Norwegian Oil Policies 9780773593268

Table of contents :
Cover
Title
Copyright
Contents
Tables
Preface
1. Introduction
International oil industry
The 'Seven Sisters' and OPEC
North Sea history
Norwegian economy
2. The Level of Production
The theory of resource depletion
Norwegian policy
Pressures for change
U.K. policy
3. Future Exploration
Exploration of 62° N.
The danger of pollution
Oil and fishing
4. Downstream Processing
The petroleum-based industries
Petroleum-based industries in Norway
The industrial use of North Sea discoveries
Petroleum-based industries north of 62° N.
Petrochemical industries and regional development
5. Employment Creation
The present position
Regional distribution
Recruitment patterns
Foreign labour
Future trends
Government policy
6. The Role of Statoil
The emergence of Statoil
Licences and exploration
Development and production
Downstream activities
Financial implications
Comparison with BNOC
7. Use of Oil Revenues
The size of the revenues
The use of revenues
International competitiveness
Domestic plans
Overseas spending
Some conclusions
8. Conclusions
BIBLIOGRAPHY
INDEX

Citation preview

NORWEGIAN OIL POLICIES

T. LIND / G. A. MACKAY

MONTREAL

McGILL-QUEEN'S UNIVERSITY PRESS

First published in the United Kingdom by C. Hurst & Co. (Publishers) Ltd., 1-2 Henrietta Street, London WC2E 8PS Published simultaneously in Canada by McGill-Queen's University Press, 1020 Pine Avenue West, Montreal H3A 1A2 © T. Lind and G. A. Mackay, 1979 ISBN 0-7735-0510-5 Legal deposit fourth quarter 1979 BibliothØue Nationale du Quebec

Printed in Great Britain

CONTENTS PREFACE

Oil and gas in the North Sea area 1. Introduction International oil industry The 'Seven Sisters' and OPEC North Sea history Norwegian economy MAP :

2. The Level of Production The theory of resource depletion Norwegian policy Pressures for change U.K. policy 3. Future Exploration Exploration of 62° N. The danger of pollution Oil and fishing 4. Downstream Processing The petroleum-based industries Petroleum-based industries in Norway The industrial use of North Sea discoveries Petroleum-based industries north of 62° N. Petrochemical industries and regional development 5. Employment Creation The present position Regional distribution Recruitment patterns Foreign labour Future trends Government policy 6. The Role of Statoil The emergence of Statoil Licences and exploration Development and production Downstream activities Financial implications Comparison with BNOC

V

page Vii viii 1 1 7 10 17 28 32 35 40 46 50 52 55 58 62 62 64 65 69 73 78 81 84 87 89 91 93 98 99 102 105 109 110 111

7. Use of Oil Revenues The size of the revenues The use of revenues International competitiveness Domestic plans Overseas spending Some conclusions

117 117 123 125 128 132 134

8. Conclusions

138

BIBLIOGRAPHY

147

INDEX

149

TABLES 1.1 Estimated crude oil production 1.2 Primary energy consumption, 1977 1.3 Licensed areas (as at 1 January 1978) 1.4 Wells drilled 1.5 Petroleum discoveries, 1968-77 1.6 International comparisons of GDP per capita, 1975 1.7 Gross domestic product by industry 1.8 International unemployment percentages 1.9 Consumer prices: percentage changes 4.1 Output of petrochemical products, 1950-72 4.2 Refineries in Norway 4.3 The Norwegian petrochemical industry, 1978 4.4 Construction and running costs for an integrated and a decentralised petrochemical complex 4.5 Employment creation and local recruitment 5.1 Oil and gas employment 5.2 Employment by category 5.3 Regional distribution by category, August 1977 5.4 Foreign labour involvement 5.5 Employment forecasts 6.1 Statoil's estimated capital expenditure 6.2 Operational and financial income 7.1 The distribution of revenue 7.2 International unemployment trends 7.3 Long-term fiscal budget, 1979-81 vi

5 7 12 13 15 17 18 20 21 63 64 64 74 76 81 83 85 89 92 109 110 122 129 136

PREFACE The origins of this book lie in various visits the authors have made to each other's research institutes during the last few years. Terje Lind was a postgraduate student in Aberdeen during the sessions 1975-6 and 1976-7, and has since paid regular visits to Aberdeen. Tony Mackay spent six months in 1977-8 as a visiting research fellow at the Norwegian Institute for Urban and Regional Research (NIBR) in Oslo. Both NIBR and the Institute for the Study of Sparsely Populated Areas (ISSPA) in Aberdeen have developed strong interests in the North Sea oil developments, and this book is one of the results of our joint co-operation. It is written primarily for an English-speaking readership, although we hope that others will find it worth reading. In the United Kingdom, and in Western Europe and North America generally, in the recent past there has been a markedly increased interest in Norway. The North Sea oil and gas discoveries have been one of the main reasons, and we therefore thought that a book on Norwegian oil policies would be a useful contribution at this time. It is in fact the first book in English on Norwegian oil policies, and hitherto there has been no comparable book in Norwegian. In a short compass it is not possible to be comprehensive and we have had to be selective in material, although we hope that all the major issues have been covered. The book was written in 1978, and the pace of change in the North Sea is such that some figures are rapidly outdated. Most of our statistical material relates to 1977 and the reader is asked to make allowance for any changes which have occurred since the work was completed. In writing the book we have been greatly assisted by our friends and colleagues in NIBR and ISSPA, the oil industry and other bodies. We wish especially to mention Kjell Stenstadvold of Bergen School of Economics and Joe Kemp of Aberdeen University. Helen Perren typed the drafts with skill and good humour. Our publisher, Christopher Hurst, deserves thanks for his encouragement and patience. Finally, we add the usual qualification that we alone are responsible for the views expressed and any errors or omissions. T. LØ, Oslo G. A. MACKAY, Aberdeen

vii

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1 INTRODUCTION There were ten girls, who took their lamps and went out to meet the bridegroom. Five of them were foolish and five prudent; when the foolish ones took their lamps, they took no oil with them, but the others took flasks of oil with their lamps. As the bridegroom was late in coming they all dozed off to sleep. But at midnight a cry was heard: 'Here is the bridegroom! Come out to meet him.' With that the girls all got up and trimmed their lamps. The foolish said to the prudent, 'Our lamps are going out; give us some of your oil.' 'No', they said, 'there will never be enough for us both. You had better go to the shop and buy some for yourselves' . . . Keep awake then; for you never know the day or the hour. (Matt. 25. 1.13) The main purpose of this chapter is to set the scene for the detailed analysis of subsequent chapters. Norway is a small country, particularly in terms of population, and outside Scandinavia relatively little is known of its economy. North Sea oil has generated a great deal of international interest in Norway, but even then the oil reserves are only a small fraction of world oil reserves and Norwegian activities will not have a major impact on the international oil industry. In this book we have chosen to examine one particular aspect of economic activity : Norwegian oil policies. A proper understanding of their formulation and operation can only be achieved if the appropriate national and international contexts are appreciated. This chapter covers the three main aspects: the international oil industry, the Norwegian energy market and the current state of the Norwegian economy. It also provides a brief historical background to the current operations in the North Sea. International oil industry The oil industry has been with us for many, many years but it is only in the last thirty years that it has become of major international importance. During this period, the demand for energy has increased sharply and oil has risen from a position well down the league table of fuels to account for now about 45 per cent of world primary energy consumption. Natural gas has had an even

I

2

Norwegian Oil Policies

more marked rate of growth, now accounting for about 20 per cent of oil consumption. In 1957, the shares of oil and gas were about 30 per cent and 10 per cent respectively. The rate of growth of international trade in oil and gas has been even faster and together they account for more than half total world trade today. Oil's importance transcends even economic issues, as events in the Middle East over the last decade have shown clearly. What, in this vast industry, is the role of Norwegian oil? Some knowledge of geological factors is essential.' Briefly, hydrocarbons are formed from marine deposits. Certain geological conditions have had to exist in the long-distant past for successful formation. The first condition is the existence of suitable source rock, which for hydrocarbons is generally believed to be sedimentary, i.e. that formed by the deposition on the sea bed of marine sediment such as plankton and bacteria. Over time the sediment became buried as more material was deposited from rivers and other sources and, as the depth of burial increased, pressure and temperature resulted in the formation within the sedimentary rock of hydrocarbon molecules. The North Sea is a sedimentary basin of this type, and the appropriate source rocks were laid down during the Carboniferous, Jurassic and Tertiary periods — between 350 million and 2 million years ago. A second condition is that there must exist above this source rock suitable strata of reservoir rock and cap rock. The reservoir rock is that in which the various forms of hydrocarbons accumulate, and it therefore has to be both porous and permeable to allow the molecules to move vertically or horizontally through the salt water trapped in the pores. The hydrocarbons will continue to move upwards — being lighter than water — until they encounter impermeable rock through which they cannot pass. In such circumstances, a pool or reservoir of hydrocarbons will build up beneath the cap rock. Various geological structures such as faults, anticlines and stratigraphic traps are particularly useful in the accumulation of hydrocarbon deposits. Very simplistically, then, these deposits occur where there have existed over time the right combinations of source rock, reservoir rock and cap rock. The necessary conditions are so severe that deposits will be rare and very difficult to detect. Oil and gas exploration is simply the search for such deposits. Although this brief description may suggest that the formation of hydrocarbon reservoirs is straightforward and common, this is far from being true and it should be remembered, for example,

Introduction

3

that the natural gas process has taken up to 350 million years to reach the present stage. For our purposes it is necessary to mention a few types of hydrocarbons. The most important in the present context is oil or, more correctly, liquid petroleum (which is distinct from petrol, a product obtained from petroleum). Petroleum is a mixture of hydrocarbon compounds, sometimes together with impurities such as sulphur and nitrogen, and can exist in three forms: as a solid, liquid or gas. In its solid form petroleum is made up of the heavier compounds and occurs naturally as tar, bitumen and asphalt, etc. These are occasionally found on the surface of the earth, as in the famous pitch lake in Trinidad and in the Athabasca tar sands in Alberta, Canada. Petroleum in its liquid form is known as crude oil and is usually well beneath the earth's surface. For example, the North Sea discoveries have been in rocks 4,000 metres beneath the surface. Liquid petroleum is the feedstock for refineries which produce petrol, fuel oil, diesel oil and so on. Petroleum in its gaseous form is known as natural gas (as distinct from manufactured gas or town gas), and consists of the lightest hydrocarbon compounds. Again, this normally occurs underground but occasionally escapes to the surface. It has been suggested, for example, that the fiery furnace of Shadrach, Meshach and Abednego mentioned in the Old Testament of the Bible was a natural gas seepage which had ignited.2 One point to remember is that these different types of hydrocarbons can be found separately or together. In the very old rocks, natural gas is almost always found on its own, but in the newer rocks crude oil is usually found associated with natural gas, sometimes in the form of condensates. The proportion of associated gas varies enormously: for most North Sea fields it is very small, but for some, such as Ekofisk, it is of a volume worth developing in its own right. The land continents, together with the shallow continental shelves which surround them, occupy about one-third of the surface of the earth; the remaining two-thirds are covered by water. Over time the continents and the oceans have shifted, however, and sedimentary basins like the Middle East have been forced upwards and lost their water cover. This is why oil and gas have been found on land — often hundreds of miles from the nearest sea — and it is certain that those parts of Western Europe where hydrocarbons have been found on land, such as in the Netherlands and the U.K., were once part of a submerged sedimentary basin.

4

Norwegian Oil Policies

There is no need here to provide a history of the oil industry. The earliest record of the use of oil is in the Old Testament. A solid form of hydrocarbons — bitumen — was used both by the builders of the Tower of Babel and by Noah for his ark. Its commercial use in modern times probably dates back to the middle of the nineteenth century when James `Paraffin' Young developed the shale oilfields in Central Scotland. It was not until 1859, in the United States, that the first well was sunk into the ground in an attempt to find oil. Offshore production, through the drilling of offshore wells, began in the shallow inland waters of Lake Maracaibo, in Venezuela in the early 1920s. In open waters the first wells were drilled in the Gulf of Mexico in the 1940s. It has taken a long time, therefore, for man to use what came into existence many millions of years ago, and offshore oil activity has a very short and recent history. The oil industry grew up in the United States. Gradually the search spread worldwide, and the era of the international oil industry began with the discovery of huge oil fields in the Middle East in the late 1940s, since when the Middle East has established itself as the largest oil and gas province in the world. One of the major attractions there is that the oil and gas are fairly close to the surface, on land, and relatively easy to produce. In contrast, those in Western Europe are deep, almost all offshore and under the North Sea, a hostile environment making exploration and production both difficult and expensive. According to British Petroleum,$ the earth's `published proved reserves' of oil at the end of 1977 were 88.6 million tonnes (or 653.7 million barrels),' of which 56 per cent were in the Middle East, 6.6 per cent in North America and only 4.2 per cent (3.7 million tonnes) in Western Europe. Regarding natural gas, estimated world reserves at the end of 1977 were 7.4 trillion cubic metres5 of which 36.5 per cent were in the U.S.S.R., 28.5 per cent in the Middle East, 10.7 per cent in North Africa and 5.5 per cent in Western Europe. From the point of view of international trade, the crucial point is that the domestic requirements of the Middle East countries are tiny in comparison with their reserves and current levels of production, so they have become the major source of crude oil supplies for countries throughout the world, with the exception of the Communist bloc. The international character of the oil industry can probably best be seen from Table 1.1 which gives estimated production figures for the period 1976-8.6 The dominance of the Middle East

Introduction

5

Table 1.1. ESTIMATED CRUDE OIL PRODUCTION (million tonnes) %Change %Share 1977-78 1978 1977 1978 1976 18.1 528.4 554.0 + 4.8 525.7 North America 7.8 233.4 240.2 + 2.9 South America 229.2 34.8 - 6.4 1,116.5 1,134.3 1,061.9 Middle East of which: 13.4 410.0 -10.6 Saudi Arabia 428.8 458.5 8.3 282.2 255.0 - 9.6 Iran 294.0 271.9 284.5 - 2.5 9.1 Africa 277.3 +29.8 64.3 83.4 2.7 Western Europe 38.9 of which: 13.7 17.8 +29.4 0.6 Norway 13.7 53.5 +41.2 1.8 12.0 37.9 U.K. 5.2 0.2 West Germany 5.5 5.4 - 3.9 1.9 1.8 1.8 - 1.6 Austria 1.6 1.5 - 9.1 Netherlands 1.5 1.1 1.1 1.4 +24.8 Italy 1.1 1.0 1.1 + 6.1 France 1.8 1.2 0.9 -30.6 Spain -23.9 Denmark 0.2 0.5 0.4 136.1 137.4 + 0.9 Far East 124.4 4.5 667.7 Communist bloc 630.6 701.6 + 5.1 22.9 World Total 2,937.2 3,048.8 3,055.7 + 0.2 100.0 can be seen again, despite the fact that their share of production (35 per cent) is much less than their reserves share (56 per cent). Furthermore, 90 per cent of Middle East production is by five countries - Saudi Arabia, Iran, Iraq, Kuwait and Abu Dhabi, with Saudi Arabia alone accounting for 13.4 per cent of total world production in 1978. By contrast, Western Europe is an insignificant producer, accounting for only a 2.7 per cent share in 1978 and that largely through Norwegian and U.K. production from the North Sea. Until a few years ago, Western Europe produced less than 1 per cent of the world total, in spite of accounting for 25 per cent of world consumption. Norwegian oil consumption in 1977 was 8.8 million tonnes; that of the U.K. 92.3 million; and that for the whole of Western Europe 696.6 million. Norway, at least, has been producing more than she has consumed since 1975. The main importing countries outside Western Europe are the United States and Japan; all other areas are virtually `self-sufficient'. Self-sufficiency requires some qualification, however, because

6

Norwegian Oil Policies

there are different types of crude oil, and swap arrangements are common. North Sea crude, for example, is not ideal for producing petrol (motor spirit), and therefore both Norway and the U.K. continue to import heavy crude oil from the Middle East for that purpose, and for industrial fuel and electricity generation. Obversely, the lighter (and more valuable) North Sea fractions are exported, e.g. for use as petrochemical feedstocks. This point is discussed in more detail in Chapter 4. The natural gas industry is significantly different from the oil industry, largely because of the greater problems in transporting gas, which means that it is much more common for gas to be consumed in the countries or areas where it is produced. There are a few exceptions, the two main ones being, first, exports from countries such as Algeria where reserves and production are sufficiently great to make liquefaction (an expensive process) a commercial proposition and, secondly, the growth of pipeline networks such as in Western Europe to transport gas over relatively short distances. Norway is in a unique position in the world energy market, as can be seen from Table 1.2 which shows world primary energy consumption in 1977.' Of Norway's 1977 consumption of 28.7 million tonnes oil equivalent,8 some 66 per cent was provided by hydro (water) power (mainly in the form of electricity), 31 per cent by oil and 3 per cent by coal and other solid fuels. Natural gas is not consumed in the country at present and there is no nuclear electricity. This contribution by water power is the second highest in the world, exceeded only by Iceland with a 73 per cent contribution, the next most important being 26 per cent in Sweden, 25 per cent in Canada and 20 per cent in Austria. In the world as a whole, water power accounts for only 6 per cent of primary energy consumption. This is a crucial factor because it means that Norway is not and was not dependent on the oil industry in the way that most other Western European countries are and were. In the U.K., for example, oil accounted for 44 per cent of primary energy consumption in 1977, and a major objective of British oil policies has been to increase North Sea production in order to reduce crude oil imports from the Middle East. The benefit of hydroelectric power and the relative unimportance of oil consumption have given Norway a freedom in her operations which has been a major influence on oil policies, as Chapter 2 shows.

7

Introduction Table 1.2 PRIMARY ENERGY CONSUMPTION, 1977 (million tonnes oil equivalent [mtoe] ) Water Natural Solid Power Nuclear Gas Fuels Oil 68.0 495.0 363.0 60.0 U.S.A. 867.3 6.3 20.0 51.2 45.9 Canada 85.4 39.6 75.9 44.0 0.4 Latin America 192.1 30.3 2.1 1.0 Middle East 79.2 58.5 12.7 57.0 Africa 6.9 64.5 10.2 1.1 South Asia 34.5 9.4 64.1 7.7 South East Asia 94.3 4.6 18.2 6.9 Japan 260.1 12.5 59.9 8.2 Australasia 37.9 7.4 29.9 8.0 402.7 44.4 U.S.S.R. 395.0 284.0 0.7 277.4 7.5 Eastern Europe 100.0 56.0 China 5.5 354.4 7.5 73.0 263.5 35.1 170.7 112.2 Western Europe 696.6 of which : 0.9 Norway 19.0 8.8 73.4 8.4 U.K. 92.3 36.9 1.2 West Germany 38.5 71.5 5.1 8.2 137.1 France 28.3 114.6 20.4 16.7 4.9 Italy 95.9 23.6 9.9 14.5 0.9 Denmark 16.6 3.9 28.2 4.4 13.6 Sweden 4.9 Finland 12.5 0.8 6.2 3.0 0.6 Iceland 0.6 1.6 World Total 2,972.4 1,167.8 2,035.9 384.8 126.5

Total 1,853.3 208.8 352.0 112.6 135.1 119.7 170.7 357.6 83.4 1,134.1 441.6 440.4 1,278.1 28.7 212.2 260.4 184.9 144.8 20.5 51.1 23.1 2.2 6,687.4

The 'Seven Sisters' and OPEC Another aspect of the international oil industry which it is necessary to mention in an introduction is the role of individual companies. In many respects the history of the oil industry in the 1970s is the story of the transfer of power from companies to governments, particularly in the Middle East. Chapter 6 takes the story a step further insofar as many governments are now creating their own state oil companies to replace the traditional private companies: in Norway this reincarnation is in the form of Statoil (Den norske stats oljeselskap). Outside North America, seven major companies were at the forefront of the oil industry. In the popular literature, these have become known as the `Seven Sisters': British Petroleum, Exxon (or Esso), Gulf, Mobil, Shell, Socal (or Chevron) and Texaco. Five of these are American companies, BP is British and Shell a

8

Norwegian Oil Policies

joint British-Dutch company. Today, it is probably correct to add an eighth company: the French C.F.P. By a system of concessions and other agreements with various rulers, the Seven Sisters built up a network of control throughout the Middle East. In each of the major producing countries, two or more of the seven were the main operating companies. Occasionally other companies appeared — such as C.F.P. — but never on a scale to threaten the dominance of the seven sisters. They developed an expertness in producing and marketing which no one else could acquire, partly because they also controlled the oil tanker industry. The Seven Sisters operated as a cartel, very much in the interests of consuming countries, particularly the United States. Although in recent years there has been a great debate about the ethics of their Middle East operations, it is undeniable that the Western World benefited considerably.9 One effect was that they were able to control the price of oil, which in real terms fell steadily throughout the 1950s and 1960s. For example the posted price of oil from the Mina al Ahmadi field in Kuwait was $1.80 in 1955, was reduced to $1.60 in 1960, and stayed at that level until 1970 despite (a low level of) inflation throughout the period. Government revenues per unit of production also fell. In 1957 the average company payment per barrel in the Arabian (Persian) Gulf was 85.7 cents. This was reduced steadily over the period to 1961 when the average was 75.8 cents per barrel; and this had increased to 85.8 cents by 1970 — only 3 cents higher than the 1957 level 10. The government's resentment over the decreases in money prices — never mind the real decreases — led in 1960 to the formation of the Organisation of the Petroleum Exporting Countries (OPEC), but this had little effect in the early years of the organisation's life. How times have changed! With hindsight it is not surprising that the Middle East producing countries reached the view that the operations of the international oil companies were not in their best interests. What they could do was really a matter of timing. There had been a few serious disagreements since the Second World War but they had been resolved without troubling the oil companies unduly. It was the 1970s that brought the major changes, however, and indirectly a great boost to North Sea activities. Throughout the 1960s the major oil companies came under increasing pressure. Their dominance was threatened by the aggressive actions of small independent companies trying to break into the market. Their return on capital was reduced by increased government `takes' on the one hand and the stickiness of final prices on the

Introduction

9

other hand. Their role as producers was being taken from them by some governments. The trickle of concessions given by the companies became a flood in the 1970s. Libya was the first country to secure an increase in posted prices in 1970 and this was quickly followed by other agreements which increased the combined revenue of OPEC members from $4,500 million in 1966 to $15 million in 1972. The Arab-Israeli war in 1973 led to a threat by OAPEC (the Organisation of Arab Petroleum Exporting Countries) to reduce output by 5 per cent each month `until Israeli withdrawal is completed from the whole Arab territories occupied in June 1967 and the legal rights of the Palestinian people are restored'.11 In addition, a unilateral decision to raise posted prices by 70 per cent was announced, and in January 1974 these new prices were doubled. The effect was to increase the average posted price from around $1.80 in 1970 to $12.00 in 1974 — a sevenfold increase in four years. Many people thought that OPEC could not get away with this action, that the cartel would collapse and that prices would soon fall to their 1970 levels. Five years later OPEC's strength shows few signs of diminishing, and there are few people who believe that prices will fall significantly. The demand for oil has proved very inelastic in the short run; alternative energy sources, particularly nuclear energy, have encountered major setbacks; and none of the non-OPEC producing countries, including Norway, has stepped out of line by reducing prices. As Chapter 7 shows, Norway has reaped a massive financial gain from the actions of OPEC, and her current interest is also to see the world price of crude oil, and associated fuels such as natural gas, maintained at its present level. It is true to say that since 1974 prices in real terms have drifted downwards, in the light of high rates of inflation and reduced demand as a consequence of the international economic recession; but in December 1978 OPEC announced further increases for 1979 which will probably bring the average posted price to around $19.50. The meek reception given to these proposed increases in the consuming countries is a testimony to the belief that OPEC is here to stay. Norway is not a member of OPEC; nor is the U.K. Nevertheless both have benefited substantially from OPEC's actions, and much of the rest of this book is concerned with the nature of these benefits. The Seven Sisters and their smaller colleagues continue to operate in the North Sea, and it is clear that one of the attractions to private companies has been the relative political

