic and radioactive characteristics ofgeological formations.
Migration A physical process in which hydrocarbons move from a source rock to areservoir.
Monte Carlo Simulation method used, in particular, to determine the probability distrib-ution function of a variable (e.g. net present value) which is a function of other variableswith given probability distribution functions.
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Mud logging A technique which involves the acquisition and interpretation at the surfaceof samples, data and information, making use of the mud circuit.
National oil company Oil company fully owned by the state or in which the state has amajority holding, to which the government delegates the role of supervising oil operationsand 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 witha project. An investment project with a positive NPV will repay the investment giving areturn equal to the discount rate and produce a surplus whose present value is equal to theNPV.
Netback The netback value of a crude is equal to the value of the products obtained fromits processing less refining and transport costs. The netback value of a crude can be comparedwith 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 conventionalhydrocarbons, are difficult and costly to produce, and whose physical characteristics andgeographical situation are exceptional. Non conventional oils include extra heavy oil (fromOrinoco) and tar sands (from Athabasca – Canada) which both need a special processingbefore treatment in traditional refineries. Non conventional oil includes also ultra deepoffshore fields.
Offshore Refers to any exploration or production activity at sea, in contrast with onshoreactivities. 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 ameans of regulating prices. Since that date, each OPEC member state has had to remainwithin 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, insand reservoirs. There are very large deposits of tar sands in Athabasca, Canada. Theproduction of oil from these sands is currently being developed.
OPEC Organisation of petroleum exporting countries, created on 14 September 1960 bySaudi Arabia, Iraq, Iran, Kuwait and Venezuela.
Opening up Many producing countries nationalised their oilfields in the 1970s. Nowcertain countries are reopening their doors, allowing foreign companies to operate in theirterritory.
Operating cash flow Cash flow excluding flows related to loans used to finance theproject.
Operating expenditures (OPEX) Total expenditure which relates to the operation of aproduction facility.
Options Financial instrument giving the holder the option to buy (call) or sell (put) acontract 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).
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Petrol (gasoline–US) Fuel used by spark–ignition engines.
Petroleum price shock Term used to describe a large increase in oil prices, particularlythe “first price shock” of 1973 and the “second price shock” of 1979 – 1981.
Petroleum system Designates the interplay of the geochemical, geological and physicalparameters, the processes and the genetically related hydrocarbons which lead to seepage andaccumulations 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 isusually a period of stable production (plateau) followed by a progressive decline.
Production Sharing Contract Arrangement by which exploration and production rightsin a given zone are granted by the state to a contractor who, in the event of commercialproduction, can recover his costs from a part of the production (cost oil) and obtain a returnon 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 costoil. This part is shared between the contractor and the state on the terms agreed in thecontract.
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 % forcrude oil depending upon field and oil characteristics. Average value (for crude oil) isaround 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 thepartners in the Iraq Petroleum Company. This line marked a region within which the partnercompanies in the IPC were obliged to act in concert.
Reserves There are many definitions of hydrocarbon reserves. The reader is referred to theindex, 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 toa percentage of the crude price. This royalty, often fixed at 12.5% of the crude price, canvary 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 byexplosions are reflected by the subsoil strata.
Sensitivity analysis Analysis of the impact on the profitability of a project of possible vari-ations 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.
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SFAS Statement of Financial Accounting Standards.
Spot market A market in which deals are struck on the day itself, with prices being fixedat the time. The products traded are physical cargoes of crude and refined products. Thereis no official record of transactions effected between operators, but estimates are publishedby specialised journals such as Platt’s. There are spot price estimates for both crudes andfor the principal products for the main consuming and refining regions: Rotterdam or NorthWest Europe, the Mediterranean, the Gulf, Singapore, the Caribbean, the U.S. The spot priceof the main crudes (Brent, WTI, Dubaï) act as indicators of crude prices and as referenceprice 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 participatein 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 theexpenditure associated with exploration and production. The costs of the geology geophysicsand unsuccessful exploration are expensed.
Swaps A type of “paper” contract in which the difference is bought between its valuesquoted on the spot and forward markets. This instrument allows oil companies to make salesto their customers for delivery several months hence (up to one year) at a guaranteed fixedprice.
Tax In a concessionary system, the operator pays the owner of the field not only royaltiesbut also a tax on profits.
Technical cost Total costs : exploration + development + production costs
Teheran Agreements Agreements (signed in 1971) between OPEC and the oil companieswhich provided for programmed increases in oil prices for the Gulf producers.
Traders Persons who buy and sell commodities, currencies or financial instruments. Unlikea 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 significantrisk. A petroleum trader may be attached to a producing country, belong to an oil companyor 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 companieswhich 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 companyand a petroleum industry service company. Unlike a cost reimbursement contract or a contractbased on a work specification, the contractor is responsible for the operations and is paid forservices rendered (a drilling project, for example) at a contractually agreed overall price.
Unitisation Contractual clause providing for the unified operations for a field extendingover several contractual zones exploited by different operators.
Uplift Device equivalent to an investment credit authorising the holder of productionrights 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.
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Wire line logging A technique which involves using sensors lowered on the end of anelectric cable to record physical parameters such that the nature of the formations, theirpressure 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 NYMEXmarkets.