10

Norwegian Oil Policies

stability of Western Europe. It is in the light of their reduced opportunities in the Middle East that any discussions about the role of the international oil companies should be seen. North Sea history Moving specifically to the North Sea, a brief historical description is necessary. The best starting-point is the discovery in August 1959 of the massive Slochteren gas field in the northern province of Groningen in the Netherlands. This has proved to be the second largest natural gas field in the world. The gas was found in rock strata which were believed to extend to the north and west, i.e. off the Dutch coast and into the North Sea. It was even suggested that these rocks could extend right across the Southern North Sea to England, where in the 1930s there had been a few tiny onshore gas discoveries in Yorkshire and East Anglia. The geologists pointed out — as mentioned earlier in this chapter — that this whole area was part of a vast sedimentary basin and at one time had all been under water. Offshore exploration, however, had to await both a legal framework and a suitable technology. Norway, like most other littoral countries, laid claim to certain territorial waters, largely so that fishing and shipping activities could be satisfactorily regulated. These claims over territorial waters varied substantially, from 3 miles in Australia to 200 miles by certain South American countries. Fishing limits often followed the same boundaries but were sometimes for wider areas (as was the case with Iceland). With improved offshore technology (having used Lake Maracaibo and the Gulf of Mexico as testing grounds) and hence the growing prospect of industrial and commercial advantage, countries began to lay claim to the natural resources of the sea bed adjacent to their coasts. The Truman Proclamation of 1945 was the catalyst to a chain of legislative changes leading to the 1958 Geneva Continental Shelf Convention. Unilateral action was not really possible in the North Sea given that it is bounded by seven littoral states: Norway, the U.K., Denmark, West Germany, the Netherlands, Belgium and France. The Geneva Convention provided a basis for `dividing up' the North Sea. It extended the sovereign rights of the states to include the exploration and exploitation of the natural resources of the sea bed on the continental shelf to a depth of 200 metres or `to where the depth of the superjacent waters admits of the exploitation of nature resources'. It is interesting to note that one of the effects of improved offshore technology has been to extend the area (or the depth) which is

Introduction

11

exploitable, far exceeding the expectations of the Geneva Convention signatories. Anyone who has followed the protracted wranglings at the various Law of the Sea conferences will appreciate the significance of this issue. Within the North Sea each country's rights depend upon the country reaching mutual agreement with other littoral countries, and given mutual agreement the boundary line could be determined by any set of principles. However, failing such agreement Article 6 of the Convention established a principle of equidistance to guide countries which were partners to the treaty. Thus, `in the absence of agreement, and unless another boundary line is justified by special circumstances, the boundary shall be determined by application of the principle of equidistance from the nearest points of the base-lines from which the breadth of the territorial sea of each State is measured.'12 Between two coastal states, such as Norway and the U.K., the boundary line is the median line between them, and indeed the line demarcating the U.K. sector is the result of five separate agreements each of which is consistent with the principle of equidistance. There remain difficult questions of interpretation and some of open dispute between countries — for example, the fierce disagreement between Greece and Turkey over their respective rights in the Aegean Sea and the recurring battles between China and Vietnam over islands in the South China Sea. In the Atlantic and the Irish Seas there appears to be ample scope for dispute between the U.K. and Ireland, despite the U.K.'s attempted assumption of sovereignty over Rockall. In the North Sea itself a dispute between Denmark, the Netherlands and West Germany was settled in favour of the last-named when the Court of Justice in The Hague determined that the boundaries should be settled by agreement based on `equitable principle'. As for Norway, the major issue in relation to the boundary line with the U.K. was whether or not the Norwegian Trench, with a depth well in excess of 200 metres, constituted the limits of the Norwegian continental shelf. The U.K. civil servants and politicians responsible for the negotiations did not seem particularly concerned about this problem (presumably on the grounds that it was only of academic interest as no oil or gas would be found in the area) and the question was settled in Norway's favour in 1965 by way of an agreement which ignored the Trench in determining the median between the two countries. A cursory glance at the map on page viii will show the importance of the decision: all the existing Norwegian oil and gas discoveries are

12

Norwegian Oil Policies

on the U.K. side of the Trench! No doubt this is a recompense for Norway's handing over the Orkney and Shetland Islands to Scotland in the fifteenth century. Until 1469 Orkney and Shetland were part of the Kingdom of Denmark, Norway and Sweden, at that time ruled by King Christian I. In 1468 a marriage treaty was signed between James III of Scotland and Margaret, daughter of King Christian. As his daughter's dowry Christian was to give 60,000 florins, of which 10,000 were to be paid immediately and Orkney given in pledge for the rest. In the event, Shetland was also included in the dowry as Christian was unable to raise the money. Events 500 years later have added a great deal of irony to this transaction because most of the oil and gas discoveries in the U.K. sector have been in waters lying immediately to the east of Orkney and Shetland. Despite the various criticisms of the Geneva Convention it did provide a framework, and the Norwegian legislation mentioned earlier in this chapter evolved from it. The total area of the North Sea (south of the sixty-second parallel) is approximately 200 square miles: of which the Norwegian sector accounts for about 25 per cent, the U.K. sector 47 per cent, the Netherlands 11 per cent, Denmark 9 per cent, West Germany 7 per cent, Belgium and France 1.5 per cent each. It is coincidental that these shares correspond closely to the shares of known reserves in the North Sea, given that the U.K. and Norway account for all the major oil and gas finds. Licensing policy is covered in detail in later chapters, so it will not be duplicated here. Suffice it to say that the Norwegian Government, through the King, has issued licences to companies for both exploration and production, and there have been three main licence rounds — in 1965, 1969 and 1974. A fourth round will be concluded in 1979. A few special licences Table 1.3 LICENSED AREAS (AS AT 1 JANUARY 1978) Year of assignment 1965 1969 1971 1973 1975 1976 1977 Total

(in square kilometres) Total Relinquished Licensed area area area 42,106 34,707 7,399 5,879 1,666 4,213 524 131 393 587 — 587 2,329 — 2,329 2,067 — 2,067 1,076 — 1,076 54,568 36,504 18,064

No. of Blocks 32 13 1 2 8 7 5 68

Introduction

13

have been awarded in intervening years, as can be seen from Table 1.3 which gives the physical areas involved in each round. The licences normally require the relinquishing of parts of the blocks involved after a period sufficient for exploration, and this is shown as the third column of the table. Thus the fourth column is the existing licensed area (as at January 1978). An indication of how exploration activity has increased over time can be obtained from Table 1.4 which lists the numbers of wells drilled in each year since 1965. A distinction is made between exploration (wells drilled on a new structure), delineation (wells drilled to determine the extent of fields already discovered) and production wells (mainly drilled from production platforms rather than exploration rigs). Exploration activity has built up slowly but steadily over the period, although 1976 represents a noticeable fall. It is interesting to compare this pattern with that

Year 1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 Total

Table 1.4 WELLS EtRILLED Exploration Delineation Production — 1 — — 2 — 6 — — 2 — 10 1 — 12 3 — 14 5 — 12 3 — 13 5 1 20 18 14 6 24 21 5 7 21 3 34 11 9 42 84 157

Total 1 1 6 12 13 17 17 16 26 38 50 31 54 283

in the U.K. sector, where there was a rapid build-up to a peak of seventy-five exploration wells in 1975 followed by an almost equally sharp rate of fall to forty in 1978. The two main reasons given for this U.K. decline are, first, changes in government oil policies which have made the North Sea less financially attractive and, secondly, lower success rates. It has been suggested, for example, that all the major fields in the North Sea have now been discovered and that the companies had to move onto second- and third-rate prospects. As will be seen from Chapters 2 and 3, these conclusions apply with much less force to Norway because licensing policies have been `go slow' and therefore there are

14

Norwegian Oil Policies

(relatively) more promising structures still to be drilled. Undoubtedly the major influence on drilling activity is the success rate. In the early years no major discoveries were made and in the late 1960s interest began to wane. Some of the American companies in both the Norwegian and U.K. sectors moved their exploration rigs to the Gulf of Mexico and the Mediterranean. This was particularly noticeable in the U.K. sector because although there had been a few small gas fields discovered in the Southern North Sea — which are now producing — the companies' main interest was in oil, and if oil was not in the North Sea they would try elsewhere. The discovery by the Phillips company, in Norwegian waters, of the Ekofisk field in 1969 proved to be the turning-point. Two small gas/condensate discoveries (Cod and Murphy) had been made in 1968 and early in 1969 but both were of doubtful commercial viability. There was no doubt about Ekofisk. Table 1.5 tells the story since then. There has been a steady stream of discoveries throughout the 1970s of both oil and gas fields, although there are indications of a lower success rate in the last two or three years. Regarding oil fields, most of the discoveries have been small and of doubtful commercial viability. The two outstanding examples are Ekofisk itself (with estimated recoverable reserves of 140 million tonnes/1,000 million barrels) and Statfjord (300 million tonnes). Statfjord is so far the largest discovered oil field in the North Sea and Ekofisk the fifth largest; the intervening fields all being in the U.K. sector — Brent (260 million tonnes), Forties (225 million tonnes) and Ninian (180 million). Luckily quite a few of the smaller discoveries are clustered around the main Ekofisk field, and this proximity has made them worthwhile commercial developments. Thus the Ekofisk group or `area' comprises seven individual fields: the initial development programme entails production from Ekofisk itself, West Ekofisk, Tor and Cod; production began in 1971 originally by tanker loading at sea but latterly by pipeline to Teesside in North-East England (which came on stream in 1975). A pipeline to the Norwegian coast was impossible because of the deep Norwegian Trench. Detailed production figures are given in Chapter 2. The next phase of development for the Ekofisk area is the production from the other fields — Eldfisk, Albuskjell and Edda — the first two planned to begin in 1979 and Edda in 1980. In addition, Hod and Valhall will be linked to the Ekofisk pipelines, are a few other small fields in the area, such as Tor South-East and as can be seen from Table 1.5 and the map on page viii, there

Introduction

15

and Tor North-West, which if proved commercial presumably will also be included. The Ekofisk group is the only current source of oil production and the only other oilfield under development at present is Statfjord (production to begin late 1979). Valhall is regarded as part of the Ekofisk group. Prospects for other fields and future production are discussed in the next chapter. Regarding gas fields, the only unassociated field in production is Frigg, discovered in 1971, and gas from this joint Norwegian/ U.K. field is being piped to St. Fergus near Aberdeen in Scotland. Production from the U.K. part of the field began in 1977 and from the Norwegian part in late 1978. The reserves of Frigg in the Norwegian sector are estimated at 120 billion cubic metres. In fact this is smaller than the recoverable gas reserves of the Ekofisk group — estimated at about 250 billion cubic metres — and they are being produced separately by way of a pipeline to Emden in North Germany. Statfjord and Valhall also have substantial quantities of associated gas, and discussions are being held about their exploitation. Table 1.5 PETROLEUM DISCOVERIES, 1968-77 Year of Name of Block find field

1968 1969 1969 1970 1970 1970 1970 1970

Licensees Phillips Cod 7/11 Gulf/ Murphy 2/3 Wintershall Phillips Ekofisk 2/4 Esso 25/8-1 Balder 25/10,25/11 Esso Tor 2/5,2/4 Amoco Group Eldfisk 2/7 Phillips Ekofisk Phillips

West 1971 1971 Frigg 1972 Bream

2/4 2/7-10 25/1 17/12

1972 Tor South-

East 2/5 1972 Heimdal 25/4 1972 Edda

2/7

1972 Albuskjell 1/6,2/4

Nature Recoverable of find reserves* Condensate 2;5

Gas Oil/Gas Oil Oil Oil/Gas

— 139;129 — 26;19

Oil/Gas Oil/Gas

58;55 21;23

Phillips Oil/Gas Petronord Gas Phillips Oil Amoco Group Oil/Gas Pan Ocean Group Phillips Shell Group

Condensate Oil/Gas Oil/Gas

—;119

—

—

6;6 21;37

16

Norwegian Oil Policies

1973 Brisling 17 /12 1973 Frigg East 25/2 1973 Tor NorthWest 2/4 1973 Eldfisk East 2/7 30/10 1974 Odin 1974 Frigg NorthFast 25/1 1974 Frigg SouthEast 25/2 1974 Flyndre 1 /5 1974 Sleipner 15/6,15/9 1974 Statfjord 33/9,33/12 1974 Hod 2/11 15/3-1 1975 1975 25/2-4 1975 30/7-2

Phillips Petronord

Oil Gas

Phillips

Oil

Phillips

Oil

Esso Petronord

Gas Gas

Petronord

Gas

Phillips Esso/Statoil Statoil /Mobil Amoco/Noco Petronord Petronord Statoil/ Petronord Amoco/Noco Statoil / Mobil

Oil Gas Oil Oil Oil/Gas Oil

Oil 1975 Valhall 2/8 Oil 1975 MurchiOil son 33/9 1976 25/2-5 Petronord Oil 1976 Statoil / Mobil Oil 33 /9-6 1976 33/9-7 Statoil /Mobil Oil 1976 7/12-2 BP/Conoco Oil 1976 1/9-1 Statoil /Phillips Condensate 1977 Statoil / Mobil Oil 33 /9-8 1977 Gamma 1/9-4 Statoil /Phillips Condensate * oil in million tonnes; gas in billion cubic metres.

—

6;8

295;62 9;3 50;40 7;1

-

Finally, as may be clear from the map and Table 1.5, there has been a steady northward movement of development activities. The 1960s concentrated on the Southern North Sea, the early 1970s on the Middle North Sea, and the subsequent few years on the Northern North Sea, particularly along the Norwegian/U.K. median line where most of the major discoveries have been made. Although there are still large areas south of the 62nd parallel to be explored, evidence from the U.K. sector suggests that the best remaining prospects lie further north — i.e. north of 62°. The policy issues surrounding this northward march are discussed in Chapter 3.

Introduction

17

Norwegian economy Our final introductory section concerns the Norwegian economy. Oil policies cannot be seen in isolation from the general state of the national economy. For example, for many years one of the main determinants of government economic policies in the U.K. was the state of the balance of payments: the recurrent stop-go policies were largely a consequence of fears about the high level of imports which accompanied expansion and growth. Norwegian problems have been very different from those of the U.K., however, but that in itself suggests that an understanding of the peculiar features of the economy is necessary. Table 1.6 is a kind of economic league table, ranking countries by their gross domestic product per head of population. On this basis Norway is the seventh richest country in the world, with an average income nearly double that of the U.K. There are Table 1.6 INTERNATIONAL COMPARISONS OF GDP PER CAPITA. 1975' Real Growth Rates (%) 1970-5 Rank Country Amount (USS) 1960-75 -3.3 15,190 -2.9 1. Kuwait 0.7 2. 8,410 2.6 Switzerland 2.3 8,150 3.1 3. Sweden 1.6 2.5 7,120 4. United States 3.3 5. Canada 6,930 3.6 1.7 6. 6,810 3.5 Denmark 3.3 7. Norway 6,760 3.6 1.9 8. 6,670 3.5 West Germany 9. Belgium 6,270 3,9 4.4 3.4 10. France 5,950 4.2 11. 5,750 2.2 Netherlands 3.8 12. Australia 5,700 2.4 3.1 13. Libya 5,530 10.5 3.9 14. Finland 5,420 4.5 4.1 15. Austria 4,870 4.3 4.0 16. Japan 4,450 4.0 7.7 17. New Zealand 4,280 2.0 1.5 18. Saudi Arabia 4,010 4.1 6.6 19. 3,910 3.2 3.7 East Germany 20. 3,790 Israel 5.2 4.0 21. 3,780 2.0 United Kingdom 2.2 ° Only includes countries with populations over one million. Source: World Bank. many reservations about using GDP per capita as a measure in this way - not least because it takes no account of differences

Agriculture, forestry 5,114 and fishing Mining and quarrying, 628 incl. oil exploitation 17,441 Manufacturing Electricity, gas and 2,563 water Construction, incl. oil 6,339 drilling 7,794 Maritime transport Other transport, storage and communication 4,762 Wholesale and retail 10,758 trade Banking and insurance 3,562 Hotels and restaurants 1,031 3,349 Dwellings Commercial buildings 709 Community, social and personal services 13,161 Less: Imputed bank service charge 1,709 Other correction items 4,374 Gross domestic product in purchasers' values 79,876 Source: Norwegian national accounts. 7,494 1,489 27,728 4,387 10,258 11,400 7,598 17,416 6,696 1,594 5,225 1,061 23,099 3,635 7,918 129,728

6,340 1,042 24,279 3,451 8,418 10,178 6,691 15,520 5,438 1,417 4,587 885 20,324 2,758 6,042 111,854

5,691 954 21,561 3,006 7,875 8,448 6,100 13,400 4,675 1,320 4,103 785 17,660 2,316 5,141 98,403

5,770 670 19,201 2,720 7,264 8,134 5,289 12,073 4,123 1,156 3,707 782 15,497 2,015 4,736 89,107

Table 1.7 GROSS DOMESTIC PRODUCT BY INDUSTRY (Million kroner, current prices) 1973 1974 1971 1972 1970

11,700

12,722 9,065 10,280

11,527 9,253

148,701

4,061 8,855

27,874

19,573 7,771 1,928 5,930 1,248

8,696

14,615 8,198

5,660

5,037

169,419

189,474

5,628 12,678

38,012

33,245 4,959 10,911

25,902 10,448 2,785 7,410 1,504

22,687 8,951 2,170 6,657 1,402

6,011

8,105 36,968 7,035 33,923

4,533 32,301

10,766

1977

9,670

1976

8,236

1975

I-

CO

saral?od 110 uvganuoN

Introduction

19

in national prices and thus the `cost of living' — but for present purposes it is useful in that it makes the simple point that Norway is a prosperous country. Furthermore, the rate of growth over the last fifteen years or so has been both fast and steady, as the two right-hand columns of the table show. It is important to remember that North Sea oil has contributed very little to national output over this period, except in 1975. Obviously, this has not been the case in countries like Kuwait, Libya and Saudi Arabia in the table, where over 95 per cent of national income comes from oil and gas activities. In fact Table 1.6 excludes countries with populations of less than 1 million — otherwise Abu Dhabi would have been top of the table and a few other Middle East sheikhdoms in the top twenty. The contribution of oil activities to national output in Norway can be better seen from Table 1.7, which provides an industrial breakdown for the period 1970-7 in millions of kroner (current prices). If we begin with 1970, it will be seen that the manufacturing sector contributes just under 20 per cent; the main manufacturing industries being food processing (particularly fish), wood processing, chemicals, aluminium and engineering. Most of these are very energy-intensive industries, particularly chemicals and aluminium, and the availability of cheap hydroelectric power has been an important reason for their development in Norway. The other major exporting industry is maritime transport — i.e. shipping — and the remainder of the industries in Table 1.7 are mainly in the service sector. Most sectors have grown steadily over the period: on average, output has more than doubled over the eight years, the outstanding exception being mining and quarrying (including oil exploration), which have increased from 628 million kroner in 1970 to over 8,000 in 1977 — almost entirely through the North Sea oil and gas activities. Nevertheless, in 1977 this sector still accounted for less than 5 per cent of national output. Another common measure of the health of any economy is the level of unemployment, and Table 1.8 shows a similar picture. One of the main objectives of the Norwegian Government's economic policy has been the maintenance of a high level of employment, and there is little doubt this objective has been achieved. Throughout the 1970s unemployment has never exceeded 1.5 per cent according to Norwegian definitions. Even on the basis of adjusted unemployment rates, using OECD (Organisation for Economic Co-operation and Development) definitions, the highest level recorded in Norway has been 2.5 per cent

20

Norwegian Oil Policies

Table 1.8 INTERNATIONAL UNEMPLOYMENT PERCENTAGES Average 1962-73 1974 1975 1976 1977 1978(Q1) 1.9 Norway 1.5 2.3 1.5 2.0 1.8 Sweden 2.0 1.6 1.6 1.8 2.1 2.1 6.6 U.K. 4.4 6.9 3.1 2.9 6.4 3.6 West Germany 3.6 0.6 1.5 3.6 3.6 France 5.2 5.1 2.2 2.7 4.6 4.1 6.1 U.S.A. 4.6 83 7.5 6.9 5.4 OECD (12) Source: OECD.

2.8

3.3

5.1

5.4

5.4

5.3

in 1975. Throughout the period Norway has had the lowest unemployment level in the OECD area (which includes Western Europe and North America) with the exception of 1975 and 1976 when the average annual rate was lower in Sweden. The marked difference in performance between Norway and most other OECD countries can be seen from Table 1.8, which gives the annual adjusted unemployment rates from 1974 to the first quarter of 1978, with the average for the period 1962-73.18 These unemployment figures suggest that somehow Norway has avoided completely the international economic recession which began in the aftermath of the 1973 and 1974 OPEC price rises and which, for example, has brought record unemployment rates in the U.K. This is not true, although Norway has probably fared better than any other country in Western Europe, and the Government had to take an extensive series of counter-inflationary measures, including a wide range of labour support assistance.14 Oil has been important here because the prospect of future oil revenues allowed the government to borrow heavily to maintain demand, as is discussed in more detail in Chapter 7. In the context of the very low level of unemployment, it is worth noting that the rate of increase in employment has been the highest in Europe. Over the period 1970-6 the registered labour force increased from 1,557,000 to 1,821,000, i.e. by 17 per cent compared with the OECD Europe average of 3 per cent. Much of this increase came in 1975 and 1976, with the annual percentage increases in those years being 3.7 per cent and 4.2 per cent respectively, the OECD Europe figures being 0.2 per cent and 0.5 per cent. In index form, taking 1963 equal to 100, the Norwegian labour force increased to 122.8 in 1976; the OECD Europe average increase being 105.5, the EEC average 115.3,

21

Introduction

Denmark 115.8, Sweden 111.7, West Germany 97.1 and the U.K. 103.7. This rate of increase was the highest in Western Europe. Furthermore industrial employment, according to the OECD definitions, increased from 511,000 in 1963 to 558,000 in 1970 and 593,000 in 1976. Again with 1963 equal to 100, the Norwegian index of industrial employment stood at 116.1 in 1976 compared with the OECD Europe average of 98.5 and the EEC average of 93.8. The only European countries to experience faster rates of growth in industrial employment over the period 1963-76 were Greece, Iceland and Spain. Another objective of recent economic policy has been the regulation of the rate of increase in prices. Table 1.9 shows percentage Table 1.9 CONSUMER PRICES : PERCENTAGE CHANGES 1973

U.S.A. 6.2 West Germany 6.9 U.K. 8.3 Sweden 6.7 Denmark 9.3 OECD Europe (ay.) 8.6 Norway 7.4 Source: National Budget, 1978.

1974

1975

11.0 7.0 16.0 9.9 15.3 13.3 9.7

9.1 6.0 24.2 9.8 9.6 13.1 11.7

1976

5.8 4.5 16.5 10.3 9.0 10.8 9.1

changes in consumer prices for various European countries over the period 1973-6: these are commonly referred to as the rate of inflation. It will be seen that the Norwegian rate of price increase has been slightly but consistently lower than OECD Europe as a whole. There is little need to point out the huge differences between Norwegian and U.K. experience. In comparison with Norway's main export markets, her performance has been much worse than that of West Germany, similar to that of Denmark and Sweden, and much better than that of the U.K. More recent figures on the same basis are not yet available, but the consumer price index produced by the OECD itself shows no marked changes in Norway's relative performance. For example, the April 1978 indices (1970 equals 100) were 217 for OECD Europe, 190 for Norway and 266 for the U.K. The percentage changes over the twelve months to April 1978 were OECD Europe 10.1 per cent, Norway 8.2 per cent and the U.K. 7.9 per cent. The position regarding wages is, however, very different. For the period 1962-73 the average annual rate of increase in hourly earnings in Norway was lower (at 5.5 per cent) than the OECD

22

Norwegian Oil Policies

average (8.1 per cent), but since 1973 the Norwegian rate has been consistently higher: e.g. 19.8 per cent in 1975 compared with 13.5 per cent, and 16.6 per cent in 1976 compared with 11.3 per cent. In relation to those of her major trading partners, the Norwegian increases were significantly greater with the exception of the U.K. in 1975. Overall, in comparison with OECD Europe hourly earnings in Norway rose by 3.5 per cent more in 1974, 6 per cent in 1975 and 5 per cent in 1976. This is despite there being a very explicit incomes policy in Norway — or, as some economists might argue, because of the incomes policy.16 The timing of this sharp rise in rates is important in the light of the history of the North Sea development, and the significance of this is discussed in Chapter 5. Briefly, one implication is that the period 1974-8 wageearners in Norway enjoyed average gains in purchasing power of about 4.5 per cent per year, while real national income grew only at the rate of 1.5 per cent. In most other Western European countries, real disposable incomes were static or even fell, as has been the case in the U.K. Undoubtedly, the labour unions and their members have been very happy with these trends. On the other hand, there is a large body of opinion which argues that the very high rate of increases in wages and prices have significantly worsened Norway's competitive position and, because of the openness of the economy, contributed dramatically to current economic problems. For example the official Norges Bank view is that `the greatest problem in the Norwegian economy and for economic policy at present is the price and cost development. It is decisive for the competitiveness of Norwegian trade and industry, for the current account of the balance of payments, and for employment in a very large segment of the economy.'16 Although wage costs increased in the early 1970s at rates in excess of those of trading partners, it appears that large increases in productivity kept the rise in unit labour costs slightly below the weighted average for major competitive countries. This position changed markedly after 1973, however, and taking account of the effective appreciation of the krone, relative unit labour costs increased by about 35 per cent over the three years 1974-6. Despite the complications of exchange rate fluctuations and differences in domestic inflation rates, some useful indications can be obtained from a recent OECD report.17 This uses three measures of competitive position: relative total unit costs in manufacturing industry; relative average value of manufacturing exports; relative consumer price index. The results show a

Introduction

23

marked deterioration in Norway's competitive position since the end of 1970 and in particular since the end of 1974. All three measures used have moved in the same direction in recent years, although during the earlier period the relative average value of Norwegian manufactured exports fell steadily. Much the best measure, however, is that covering total unit manufacturing costs, and in that context the Norwegian experience has been worse than all other OECD countries excepting Japan. Total unit costs were calculated as geometrically weighted averages of unit labour costs and material costs in the proportions 70 per cent and 30 per cent respectively for Norway. The importance of taking account of exchange rate fluctuations is clear from the annexes in the OECD report, because in terms of local currencies the rise in Norwegian current costs since 1970 was less than in Italy and the U.K.; although in terms of the U.S. dollar the Norwegian rate of increase was higher. During the 1970s the krone has been part of the European snake, and no realignments were made until April 1977 when the rate for the krone was reduced by 3 per cent against the Deutschmark, Dutch guilder and Belgian franc. In August 1977 the Swedish krone was devalued by 10 per cent and withdrawn from the snake. As a result both Norway and Denmark decided to devalue by another 5 per cent against the remaining snake currencies. In relation to all currencies this involved a reduction of about 2.5 per cent in the effective exchange rate. In February 1978 a further downward adjustment of 8 per cent was made in the intervention rate of the krone vis-å-vis the other snake currencies, and it is estimated that the effect of this in relation to other currencies was an average decline of between 5 per cent and 6 per cent. Nevertheless, the total effective appreciation of the krone since 1970 has been about 9 per cent on average and much higher in relation to the pound sterling and the dollar (the U.K. and U.S. accounting for about 20 per cent and 10 per cent respectively of Norway's foreign trade). The issue of declining international competitiveness has been of great concern in Norway. A manifestation of the problem has been the deteriorating external balance. Since the mid-1960s Norway has traditionally had very small deficits on the current account of the balance of payments. In 1970 the deficit was 1.7 billion kroner, in 1971 3.7 billion, in 1972 0.4 billion and in 1973 2.0 billion. Since then the deficit has increased rapidly: in 1974 it was 6.8 billion, in 1975 13.2 billion, in 1976 20.0 billion and in 1977 26.5 billion. In 1974 and 1975 almost all the deficit was

24

Norwegian Oil Policies

attributable to imports for the North Sea developments, but of the 1977 deficit the oil sector (including Statoil) accounted for only 40 per cent, the shipping industry for 30 per cent, central and local government for about 20 per cent and the rest of the economy the remaining 10 per cent. By 1979 the oil sector is not expected to have a net borrowing requirement, so the greater part of any deficit will then be attributable to other activities. At the end of 1977 the total net foreign debt was about 80 billion kroner, and it is likely to have risen to 100 billion by the end of 1978. It could well rise to 150 billion before it could be amortised with the help of oil revenues; and by that time (say 1981) the Central Government's share will be around 60 billion kroner. Related to gross domestic product, the Norwegian deficit in 1977 — at 14 per cent — was the highest ever recorded by an OECD country. This deficit has been almost entirely financed by foreign borrowing, largely long-term, and the ease with which this has been possible is attributable to widespread confidence in future oil revenues. To a lesser extent, the U.K. is in a similar position. A significant part of the deficit is in fact attributable to the oil sector itself and some of the unforeseen increases in 1976 and 1977 are due to a slower rate of domestic oil production in the light of the Ekofisk blowout and other delays. If we look beyond the oil sector, however, it is clear that the two main causes of the huge increase have nothing to do with North Sea oil. First, the export industries, particularly shipping and shipbuilding, have done very badly: export markets have dwindled, as they have for most trading countries, but — more important — Norway's share of these export markets has gone down substantially, and this is mainly attributed to the loss of competitiveness described in the previous section. Secondly, imports have continued to rise steadily: e.g. from 63.5 million kroner in 1974 to 96.6 million in 1977 (with the shipping and oil sectors accounting for only 20 per cent of the latter figure). The Norges Bank has little doubt about the source of the problem: 18 `More rapid price and cost rise in Norway than abroad has led to the loss of market shares for Norwegian production and thereby to smaller exports and larger imports than otherwise would have been the case. In other words, the counter-cyclical policy has been run in such a way that it has led to a greater increase in the current account deficit than would have been the case if full employment had been combined with a more moderate cost rise.' In the present context, two other points concerning the

Introduction

25

foreign deficit merit consideration. The first is that there has been a very sharp fall in the output and profitability of the exposed sector, i.e. those industries exposed to foreign competition. In 1977, for example, gross domestic product rose by 4.1 per cent in real terms. In the sheltered sector (non-exposed industries) gross production rose by 5 per cent, but in the exposed sector (excluding shipping and oil) it fell by 0.5 per cent in foreign markets and by 2.5 per cent for those competing on the domestic market. This difference is expected to widen, according to the revised 1978 budget, with output in the sheltered sector forecast to increase by 2.5 per cent but output for exposed foreign markets to be static and to fall in domestic markets by 4 per cent. The second point is that an examination of the financing of the North Sea developments suggests a sharp fall in the domestic savings ratio. The contribution of domestic savings to total net real investment (gross capital formation less depreciation) declined from 97 per cent in 1972 to 34 per cent in 1977 and the gross savings ratio (i.e. the proportion of disposable national income not used for consumption) fell from 18 per cent in 1974 to under 9 per cent in 1977. Saving has obviously declined in the exposed sector, but there has been a much greater fall in public saving, with a shift in resources towards greater consumption. This in turn leads on to the changes in public expenditure. There has been a sharp rise in public consumption expenditure, with an increase from 12.3 billion kroner in 1970 to 35.5 billion in 1977 (current prices). As a proportion of GDP, public consumption, after being steady for a number of years at around 16 per cent, has gone up sharply in the period 1975-7. By comparison, private consumption fell steadily during the period 1970-4 but has also increased sharply in the last three years. The public sector borrowing requirement rose from 3.5 billion kroner in 1974 to 10 billion in 1976 and over 14 billion in 1977. Much of this increase in public spending is a consequence of the combined incomes settlements, including the subsidies to exposed industries. The selective or discriminatory nature of the fiscal stimulus has had a greater-than-expected effect on aggregate demand, with the result that fiscal policy has been substantially weakened. This in part may explain why inflation rates have been consistently higher than official expectations. Similarly, there has been a sharp acceleration in the rate of growth of the money supply with M2 now increasing at about 20 per cent per year compared with 8-10 per cent in the early 1970s. Central Government budgetary requirements have been a major factor

26

Norwegian Oil Policies

here. Although credit policy has been tightened in the twelve months prior to the time of writing, it is difficult to avoid the conclusion that the co-ordination of fiscal and monetary policies has become much more difficult and that on present evidence it is impossible to predict accurately the effects of most monetary policy changes. Detailed discussion of these issues is outwith the scope of this book, although some are returned to later when they impinge directly on oil policies. The purpose of this section has been to provide the economic context within which the North Sea developments have occurred and policies have evolved. NOTES 1. Those interested in the geological issues are directed to the books by Donovan and Hepple listed in the bibliography (where full publication details of all references are given). 2. P. Hinde, Fortune in the North Sea, p.25. 3. Source: BP Statistical review of the world oil industry, 1977. 4. A barrel is the common measurement used in the oil industry. There are between 7 and 8 barrels to the tonne, depending on the gravity of the oil. A metric tonne is equivalent to 0.984 long tons or 1.102 short tons, so the figures given are little different from their U.K. ton equivalents. A barrel of oil contains about 140 litres or 35 gallons. 5. A trillion is one million million and a billion one thousand million. 71.4 trillion cubic metres equals 2519.9 trillion cubic feet. One million tonnes of oil equal approximately 1.167 billion cubic metres of gas. 6. Source: Petroleum Economist, vol. XLVI, no. 1, January 1979. 7. Source: BP Statistical Review, op. cit. 8. All the energy sources have been converted to an 'oil equivalent' basis. One tonne of oil equals approximately 1.5 tonnes of coal or 3.3 tonnes of peat, for example. 9. See, for example, W. A. Adelman, The World petroleum market, and the more recent, journalistic account by A. Sampson. 10. Adelman, op. cit., p.208. 11. See D. I. Mackay and G. A. Mackay, The political economy of North Sea Oil, p.10. 12. Mackay and Mackay, op. cit., pp.20-1. 13. The group known at the OECD Twelve comprises the United States, Japan, West Germany, France, the U.K., Italy, Canada, Australia, Finland, Norway, Spain and Sweden. 14. For more detail see the National Budgets for the various years. 15. See J. T. Addison and G. A. Mackay, Norwegian incomes policies: the recent experience. 16. Norges Bank, Economic Bulletin, 1978, no. 1, p.9.

Introduction 17. OECD, Economic Outlook: Occasional Studies, July 1978. 18. Economic Bulletin, 1978, no. 1, pp.8-9.

27

2 THE LEVEL OF PRODUCTION Produce! Produce! Were it but the pitifullest infinitesmal fraction of a product, produce it in God's name. 'Tis the utmost thou has in thee: out with it, then. (Thomas Carlyle, Sartor Resartus) One of the crucial aspects of policy is the production level which the government permits. Directly or indirectly, this affects a whole range of economic activity — employment, government revenue, company profits, inter alia. In many countries and in most industries, the level of production is largely determined by the aggregate wishes of the companies involved but in the case of both North Sea oil and gas the Norwegian Government believes it is to be so important that it has instituted very strict controls. Taken together these can be described as a depletion policy or conservation policy. As we shall see in respect of other North Sea activities, a clear distinction should be made between policy objectives and policy implementation. In other words, although the Government may possess very wide powers, it may not necessarily use them. In particular, depletion policy falls into this category. For example, although it appears that the Government — through the King — has had strong powers to control the level of production since 1963, it is only since 1970 that there has been any serious discussion of these powers in the context of their constituting a depletion policy. Thus the Royal Decree of 31 May 1963 stated that the sea bed and its subsoil were subject to Norwegian sovereignty, and Section 3 of the Act which resulted in June 1963 stated: `The King may issue regulations concerning the exploration for and exploitation of submarine natural resources.' The main means of issuing such regulations is through the licences given to or agreed with the companies. The 1963 and 9 April 1965 Royal Decrees set out the main guidelines for activities on the Continental Shelf; these were superseded by the Royal 28

The Level of Production

29

Decree of 8 December 1972 which identified three types of licence: 1. a reconnaissance licence; 2. a production licence; 3. licences for pipelines, storage installations, shipment installations, etc. A petroleum reconnaissance licence is granted for a period of three years, giving the right to carry out general geological and geophysical surveys, but no drilling. The licence does not give exclusive rights. In contrast a production licence grants exclusive rights of exploration drilling and exploitation of petroleum deposits in the area covered by the licence. South of 62°N. the Continental Shelf is divided into blocks each with an area of about 500 square km. (which is larger than the blocks in the U.K. sector). A production licence may cover more than one block. According to the Royal Decree of 8 December 1972 a licence should apply for a period of thirty-six years. The licensee, however, must relinquish 50 per cent of the original area within six years. To obtain a licence the applicant has to agree to undertake a definite programme of work for the licensed area during the first six years, with the programme being determined after discussions with the Ministry of Petroleum and Energy (previously the Ministry of Industry). The main aspect of such programmes is the drilling of a certain number of exploration wells to agreed depths. Licences for pipelines, storage installations, etc., are granted on the terms drawn up by the Ministry in each particular case. Although this type of licence may seem less important than the production licence in relation to depletion policy, it will be seen later that it can be used to enforce production controls. The conditions attached to licences, particularly production licences, can be strengthened by the subsequent addition of other regulations. Thus, for example, the drilling of an exploration well cannot begin until a drilling permit has been applied for and been received from the Norwegian Oil Directorate. Before a drilling permit is granted, the applicant submits to the Directorate a drilling programme including such information as the drilling platform (or rig) to be used, the expected depth of the well, the installation of casing, and the use of drilling mud. On many occasions the Oil Directorate has insisted on changes in proposed drilling programmes, usually on geological grounds. We do not

30

Norwegian Oil Policies

know of a single occasion on which approval has been refused or delayed because of reasons relating to depletion or conservation policy, but the point is that the power to do this exists. If all else fails, there is no reason why the Directorate could not refuse a drilling permit, for example which would have the effect of stopping exploration and/or production. Policy, however, has taken other directions. The first detailed discussion on the issue came in 1974 in the Report no. 25 to the Storting by the Ministry of Finance.' This was followed a short time later by Report no. 30 by the Ministry of Industry.' These reports are part of the regular series which has been put to the Storting (the parliament), normally on an annual basis, to enable it to discuss the main issues of oil policy. In the preamble to Report no. 253 it is stated as follows: `The aim of this report is to provide the basis for important decisions which will have to be taken in the near future.... The report attempts to illustrate the main issues raised by the Norwegian petroleum activities, and their impact on Norwegian society, the opportunities they present and the problems they may create.... By means of this report the Government aims at providing the basis for an extensive discussion of the petroleum policy by a wide cross-section of the Norwegian population.' It is worth digressing briefly on this series of reports, which have greatly assisted the writing of this book. There is little doubt that most of them have served the purpose set out above and have contributed to detailed and extensive discussions of the range of policy options, including depletion policy. They stand out in marked contrast to similar reports in the U.K., which are more notable for their virtual non-existence. In the U.K. the written documents of the Government usually consist of an annual report by the Department of Energy (the `Brown Book'), which is essentially a factual account describing what has happened in the North Sea in the last year, and, more recently, the annual report of the British National Oil Company (BNOC — the state oil company). Policies are rarely discussed in these reports and, if so, only retrospectively. The discussion of future policies in parliament, for example, occurs largely in a vacuum of published material, which has clearly hindered the consideration of alternatives. In Norway, in contrast, in addition to these occasional parliamentary reports, both the Oil Directorate and Statoil (the Norwegian state oil company) produce very detailed annual reports — much more extensive than their U.K. equivalents — and the

The Level of Production

31

Central Bureau of Statistics produces an annual statistical account of activities on the Continental Shelf. This volume of literature may lead to delays in policy-making — for example the development of the area north of 62°N. which is discussed in Chapter 3 — but it has certainly contributed to more democratic discussion and decisions, both inside and outside the Storting. Furthermore, it is probably fair to say that one result has been the avoidance of mistakes which have been made in the U.K. because of hasty decisions in the absence of the necessary information. The best examples are the number of production platform sites and the arguments about a gas-gathering pipeline. Report no. 25 stands as something of a landmark in Norwegian policies. It sets out for the first time the implications of the OPEC changes: `Democratically elected institutions must have full control of all important aspects of petroleum policy: exploration, rate of extraction, safety measures and localisation. It is important to have public direction and control of the exploitation of resources ... first and foremost the scope of the operations on the Continental Shelf must be controlled by regulating exploration activities. Once a discovery is made, technical, economic and political reasons will tend to require that the resources be exploited as rapidly as possible. The harsh climatic conditions on the Shelf mean that the individual fields must be exploited at a relatively rapid pace, before the installed equipment has to be renewed. This reduces the possibilities of regulating the rate of extraction once production has commenced. In order to regulate the level of production, it is necessary, however, also to develop regulatory measures, so that the extraction operation itself is brought under control after a find has been made. One appropriate method of control might be to delay the development (build-up) of individual finds. This will be facilitated by increased government participation in the activities on the Shelf. But consideration should also be given to drawing up forms of contract which make it possible to delay the exploitation of discoveries made by private enterprises.'' There is no serious discussion of the need for a depletion policy, although it is clearly implied throughout the report that in the absence of government intervention the rate of production and depletion will be higher than desirable. The target figure suggested is 90 million tonnes of oil and gas per year in the 1980s. The implications of this figure are discussed in more detail below, but first it would be useful to consider the economic theory underlying alternative policies.5

32

Norwegian Oil Policies

The theory of resource depletion There is no need here to provide a detailed account of current economic theories, and a simple summary will suffice.° Let us start with the assumption of a commercial oil or gas discovery. The size of recoverable reserves, geological and geophysical factors will put a maximum (and possibly a minimum) limit on production. Thus there is a range of possible production levels from which the operator can make these decisions. The choice is essentially one of producing or leaving the oil in the ground for production at a later date. If the oil is produced it represents revenue to the operator, which could be invested to yield income in the future. If the oil is left in the ground, this is also an investment in that it will yield income in the future. If the price increases over time, so will the revenue to the operator, bearing in mind that taxes and production costs may also increase. Whether or not an operator decides to produce depends therefore on whether he believes that the price of oil (net of taxes and production costs) will increase at a faster rate than his rate of discount (the opportunity cost of not producing, which can be taken as roughly equal to the rate of interest). If we denote the rate of price increase as p and the discount rate as i, the operator will be in equilibrium when his level of production in any time period is such that p=i. If p does not = i, then the operator will choose to move output from one time period to another. If p exceeds i, he should reduce output and delay production; if p is less than i, then he should increase output. For example, let us assume that the expected rate of price increase of oil and gas is 10 per cent per year, that the rate of interest earned on investment (which can be taken as equivalent to the operator's rate of discount) is 5 per cent, and that the current price of a barrel of oil is 75 kroner ($15). If the operator produces that barrel and invests the 75 kroner, in five years' time the asset will be worth 96 kroner. On the other hand, if he delays production for five years, the barrel of oil would then be worth 121 kroner. Thus if he is acting rationally he will delay production. If the expected rate of price increase were 5 per cent and the interest rate 10 per cent, it would be more sensible to produce now and invest the revenue. This is a simple example but it clearly demonstrates the main issue. It is necessary, however, to introduce some more realistic qualifications. First, there is uncertainty. No operator or producer can forecast accurately future rates of interest and the price changes. Given that in the latter case there is the further complication of possible changes in production costs and taxes (in-

The Level of Production

33

eluding nationalisation or appropriation), it is to be expected that operators will use relatively high discount rates and thus have an inherent preference for early depletion. This is particularly true when we are considering international oil companies operating in foreign countries. Secondly, there is the possibility of divergence between the operators' or producers' interests (the oil companies) and `society as a whole'. It is often argued that a private individual or company will have a higher rate of discount than that of a country as a whole, mainly because the former reflects risks to individuals which cancel out for society as a whole. Given that market interest rates are related to the demands of individuals or companies, it could be argued that these are too high. The implication is that i will be increased relative to p and that therefore oil and gas reserves would be exploited at a faster rate by private companies than the state (society) would wish. Thirdly, in the case of Norway and most OPEC countries there is the question of absorptive capacity. This is discussed in Chapter 7 in relation to the use of oil revenues but it has also important implications for the level of production. The reserves are so great in relation to the country's economic and financial structures that it would be impossible to invest domestically the receipts from high levels of production. There is then the added alternative of investing overseas which needs to be considered. In the context of Kuwait, Khouja and Sadler have made the same point: ' `In theoretical terms an optimising policy for a country like Kuwait would be such that the extraction rate of oil and the disposition of the proceeds of its sales would ensure that the rate of increase in the value of its oil reserves is equal to the marginal return on productive capital at home, and that both are equal to the return on capital invested on the world's monetary markets... . Its choice of action would be based upon its view of how its future income flow from all sources (future oil sales, home production, foreign investment, etc.) will be affected. If oil values are expected to rise more than the rate of return expected from investments, then it is better to leave oil where it is. If anticipated returns from investments are greater than the expected increase in oil values, then it would be beneficial to increase oil output and devote the results to increased investment. Once Kuwait has the option of extracting or not extracting oil it is choosing the form in which it will hold its capital in exactly the same way as any businessman or industrialist would look at a portfolio of investments and decide upon its structure.'

34

Norwegian Oil Policies

Khouja and Sadler describe Kuwait as a capital-surplus economy which has the freedom to plan for a longer-than-normal time horizon, and it is possible to argue that Norway shows similarities with some of the OPEC countries. `This freedom permits countries such as Kuwait to take a much Ionger view of their planning and to evaluate the benefits and drawbacks of alternative end states and their required strategies in a manner different from that which would be required under conditions of capital shortage.'8 The final qualification is that it is necessary to recognise the existence of political pressures on countries like Norway to produce at higher rates because of the great need of other countries for oil and gas imports. These pressures occur in Western Europe and the Norwegian response is discussed later in this chapter. Two points stand out from the above discussion. First, an equilibrium position exists in theory for any producer (private oil company, state oil company or society) when the expected rate of price increase equals the rate of investment (the discount rate). In some cases it may be necessary to refine this analysis to divide the investment rate into domestic and foreign components; under some circumstances Norway could fall into this category. Secondly, it is possible that the optimum level of production for a private company will be different from that of a government. Most people would accept that private companies would choose to produce at higher levels than the government would wish them to do — hence the case for government intervention in the form of production controls and depletion policy. A few economists have disagreed with this conclusion. For example, Robinson and Morgan, who represent the right wing of British academic economists interested in the North Sea, are strongly opposed to state intervention. They argue: 9 `It is an open question whether, at any given time, government can even identify in which direction company programmes should be varied, let alone whether it can determine such an elusive question as the optimal depletion rate for society, the criteria for establishing which are by no means obvious ... One must consider the possibility that government intervention will move the depletion rate further from its optimum than it would have been under producer control.' They criticise U.K. policies on the grounds that depletion controls have introduced greater uncertainty into North Sea operations, but it is probably fair to say that their objections are based more on political views than economic reasoning.

The Level of Production

35

Norwegian policy Mention was made earlier that the Norwegian Government set a peak production rate for the 1980s of 90 million tonnes of oil and gas (the latter being measured in oil equivalents). How has this target figure been reached? How can it be enforced? Unfortunately it is difficult to provide answers to these questions because, despite the lengthy discussions in the various parliamentary reports, there is very little written material on the reasons for the choice of particular policies. The reports set out in welcome detail the advantages and disadvantages of alternative policies but — mainly because they are intended as advisory documents for the Storting — are often inconclusive. The Storting and the Government have then taken decisions on certain policies on political rather than economic grounds — i.e. on grounds not discussed in the various reports — which makes the analysis of the evolution of policy difficult. The establishment of the state oil company, Statoil, is probably the best example (see Chapter 6), but it is similarly difficult to set out the rationale of Norwegian depletion policy. This is not to say that the policy is irrational or erroneous, but just that the arguments presented in the parliamentary reports are misleading in so far as they do not necessarily represent the evidence on which the policy-makers made their decisions. Take oil prices as an example. In one of the few explicit statements about depletion policy, Per Kleppe, the Finance Minister in 1975, said: 10 `As long as some of Norway's petroleum reserves remained below the North Sea, our assets are probably fairly well placed. A gradual rise in the relative price of petroleum would represent interest earned on these untouched assets. Reasoning along these lines, this kind of investment compares favourably with financial investment abroad.' This is fully in agreement with the simple depletion model described above, and the expectation of rising prices leads logically on to a slower rate of depletion. In contrast, the general impression given from the parliamentary reports is that the official view is of a declining real price of oil. Report no. 25 (1973-4) gives the view that the growth in oil consumption in the 1960s led to a more rapid rate of depletion of reserves than the OPEC countries wanted and that they consequently raised the prices in 1973 and 1974 to reduce consumption. That was not really true. The report goes on to suggest that Norwegian oil would be sold at $2-$4 less than the OPEC prices and that the real price could fall because of the availability of

36

Norwegian Oil Policies

substitutes and reduced consumption. This conforms closely to the view of most OECD countries in 1974, and has proved to be mistaken. That is not a criticism because no one at that time could have foreseen the effects of the OPEC actions. However, this view of a declining real price of oil and gas has been expressed regularly since 1974 in other parliamentary reports and ministerial statements — but this has had no discernible effect on depletion policy. `Assumptions that the international price level for petroleum might be higher in the first decade than in subsequent decades might also be used as an argument in favour of its rapid extraction. In view of its desire for a long-term exploitation of resources and on the basis of an overall evaluation in a social context, the Government has nevertheless decided Norway should adhere to a moderate pace of extraction of the petroleum resources.'11 Many countries exercise direct controls over production levels by setting production limits for individual years, by closing down fields for periods, or by delaying the start-up date of new fields. In contrast, the Norwegian approach has been to try to exercise indirect control through the limiting of exploration activity. Is other words if the level of production is a function of a number and size of commercial fields and development, the Government can control production levels by ensuring that exploration activity generates a certain number of commercial discoveries. If this can be done fairly precisely, there would be no need even to delay the start-up dates of new fields. Thus Report no. 25 states: 12 `First and foremost the scope of the operations on the Continental Shelf must be controlled by regulating exploration activities. Once a discovery is made, technical, economic and political reasons will tend to require that the resources be exploited as rapidly as possible. The harsh climatic conditions on the Shelf mean that the individual fields must be exploited at a relatively rapid pace, before the installed equipment has to be renewed. This reduces the possibilities of regulating the rate of extraction once production has commenced.' Exploration activity is therefore seen as the main instrument of a depletion policy. A moderate level of production — 90 million tonnes — implies a moderate rate of exploration. The Government's objective is always to have proven reserves equivalent to 10-15 years of production, which for an annual level of 90 million tonnes implies proven reserves in the range 900-1,350 million tonnes of oil and gas. The exact range suggested has been 1,000-1,200 million tonnes.