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UNITS FOR THE PETROLEUM INDUSTRY,RATE CONVERSION
Symbols
k = 103 = kilo = thousand
M = 106 = mega = million
G = 109 = giga = billion
T = 1012 = tera = trillion
t = ton
m3 = cubic meter
ft3 = cubic foot (or cu ft)
bbl = barrel
oe = oil equivalent
Petroleum units Gas units
1 bbl= about 0.14 t (1 t = 7.3 bbl) 1 Tm3 = 35.3 T · cu ft (1 T · cu ft = 28 G ·m3)
1 bbl= 0.159 m3 (1 m3 = 6.3 bbl) 1 boe = 5.35 k · cu ft (1 k · cu ft = 0.18 boe)
XIV
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INDEX
Index Terms Links
A
Abandonment 186 197
Achnacarry Agreement 18
AGIP 23
Agreements 302 305
geneva 302
teheran 305
tripoli 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 9
Balance sheet 266
Balikpapan 10 11
Barges 73
Benchmarking 254
Between Iraq and Iran 31
Index Terms Links
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Bonus 194 195
Brent 48
Brent blend 44
British Petroleum Company 12
Buyback contracts 203
C
C.S. Gulbenkian 18
Cash flow statement 271
Casing 73
Caspian 8 9
Caspian Sea 8
CFP 15 16 17
18
Churchill 12
CIF 45
Clemenceau 15
Club of Rome 25
Commerciality 185
Compaction 61
Compagnie Française des Pétroles 15 17
Competent authority 176
Completion 86
Concession 174 179 180
193 206
Consolidated accounts 272
Contract 164
day-rate 164
foot-rate 164
turnkey 164
Conventional hydrocarbons 99
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Cost 221
equivalent cost 221
Cost oil 200
Costs 125 127 131
156 158 255
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 250 270 271
declining balance 271
straight-line 271
UOP 250
Derivatives 49
Derrick 73
Deutsche Bank 17
Diesel 3 44
Diesel oil 44
Diesel-oil 7
Discordance 61
Discount rate 217
Dubai 49
Index Terms Links
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E
Economic reproduction 109 110 111
Ekofisk 44
Elf 15 20
EMS 144
ENI 15 20 23
EPC 144
Expected value 231
Exploration 65
Extra-heavy oils 100
Exxon 7
F
FASB (Financial Accounting Standards Board) 245
Fina 20
Finding cost 259
FOB 45
Forward 49
Fossil carbon continuum 100 111
Fuel oil 7
Full cost method 247
Futures 49 50
Futures markets 48
G
Gas cap 79
Gas clause 192
Gas hydrates 104
Gasoline 7 44
Geneva 27
Index Terms Links
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Geology 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 46
Horizontal drilling 85
Hubbert theory 105
Hydrocarbons in place 95
recoverable 95
I
IEA 29 50
Incentives 193 204 207
INOC 25
Installations 137
production 137
transport 137
Institut Français du Pétrole 23
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Intensity of 259
Internal rate of return 220
Investment 259
Investment credit 197 200 208
J
Jackup 73
Jet-fuel 44
John D. Rockefeller 5
Jossef Djugashvili 9
K
Kerosene 2 5 6
7 10
Kirkuk 18
Kuwait 4 19 36
L
Lacq 21 22
Law 175
Legislation 175 176
LNG cycle 151
Logging 75
logging while drilling 75
mud log 75
wireline logging 75
Lognormal distribution 96
M
Majors 7 20
Marcus 10
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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 102
Non-conventional hydrocarbons 99
Norsk Hydro 167
O
OAPEC 28
Oil shales 101
Oil shock 27 28 30
Oklahoma 45
OPEC 24 28 30
31 32 33
Optimists 109 110
Options 49
Ownership 171 172 194
P
Participation 207
Permeable 65
Pessimists 109 110
Petrol 3
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Petroleum system 65
Platforms 73
Polar zones 103
Porosity 65
Production profiles 104
Production sharing 174
Production sharing contract 179 180 199
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 19
Regulations 177
Relinquishment 183
Rent 178
Reserve 258 260
Production-sharing contract (PSC) 261
replacement cost 260
replacement rate 258
Reserve ratio 252
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Reserves 93 95 248
1P, 2P and 3P 97
conventional 94
non-conventional 94
P90, P50, P10 97
possible 98
probable 98
proven 98
SFAS 69 definition 248
ultimate 93
Resources 95
Rigs 73
Ring-fencing 196
Risk service contract 179
Rockefeller 5 6 45
Rothschild 8
Royal Dutch Shell 9 15
Royalty 194 195 206
S
Samuel 8 9 11
Saudi 4
Saudi Arabia 19
SEC 244
Sedimentary basins 61
Seismic 69
reflection 69
Semi-submersibles 73
Service contract 180 202 203
Seven sisters 23
SFAS 69 (Statement of Financial Accounting
Standards) 245
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Shell 9 10 11
Sherman Act 6
Six Day War 25
Slot ratio 252
Socal 19
Sovereignty 171 173
Spar 149
Spindletop in 1900 12
Spot markets 48
Stalin 9
Standard Oil 5 6 9
10 15 18
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 176 194 205
207
Tax incentives 190
Taxation 197 202
Teheran Agreement 27
Texaco 12 19
Texas 12 45
Texas Railroad Commission 46
Title 199
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