The Level of Production

37

In 1974 the Norwegian Oil Directorate estimated that proven reserves south of 62°N. were in the range of 800-1,000 million tonnes. The current official estimate is 1,500 million tonnes, the main reason for the increase of course being the discovery of Statfjord with estimated recoverable reserves of 300 million tonnes and gas reserves of 60 million tonnes oil equivalent. 1,200 million tonnes are in fields for which positive development decisions have been made. In 1974, total probable recovery reserves south of 62°N. were estimated at between 2,000 and 4,000 million tonnes. The Oil Directorate's current estimate of probable reserves is 3,000-4,000 million tonnes with `the view that there is little probability that the reserves south of 62°N. are greater than 5,000 million tonnes oil equivalent or less than 2,000 million tonnes oil equivalent'.13 The important point is that the range of 3,000-4,000 million tonnes represents 35-45 years of production at the target level of 90 million tonnes per year. This is roughly three times the length of the required period suggested in 1974, and thus the distinction between probable and proven reserves is crucial, particularly as nothing north of 62°N. has been considered. Norwegian exploration policy has been described as `go slow' and it is difficult to deny that. The distinction can be made between policy that applies to existing Iicences — i.e. those in force in 1974 when the depletion policy was formerly formulated — and future licences. In 1974 there were few possibilities of controlling the level of production from existing licences, unless the Ministry introduced retrospective conditions — which it threatened, although has done nothing. The U.K. Government has in fact introduced retrospective legislation of this type. The Norwegian Government confined itself to promising that future production licences will include provisions enabling the Ministry to impose production cuts or delays if it so wished. In practice, however, policy objectives have been met by very restrictive licensing rather than restrictive conditions attached to licences. As explained in Chapter 1, the first Norwegian licence round in 1965 was smaller than the first U.K. round in 1964 — seventy-eight blocks compared with 348 (although Norwegian blocks are about double the size of U.K. blocks). The second round in 1969 covered fourteen blocks and the third round in 1974 only eight blocks. Some blocks have been licensed on an ad hoc basis but the fourth round has frequently been postponed and even if it is finalised in early 1979 it will be about two years later than the original announced date. By then there will have

38

Norwegian Oil Policies

been six licence rounds in the U.K., all of greater acreage than Norway — 1964, 1965, 1969, 1971, 1977 and 1979. Given the differences in economic size and energy demand, the rate of development in the U.K. sectors was probably very similar in the late 1960s and early 1970s. The turning point dates from 1974, by which time the full significance of the Ekofisk and Frigg discoveries was known. It is clear now that the period 1974-8 has been used by the Government to mark time and to reflect on alternatives. The fourth licence round was due to take place in 1977. The Ekofisk blow-out in April 1977 was the first cause of delay; this is discussed in more detail in Chapter 3. In addition there are the even longer delays regarding licensing of Mid- and North Norway, which are also discussed in Chapter 3. The official endorsement of the suggestions in Report no. 25 (1974-5) was made by the Industrial Committee of the Storting in 1975: 14 `Without wishing to bind themselves too much to specific figures the majority of the Committee ... would like to recall that the Government has previously chosen an annual production of approximately 90 million tonnes of oil equivalents for the 1980s as an illustration of a moderate tempo. The majority of the Committee is of the opinion that this moderate tempo ought to be maintained in the exploitation of petroleum resources and that this moderate tempo ought also to be evaluated on the basis of the following: — the Norwegian labour market and industry; — regional policy concerns; — environment and pattern of settlement; — safety requirements; — the general energy situation in Norway and in the rest of the world; and — what serves the society as a whole.' The official announcement of the fourth round blocks made it clear that the Government was still of the same opinion, and considered that events since 1974 had shown the sense of a moderate, or go-slow, policy. The long delay in allocating these blocks has undoubtedly been the crucial factor in implementing the policy but certain conditions attached to the other documents may be of greater significance in the future. For example,15 `among the blocks which are proposed for announcement, there are some considered as very promising. The production licences will include clauses on the rights to postponement of field development within time limitations, but without the Government having

The Level of Production

39

to give reasons. This is done based on the purpose of these allocations; particularly the consideration that there be a moderate tempo, as well as the desire to maintain the best possible control of both development and exploitation. It is the opinion of the Ministry of Industry that this will be especially necessary on blocks where there are possibilities of major discoveries. Furthermore, on such blocks it will be evaluated to reserve special rights for the authorities to determine the level of production .. . likewise it will be evaluated to include a clause saying that the State may determine a production profile which departs from the optimal profile as seen from a private economic point of view.' In essence, this is making explicit what was generally understood before. Conditions have always been attached to the exclusive production licences which in law would appear to give the Government very wide powers of intervention — although the only major case in which such powers have been exercised was regarding Ekofisk production after the Ekofisk Bravo blowout. Before the blowout, Phillips was only given permission to produce for three monthly periods. Although this permission was renewed automatically, Parliamentary Report no. 30 (1973-4) makes it clear that1e `in the time ahead further information will be forthcoming concerning the reservoirs and production capacity in the Ekofisk area, from the drilling of production and exploratory wells and from the course taken by production. Some of the assumptions underlying the production plans submitted will therefore become clearer in time. Accordingly it will be expedient to make continuing appraisals of the existing and other applications for production. Approval of production plans can thereby be given in accordance with information available at the time as far as physical conditions, etc. are concerned.' In fact, if the Government wishes to delay, stop or reduce production from a commercial field it can do this under a number of headings. For example, strict safety regulations apply to production installations, and it would be easy to find reasons for implementing controls. Much of the delay in Statfjord is attributable to the Oil Directorate's insistence on changes in the production platforms. Licensees have to agree work programmes, and the Directorate could withold agreement, thus delaying activity. The state oil company, Statoil, has similar powers because it can influence the decisions of licensees with whom it is a partner. The additional conditions which will be incorporated into the fourth round licences, therefore, are really just formalising existing

40

Norwegian Oil Policies .

powers and presenting them in a clearer light. But is there any need for such powers? Will they be used? Pressures for change Ninety million tonnes is the magic figure given by the Government. If we take production from fields under development (the Ekofisk area, Statfjord, Frigg and Valhall), peak production will probably be around 65 million tonnes oil equivalent in the period 1980-7. This is lower than previous forecasts, mainly because the delays in developing Statfjord mean that by the time it reaches its peak, Ekofisk and Frigg will be on the decline. Oil and gas fields normally take 3-5 years to build up to peak production which can be maintained for about three years and is followed by steady decline at roughly 10 per cent per year. This means that production from the established fields will fall sharply after 1990, probably to no more than 20 million tonnes by 1995. The shortfall between the `moderate tempo' figure of 90 million tonnes and expected production will therefore be around 25 million tonnes per year throughout the 1980s, and will rapidly increase to 80 million tonnes per year by the end of the century. This shortfall has to be met by production from new fields. In addition to the fields listed above, Table 1.5 lists a number of smaller discoveries. Murchison is being developed from the U.K. sector, but its Norwegian content is small — an estimated 8 million tonnes of oil and gas. The only other named possibilities in the near future from Table 1.5 are Heimdal, Hod, Odin and Sleipner, but again they are small and the last two may depend on an extensive gas trunk line being laid. The best possibilities appear to lie on the Statfjord blocks (33/9 and 33/12) and block 1/9, but drilling results to date do not suggest major discoveries of Statfjord size. Government hopes for some of the fourth-round blocks are very high, but any discoveries there would take at least 6-8 years to develop, and production could not occur on any large scale before 1990. This would apply also to possible production from north of the 62nd parallel. The clear implication is that the production forecasts or targets set by the Government will not be met. In the short run, this will be because of production delays on almost all the fields in the Norwegian sector, which create short-term problems but nothing of such major consequence that it justifies radical changes in depletion policies. In any case, the policy target period has consistently been seen as the 1980s by which time even Statfjord should be producing at acceptable levels. Apart from the em-

The Level of Production

41

barrassment of delays and inaccurate forecasts, the main pressure comes from the Government's high level of borrowing. As Chapter 7 shows, this has increased very sharply, and the balance of payments has similarly deteriorated. The borrowing has been possible because of the prospect of oil revenues and has been used to maintain high levels of demand and employment, largely by subsidies to industry. It is becoming increasingly clear that these policies have not been as successful as desired. The reasons for the lack of success are outside the scope of this book, but they include the continuing international recession, the disintegration of the national incomes policy and the failure to restructure industry during the period of subsidy. At the time of writing we do not know what response the Government will make. It could continue to borrow heavily, but that is unlikely. Probably the period 1979-81 will be relatively austere in the context of Norway's recent economic history. We do not see increasing oil revenues as offering any solution to these continuing problems, which in any case should be short-term if general fiscal and monetary policies are applied sensibly; but there is little doubt that some sections of the community will use this evidence to support their claims for a faster rate of offshore development. Thus the second major pressure for change comes from those sectors of Norwegian industry which see the North Sea as a market, potential or existing, for their products. In the front line are those industries and firms directly supplying offshore oil and gas equipment. Already they have experienced a sharp fall in demand in the North Sea and future prospects do not appear to be much better. For example, for the period 1974-7 we estimate that (in 1974 prices) capital expenditure for Norwegian sector developments averaged 11,000 million kroner per year; for 1978 and 1979 the estimates are an average of 7,500 million; and for the period 1980-83 an average of 5,500 million. The employment counterpart of these figures is given in Chapter 5. According to Labour Directorate definitions, oil-related employment rose from 6,600 in August 1973 to 21,700 in August 1975 and to 29,000 in August 1978. We estimate that a peak of around 32,000 will be reached in 1981 or 1982, and that thereafter there will be a steady fall — to an estimated 24,000 in 1985 and 15,000 in 1990. The underlying reason for this pattern is the gradual change from development activity to production activity, the latter being much less labour-intensive. As was pointed out above, once the Ekofisk, Frigg and Statfjord developments are

42

Norwegian Oil Policies

completed, future prospects are for smaller fields. Even if there proved to be a steady stream of new discoveries, the evidence from the U.K. sector suggests that equipment requirements may be considerably less. With pipelines, for example, the common U.K. pattern is now for new fields to be tied (joined) to the existing pipeline and terminal networks, rather than for new pipelines to be laid. Thus Magnus is to be tied into the Ninian pipeline system and the Sullom Voe terminal; Tartan into the Piper/Claymore pipeline and the Flotta terminal in Orkney; and Piper gas into the Frigg pipeline to St. Fergus. Production platform construction is probably one of the best examples of the depressed North Sea market. Over the period 1970-5 Norwegian platform yards built thirteen platforms for Norwegian fields and four platforms for U.K. fields; then there were only two orders in 1976 and 1977; and the first order in 20 months came in 1978 with the order for the Statfjord B platform. The weak market shows an even greater decline because of the original success of the Aker group in building exploration rigs for use in other offshore areas. It is not surprising therefore that the Aker group has been at the forefront of Norwegian industry in trying to persuade the Government to increase the tempo of offshore activity to a level which would generate a higher — and steadier — demand for equipment and services. The Federation of Norwegian Industries has made repeated requests to the Government to relax the `go slow' policy, and there is little doubt that these representations will continue. The position has been summarised in a recent editorial in the magazine Noroil: 17 `It is worth saying again that what was a good oil policy for yesterday may not be good for today. What may happen is that the facts upon which those concepts are based change, a factor that is more likely in the North Sea operations than most others.... The go-slow concept that has been a principle factor in Norwegian oil policy is currently having an adverse effect on both offshore activity and the Norwegian economy in a manner that one should have expected. Licensing policy can indeed act as the regulating element in a nation's overall oil policy, but only if that policy is designed with enough flexibility to match the real demands for adjustment at a rise as a natural consequence of the fickle nature of offshore activity. . . . When the first estimates are adjusted downwards after an exploration.. programme fails to result in reserves, and when industry suffers from a lack of new business, it should be an obvious reaction for any Government to draw the only sensible

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solution — to prepare the best possible conditions for increased exploration. This has not been the case on the Norwegian Shelf.' It is perhaps ironic that similar pressure is coming from industrial concerns outside Norway and that their reasoning may have a greater effect on Government action than the views of Norwegian companies. The Ministry of Petroleum and Energy has been having a series of discussions on industrial co-operation with foreign companies and governments. From the Norwegian point of view the main inducement is Norwegian oil and gas, or at least the opportunity to explore for them. In Chapter 4 there is some discussion about downstream oil refining and petrochemical developments. Given that most Norwegian oil and gas is being exported in crude form, such developments will happen on a larger scale outside Norway than in the country — e.g. at the terminals in Emden (West Germany) and Teesside (England). Although they are important in other contexts, the significance for depletion policy is limited. Of more interest are industrial developments linked directly to the involvement of foreign companies on the Continental Shelf. The fourth licence round of the documents stated that the Ministry would pay particular consideration to `the extent to which the applicant has contributed or will contribute to the strength of the Norwegian economy, industrial growth and employment'. This led to a number of applications for production licences from foreign companies. The most notable was that by Volvo, the Swedish motor vehicle company. Although this interest has been stopped, or at least delayed, it is worth discussing as a type of industrial co-operation on which the Norwegian Government was keen. After lengthy discussions at both company and Government levels, it was announced in May 1978 that Volvo was to be reorganised as a joint Swedish-Norwegian concern with a 40% Norwegian shareholding. The Norwegian Government was to guarantee a 750-million-kroner (Swedish) investment in the share capital of the new company, which was to develop and produce aluminium and plastic components for motor vehicles in Norway and transfer the production of one make of vehicle from Sweden. In addition the head office of Volvo Penta was to be moved to Norway, where a type of marine engine was to be developed and produced. It was expected that these developments would create between 3,000 and 5,000 jobs in Norway and introduce new types of activity such as the manufacture of motor vehicles, with an eventual reduction in imports. In return, Volvo would establish an oil company which was to be granted certain

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Norwegian Oil Policies

exploration rights as part of a fourth licence round. In the first instance, these were to be minority interests in three blocks 30/2, 30/3 and 30/6, of which the last is rated as highly promising. In the event this `cars for oil' deal collapsed after criticism from two fronts. On the one hand there was considerable opposition from other political parties in Norway, including the two main opposition parties, the Conservatives and the Christian People's Party. On the other hand the Swedish Shareholders Association (SARF) objected on the grounds that Norway would get the 40% stake too cheaply, and that there would be a detrimental effect on the company's cash flow and an undermining of the equity consolidation. The Association was able to muster about 40% of the Volvo shareholders' votes against the agreement, and given that the Board required a two-thirds majority in favour, Volvo and the Swedish Government had to withdraw. In fact this probably saved the Norwegian Government from embarrassment because there was a strong chance that the opposition parties would have defeated the Government on the issue and the Prime Minister, Odvar Nordli, had threatened to resign if that happened. It may well be that some aspects of the proposed deal — such as increased Swedish timber exports to Norway — may come to fruition, but it is certainly a major setback for industrial co-operation. Similar negotiations have been held with the West German company, Veba. The two Governments have entered into an agreement in principle on energy co-operation and details are being worked out with various companies. Veba has signed letters of intent with a number of Norwegian companies concerning possible West German investment, in exchange for a share of Norwegian oil production. The investment would be designed to secure outlets (either in Norway or West Germany) for petrochemical products from the Bamble complex, which, as discussed in Chapter 4, faces increasingly difficult export markets. The offshore oil participation would be through Deminex, a Veba subsidiary, which already has interests in three blocks (33/5, 33/6 and 33/7) to the north of Statfjord and who have applied for further concessions in the fourth round. One major factor in Deminex's favour is that they have already significantly and successfully expanded their interests in the U.K. sector — largely through the purchase of other companies' stakes — and have a major share in the Thistle field which is producing. Whether or not deals such as the Volvo and Veba proposals eventually come to flourish, it is undeniable that it has become a major issue in licensing policy. Although it has not been officially

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45

admitted, our interpretation is that any licence agreements which are made will be in addition to those involving Norwegian companies — in other words, more licences will be issued more frequently. In the fourth round there is unlikely to be a discernible effect, because any agreements would probably only result in a slight reduction in Statoil's participation rate in certain licences. From discussions we have had with Government officials, however, we have gained the impression that the fifth licence round may follow on soon and that by then the precise forms of the international industrial agreements will have been recognised and incorporated in licensing policy. It is probably fair to say that these initiatives on the industrial front are manifestations of a wider and more political concern of the major European oil-importing countries, particularly West Germany. It is well known that Norway rejected membership of the EEC in 1973, and one of the major reasons was the fear of external interference in oil and fishing policies. It is less well known that in 1974 Norway declined to become a full member of the International Energy Agency (IEA) set up under the auspices of the OECD. The IEA, particularly the United States and West Germany, have been eager to introduce oil-sharing agreements under which alternative supplies would be made available to member countries in the event of disruptions of supplies from the Middle East. If that happened, Norway and the U.K. would have been obliged to increase domestic production as rapidly as possible to meet the needs of their partners. This idea has been taken even a stage further by the geographer Peter Odell, who has argued that North Sea gas fields should be depleted as rapidly as possible in order to reduce Western Europe's growing oil import bill.18 It is not surprising that Norway has ignored these demands, but once again it has to be recognised that if there were a recurrence of the 1973/4 supply problems, Norway would be in a difficult position to resist requests for increased production. Finally, pressure for change may come from the desire to develop marginal fields. In aggregate terms this may not mean a major change in policy, because we are only talking of 5-10 million tonnes of.production per year, but it would be a recognition that past policies have been too inflexible. As Table 1.5 implies, there are quite a number of small fields in the Norwegian sector on which development decisions are being awaited. Some were discovered at a very early stage: Cod in 1968, Murphy in 1969 and Balder in 1970. With existing technology such fields

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Norwegian Oil Policies

appear to be too expensive to develop. One of the complications, as Chapter 6 shows, is the inflexibility of existing oil tax policies, which tend to discourage the exploitation of the smaller fields."° This has been recognised recently by the Government which has established a special committee to consider the problems and to make recommendations. Two possible solutions would be to reduce respectively the royalty rates and the Statoil participation rates. U.K. policy Before making a few concluding remarks, it is worth digressing briefly to describe U.K. policies, mainly because it is largely as a consequence of comparisons with the U.K. that Norwegian policy has been described as `go slow'. The best description is given by Robinson and Morgan,20 although it should be remembered that they are strongly against Government intervention. During the first ten years of activity on the U.K. Continental Shelf (1964-74), the policy of successive U.K. governments was to exploit reserves of oil and gas as quickly as possible. The authorities had decided21 `that the balance of advantage to the United Kingdom lay in exploiting and extracting these reserves of gas and oil as quickly as possible. In arriving at this decision they took into account relevant factors including balance of payment savings, security of supply, possible future fuel shortages, as well as the purely economic advantage judged, for both gas and oil, by comparisons of the estimated present net value of the resources if extracted earlier or later'. Thus there were regular and large licence rounds, and a relatively easy fiscal regime. When the Labour Government returned to power in 1974, it became clear that there were second thoughts about the appropriateness of a rapid depletion policy. In part, this was due to pressure in Scotland from the Scottish National Party, which wanted policies more in keeping with the needs of Scotland than those of the U.K. The Government White Paper (comparable with the Storting propositions) in 1974 stated that the Government intended to take powers to control the level of production in the national interest, not with a view to the immediate period ahead but with a view to the 1980s. This attracted a lot of criticism from oil companies, and the Secretary of State for Energy issued a series of guidelines which were subsequently incorporated into the 1975 Petroleum and Submarine Pipeline Acts. The guidelines are: 1. Finds made before end-1975 under existing licences:

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47

No delays would be imposed on development plans. Any production controls would not be applied before 1982 or four years after the start of production, whichever is later. 2. Finds made after end-1975 under existing licences: No production cuts will be made before 150 per cent of investment in the field had been recovered. 3. All finds made after end-1975: Development delays would only be imposed after full consultation with the companies concerned so that premature investment is avoided. 4. General: Any use by the Government of depletion controls would recognise technical and commercial aspects of the fields in question, which would generally mean production cuts of no more than 20 per cent. The industry would be consulted of the necessary period of notice before cuts became effective. The Government would also take into account the needs of the offshore supply industry in considering development delays or production cuts. So far these powers have only been exercised in relation to oil fields with significant reserves of associated gas. Companies have been told to delay or reduce oil production until such time as they have agreed plans with the Department of Energy for the satisfactory handling of the gas. This was done to avoid excessive flaring of associated gas and the agreements reached appear very sensible. Flaring is still allowed in some cases, but in others the proximity of the Frigg and Brent gas lines has enabled plans to be formulated for the use of the gas. More informal pressure has been put on a few companies in relation to their oil development programmes. Mesa, the operator for the Beatrice field (a small field in the Moray Firth only 15 miles from shore and a good fishing area), were refused permission for offshore loading and had to re-submit proposals which included a pipeline to shore. Permission has been similarly delayed for the Maureen and Magnus fields, but in no case does it appear that an excessive level of production — per year on an individual field or aggregate basis — was a factor. By 1980 the U.K. will be producing in excess of 100 million tonnes of oil and about 25 million tonnes of gas (oil equivalent). U.K. domestic consumption of oil is currently about 90 million tonnes — ten times Norwegian consumption. It is possible that by the mid-1980s U.K. production could reach an annual level of 150 million tonnes, although that could not be sustained for more than six years unless there are some major new discoveries in the

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Norwegian Oil Policies

near future. In the U.K., then, the question is: would the Government use the depletion powers it has? Any answer is a guess, but our view is that it would be very unlikely. At most this level of production would only amount to a 50 per cent surplus over domestic needs, and the U.K. balance of payments is such — and almost certainly will still be such in the 1980s — that the additional foreign revenue will be a major benefit to the national economy (and to the Government exchequer). Furthermore, the Norwegian pressures described above apply with even greater force to the U.K., particularly in relation to the need to maintain a steady level of demand for production platforms, modules, pipelines and other equipment. Thus the main contrasts between the U.K. and Norway are in the powers which the Governments have taken and in the use made of them. In Norway the emphasis has been on control by way of limiting exploration; and this power has been used strictly. In the U.K., licensing policy has not been used, and instead the Government has taken control through the 1975 Petroleum and Submarine Pipelines Act; but these powers have not been used on a major scale and we think it unlikely that they will be. In relation to non-recoverable reserves, there is little difference between U.K. and Norwegian policies. At present and planned production levels, reserves of oil and gas in both sectors will be exhausted at about the same time — i.e. 20-25 years hence. However, in relation to domestic gas and oil requirements the U.K., target level of 150 million tonnes oil and gas is about 50 per cent greater than domestic demand. In Norway the target level of 90 million tonnes oil and gas is about 800 per cent greater. Looked at in that way, it could be argued that the Norwegian rate is about forty times faster than in the U.K. Does that constitute a `go slow' policy? NOTES 1. Ministry of Finance, Parliamentary Report (MFPR) no. 25 -(1973-4). 2. Ministry of Industry, Report to the Storting (MIRS) no. 30. 3. MFPR no. 25, p.5. 4. MFPR no. 25, p.10. 5. See, e.g., various chapters in D. I. Mackay and G. A. Mackay, The political economy of North Sea oil. 6. For more detail see D. W. Pearce (ed.), The economics of natural resource depletion. 7. M. Khouja and P. G. Sadler, The economy of Kuwait. 8. Ibid., p.134.

The Level of Production 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21.

49

C. Robinson and J. Morgan, North Sea oil in the future, p.33. Financial Times, 13 November 1975. MFPR no. 25, p. 16. Ibid., p.9. MFPR no. 75 (1977-8), p.131. Storting recommendation no. 402 (1974-5). Storting proposition no. 72 (1977-8). MIRS no. 30, p.18. Noroil, June 1977, p.19. P. Odell, Oil and Western Europe. See also A. G. Kemp and D. Crichton, Oil taxation in Norway. Robinson and Morgan, op. cit., esp. Ch. 2. Public Accounts Committee, `North Sea oil and gas', para. 96.

3 FUTURE EXPLORATION Where your treasure is, there will your heart be also. (Matt. 6. 21) Although it is impossible to be certain, our interpretation of the discussion in the preceding chapter is that there is likely to be an increase in exploration activity in Norwegian waters over the next few years. If the original objectives of depletion policy are to be met, there is a fairly urgent need for the discovery of new oil and gas reserves, even if they are not exploited in the near future. If the original objectives are believed to have been superseded by recent events, most of the new pressures are for an increase in exploration activity. It seems reasonable to us therefore to argue that the end of one phase has been reached and that a new phase in Norwegian offshore activity is about to begin, characterised by a marked change in the direction of exploration activity. To date all exploration and production activity has occurred south of the 62nd parallel. This is true also of the U.K. sector. However, in U.K. waters during the last two years there has been new activity to the west of the country — to the west of Orkney and Shetland, in the Celtic Sea (between England and Ireland) and most recently off the south-west coast of England. None of these areas has proved fruitful so far, but they have diverted some interest away from the North Sea and helped to maintain an otherwise slacking level of drilling. As can be seen from the map at the beginning of the book most activity has concentrated on the areas immediately to the east and west of the median line dividing the Norwegian and U.K. sectors and, further south, the Dutch and U.K. sectors. Chapter 1 made the point that there has been a steady northward trend, and it is surprising but true that most of the discoveries have been made near these median lines. Almost all the blocks along the Norwegian/U.K. line have been licensed and explored. On the Norwegian side the only outstanding exceptions at the present time 50

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are blocks in quadrant 7, to the north of the Ekofisk area and the Cod field and to the east of the small Montrose field in the U.K. sector. This is not a promising area and there has been little pressure from the oil companies in Norway on the Government to licence these blocks, partly because of poor results on nearby blocks. In fact it is important to remember that the main reason for the ad hoc licensing of quite a number of Norwegian blocks has been the discoveries of fields in the U.K. sector and the possibility that these extended into Norwegian waters, thus creating a need for rapid licensing and appraisal drilling. In the U.K. quadrant immediately to the west of quadrant 7 there has also been little interest, so there are unlikely to be pressures from that direction in the foreseeable future. This is not to say that there are no areas south of 62° N. which are of prospective interest to oil companies. Apart from the southern tip of the Norwegian sector, relatively little exploratory drilling has been done on the blocks lying between the median line and the Norwegian Trench, and certainly some of these blocks are of great interest. The best examples are undoubtedly block 29/3 and the blocks in quadrant 30 lying to the south and east of Statfjord. As mentioned in Chapter 2, most of these were included in the fourth licence round, and drilling is expected to start on them before the end of 1979. Nevertheless, it is probably fair to say that about 80-85 per cent of the prime drilling prospects have been licensed (including the fourth round). One implication of that is that there could be a sharp reduction of interest in a fifth round unless new areas are opened up — and in the case of Norway this must be north of the 62nd parallel. Unlike in the U.K., there are no other offshore areas to licence, but on the other hand this area is very large. The main focus of this short chapter, therefore, is the area to the north, which already has attracted much attention. This area merits special attention because of its unique place in the Norwegian economy and society, which has been fully recognised in the context of oil policies. Furthermore, the area has similarities with many other remote areas throughout the world which are attracting attention as possible offshore oil provinces — e.g. eastern Canada, northern Australia and the south-western United States — and other countries may have lessons to learn from the North and Mid-Norwegian experience. In turn, this may also be true of Norway in relation to Orkney and Shetland, which are the areas in the U.K. most similar to Northern Norway and

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where oil developments have already occurred. These developments have taken place in the absence of the detailed planning and thought which is in progress in Norway, so it may well be a case of learning from British mistakes. Whatever the lesson, however, there are useful comparisons to be made between North Norway and Orkney and Shetland, and these are discussed later in the chapter. Exploration north of 62°N To date activity has been confined to the area south of 62°N. The Government has encouraged seismic work over the whole of the Continental Shelf, in order to obtain some indication of possible petroleum deposits and some guidelines for future exploration drilling. In 1974 the possibilities of Mid- and North Norway were discussed in Report no. 30: 1 `The Ministry assumes that in view of regional policy considerations, one should start reconnaissance and drilling in the northern parts of the country.... The Ministry recommends opening up for exploration drilling a limited area comparatively near the coast of Troms in 1975-6 and, if conditions are appropriate, a smaller area off Møre-Trøndelag, either at the same time or a little later.' This view was endorsed by the Storting Industrial Committee, but in view of the lengthy seismic and other surveys required, the starting date was postponed to the summer of 1977. In the intervening period there was considerable discussion about the exact areas for exploration drilling. Some bodies favoured Mid-Norway, i.e. the counties between 62° and 65°N. (Møre og Romsdal, SørTrøndeIag and Nord-Trøndelag), but this was rejected, mainly on the grounds that it could add to the pressures in the western counties already affected by the Stavanger-based developments. North Norway was preferred, partly because of its relatively serious economic problems. This is the area between 65° and 71°N., comprising the three counties of Nordland, Troms and Finnmark. The total land area is about 113,000 square km., more than one-third of the total land area of Norway. From a physical viewpoint it is at a considerable disadvantage when compared with all other regions of the country, because of the inherent problems of climate, topography and remoteness. The climate determines to a large extent the profitability of the primary industries, and has a major influence on other economic activities, particularly of the building and construction industry. The mountainous topography, with numerous islands and fjords

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dividing the region into many separate districts, is an added problem. If Norway were pivoted around the southernmost point, the country would cover the distance south to Rome. No other region of a European country is further away from its capital and main consumer markets than is North Norway. The transport costs of importing consumer goods and other products are very high, in spite of good communications and transport subsidies; and the same is true of the export of raw materials and finished products. Other facts which make the economic developments of the region difficult are the dispersed settlement pattern, a long tradition of emigration, the generally low levels of education of the inhabitants, and the limited economic base. The main economic activities are agricultural, forestry, fishing, hunting and mining. Fishing and whaling, for example, account for about 8 per cent of the total population, compared with less than 2 per cent in Norway as a whole. In contrast there are markedly lower percentages in the manufacturing and service industries. The economic status of North Norway can be guaged roughly from its share of gross national product: about 8 per cent at present, compared with a 11.5 per cent share of national population. This implies relatively low income levels. The gross product of the region equals about 60 per cent of the total consumption of goods and services, so in other words about 40 per cent has to be imported from South Norway or from foreign countries. As in many similar areas throughout Western Europe, the Government has implemented an active regional policy to try to reduce the disparities in income and employment levels.2 North and Mid-Norway have been particularly favoured, and although the policies had had some success, the result has been to slow down the rate of relative decline of these regions rather than to reverse the trends. Thus both the general economic situation and the rationale of regional policies in the 1960s and early 1970s favoured the introduction of oil-related activities. Manufacturing activity was seen as the main hope of expanding and stabilising the indigenous economy base, and there was no reason to treat oil and gas activities as different from other manufacturing activities such as pulp mills and aluminium smelters. It should be pointed out, however, that a tremendous amount of thought had been given to the ways in which such industries could be organised to maximise the benefits to the more remote areas. Suggestions for a decentralised oil refining and petrochemical industry in North

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Norway are discussed in Chapter 4, but this aspect of industrial development is outside the scope of the present chapter. These possibilities need to be seen in the light of the fact that exploration drilling has not yet started. It was first proposed in 1970, and unofficially it was suggested that drilling could begin in 1971-2. A year later the start had been postponed to 1974-5. Report no. 30, which came out in May 1974, then suggested 1975-6, and in February 1975 the then Minister of Industry, Mr. Ulveseth, stated that drilling was unlikely to begin before the summer of 1977. In April 1976 the Ministry of Industry presented Report no. 91 to the Storting,3 which discussed in detail appropriate policies for exploration activity north of 62°N., and this now famous report recommended that drilling should begin in the summer of 1978. One consequence of this report, however, was the establishment by the Government of a special `Study Committee for Petroleum Activity North of 62°N.' to investigate certain aspects in more detail, and this has had the effect of further delaying proposals. It is now expected that drilling will begin in the summer of 1980 — five years after the original official date and 8-9 years after the first unofficial proposal. Although the North Sea is notorious for delays, this is certainly one of the longest and most noteworthy. There is little point in retracing the debates prior to Report no. 91 because that was the first time that the detailed arguments had been presented to the Storting. It was also a sufficiently long time after the major OPEC-induced changes in 1973-4 to reflect the new policies of the Norwegian authorities. On the basis of an extensive analysis of existing geological data, mainly from seismic surveys, the report recommended that priority be given to one area (Area 1) off Troms/Vest-Finnmark where the sedimentary strata were estimated to be more than 10,000 metres thick. In addition, seismic surveys carried out there in 1974 suggested that there were a number of potential types of trap within the area which had reasonable prospects of holding petroleum deposits. One other area (the so-called Harstad basin) further south and closer to land was identified but given a lower priority, mainly on the grounds of incomplete geological data. It was intended that drilling should be confined initially to these two areas, although the possibility of drilling in the immediate vicinity of Area 1 was raised if results were particularly encouraging. Similarly, two areas of Mid-Norway were proposed: Area 1 off Ålesund and Kristiansund and Area 2 to the north-west of Trondheim. No priority was attached to either of these areas.

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Regarding the extent of operations, it was made clear that drilling would only be allowed during the summer season, i.e. from May to September or October, which implies a maximum of two wells per rig. `It must be emphasised that the moderate tempo planned north of 62°N., with a small number of wells a year, provides the most expedient method of control. This, combined with taking safety and fishery into consideration, must determine the level of activity.... It is not desirable to plan greater activity in these areas until more knowledge of the geological conditions has been obtained by drilling. A more extensive programme for exploratory drilling would lead to bigger investments in basis and other petroleum related activities. These might prove worthless if no petroleum is discovered. Moreover a low level of the activity in the opening phase will be more sensible because the new geological information obtained by drilling can then successively be fully employed in the further planning.... In practice this means that with two rigs as envisaged in the first season, about four wells can be drilled. Four rigs may be used later. If geological/financial conditions permit it would be natural to increase the number to three rigs the following year.'' This suggested level compares with the twenty-one exploration wells drilled in Norwegian waters in 1975, twenty in 1976 and eleven in 1977. It should be mentioned that up to the end of 1977, ten exploration wells had been drilled on Svalbard, the island north of Norway `shared' with the U.S.S.R. The first of these was in 1965, but results have been very poor. Further exploration here will depend on boundaries being agreed with the Russians, and there is no haste on either side to do that. Incidentally, this problem of agreeing boundaries has also delayed the expansion of the U.K. offshore area to the north and west of 62°N. There agreement will have to be reached with Faroe. The danger of pollution One of the main reasons for the continuing delay in giving permission for exploration drilling in the areas identified above has been a concern about safety and possible oil pollution. In 1976 disagreements within the Government on this issue led to the postponement of drilling off North Norway. The Ekofisk blowout in 1977 served only to reinforce fears and to delay the startup even further. Reading through the Parliamentary Reports written before the Ekofisk disaster, it is remarkable how accurate their worst prognostications proved to be. Pollution was identified from the outset as a significantly

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greater problem north of 62°N. because of the more sensitive marine environment. Petroleum is a compound of hydrogen and carbon, occasionally mixed with small quantities of sulphur, nitrogen, etc. The composition of crude oil — which can vary from field to field — determines its detrimental effect on the marine environment. The constituents and their decomposition products have different poisonous, destructive and solubility characteristics in water. They are absorbed by living organisms in varying degrees. Some compounds are harmless but others can be very dangerous, and it is therefore necessary to have a detailed knowledge of both the particular marine environment and the composition of the crude oil before an analysis of environmental consequences can be made. When oil gets into the ocean, some will evaporate and some dissolve. The heavier fractions of components will normally sink to the seabed. With an oil spill the oil is highly concentrated in the upper layers of the sea, and this is likely to affect the plankton there on which many species of fish, seabirds and other marine life depend. The damage to food resources is certainly the greatest or worst effect, although oil washed on to beaches usually attracts more attention. The Oil Directorate has estimated that the total amount of spilt oil taken from the world's oceans is between 5 and 8 million tonnes per year, of which 3-4 per cent is attributable to offshore oil production and exploration drilling. In comparison, spills from vessels are estimated at approximately 20 per cent. The main danger is a blow-out during drilling. Other potential sources are well leakages, spills during tanker loading at sea, the fracturing of pipelines, and collisions between vessels or between vessels and offshore installations.5 It is clear that the dangers of pollution and related problems have been a major source of concern to those involved in planning activity in the North and have been the main cause of the continuing delays. A majority of the Industry Committee, supported by a majority in the Storting, recommended that drilling should take place only provided that the technological conditions were clarified and if drilling could take place `within an acceptable level of risk'. As a basis for such an evaluation the Ministry of Industry has used a definition of the term `level of risk' which takes account not only of the purely technological and safety aspects of possible activities but which also seeks to illustrate the consequences which the activities will have on community life and the environment

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in the Northern regions. Much of this work has been done by the Special Study Committee mentioned earlier. The conclusions reached by the Ministry in regard to pollution were that° `one cannot preclude the possibility of an oil blow-out occurring, but there is very little risk of this happening. As regards the danger an oil blow-out north of 62°N. may cause, it must be assumed that the consequences would be more serious than in the North Sea, especially during the winter or spring. This is because parts of the selected areas north of 62°N. are in a location of central importance for some principal species of fish [ ... ] Should a major blow-out occur, extensive damage could be prevented only to a limited extent with the present-day state of technology. The Ministry will not permit drilling to begin until the operators have submitted an acceptable oil emergency preparedness plan based upon access to the best existing equipment. Moreover drilling will not begin until satisfactory public emergency preparedness is established.' It was expected. that drilling would begin in the summer of 1977 or 1978. Statoil and the other oil companies possibly involved gave assurances about their state of preparedness and these were accepted by the Ministry. The Ekofisk blow-out on 22 April 1977 demonstrated clearly that neither the companies nor the public authorities were really in a position to give such assurances, and one consequence of the disaster was the further postponement of activity north of 62°N. In the Storting the simple point was made that the worst fears had been confirmed. This is not the place to give a detailed account of the Ekofisk blow-out,' its main significance in the present context being as the generator of the delays mentioned above. The oil and gas blow-out occurred in well B 14 on the Bravo production platform on the field. The well was being worked over, i.e. some of the equipment was being replaced and about 3,000 metres of tubing were being removed from the well. To do this the valves on the production deck — the `christmas tree' — have to be removed and replaced by a blow-out preventor (BOP). The blow-out occurred during the installation of the BOP, the immediate cause being that a safety valve had been incorrectly installed. In accordance with the Royal Decree of 9 July 1976 relating to safe practice, a workover programme had been prepared before the start of the work and had been approved by the Oil Directorate. In the course of the work, changes had to be made because of doubts about the type of pressure valve which could be used, but the Directorate was not told of these. The special

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committee appointed to investigate the cause of the blow-out was also of the view that a weakness of the programme was that it did not prescribe pressure testing of the mechanical safety device in the tubing and that the Directorate ought to have required such testing. Both the Phillips Company and the Directorate came in for strong criticism, and the commission recommended the number of major changes in safety, training and administrative procedures. These conclusions appear to have been accepted by all the parties involved. It is ironic that the blow-out occurred in Norwegian waters, because it is probably fair to say that the authorities and the general public have shown a much greater awareness of safety and pollution problems than in all other North Sea countries, particularly the U.K. This is clear from any reading of the Parliamentary Reports mentioned earlier. There is certainly more scepticism — or possibly less trust — concerning the activities of oil companies in Norway than in the U.K. With hindsight and a few more years of offshore production, it may well be that the Ekofisk blow-out will be seen as an unique aberration, but at the present time it has clearly had a considerable influence on the public attitudes towards oil developments. In that context it is worth mentioning a recent article by four political scientists who interviewed oil policy officials before and after the blow-out.8 Two groups of officials had been identified — the environmentalists (those who ranked `protection of the environment' near the top of the list of nine policy values) and the non-environmentalists who gave priority to other policy values (such as economic growth). Both groups agreed on the immediate consequences of the accident: it would lead to political uproar in Norway, strengthen the forces favouring a `go slow' policy, and result in a lower rate of production. There were marked differences, however, about the long-term consequences. The environmentalists `believed that the accident would have some consequences that would promote Norwegian values' by reducing oil activity and infiational pressures in the economy, thus helping agriculture, protecting the environment and fishing, and preserving traditional Norwegian values. The other group did not foresee such fundamental changes in attitudes and policies. Oil and fishing One related aspect of Norwegian policy is the great attention paid to the interactions between the fishing and offshore oil industries. Worries about possible harmful effects on fish and the fishing

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industry have been another major reason for the delays in licensing blocks in the North. This is in marked contrast to the U.K. experience. Thus Report no. 91 stressed that° `the Continental Shelf north of 62°N. and particularly the banks off Northern Norway are of vital importance to the fishery industry. Therefore all petroleum operations in this area must be arranged so as to minimise inconvenience and damage to fishing.' In an appendix to the same report, the Norwegian Fishermen's Association concluded that `it has always been an absolute prerequisite that the safety problems must be clarified before any form of drilling activity is commenced north of the 62nd parallel. Furthermore it was a prerequisite that the probable effects petroleum operations would have upon employment in the fishery and upon population patterns in the coastal districts should be clarified. The Norwegian Fishermen's Association has received no information from the authorities indicating that these conditions are fulfilled. Therefore, one must mention that the time has not yet arrived for any form of petroleum operations north of the 62nd parallel, and thus not for exploration drilling from either.' There are five main areas of possible conflict: oil pollution, loss of fishermen and vessels, damage to gear from oil-related debris, and loss of access. Pollution has already been dealt with. The loss of fishermen and vessels would arise mainly from the transference to oil-related activities: fishermen could move if they could obtain higher incomes in the oil industry, and vessels could be used as standby safety boats. The statistics in Chapter 5 show that in Southern Norway the loss of fishermen to oil activities has been small, but this may not be the case in the North. Regarding debris, arrangements have been made to compensate fishermen for damaged gear and for loss of fishing time, and these arrangements appear to be working satisfactorily. Loss of access is more difficult, however: this arises because of the existence of safety zones around the platforms, rigs and other installations within which fishermen are not allowed to enter, and similar zones exist in practice (although not necessarily in law) in the vicinity of pipelines, particularly those which are not buried. Loss of access is difficult to quantify because of the movement of fish stocks — although an attempt has been made in Scotland — and, until satisfactory agreements can be reached, the Norwegian Government's response has been to refuse to licence sensitive fishing areas. This is similar to certain areas in the Gulf of Mexico. The significance of these details is that together they represent

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a concerted and serious effort on the part of the authorities to minimise the detrimental effects on the fishing industry, and in cases where problems are unavoidable to ensure that the fishing industry is adequately compensated.10. In some cases this compensation is paid by the oil companies, but generally the Government takes the responsibility, partly on the grounds that it is receiving income from the oil companies for the production licences. This is in marked contrast to policies in the U.K., where fishing interests have been all but ignored by the Government in formulating its oil and gas policies. Mackay and others have shown that, apart from a small debris compensation fund, very little assistance has been given to the industry to overcome problems, and fishing interests have not been taken into account in licensing." The only direct exceptions to this lack of concern are in Orkney and Shetland, where the Flotta and Sullom Voe terminals are located. The two island groups are close to the main oil and gas producing areas in the U.K. sector. Opposition to oil developments there was on a scale and of a nature comparable to that in North Norway, and planning permission was only given when the Government allowed the local authorities to introduce special legislation in Parliament to give them additional controls, and when the oil companies agreed to pay special funds to the local authorities — partly as compensation for disturbance and partly to provide help for local industries, particularly during the period when oil employment begins to fall. In Shetland the fishing and fish processing industries are very important, and there are strong fears of the long-term effect that the oil activities will have. Thus a major proportion of the special funds has been devoted to assisting the industry to overcome short-term problems such as labour shortages in the processing factories.12 In Orkney fishing is less important, but the inshore and shell fishermen have received similar assistance. Fishing is just one example of the authorities' concern. The important point is that the islands have tried to accept the industry on their own terms by using their new planning powers, and it may well be that they provide a good example for local authorities in North and Mid-Norway. In any case, they have certainly provided a good example for other communities on the Scottish mainland, who hitherto have been less successful in their negotiations with central Government and the oil companies.

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NOTES 1. MIRS no. 30 (1973-4), p.69. 2. Distriktenes Utbygginsfond, Instruments of regional development policy. 3. MIRS no. 91 (1975-6) (Petroleum exploration North of 62°N.). 4. Ibid., pp.39-40. 5. For more detail see MFPR no. 25 (1973.4), Ch. 5. 6. MIRS no. 91, p.84. 7. See for example NOU, Bravorapporten. 8. G. M. Bonham et al., A cognitive model of decision-making: application to Norwegian oil policy. 9. Ibid., p.62. 10. For more detail see NOU, Olje- og fiskerinaeringen. 11. G. A. Mackay et al., The conflict between the oil and fishing industries in the North Sea12, See, e.g., J. R. Nicholson, Shetland and oil.

4 DOWNSTREAM PROCESSING Neither do men put new wine into old bottles. (Matt. 9. 17)

The purpose of this chapter is to examine the opportunities for a Norwegian petroleum-based industry arising from the North Sea discoveries and possible discoveries north of 62°N. The chapter opens with a general description of the petrochemical industry and explains why the discoveries on the Norwegian Continental Shelf are so interesting from an industrial point of view. The use of the petroleum from the producing fields of the North Sea is discussed, as well as the disposal of any future discoveries north of 62°N. Finally, the role of various types of petroleum-based industries in a regional planning context is considered. The petroleum-based industries In many ways the production phase is much more important than the exploration and development phases. Firstly, this phase should be of much longer duration than the other two. Secondly, the oil and gas produced is not only important from an energy point of view, but also as a potential raw material for a number of processing industries. It is these industries which are of primary concern in this chapter. The petrochemical industry is the main consumer of petroleum as a raw material as opposed to its use as energy. In spite of this and the fact that the petrochemical industry is extensive and growing, it does not process more than about 5 per cent of the world oil production. The remaining part is used as fuel (80-85 per cent) or as waxes, lubricants, bitumen (asphalt), etc. (10-15 per cent). The growth rate of the industry has been very high since its breakthrough after the Second World War, as shown in the table below: 62

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Table 4.1 OUTPUT OF PETROCHEMICAL PRODUCTS 1950-72 (million tons) 1970 1972 Area 1950 1960 0.1 19.0 23.4 Western Europe 2.3 32.0 3.0 10.4 U.S.A. 29.3 0.3 10.5 12.8 Japan — Rest of World — 0.1 2.2 2.9 Total 3.1 13.1 61.0 71.1 Source: Shell Chemicals, Chemicals Information Handbook 1974-5.

The growth rate has been strong and steady since 1950 with 1972 production about 20 times higher than that of 1950. This growth has been particularly strong in Western Europe and Japan, with an average consumption of petrochemicals of 75 and 130 kg. per person in the 1970s. There is some way to go to reach the U.S. level of 160 kg. per person. There are some doubts as to when, or indeed whether, this level will ever be reached. In recent years there has been a decline in the consumption of most petrochemicals, with falling prices. It is difficult to say whether this is due to an overcapacity on the production side, a reflection of the world economic recession or whether in fact the market in the industrial world is about to become saturated. This is a discussion we shall return to at a later stage. The definition of the petrochemical industry is that it processes hydrocarbons, i.e. the compounds of petroleum. The basis for this industry has been the `surplus' fractions left when producing energy carriers (petrol for cars and aeroplanes, fuel oil, etc.), in refineries. The refineries have generally speaking been designed to yield a maximum output of these products, which in effect has meant that the raw materials for petrochemicals, i.e. mainly naphtha and lighter fractions, have been available there at little or no cost. This situation has been, and still is, characteristic of the Western European countries. These countries have had to import crude oil for their refineries. In the U.S. the situation is different, because the indigenous production of petroleum has in many instances also resulted in large quantities of wet gas becoming available. The wet gas — ethane, propane and butane — has to large extent formed the basis of the U.S. petrochemical industry. With their North Sea oil and gas discoveries, Norway and the

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U.K. are now about to leave the European and embark upon the U.S. tradition of petrochemical production. For both countries this could mean a sharp increase in the opportunities for establishing petrochemical industries. This is particularly true for Norway, whose petrochemical and other petroleum-based industries have thus far been very small. Their size and structure are as follows. Petroleum-based industries in Norway Until 1978, when the Bamble petrochemical complex came on stream, the petroleum-based industry in Norway consisted of three refineries and a small number of plants producing petrochemical bulk, intermediate and consumer products. The refineries are shown in the table below: Table 4.2 REFINERIES IN NORWAY Refinery (owner) Esso (Esso) Shell (Shell) Rafinor (Statoil, Norsk Hydro)

Location Slagentangen, Vestfold Sola, Rogaland Mongstad, Hordaland

Established 1961 1968 1975

Capacity (mill. tons) 5.5 t/y 2.8 t/y 4.0 t/y

The total capacity of the three refineries is 12.3 million tons per year, which exceeds the annual domestic consumption of about 9 million tons. The excess capacity is a potential export possibility, although currently the refineries are producing below capacity because of the difficulties in selling refined products on export markets. The existing petrochemical industry is heavily dominated by three companies: Norsk Hydro, Borregaard and Dyno Industries. Norsk Hydro is the biggest firm in Norway, but only about the 250th biggest in the world. Table 4.3 shows the present structure of the industry. The development of the Norwegian petrochemical industry has been characterised by a limited number of products within the range of bulk petrochemicals for export. The small domestic market has not encouraged the development of a diversified processing industry with a consumer market orientation. In the future this trend is not likely to change. On the contrary, the availability of raw materials and relatively cheap energy could

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Table 4.3 THE NORWEGIAN PETROCHEMICAL INDUSTRY, 1977 Production Capacity Company Product Type 1000 t/y Basic Ammonia 500 Nork Hydro 60 Methanol Norsk Hydro Intermediates Urea 240 Norsk Hydro Formaldehyde Dyno Consumer PVC 70 Norsk Hydro Urea, tenol, melamin formaldeDyno hyde, etc. 250 Borregaard Polyvinylacetate 15 Jotun Group 30 Polyesters Jotun Group 20 Aleydes Jotun Group 7 Latex dispersions 5 Brd. Sunde Polystyrene

mean a concentration on processes involving a considerable input of these two factors into export-orientated products. The industrial use of the North Sea discoveries So far there are three fields — or groups of fields — in the Norwegian sector which are producing, or about to start producing, oil and gas. The `oldest' and most developed is the Ekofisk group, which is characterised by a mixed output of light oil and wet and dry gas. Frigg, on the other hand, is a typical dry gas field, while Statfjord is predominantly an oil field. A permanent transportation system involving pipelines to Britain and West Germany has been decided for the former two, while the decision is still pending for Statfjord. The industrial use of the petroleum landed is described below. Ekofisk. The peak production of the fields in the Ekofisk area is expected to reach about 600,000 barrels of oil per day and about 21 billion Nm3 gas per year. This peak period will occur during 1980-6. The oil and wet gas are piped to Teesside in England and the dry gas to Emden in West Germany. In Teesside the petroleum goes through the reception and separation facilities, and the crude oil enters the transportation system of Phillips Petroleum or is sold. The Norwegian government has the option to buy back the NGL required for a petrochemical industry, and this agreement will begin when the Teesside separation facilities become operative. This NGL was the basis of the establishment of the Bamble

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Norwegian Oil Policies

petrochemical complex. Due to delays at Teesside the Bamble owners (Norsk Hydro, Saga and Statoil) have been forced to buy their feedstocks (i.e. propane mainly, since ethane is not available on the world market) at considerably higher prices. The price difference is supposed to be met by Phillips Petroleum under some sort of agreement with their Norwegian counterparts. It should be mentioned that Norsk Hydro was interested in building a cracker at Teesside in co-operation with ICI, but this idea was not approved by the Norwegian government, and Norsk Hydro backed out. Seemingly this was a wise decision — ICI which went along with similar plants have now cancelled their building programme at Teesside, leaving an £80 million VCM plant half-finished. The processing of the Ekofisk wet gas does not end at Bamble, however. The output of the plants there require further processing before they can reach the consumer markets. The companies involved have had problems finding an outlet for these products. Norsk Hydro, together with Swedish interests, applied for planning permission to build a petrochemical plant in Skelsor, Denmark. This application was met by strong opposition by environmentalists, and the authorities were unable to reach any conclusions as to whether the application should be approved or not. Consequently, Norsk Hydro and the other parties involved withdrew their application. Instead, Norsk Hydro has bought a major share of a petrochemical plant in England. This policy of buying an existing plant has the added advantages of giving easy access to a group of traditional customers while at the same time the total production of petrochemicals is not increased to any degree. Naturally, the existing supplier of feedstocks, which happens to be ICI, is not particularly delighted about Norsk Hydro's move. The dry gas piped to Emden enters the West German gas grid through the Ruhrgas system. The Norwegian government has the right, however, to take out a certain amount of the landed gas in natura and the government therefore recently signed agreements with the Norwegian companies Dyno Industries A/S and Sydvaranger A/S regarding sales of about 400 million Nms per year to each of the companies. Dyno will use the gas as feedstock in a methanol plant currently being built in Delfzijl in the Netherlands, together with Dutch and Swedish interests. Sydvaranger, a North Norwegian mining company, plan to use their gas in an iron ore reduction plant in Emden; this plant has West German interests involved.

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It is also expected that new developments could take place as a basis of the Emden gas. The West German industrial giant, Veba AG, which owns the Deminex oil company, which has applied for concessions in the fourth round of licences, is currently negotiating with the Norwegian government, Norsk Hydro and others on forms of industrial co-operation. It is expected that these negotiations could give rise to a substantial increase in bilateral development programmes, some of the implications of which were discussed in Chapter 2. Frigg. While Ekofisk is wholly situated on the Norwegian Continental Shelf, Frigg is a joint Norwegian (about 60 per cent)British (40 per cent) field. This means that the two countries have to agree about the development plans, and the plans for landing and processing. The gas from this, the biggest dry gas field in the North Sea, is piped to St. Fergus in Scotland, where the methane is sold to the British Gas Corporation, as is mandatory for all dry gas landed in Britain. There have been several plans as to the disposal of the wet gas fractions. The most recent one, which at the time of writing is with the Secretary of State for Scotland for his decision on a public inquiry, is to pipe the fractions overland to Fife. Here the propane and butane would be shipped out as LPG, and the ethane fed into a cracker which forms the first building block of a petrochemical complex. Again, Norsk Hydro and another Norwegian company, Borregaard A/S, together with other Scandinavian firms, have been putting forward plans for the use of some of the gas. In 1973 the company Scanitro, which comprises the above-mentioned firms, submitted a planning application to build an ammonia plant in Peterhead, about 7 km. from the landfall site of St. Fergus. Various local groups raised opposition, including a local whisky distillery and a food processing firm which feared the smell of ammonia could damage their produce, but on the whole the application was favourably received. When it appeared as if the approval would come through, Scanitro suddenly withdrew their application. This time the decision not to go ahead with the development was taken primarily on the basis of market surveys. It appears that the rapid escalation of ammonia production in Eastern Europe and the future threat of Middle East production made Norsk Hydro and associates shelve their plans, at least temporarily. Statfjord. The use of the Statfjord petroleum represents the most interesting case because this is the first time the principle of `land-

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Norwegian Oil Policies

ing in Norway' has been seriously considered. Statfjord is the biggest oilfield in the North Sea but considerable amounts of gas are also present. Three possible transport systems are being considered for the Statfjord petroleum: a pipeline to Sotra (an island west of Bergen), offshore loading, or a combination of offshore loading of the oil and a pipeline for the wet gas. A fourth alternative — piping the hydrocarbons to Scotland — has been ruled out on political grounds (see Chapter 6). The pipeline alternative is the one which has hitherto received most attention. Statoil, using Foster Wheeler (who are responsible for the Sullom Voe terminal) and Cavern Engineering (which consists inter alla of Kvaerner Engineering) as consultants, has produced detailed plans for the terminal at Sotra. Both underground storage and traditional steel tanks have been considered in the layout but there are no official statements as to which are the most favourable. In addition, a committee (the `Sotra Committee') has been studying the possible environmental, economic, regional, social and cultural effects of the terminal since 1975. The Sotra Committee consists of representatives of government (national, regional and local), the developer Statoil, the Oil Directorate and various other bodies. They have sponsored considerable research and consultancy work at outside institutions in the Bergen area. Detailed planning of the terminal and the study of its possible effects have taken place before it has been officially decided whether it would be feasible to lay a pipeline to Sotra. The depth of the Norwegian Trench is the main problem. The Statoil-Mobil group has been obliged to undertake a 300-million-kroner feasibility study, including deep water pipeline repair work. After at least one fatal accident parts of this programme were cancelled, but later tests report that the deep water problem has been solved. Thus there should be no technological reasons for not laying a pipeline to Sotra. There is, however, the economic side. The pipeline is considered immensely expensive but no official estimates are published. A recent report from Norsk Hydro, Statoil and Saga Petrokjemi A.S. concludes that the reserves of the Statfjord field are not sufficient to justify the costs of laying a pipeline, and it is necessary to have an additional discovery of the same magnitude to justify a pipeline. Their reasoning is based on the use of the Statfjord petroleum as a raw material for a petrochemical industry in Norway. The present wet gas reserves are not considered large enough for this: it will give secure supplies for a cracker for only 10-15 years, which is

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too short a time horizon for developments of this nature. An additional find of roughly the same size would extend the life expectancy of the cracker to more than 20 years, which is reckoned to be sufficient. This argument is again related to the main advantage of pipeline transport over offshore loading: it is not possible to load the wet gas fractions directly into tankers by present day offshore loading techniques, so the wet gas must be re-injected or flared, and if there is no wet gas the case for establishing a new petrochemical industry disappears. The pipeline, on the other hand, can take care of high vapour pressure unstabilised oil. Realising the cost advantages of offshore loading compared to piping, the Ministry, the companies involved and various research institutes are currently undertaking a development programme aimed at the offshore loading of high vapour pressure oil. The decision on a permanent transport system will not be taken before the present study will be finished. In the meantime, the Statfjord oil will be transported by offshore loading of tankers and the wet gas re-injected. Anybody looking at a map of the North Sea can see the close proximity of Statfjord to the Brent, Ninian and other fields in the U.K. sector and the pipeline system linking these fields with terminals in Shetland, Orkney and mainland Scotland. One obvious question is therefore — why not use these pipelines to transport the Statfjord petroleum? This is discussed in Chapter 6. Petroleum-based industries north of 62°N. If commercial quantities of petroleum are found off the coast of North or Mid-Norway and piped ashore, the resource capabilities of these parts of Norway will change dramatically. Not only will a completely new type of resource become available, but the quantities will necessarily be very substantial. Constantly escalating development costs, greater water depths, etc., mean that the criteria for a field to be declared commercial north of 62°N. will be more strict than in the North Sea. It is very difficult to estimate a lower limit to the size of a field because the development costs are dependent on a wide range of factors, but there are reasons to believe that the discovery must be in the range of Ekofisk or even Statfjord to be developed. For our purpose here this means that sufficient quantities of petroleum will be available as feedstocks for most types of petrochemical industries. Before attempting to answer which types of petrochemical industry should be established north of 62°N., it is essential first

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to discuss whether any such industry will be built at all. It is quite clear that a number of inherent disadvantages will counteract the industrial development of the region, especially of the northernmost counties. The most important are the remote location from the main markets, and the lack of industrial tradition and of the necessary infrastructure and labour skills. On the other hand, there is a strong and persistent policy, especially in the Labour party, to further the economic development of North Norway and outlying districts elsewhere. The Government has stated more than once that petroleum landed north of 62°N. should be processed there and not shipped out as crude. Therefore, the regions north of 62°N. are in a very strong political position to claim that petroleum-based industries should be established, even if from a company point of view these developments look rather dubious. Which, then, are the likely developments? This question was put to the Society for Industrial and Technical Research (Norwegian abbreviation: SINTEF) at the Technical University of Trondheim by the Study Committee for Petroleum Activities north of 62°N., an inter-ministerial research group headed by the Under Secretary of State at the Ministry of Petroleum and Energy.' The SINTEF study stresses the above-mentioned constraints faced by any petrochemical development in this part of the country, and suggests that most of the petroleum should be shipped out. There are, however, important exceptions. If export markets for refined products improve, there should be some scope for an export-orientated refinery of limited capacity. The most interesting exceptions concern the use of dry and wet gas. Both are difficult and costly to export from, say, the North of Norway, whether in liquefied form or by a pipeline. In the case of dry gas, the means of transport are either as liquefied natural gas (LNG) in specially designed tankers or by pipeline through Sweden to the large markets of West Germany and the Continent. Both alternatives are very expensive, especially the latter, and could only be justified if very large quantities of natural gas are present. In the case of the wet gas, the picture is somewhat more complicated. As mentioned earlier, the wet gas consists mainly of ethane, propane and butane. With regard to the last two, export by liquefied petroleum gas (LPG) tankers is the conventional (although not very common) method of transport today. Thus these fractions could easily be exported but the problem of finding a profitable form of taking care of the ethane remains. There are two factors which bear upon this

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question. First, there are so far no conventional methods of shipping ethane. One should not, however, exclude the possibility that ethane ships could be built and an ethane trade develop in the course of the next 10-20 years. Secondly, ethane is a very valuable feedstock for the petrochemical industry because of its favourable yield of ethylene — which, as mentioned earlier, is a valuable petrochemical intermediate. This suggests that the value of ethane landed in a remote location is greater at the point of landing than at the market place. Consequently, any petrochemical development north of 62°N. is likely to utilise ethane as the prime input. Again the picture needs to be filled with some qualifications. There are obvious disadvantages in making the petrochemical plants dependent upon one feedstock, e.g. ethane. This is even more so if the ethane is coming from one field alone, because development becomes very vulnerable to cut-offs in the supply of ethane. For this reason it is considered wise to build a multifuel cracker, capable of processing traditional commodities like propane. Butane and gas oil/naphtha could also be used, but these feedstocks yield relatively large quantities of by-products and have therefore been ignored.. The size of a cracker is put at c.300,000 tons of ethylene per year. Turning now to the dry natural gas, a similar line of reasoning has been adopted by the SINTEF study group, who have suggested that some of the dry gas should be processed into ammonia and methanol for the export market. The proposed size of the plants are 500,000 and 300,000 tons per year, respectively. It was also suggested that the methanol should be used in the production of single cell proteins, but this option was dropped after more detailed investigation. This leads to the following pattern of development: — the oil exported as crude except for about 4 million tons per year to feed an export-orientated refinery; — the dry gas exported as LNG (or by pipeline through Sweden to Germany), except for a tiny proportion to feed an ammonia and a methanol plant; — the wet gas the heavier fractions like butane and most of the propane are to be exported while the ethane and the rest of the propane is fed into a cracker.

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The SINTEF study deserves a few comments. First of all it is obvious from the study that no thorough analysis of the prices of raw materials or products at the time of marketing has been attempted. Considering the long time-span — a petrochemical industry north of 62°N. would become operative in the 1990s at the earliest — this is not surprising. It does mean, however, that the identification of individual products becomes a rather dubious exercise. It is also doubtful whether the principle applied — that the fractions which are difficult or costly to ship should be processed into more easily transportable bulk chemicals — is valid. There are many signs that the current surplus of such petrochemicals on the world market could become even bigger in the future because of the build-up of processing plants in the oil-producing countries in the Middle East, in the Soviet Union and elsewhere. If so, this will imply even sharper competition for such products on the world market, and lower prices. It is indeed very difficult to see today how this problem could be overcome. The possible alternative for a petrochemical industry in North Norway could be to concentrate upon one type of feedstock and take the hydrocarbons through a train of processes to the stage of consumer products. These could be produced in large quantities, but over a limited range. Furthermore, the SINTEF study deals only with petroleum as a feedstock for a petrochemical industry, and there are a number of alternatives. Perhaps the most interesting is the use of dry gas in the reduction of iron ore, which is present in large quantities in Northern Scandinavia. The Norwegian mining company, A/S Sydvanaranger, have asked for and been granted permission to use some of the Ekofisk gas piped to Emden to reduce their iron ore in a nearby plant. It could be more sensible to take the iron ore through this process near their mines in Northern Norway and avoid the shipment of slag several thousand km., if dry gas becomes available. In addition, the dry gas could be put to use in one of several gas-fired power stations or it could be used in the production of aluminium or other metals with a high power input and in which Norway has much experience. To conclude this section it could be argued that the scope for petroleum-based developments in the North of Norway is slight from a company's commercial point of view. The industry will undoubtedly find it most profitable to export the petroleum as crude. Such a proposition, however, will meet a lot of opposition in North Norway, with its hunger for economic develop-

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ment and new, stable jobs. It will be politically impossible to ignore the demands of seven hundred thousand voters in this respect and some sort of compromise will have to be found. Thus, the petroleum may come to serve the interest of the industry as well as the regional development. Petrochemical industries and regional development The petrochemical industry was described earlier in this chapter. The characterisation of the industry makes it clear that it is not well suited as a means of regional development in a sparsely populated region like North Norway. This is mainly due to the tendency of plants to cluster together in integrated petrochemical complexes which is the common location pattern in Western Europe.2 The new petrochemical complex at Bamble in Telemark country is a good example of the structure of a modest-sized development; the number of employees at the complex is about 700. It is clear that any development of this size could cause widespread effects in North Norway, not all of them beneficial. If, on the other hand, the complex could be split into separate production units and spread in a decentralised pattern, the regional effects could be much more positive. The Government has been aware of this situation, and pointed out the need to decentralise any petrochemical developments. The clearest example of this is found in Parliamentary Report no. 91 (1975-6): ' `From the point of view of regional policies and social economy it is necessary that the activities following in the wake of petroleum explorations are not located in some few places, but are divided up between several locations. However, it will not always be easy to achieve such an objective, because of the technological and economic problems that may ensue from such division and decentralisation. However, it is highly important that such problems should be examined both in respect to which parts of the activities it is technically possible to separate and to the extra costs and problems this may involve.' Very little was known about the possibilities for and effects of splitting up petrochemical complexes, and it was necessary for the Ministry of Petroleum and Energy to call in research institutes to look into the matter. Again SINTEF was asked to contribute, this time in co-operation with the Norwegian Institute of Urban and Regional Research (NIBR). Their conclusions were presented in a joint report published in the autumn of l978 The starting-point of this report is the assumption that a commercial petroleum field is found; that the oil, NGLs and natural

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gas are piped ashore in Northern Norway; and that the aforementioned processing facilities are established. The report states that it is technically possible to spread all the likely developments to separate locations. This degree of decentralisation is, however, considered unrealistic, and a modified pattern is suggested. In this the plants are located in eight different regions. The transport of feedstocks and products between plants is supposed to be by ship. On the basis of various assumptions, the construction and running costs of this pattern is calculated and compared to that of an oil/NGL complex and a natural gasbased complex. The results are shown in Table 4.4 The table shows that the decentralising of the petrochemical complex will increase the construction cost by between 10 per cent and 50 per cent. Although there are wide margins of errors in these figures, the conclusion is very clear: a decentralised petrochemical pattern is very expensive. The very high costs of building the plants makes the decentralising of the industry extremely expensive also in monetary terms. For the plants suggested (excluding the terminals) the construction bill will rise from 8.73 billion kroner to 11.4 billion kroner, or by about 23 per cent. Add to this a 14 per cent increase in the production costs of the petrochemicals and the economic picture becomes even darker.

Table 4.4 CONSTRUCTION AND RUNNING COSTS FOR AN INTEGRATED AND DECENTRALISED PETROCHEMICAL COMPLEX Construction Costs Additional costs Type of Integrated Decentralised of decentralising Activity Product (M. kroner) (M. kroner) 3,500 3,500 Oil/NGL terminal 3,800 30-50 2,800 Refinery 2,000 10-30 1,700 Cracker/ ethylene 1,300 10-30 1,100 Polyethylene 550 650 10-30 Ethylenglycol 500 330 40-60 Acrylnitril Natural gas terminal Ammonia Methanol Proteins

9,500 1,200 650 400

9,500 1,700 900 550

30-50 30-50 30-50

75

Downstream Processing Running Costs Type of Activity/Product Oil/NGL terminal Refinery Cracker/ethylene Polyethylene Ethylenglycol Acrylnitril Natural gas terminal Ammonia Methanol Proteins * Kroner per Nm3.

Additional costs Decentralised of decentralising Integrated (M. kroner) (M. kroner) per ton prod. per ton prod. 750 2,000 3,900 2,600 4,000

800 2,300 4,300 2,800 4,700

5-20 10-30 5-20 5-20 10-30

0.40* 750 700 4,000

0.40* 1,050 1,000 4,800

30-50 30-50 10-30

What, then, are the regional consequences of the two alternatives? Can the extra costs be offset by the economic and social gains if the plants are located in separate regions? The regional effects of any given establishment is often measured in terms of temporary construction and permanent employment creation. It is quite obvious that the construction phase will need a very substantial workforce since each of the bigger plants requires a peak workforce of up to 3,000 men. Altogether the peak construction workforce is estimated to be 11,000-12,000 if the plants are built simultaneously (which, however, is not likely). To put this figure in perspective it could be compared to the total construction labour force in North Norway, which in 1976 was about 14,000 men, scattered over a distance of more than 1,500 km. Traditionally construction work is carried out by migrant or semi-migrant labour, and the figures suggest a need to import very large amounts of labour from other areas of Norway and perhaps abroad. They also underline the importance of building the plants in as many locations as practically possible, and to extend the construction period by building one or possibly two plants at a time. Regardless of the measures taken, the construction period could mean a drastic increase in the level of activities in the areas affected. The period is, however, short, possibly not extending over more than four to five years at the most. The operational phase is different in this respect. The number of people employed is considerably smaller but the phase itself is normally a great deal longer. Most of the permanent changes in the eco-

Ch

Alternative A (2 regions) Type of petroleum- Total employ based industry 500 GAS Terminal 150 Ammonia 100 Methanol 100 Proteins

External rec.

Local rec.

570

280

(75)

500

250

(70)

450 360

(50)

180 200 100 120

OIL

Terminal Refinery

4501 300

NGL

Cracker Polyethylene Ethylenglycol Acrylnitril

150 200 100 100

420

2,150

1,490

Total

Alternative B (8 regions) (of which External after Total Local training) employ. rec. rec. 300 200 (50) 500 140 40 (10) 180 120 90 30 (10) 120 30 (10) 90

(of which after training)

130 660

(195)

2,330

280 270

170 90

(35) (35)

365

115

(50)

85

35

(10)

1,620

710

(210)

samod no uvräanuoN

Table 4.5 EMPLOYMENT CREATION AND LOCAL RECRUITMENT IF PETROLEUM-BASED INDUSTRIES ARE LOCATED IN TWO REGIONS (A) AND EIGHT (B)

Downstream Processing

77

nomic structure of the affected communities will take place during this period. There are therefore, strong cases for decentralising the developments, first because the problems of integrating a new very large complex of plants could be avoided, and secondly because a smaller number of new jobs could be distributed to a greater number of communities in need of new employment opportunities. Besides these two main points, the NIBR/SINTEF report also suggests a number of other advantages, such as an increase in the total number of jobs, a greater multiplier effect, a reduced risk of establishing new `single-industry towns' and more flexibility in the locations of plants. One crucial question related to regional development is the number of jobs likely to be taken by local people. The report goes into this in some depth. On the basis of various assumptions regarding the education and skills required and their availability, the share of local employment is calculated in Table 4.5. The table also shows the number of jobs related to each development. The higher employment figures in the column for the decentralised pattern is due to an estimated increase of 20 per cent in labour demand when one plant is separated from the upstream one. The alternatives represent a move from plants located in two separate regions (A) to eight (B). The table shows that of the estimated 2,150 jobs created, only 660 (or 30 per cent) are expected to go to locals if the plants are located in two regions. The same percentage of local recruitment will occur if the plants are located in eight regions, although the number of jobs in this case is slightly higher. These figures are based on a recruitment pattern involving local recruitment of all unskilled workers (who, as mentioned earlier, are very few), 20 per cent of the skilled workers and none of the jobs requiring higher qualifications. The report concludes that training programmes must be made available to local people if the local recruitment share is to be increased. Thus, if 40 per cent of the skilled workers could be recruited locally this would increase the overall share of local recruitment to 40 per cent, bringing the figure up to the national average for developments of this type. NOTES 1. SINTEF Foredlingsmuligheter av ilandfört olje og gass nord for 62°N. — tekniske forstudier. 2. See K. Chapman, North Sea oil and gas. 3. P.74. 4. NIBR-SINTEF, Foredlingsmuligheter og regionale konsekvenser ved petroleumsfunn nord for 26° N.

5 EMPLOYMENT CREATION Every man's work shall be made manifest. (I Corinthians 3.13) When new industrial developments occur, initial interest is usually concentrated on the employment implications, because these are of direct concern to those involved. Thus, when a company announces plans for a new factory, the main interest is in the number of new jobs it will create rather than the investment required or the likely future output; similarly, when a factory is closed, the main issue is the unemployment it will create. In other words, employment or unemployment are widely regarded as the key economic indicators. This is also true of the North Sea developments. A great deal has been written and spoken about the level of employment created by the offshore oil and gas industry and the issues which this has raised. The purpose of this chapter is to examine this aspect in more detail. First, however, it is necessary to put the whole question of employment in its proper perspective because the oil and gas developments have very unusual implications and are very different from other industrial developments. It should be clear from the earlier chapters that the major benefits of the oil and gas discoveries will be the increases in government revenue and company profits and the effects on the balance of payments. An outstanding feature of the oil industry is the substantial difference between production costs and selling prices — in other words, the industry generates a very high surplus value and much of the debate about North Sea oil has concentrated on the distribution of this surplus or added value. In this respect the oil industry is very different from most other Norwegian industries, for which selling prices are much closer to production costs. The main reason for the vast disparity is the success which OPEC had in 1973/4 in forcing up the price of crude oil, at that time from about $3 per barrel to $12 per barrel. This latter level then became the world market price for crude oil because OPEC 78

Employment Creation

79

controlled a very large proportion of oil sold on the world market and because, at least in the short run, it has proved impossible to find alternative sources of energy to replace crude oil to the extent that its price would fall. There is, of course, no reason why Norwegian oil should be sold at this price — which has now risen to about $14 or 75 kroner per barrel — because Statoil, for example, could easily sell it at a lower price. This would be economic nonsense,l however, and in any case the volume of Norwegian oil, or indeed all North Sea oil, is not sufficiently large to influence the market, although in 1978 there was evidence that the increased production of oil and gas from the North Sea slowed down the rate of increase in the price of oil, as some of the OPEC countries had difficulty in selling all their domestic crude oil production. The effect is small, however, and can be ignored in the present context, particularly as åemand conditions have improved sharply in 1979, partly as a result of the revolution in Iran. The main point is that Norwegian oil will be sold at the world market price, currently around 75 kroner per barrel. The cost of producing a barrel of oil from Norwegian fields does not enter into the equation, although this cost is much higher than the production costs of Middle East oil. At the time of writing the average cost of producing a barrel of oil in the Middle East is around 5 kroner. If it is sold in Western Europe or North America, transport costs increase this to about 20 kroner. In comparison, Ekofisk oil costs around 30 kroner per barrel, made up of a capital cost of 25 kroner and an operating cost of 5 kroner. Transport costs to markets in Western Europe or North America will be correspondingly smaller, probably adding no more than 5 kroner on average to the price. Thus the total cost of extracting, producing and transporting Ekofisk oil is approximately 35 kroner per barrel. On current selling prices this still leaves the considerable margin or surplus value of 40 kroner per barrel, which will be shared between the Government and the oil companies. Regarding employment, the crucial factor is that the number of jobs created is not related to selling price but to the production and operating costs. The latter determines the level of investment required and hence the level of employment. Thus it is the 30 kroner per barrel (disregarding transport costs) which sets the level of employment. In other words, the employment effect is 30/75 — or about half — of what it would be in other Norwegian industries. An investment of 1,000 million kroner

80

Norwegian Oil Policies

in the shipbuilding or aluminium industries, for example, will create about 1,000 permanent jobs, but in the offshore oil and gas industries, 500 jobs at most. This is not because it is a capitalintensive industry (although it is, and probably even more so than aluminium or shipbuilding), but because of this great difference between costs and the price of oil (and gas). In Norway there is an added complication. The cost figure of 30 kroner per barrel is the total cost and makes no allowance for imports. To the extent that equipment, materials and services required for the North Sea fields are imported, then the direct impact on the Norwegian economy and on employment will be correspondingly lower. These goods and services will be produced in other countries, and the employment created there. As is well known, the share of imports for the Norwegian oil developments has been very high and consequently the number of jobs created in Norway has been much lower than it could have been — and has been in Britain for example. The issue of the level of imports is a very important one and is considered in more detail in Chapter 2. This chapter deals later with a related problem — the number of foreign workers employed in the oil industry, which in effect reduces even further the level of employment created for Norwegians. This argument may seem rather convoluted but it is a crucial one for Norway and it is necessary to understand this basic economic difference between the oil industry and almost every other industry or economic activity. The overriding implication of this difference is that employment in oil-related activities is much less important than it would normally be. In other words, the direct benefits from the North Sea developments — these being the increases in employment and wages — are less important than the indirect benefits — these being the increases in government revenue through royalties and taxation, the increase in company profits and the savings on the balance of payments. Chapter 7 looks at some of these indirect benefits in more detail. Having said that, this does not mean that employment creation can be ignored. It is still important in the Norwegian context, particularly for the communities on the West Coast which have been most involved in the industry up to now. It may be useful to bear in mind the position in Scotland, where the level of unemployment is much higher than in Norway, and where there have been attempts to use the North Sea developments to increase the level of employment in order to offset redundancies in the older, traditional industries such as coalmining, shipbuilding and

Employment Creation

81

fishing. These attempts have not been very successful, however, mainly because of the same disparity between direct and indirect effects as is evident in Norway, and because the relatively small contribution of the North Sea developments to employment has become an important political issue in the debate in Scotland about devolution and independence.' The present position In Norway, the present level of oil-related employment is approximately 31,500. This figure is taken from the main statistical source, namely the twice-yearly surveys undertaken by the Labour Directorate.3 These surveys have been undertaken every January and August since August 1973 and the totals are given in Table 5.1. Table 5.1 OIL AND GAS EMPLOYMENT 1973 August 1974 January August 1975 January August 1976 January August 1977 January August 1978 January August 1979 January* August*

6,600 12,100 16,200 21,600 21,700 25,100 25,100 26,100 27,600 29,100 29,100 31,300 31,500

* forecasts

The total Norwegian labour force is around 1,700,000, so direct oil-related employment represents only about 1.8 per cent. If we take only employment in the category `mining, quarrying and manufacturing', the oil component represents about 6.5 per cent of the total 400,000 employed. Here it should be remembered that not all jobs in the oil industry can be classified as manufacturing and the manufacturing jobs probably account for about 3 per cent of total manufacturing employment. By comparison with the 31,500 employed in the oil industry, the fishing industry accounts for 18,000, food manufacturing 45,000 and shipbuilding 50,000. In Scotland, the offshore oil industry accounts for about 60,000 jobs, although the definition of employment there is slightly different from that in Norway. Also, it is im-

82

Norwegian Oil Policies

portant to remember that there are multiplier effects creating additional employment in the service industries, and using a multiplier of 1.5 would give total direct employment of about 40,000 in Norway. This is the gross increase, however, and to the extent that jobs are lost in other industries, the net figure will be correspondingly lower — probably no more than 30,000 although it is impossible to know exactly. Table 5.2 breaks down the employment into the five categories used by the Labour Directorate, namely: (1) exploration, drilling, production (i.e. offshore employment); (2) supply bases, transport, catering and administration; (3) building of steel platforms, modules and supply boats; (4) building of concrete platforms; (5) building and operation of (new) refineries and petrochemical plants. This table is helpful because it allows us to see how the various components of the industry have changed over time. Some forecasts of future employment are given later in this chapter, on the basis of different trends for the various categories of employment. It is clear from Table 5.2 that at the time of writing the major activity is the construction of decks, modules and other equipment for rigs and platforms, accounting for 40 per cent of total employment. This has been the dominant category since 1973, but since 1975 the level of employment has been static and, as discussed below, it is likely to fall significantly in the near future. In contrast, three of the other four categories have shown steady growth over almost the whole period, the only exceptions being a fall in employment in category 1 from August 1975 - January 1976 and a similar fall in category 5 from January - August 1975. It may be useful to describe these categories in some more detail, given that to a large extent they represent a new form of activity in Norway. In fact the concept of the `oil industry' as one industry is unusual, given the wide spread of its activities, and the Labour Directorate had to devise a new classification for its surveys. Category 1 comprises people employed on the rigs and platforms. This covers all firms registered in Norway which are working offshore in the Norwegian sector. Thus employment on Norwegian rigs in the British sector is included, which has been important in the last few years, with an average of four Norwegian rigs operating in the U.K. sector compared with five in the Norwegian sector. The pattern of exploration activity in Norwegian waters was described in Chapter 1. Regarding pro-

1. Offshore 2. Supply bases 3. Steel platforms, boats 4. Concrete platforms 5. Refineries, petrochemical plants Total

Aug. 1973 1,249 900

Jan. 1974 1,801 1,378

Aug. 1974 2,621 2,051

Jan. 1975 3,524 2,360

Aug. 1975 3,975 3,353

Jan. 1976 3,316 4,587

Aug. 1976 4,369 4,548

Jan. 1977 4,093 5,365

Aug. 1977 5,109 6,723

3,509 149

6,454 888

7,616 2,008

10,691 2,974

9,457 3,321

10,710 3,763

10,310 1,584

10,717 1,129

9,000 1,183

800

1,550

1,886

2,096

1,566

2,563

4,269

4,566

5,152

6,607

12,071

16,182

21,645

21,672

24,939

25,080

25,870

27,167

uorlvard Juaudotdurg

Table 5.2 EMPLOYMENT BY CATEGORY

Co

84

Norwegian Oil Policies

duction facilities, at the time of writing these consist of the Ekofisk complex, the Frigg platforms and the Statfjord A platform, and the figures include both production and drilling crews. Category 2 is self-explanatory and its main function is to provide the back-up services needed for the various offshore operations. The main components of category 3 have been the construction of mobile drilling rigs by the Aker group and other shipbuilders, and supply ships. At the time of writing Norwegian firms own or partly own approximately 55 rigs and 130 supply ships, although not all of these are operating in the North Sea. Aker's involvement in rig construction has been a tremendous achievement, although the recent reduction in demand for rigs has created problems similar with those facing the shipbuilding industry because of the excess tanker capacity throughout the world. Category 4 consists of those involved in the construction of Condeep production platforms and the Frigg CPI platform built at Andalsnes. Finally, category 5 covers mainly those employed in the construction and operation of the Mongstad refinery and the Bamble petrochemical complex. Regional distribution Another important feature of this employment is its regional distribution within the country. Economic activity and hence employment are not spread uniformly over the whole of Norway. The oil industry has its own peculiar locational characteristics and consequently the geographical distribution of oil-related employment is very different from the national distribution of population and employment. This can be seen from Table 5.3 which sets out the distribution in August 1977 by county and and category. The outstanding features are the 44 per cent share in Rogaland, 18 per cent in Telemark, 15 per cent in Hordaland and 11 per cent in Oslo/Akerhus. Together these five counties account for 87 per cent of all oil-related employment, and employment elsewhere is almost negligible. In comparison, in 1970 — before oil — the five counties accounted for less than 40 per cent of all employed persons in Norway. There is no need to explain in great detail this marked geographical concentration of activity and employment because the locational pattern is obvious and almost as one would expect. The main areas affected are those closest to the oil and gas fields, and Stavanger has established itself as the main operational and service base in Norway for offshore operations. The industry is one in which transport costs are an important influence on loca-

Employment Creation

85

Table 53 REGIONAL DISTRIBUTION BY CATEGORY, AUGUST 1977 Category % of County 2 5 1 3,4 Total total Ostf old — 14 — 14 0.1 Oslo /Akerhus 555 770 1,430 115 2,870 10.6 Hedmark 20 20 0.1 — — Oppland 27 27 0.1 — Buskerud Vestfold Telemark Aust-Agder Vest-Agder Rogaland Hordaland Sogn og Fjordane More og Romsdal Sor-Trondelag Nor-Trondelag Nordland Troms Finnmark Total

116 12

234

56 61 286 414 221

3,901 233

4,172 914

3,625 2,510

218 11,916 300 3,957

262

337

599

235 — 1 135

203 801 138 40

112

160 — 5 15 5,109

6,723 10,183

4,519

— — — —

56 173 4,805 530 467

0.2 0.6 17.7 2.0 1.7 43.9 14.6 0.0 2.2

598 801 144 190

5,152 27,167

22 3.0 03 0.7 0.0 100.0

Note: Categories 3 and 4 were combined in the August 1977 survey. tional decisions, and therefore there has been a strong tendency for firms to set up their plants on the south-west coast in locations with suitable infrastructure and labour pools. Regarding the former, a good harbour and airport (for both fixed-wing and helicopter services) have been essential and this explains Stavanger's dominance. Similarly, in Scotland the growth of Aberdeen rather than Dundee as the main centre is in part attributable to the latter's lack of a proper airport. The regional differences are more marked in Scotland because Glasgow and the Strathclyde region, which together account for some 80 per cent of the Scottish unemployed, have only 15 per cent of oil-related employment. Another outstanding feature of the oil industry is its tendency to congregate. Individuals and individual companies in the industry have a strong preference to locate close to their colleagues and even their competitors. The creation of external economies such as a common specialised infrastructure or a

86

Norwegian Oil Policies

pool of skilled labour is obviously one factor in this, but psychological factors also seem very important. Possibly it is a continuation of the necessary practices adopted by the American companies who pioneered oil exploration and production in the desert areas of the Middle East. In any case, once a town or city like Stavanger or Aberdeen has been chosen by the major oil companies, other companies follow suit and a sizeable industrial complex is established. Over time this reinforces the industry's preference to congregate in one or two locations. Houston, Texas, is the best example. Nevertheless, the distribution of oil employment in Norway is more widely spread than in Scotland. Probably the main reason for this is that there were capacity constraints in the early years. For example, the success of the Aker H-3 rig was so great in 1973 that Aker themselves were unable to fulfil all their orders, and they sub-contracted rig orders — either in whole or in part — to other shipbuilding yards in Norway and abroad. This explains, for example, the high shares of employment gained by Aust-Agder and Nord-Trondelag. Also, it is important to remember that the Labour Directorate figures include downstream activities and certain suppliers of goods for oil companies, so the coverage is probably more comprehensive than in Scotland. Furthermore, Stenstadvold, with reference to the investment goods sector (categories 3, 4) has claimed: 4 It is thus fair to say that the firms which acquired orders from the oil industry to a considerable extent followed the general suggestions of a balanced and relatively scattered regional distribution of the job opportunities of oil. It is natural to mention the Aker group because of its leading position but other companies have also followed this pattern.' Nevertheless, overall the pattern is highly concentrated, with Rogaland (Stavanger) the main operational centre, Hordaland (Bergen) the second centre (mainly through its involvement in platform construction) and Oslo/Akerhus the third centre (because of its role as the national administrative and service centre). A corollary of this is that although the total number of jobs is only a small proportion of national employment, in the areas most affected the oil industry has become a major employer, generating both substantial costs and benefits. On the benefits side, there has been the creation of significant numbers of jobs in counties where unemployment was relatively high and there was a higher-than-average level of out-migration, presumably in part because of poor employment opportunities. Consequently

Employment Creation

87

in Rogaland, for example, there has been a sharp increase in population, employment and incomes. There are also costs, however. These include the great pressures put on housing, schools and other public services by the rapid advent of a large labour force. Housing shortages lead to higher prices which in turn will generate a range of social problems. In Shetland (Scotland), for example, there has been a great concern about the increase in crime, drunkenness and prostitution attributed to the construction of the Sullom Voe terminal.° Although there is much less evidence of these problems in the West Coast counties in Norway, they have undoubtedly occurred to some extent, but a discussion of them in this chapter would be out of place.° There are employment costs, however, which can be discussed. Over the period 1972-4, when industry was recruiting most of its labour, the national labour market was very tight. In 1972 unemployment averaged only 1.0 per cent in 1973 0.8 per cent and in 1974 1.1 per cent. Thus any new demand for labour had to be met largely by recruitment from other industries or by existing firms reorganising their activities to diversify into oil-related work. Recruitment patterns One of the main fears of many communities has been that their traditional industries, particularly fishing and agriculture, will lose labour to such an extent that their future prospects will be badly and permanently damaged. As discussed in Chapter 3, this has been one of the major issues in the North Norway debate, as it has also been in Scotland, particularly in Shetland. Assessing the likely impact of future developments is always a difficult task and usually has to depend to a large extent on previous experience. In this context, although a good deal of work has been done on the recruitment of labour to the industry,' it has not been done in a co-ordinated way and it is almost impossible to draw conclusions from the studies which could be applied to North Norway and other parts of the country. Experience in Shetland and the North of Scotland may be probably a better guide than other Norwegian experience. The main studies done in Norway are those by the Institute of Industrial Economics (IØI) in Bergen.° From these studies, to the extent that general conclusions can be drawn, it appears that the fears described above are not really justified on the evidence to date. The main source of historical data is the Labour Directorate. Recognising the need for better information, in addition

88

Norwegian Oil Policies

to their twice-yearly surveys of employment, the Directorate in 1974 undertook a recruitment survey which covered nearly 3,300 of the c. 18,000 people then employed in the oil industry. The survey covered the major onshore developments, including the Andalsnes and Stavanger concrete platform sites, rig fabrication at Verdal and refinery construction at Mongstad. Of the 3,300 employees only 3.1 per cent had come from agriculture and forestry and only 1 per cent from the fishing industry. The main recruitment sources were building and construction (28.7 per cent), mining and manufacturing (24.4 per cent) and people not gainfully employed (19.4 per cent). The last figure includes the unemployed. The high proportions coming from the construction and manufacturing industries is in part explained by the fact that long-distance commuting, on either a daily or weekly basis, was very common, thus increasing the geographical area from which the companies concerned could find the skills required. Nearly 35 per cent of all employees lived more than 50 km. from the place of work and over 28 per cent more than 100 km. The construction industry in Norway has always had a strong tradition of long-distance commuting, for example for the hydroelectric schemes in the 1950s and 1960s, and it appears that many of the major oil developments such as concrete platform construction are regarded simply as large construction developments with normal recruitment requirements. Here a crucial factor is the permanence of the development concerned. There is plenty of evidence to suggest that over time people are more willing to move their homes closer to their place of work. The recruitment survey showed that in 1972 42.5 per cent lived within 25 km.; by 1974 this proportion had risen to 61.3 per cent. If oil developments are believed to be shortterm, therefore, the inclination to move home will be considerably less and despite earlier beliefs, it is very clear now that activities such as rig and platform construction can only be temporary, short-term activities. This is not to deny that in individual communities the recruitment of labour from local firms is not or will not be a problem. In advance, however, it is impossible to make firm predictions. In any case it is important to remember that the Labour Directorate survey summarised above was based on a sample of only 3,300 employees and excluded a high proportion of non-construction activities.

Employment Creation

89

Foreign labour Another interesting aspect of employment creation is the high involvement of foreign labour. Foreign involvement of all types is a very noticeable feature of Norwegian oil developments and has been mentioned regularly throughout this book. The scale of this involvement is probably best seen from the employment statistics, which can be taken as a good proxy for a wide range of economic activities. Statistics are available from the Labour Directorate's twiceyearly surveys. Table 5.4 below shows the number and proportionate involvement of foreign labour of the period 1973-8. Table 5.4 FOREIGN LABOUR INVOLVEMENT Proportion of Total No. of Employment foreigners foreigners 1973 August 1974 January August 1975 January August 1976 January August 1977 January August 1978 January August

6,607 12,071 16,182 21,654 21,672 24,939 25,080 25,870 27,167 25,975 29,149

826 1,517 1,992 4,552 2,582 3,369 4,278 4,905 5,745 4,509 5,732

125 12.6 12.3 21.0 11.9 13.5 17.1 19.0 21.2 17.4 19.7

The proportion of foreigners has increased fairly steadily over the whole period, from 12.5 per cent in 1973 to 21 per cent in 1977. The figures for 1978 imply a fall to around 18 per cent but it remains to be seen whether or not this will continue. Over the period 1973-7 the average proportion of foreign workers was 16.4 per cent. At the time of writing, almost all these foreigners are working at the Bamble petrochemical complex in Telemark (1,000) or are based in Rogaland (4,600). Most of the latter are working offshore, principally on the Frigg and Ekofisk platforms. The involvement of foreign workers in the British and Dutch sectors of the North Sea is approximately 8 per cent and 12 per cent respectively. In the Norwegian labour market as a whole foreign workers account for less than 2 per cent of total employment, which shows how unusual the oil industry is in this respect. The issue of whether or not these numbers are unacceptably

90

Norwegian Oil Policies

high is really a value judgement because there are factors both for and against. It can be argued, for example, following on the discussion in the preceding part of this chapter, that to use foreign labour minimises the detrimental effects on the Norwegian labour market. Alternatively, the use of foreign labour prevents Norwegians from taking up employment in the industry. Regarding the latter, it is probably true that on the whole foreign workers — particularly Americans — tend to take the more skilled and well-paid jobs. In our opinion, domestic involvement in the industry has been disappointingly low hitherto. Given the obvious preference of foreign companies for foreign labour (particularly those who have worked for the companies concerned for many years), this also means that the level of foreign labour has been too high. It seems to us that the arguments in favour of using foreign companies and foreign labour are basically short-term, i.e. to avoid sudden dislocations in national or local labour markets. In the long run, however, if Norwegian labour is to acquire the skills of the industry, it must become involved at all levels and all stages, possibly with a view to using those skills in other offshore areas, just as the Americans do throughout the world. There may also be peak construction periods when it is sensible to use imported labour as a very short-term measure. Having said that, it is important to remember that Norway traditionally has had very little experience of foreign labour, with the exception of people from the other Nordic countries and foreign seamen working on Norwegian ships. Norden — i.e. all the Nordic countries including Finland and Iceland — is an open labour market. With that exception, Norway's location, climate and language probably account for the low level of inmigration. Despite the tight domestic labour market conditions, large-scale in-migration has not been seen as a desirable solution, presumably largely because of the anticipated problems of social integration, housing, etc., which have occurred in other countries in Western Europe. It may be coincidental, but it certainly is the case, that since the advent of the oil discoveries, in-migration regulations have been stringent° and enforced more rigorously. Nevertheless, as the figures in Table 5.4 suggest, the oil companies appear to have been able to circumvent these regulations by gaining dispensations, usually in the form of group work permits. One undesirable aspect of this came to light in December 1973 when it was discovered that Turkish and Pakistani welders employed

Employment Creation

91

by an American firm at the Mongstad refinery were being paid an average of 7 kroner per hour to do the same work for which Norwegian welders were being paid 40-50 kroner. Similar allegations about the exploitation of some foreign workers have also been made regarding the rig and platform yards and the pipelaying barges. This problem does not appear to have been solved, although it is very difficult to obtain accurate information on the current nature and extent of the difficulties. One side-effect of the Ekofisk Bravo blow-out, however, was the revelation that the regulation of working hours and conditions, particularly of foreign workers, was still far from adequate, and this is an aspect which the government is actively investigating. Of course, it is not a problem confined to Norway, and the International Labour Office is trying to establish codes of practice which could be implemented internationally. It would be encouraging if Norway, with experience of these problems but on a much smaller scale than other countries, could give the lead in the implementation of appropriate legislation on the working hours and conditions of foreign labour. Future trends In looking at possible future trends, it is better to use a different classification than that used by the Labour Directorate. The industry can be divided into three main phases — exploration, development and production — and it is possible to identify a fairly general temporal relationship between the various phases. By definition, exploration activity has to precede the other phases; following the discovery of a commercial oil or gas find, the development phase (i.e. the construction and fabrication of the production facilities required) will last for three to seven years; and finally the production phase will last for a period of up to thirty years. Inevitably, phases will overlap as new discoveries are made, but the overall pattern should be reasonably clear. In the table below we have produced some tentative forecasts of future oil-related employment, according to these three phases. The many problems inherent in forecasting exercises of this type should not be forgotten but on present information we think that Table 5.5 gives a reasonable view of likely future trends. Taking the three phases separately, the level of exploration activity is largely a political decision, as discussed in Chapter 3. Present evidence suggests that exploration drilling will be fairly constant

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in the period up to 1983, if North Norway is included, but thereafter we expect it to fall quite steadily. In the main this is based on the assumption that by then the best areas will have been explored and we shall be testing the second and third rate prospects. If so, the discovery rate of new fields should fall significantly, either in terms of number or size, which would in turn reduce the interest in exploration drilling. In any case, the direct employment creation of this phase is not great, as the table shows. Taking the third and final phase next, it is important to remember that this is also a capital-intensive activity which creates relatively few jobs. Virtually all the employment in this category in the 1980s will be related to the Ekofisk, Frigg and Statfjord fields and associated onshore activities, but we have assumed that there will be other commercial discoveries such that production employment will increase, albeit fairly slowly, to around 9,000 by 1989. Table 5.5 EMPLOYMENT FORECASTS (AUGUST OF EACH YEAR) Exploration Development Production Total 1978 4,000 20,800 1,800 26,600 1979 2,000 26,000 4,000 20,000 1980 20,300 28,000 4,500 2,800 1981 5,200 23,300 3,500 32,000 1982 5,200 22,800 4,000 32,000 1983 5,200 4,300 20,500 30,000 1984 5,200 17,300 4,500 27,000 1985 4,500 14,500 5,000 24,000 1986 4,000 11,500 5,500 21,000 1987 3,000 10,000 6,000 19,000 1988 8,000 2,500 6,500 17,000 1989 7,000 2,000 7,000 16,000 In terms of employment creation, the most important phase is the development phase and in particular the construction of platforms, refineries and petrochemical plants. The current problems of the platform industry are well known, and it is now unlikely that we shall ever again experience a period of high activity such as we had in the early 1970s. Also, with the construction of the Mongstad refinery and the Bamble petrochemical complex, the future need for new processing facilities will be fairly small. The main exception to this generalisation is undoubtedly the possibility of locating similar facilities in Mid- or North Norway, if there are commercial offshore discoveries

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there. If this happened it would create another peak or bump in the development curve shown in the table, similar to the 1978 and 1982 peaks. Apart from that, however, the underlying trend in this phase must be downwards, given that most of the Ekofisk and Frigg facilities are completed and that by the mid- or early 1980s Statfjord should be in a similar position. Putting the three phases together gives the final column shown in Table 5.5. This suggests that there will be a slight fall in employment from the August 1977 peak but that there will be another higher peak, possibly reaching 35,000 (around 1980-1) before a slow but steady decline sets in. By the end of the 1980s total employment will probably be less than 20,000, of which production will by then account for the greatest share, unless there are major discoveries in the north. This may seem a pessimistic view, but is borne out to a considerable extent by experience in Britain. In Scotland, for example, employment has already begun to fall, mainly because of the closure of concrete and steel platform yards. The recent Aberdeen University report for the Scottish Office forecast that employment will fall from its 1977 peak of 50,000 to around 35,000 by 1985.10 In Scotland the rate of decline will probably be much sharper than in Norway, because of the British government's present policy of rapid exploration and development, which has meant that most of the oil and gas fields have been developed in two large groups, thus producing a very cyclical pattern of activity and employment. By 1980, around twenty oilfields will be producing in the British sector. The effect of these differences will mean that the decline in employment in Norway will come at a later date and at a slower rate, but a decline is inevitable. Finally, it should be pointed out that the estimates in Table 5.5 are aggregate ones for the whole of Norway. Because different parts of the country are involved to different extents in the various phases, the pattern for individual areas could be very different. In particular, those areas specialising in development work — e.g. rig and platform construction — will be much more adversely affected than those specialising in exploration or production work. Verdal, Åndalsnes and Sandnessjøen are already clear examples of that. Government policy So far this chapter has been concerned largely with what has happened and why. By way of conclusion, it may be worthwhile

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considering if the pattern that has emerged has been in the best interests of Norway and, if not, what the government and other responsible authorities could do or could have done to have brought about a different sequence of events. This final section therefore deals with the four policy issues which we think are most important: the level of employment, its geographical distribution, environmental legislation and the role of foreign workers. The obvious first question is: Is the total level of employment too high or too low? Here it is essential to bear in mind some of the points made in the introductory part of this chapter, mainly that the oil industry is a capital-intensive industry with relatively low labour requirements and that the direct effects are much less important than the indirect effects. It is also necessary to recognise that there is an inevitable conflict between a desire to maintain production at a relatively low level and the need to create or preserve employment, either at a national or regional level. Given the vast disparity between the direct and indirect effects, however, the objective of creating or maintaining employment can probably be better achieved by the spending of government oil revenues rather than the stepping-up of oil exploration and production. Hence the level of direct oil employment is not really the important question it may appear to be on the surface. This is not to say that what has actually happened has been the best outcome. Our own interpretation of the statistics presented above is that the oil jobs have on the whole been welcome, by providing a healthy diversification of employment in the areas affected and by providing a check to the steady drift of employment and population to the Oslo area. Given the problems currently being experienced by the fishing and shipbuilding industries in particular, without oil jobs some of the counties in the west would probably have had unacceptably high levels of unemployment or emigration. There have been problems caused by oil employment but not on the scale experienced in Shetland and elsewhere in Scotland. Also, the worst problems have been a consequence of the fluctuations in the labour force, for example by the noncontinuity of Condeep orders. What this experience should teach us is that it is a mistake for communities to welcome with open arms all types of oil-related activity. Although some parts of the industry — exploration and production in particular — appear to have a lengthy lifespan — others, mainly the development phase which concludes the construction of production platforms and

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rigs — are inevitably short-term. Many of the problems that have occurred therefore could have been avoided if there had been a more stable level of employment and onshore activity, and it is here that government action has been missing. The blame also probably falls on the communities which were too eager to attract temporary activities like platform construction and also on the companies like Aker and Norwegian Contractors whose assessment of the market has proved inaccurate. Clearly, what is required is more thorough analysis of the type of employment generated and the long-term prospects. It may be salutary to remember that opinion in Scotland of this aspect has changed radically. For example, regarding the construction of production platforms, British policy up till now has been to build as many as possible in domestic yards. There is now a strong move, however, to close certain platform yards and to have a much smaller but stable industry and to meet unusual requirements by importing platforms from Norway and other countries.11 To the extent that this problem could occur in Norway, there is no reason why imports from Scottish yards could not be used to even out fluctuations. Looking to the future, there are strong factors in favour of a modest increase in employment. Table 5.5 suggests that without government intervention employment in the industry will fall steadily over the next decade. If there is a shift of activity north of 62°N., some of the West Coast counties are likely to have serious problems. National employment prospects are not as good as they have been over the past decade, and it is probably reasonable to conclude that the era of full employment is over. For example, the recent Parliamentary report on the long-term programme 1978-81 stated: 12 `During the 1960s and the early 1970s it was not so difficult to reach full employment. Since the last international economic recession the situation has changed. It is now estimated that most of our most important trading partners will have continuing high unemployment in the years ahead. This will mean it will be more demanding than previously to achieve full employment in Norway.' If this argument is accepted, oil-related employment will become increasingly important in both national and regional contexts. The level of employment creation, however, is only one factor which needs to be considered when deciding on exploration and production policies, and by itself is not crucial. Chapter 7 discusses the ways in which the national employment objectives can be achieved by the use of oil revenues rather than any increases in

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direct activity. Regarding environmental legislation, it is obvious to anyone who spends time offshore on rigs or platforms that environmental conditions, particularly health and safety, are worse than in comparable onshore activities. To us there seems no reason why the increasingly strict legislation which applies to onshore industrial activities should not apply offshore. There may be some problems in enforcing regulations retrospectively, if this required alterations to facilities on rigs and platforms, but they should certainly be applied strictly to new developments — and enforced. The Ekofisk blow-out, for example, showed that the companies involved had not followed the correct procedures, nor had the Oil Directorate ensured that they were being followed. It appears that one of the Oil Directorate's responses was to insist on the separation of accommodation and drilling/production for the Statfjord B platform, which in effect would mean two separate platforms. This would certainly have improved safety but at unnecessary expense, and in the event was over-ruled. On present evidence, U.K. legislation seems to be adequate (with the possible exception of diving regulations) and we would recommend that similar legislation be applied to the Norwegian sector. In fact the main difference between the U.K. and Norway is that in the former, sector legislation is strictly enforced ... and, very simply, if existing Norwegian legislation had been similarly enforced, many problems would not have occurred. This is our view also on the legislation concerning foreign workers. To the extent that problems have occurred — and the point was stressed earlier that under some circumstances foreign labour is advantageous to Norway — it was because the companies concerned ignored the legislation or found ways of avoiding it, and the Government authorities either did not notice or were not worried. In both these areas these may appear simplistic conclusions, but we are strongly of the view that existing legislation is on the whole sufficient. It needs to be enforced firmly and sensibly. NOTES 1. For more detailed explanation, see pp. 9-11. 2. See, e.g. D. I. Mackay and G. A. Mackay, The Political Economy of North Sea Oil.

3. Part of the Ministry of Local Government and Labour. 4. K. Stenstadvold, Regional and Structural effects of North Sea Oil in Norway, p.21. 5. See, e.g., J. Nicholson, Shetland and Oil.

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6. See, e.g., Stenstadvold, op. cit. 7. Most of the studies are listed in O. Osland, Petroleum virksom het og Sysselsetting. 8. K. Stenstadvold, Recruitment to Oil-Related Activities in Norway. 9. See, e.g., Statistisk Sentralbyra, Inn og utvandring for Norge 1958-75 (Immigration to and emigration from Norway). 10. G. A. Mackay et al., The Economic Impact of North Sea oil on Scotland. 11. G. A. Mackay, Revised Demand for Production Platforms, 1977-82. 12. MFPR no. 75 (1976-7), p.61.

6 THE ROLE OF STATOIL 'I don't wish you anything but just what you are — my own sweet little song-bird.' (Henrik Ibsen, A Doll's House) There has never been any doubt about the ultimate ownership of the oil and gas discovered under the North Sea. The Royal Decree of 31 May 1963, for example, stated the position clearly: `The sea bed and its subsoil in the submarine areas outside the coast of the Kingdom of Norway are subject to Norwegian sovereignty in respect of the exploitation and exploration of natural deposits, to such extent as the depth of the sea permits the utilisation of natural deposits, irrespective of any other territorial limits at sea, but not beyond the median line in relation to other states.' Act no. 12 of 21 June 1963, section 2, stated: `The right to submarine natural resources is vested in the State. The King may give Norwegian or foreign persons, including institutions, companies and other associations, the right to explorate for or exploit natural resources. Specific conditions for such permission may be stipulated.' This sets the framework within which Norwegian policies have evolved. The main specific provisions are set out in the Royal Decree of 8 December 1972, which has been modified from time to time since then, but which still forms the basis of the current legislation. Like all other Western countries, the Norwegian state has never been in the position where it could exploit the oil and gas reserves itself, and until recently this task was left entirely to private industry in the form of the international oil companies. As the importance of the North Sea discoveries increased, so too did legislation and powers controlling the industry. They cover an extensive range: licensing, taxation policies, controls over production and the landing of oil and gas, permits for development, employment legislation, safety legislation, etc. The most important aspects of government control have been discussed earlier, with the exception of taxation policies which are considered in the next chapter. The main concern of this chapter is 98

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the role of the new state oil company, Statoil, which has added significantly to the powers of the state in its dealings with the private oil companies. Although Statoil was set up in 1972, only in the last two years has it emerged as an important body, and as should be obvious from what follows, it will probably not be until the mid-1980s that its permanent role becomes clear. The emergence of Statoil Let us start with the question `Is or was Statoil necessary?' (we shall not attempt to answer this but it enables the main arguments to be discussed). Free market economists would argue that any reasonable objectives of the government in controlling the oil industry could be met by licensing and fiscal legislation. Thus if the intention were to increase the government's share of the income (which Statoil is doing), the best way to do so would be by increasing the royalty or tax rates. If the intention were to ensure that companies were using `best practice' techniques, this could be done by increasing the powers of inspectors. If the intention were to build up a domestic refining and petrochemical industry, this could be done by investment incentives and controls over the export of crude oil. In this way it is possible to demonstrate or claim that all the explicit objectives of state oil companies. including Statoil, could he met by other means: this is basically the argument of recent books by Blair and Dam.1 Despite these views, history shows clearly that politicians and civil servants have held different views. The relationships between national governments and private oil companies have changed tremendously in the last decade, with the Middle East being in the forefront. Nationalisation was the first strategy, the outstanding examples being Mexico (1938), Iran (1951), Algeria (1971) and Iraq (1972). In most other countries nationalisation has not led to state operation of the oil fields but to some modified form of governmentcompany relationship. Nationalisation was not a possibility in Norway because there was no domestic production, either onshore or offshore. As was shown in Chapter 2, the licensing — or concession — system was adopted, a crucial point being that licences were awarded to a number of companies rather than to a single one, as it had been the case in some Middle East countries. Here there is little difference between the Norwegian approach and that of the U.K., although it should be pointed out that the British Government had a large share of one of the major companies, British Petroleum (BP).

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The period 1970-3 saw radical changes being made in the Middle East, following the revolution in Libya in 1969 and consequent changes in oil policies, and culminating in the OPEC price rises in 1973 and 1974. This is not the place to recount these changes,2 but we must point out that they had a great influence on policy thinking in both Norway and the U.K. Dam has aptly summarised this:$ `The events of this period demonstrate that the bargaining position of companies and governments had been drastically altered, and that governments could get away with tougher financial terms and with unilateral, retrospective changes in licensed conditions.... The consequence of these unilateral changes and the altered supply-demand balance that made them possible was a quadrupling of the world crude oil price from 1973 to 1974. This price escalation made existing licences enormously more valuable to the licensees. The economic rent accruing to the licensee had multiplied.... The twin perceptions that a giveaway had occurred and that governments could get away with a much tougher stance and perhaps even with unilateral, retrospective measures created the political conditions for many of the innovations in British and the Norwegian policy.' We think that this is a reasonable explanation of feelings during that period. It is important to remember that when the licensing and taxation system was first set up in the 1960s, there was no reason to believe that any major discoveries would be made and thus policies then were designed to attract companies and to encourage exploration. The terms were therefore relatively easy. The discovery of Ekofisk and Forties marked the beginning of a new era in both Norway and the U.K., which the OPEC price rises in 1973 and 1974 merely confirmed. Norway had a social democrat government from the end of the Second World War until 1965, and since then most governments have had a left-wing aura. State control and involvement is common in a wide range of industries. In the oil sector both Norsk Hydro and Norol have the government as majority shareholders. Despite this background, the establishment of a state oil company had never been seriously discussed prior to 1970, although it had been proposed by the small Socialist People's Party (Sosialistik Folkeparti) as part of their election manifestos in the 1960s. Ekofisk and the Middle East developments changed that, and there were lengthy and detailed discussions when the Labour minority government was formed in 1971. Although this government fell in 1972 in the aftermath of the EEC referendum, the idea was confirmed by the new coalition of non-socialist parties. The formal

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establishment of a wholly-owned state oil company — Den norske stats oljeselskap A/S — was announced in 1972 and the company was established following a decision on the Storting on 14 June 1972. The company is popularly known by its abbreviation Statoil. It is undeniable that very little detailed consideration was given to the reasons for establishing Statoil. Even the famous Parliamentary Report no. 25, issued in 1974 approximately 18 months after the Storting gave its approval for Statoil, is vague:' 'Statoil will be an important institution for implementing the authorities' petroleum policy. Guidelines for Statoil's functions will be decided by the relevant political institutions. The necessary facilities will be provided for the enterprise, so that the objectives laid down in the preamble may be attained. Among other functions, the enterprise will therefore be entrusted with the task of acting as an independent operator as soon as possible. This means technically the company will be responsible for executing the exploration for and extraction of petroleum discoveries.' It is interesting to note that this report confirms the view expressed at the beginning of this chapter:° `Norwegian authorities have full rights of disposal over oil and natural gas resources, and it is their responsibility to ensure that these resources are used with due care, both with regard to Norwegian interests and in an international context. Private enterprises, Norwegian or foreign, may be engaged at the exploration and production stages and will receive suitable compensation for their efforts. But in future they should obtain the right to exploit these natural resources in exceptional cases only. The organisational pattern for Norwegian petroleum operations must provide Norwegian authorities with full control of all stages in the operation: exploration, production, processing, exports and marketing.' The legislation covering Statoil is extremely vague and in our view the policy has been to give Statoil a great deal of freedom to find its own role. Within the objective described above Statoil steadily expanded and its role is now what Statoil wants it to be, rather than what the politicians wished in 1972. Is there any significant difference? Probably not, although from time to time Statoil has come into conflict with either the government or Storting and has usually backed down. The impression is given that the government will only interfere when Statoil clearly contradicts its vague terms of reference, which suggests by implication that the government supports Statoil in its expansion plans, subject to occasional checks and controls on its growth. However, Statoil has only been seriously active for two years and it may well be

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that the government will impose more limits on future operators. Because of the vagueness of its terms of reference, the best way to evaluate the role of Statoil is to describe briefly what it has done since 1972. This can be done in sequence with regard to activities. Licences and exploration Originally there were no provisions concerning state participation: the first round of licences in 1965 made no mention at all, although as was mentioned in Chapter 2, there is some evidence to suggest that foreign companies willing to form consortia with existing Norwegian companies (such as Norsk Hydro and Noco) received preferential treatment. In the second round in 1969, government participation was required for the first time. Two methods were put forward: net profit sharing and carried interest. Under the net profit sharing agreements, a fixed percentage of net profits from a commercial discovery was to be paid to the State. Esso received four licences (four separate blocks) on the basis of a 17.5 per cent profit rate; the Amoco-Noco group received two blocks at a 10 per cent rate°. It is difficult to see any significant difference between these profit shares and the imposition of royalties or the special petroleum tax, and this was eventually recognised by the government in that the arrangement was not used after the 1969 licence round. When Statoil was set up, the net profit shares were transferred to it, but as yet there have been no commercial discoveries on these blocks, although the Hod discovery on block 2/11 and the Odin gas discovery on 15/10 fall into this category. The carried interest system has been of much greater relevance. The arrangement is that the government's potential interest is carried by the licensees during the exploration phase; if hydrocarbons are discovered the government have an option to participate; if it wishes to do so it must contribute at least part of the cost. Thus the system depends again on commercial discoveries and its effect depends on the arrangements made concerning the government's financial contribution. In the 1969 licences, the carried interest share ranged from 5 per cent to 40 per cent. The detailed arrangements for each licence have been impossible to obtain because of confidentiality restrictions, but the arrangements with the Petronord Group for the Frigg field (block 25/1) have been published,' although it is not known how representative they are. Probably they are less lenient than most of the other arrangements. Under this licence the government's share of exploration costs was financed by the other companies, but if a

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commercial discovery was made these costs could be recouped from production revenue. A similar method was adopted for the government's share of development costs, with a special account being set up, but normal operating costs would be met by the government. For the companies involved this meant that their financing burden was correspondingly greater; for the government it meant they obtained an easy and cheap source of finance but delayed their participation revenue. It should be pointed out that in this licence for the Frigg block the government's participation share was only 5 per cent, so the added burden was not great. It is understood (although no official confirmation has been given) that in most of the 1969 carried interest agreements the government agreed to participate in meeting costs on the same basis as the various licensees. The third round of licences was not announced until 1973 and awarded in 1974, in accordance with the `go-slow' policy. However, two ad-hoc licences were awarded during this period. The first was in 1971 for block 25/4 (the Heimdal discovery): this was originally licensed to the Syracuse group with a participation rate of 26 per cent, but in 1972 the licence was trasferred to the Pan Ocean/Petronord group on condition that government participation was increased to 40 per cent. This method of increasing government participation had been used in 1971 when two other licences were transferred. In one instance, the government included as a condition of consent a 7.5 per cent participation on a carried interest basis in four blocks in the Dutch sector. The other and more important licence issued during this period was in 1973 for two blocks, 33/9 and 23/12, adjacent to the Norwegian/U.K. boundary. In the U.K. blocks immediately to the west, three commercial fields have been discovered to date — Brent, Dunlin (part) and Murchison — and, of course, blocks 33/9 and 33/12 contain most of the famous (or infamous) Statfjord field. The exceptional reasons for the licensing of these blocks were the need to evaluate blocks adjacent to commercial discoveries because of the belief that they may straddle the international boundary and that the U.K. government would wish to see them developed quickly. In the present context the important point is that in this licence the government raised its participation rate to 50 per cent and Statoil, now in existence, was nominated for the first time as the shareholder. By then, Statoil had taken over all the government's earlier participation arrangements. Statoil's role in the development of Statfjord is discussed below, but in terms of exploration it took full rights in decision-making while

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being fully exempted from exploration costs. Mobil (with a 15 per cent share) was the nominated operator, but Statoil had the right to take over as operator ten years after it exercised the carried interest option. The third licence round in 1974 saw this principle further adopted. The government awarded five licences covering eight blocks, with Statoil having a 50 per cent carried interest in four licences and 55 per cent in the fifth, with an option to increase its participation up to 75 per cent in accordance with an agreed scale based on the eventual size of the discovered reserves. For one licence (covering three blocks) Statoil was to be the operator, with Esso providing technical assistance. In 1973, when the government announced the proposed third round, it had been intended to reserve nine blocks for Statoil alone. The conditions for Statoil were to be similar to those of licensees on other blocks with, for example, the work programme to be submitted and approved. Statoil was `to propose partners, for instance, large integrated oil companies, capable of giving Statoil opportunities for such co-operation in and outside Norway as conforms to Statoil's object of being an integrated company'.' In the event this exclusive licensing did not take place, for reasons which have never been released but which presumably concerned Statoil's ability to operate independently at that time. The 1974 licence round appears to represent the state of official thought then. The fourth round of licences is to be issued in early 1979; the deadline for applications for the fifteen blocks was 1 June 1978. However, once again in the interim period a number of licences were issued on an ad hoc basis. Four were issued in 1976 covering seven blocks — almost all on the median line with the U.K. — and in each Statoil has a 50 per cent carried interest share, with an option to increase on the same basis as the third round licences. For the licence 044 (block 1/9) Statoil is the operator, with the Phillips group providing technical assistance. Three more licences covering five blocks were issued on the same basis in 1977. The fourth round involved applications for licences for fifteen blocks. The invitation documents set out Statoil's role:9 `As a condition for granting a production licence, it will be demanded that an agreement with Den norske stats oljeselskap (Statoil) is entered into concerning participation in the exploration for and exploitation of petroleum. The agreement will be formulated according to the same pattern as used in the State participation agreements entered into in the third concession round. The parties

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shall form a joint venture in which Statoil initially has a participating interest of at least 50 per cent which can be increased in accordance with an agreed scale, dependent on the expected peak production in case of a commercial discovery. Until a commercial discovery is made, Statoil's share of the expenses are to be covered by the other companies holding the production licence. The agreement also contains a number of provisions involving the organisation of work in the joint venture.... When allocating a production licence the Ministry of Petroleum and Energy may in each separate case consider suitable forms of co-operation between the licensees and Statoil.' This suggests that in terms of the granting of licences the government is now clear in its own mind of the role of Statoil, given that the conditions have not changed for four years. The scope for change comes more from Statoil's own exploration activities than the participation policies. To date Statoil, as operator, has drilled fifteen exploration wells. No exploration expenditure was incurred before 1977; the estimated expenditure in 1977 was 56 million kroner; and the estimate for the four years 1978-81 is 150 million kroner. Given that the average exploration well is currently costing around 40 million kroner, this amounts to little over one well per year, but of course Statoil is not paying its full share of exploration costs, even on blocks where it is the operator. It is impossible to obtain precise details for each licence, but in the case of licence 045 (blocks 24/11 and 24/12) it is understood that Statoil is paying only 7.5 per cent of the costs it incurs as the operator. In the case of licence 044 (block 1/9), which was the first for which Statoil took full responsibility as operator, it is understood that Phillips is paying all the exploration costs. Oil and gas have been discovered on that block. During 1978 nineteen exploration or appraisal wells were completed in Norwegian waters, seven by Statoil; so within the space of about two years it has emerged as a major exploration force. The results have been reasonably successful to date also: in addition to 1/9, hydrocarbons have been discovered on 34/10 and 15/9, although the former is not a surprise given that it is the famous `golden block' adjacent to the Statfjord field. Development and production There has been a similar rate of expansion in the cases where commercial discoveries have been made. In some respects, however, this has again been done in a rather haphazard and retrospective fashion. Take Ekofisk as an example. Statoil has no share

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in production because most of the fields in the group were discovered before it was set up, although 1/9 could be incorporated into the Ekofisk system in the future. Statoil is involved, nevertheless, in the transportation facilities, in two out of the four companies formed in 1973. In both Norpipe A/S and Norpipe Petroleum U.K., Statoil has a 50 per cent share; the former own the oil and gas pipelines and the initial metering and storage facilities at Teesside in England and the latter own the terminal and processing facilities at Teesside. Financing has been 90 per cent debt and 10 per cent equity, but the Phillips group has been solely responsible for the debt finance. Thus even in the case of a pre-Statoil field, the state oil company has been given an influential role in so far as production is controlled by the transportation and processing facilities. Furthermore, in accordance with the Royal Decree which authorised the laying of the oil and gas pipelines, the Government has an option to purchase on longterm contract sufficient NGL to produce 250,000 tonnes of ethylene per year. This option has been assigned to Noretyl which owns the ethylene and propylene plant at Rafnes and in which Statoil has a 33 per cent share. At the time of writing the Government is also taking its royalty payments in the form of crude oil, which is being marketed by Statoil. Frigg provides a similar example. It was discovered in July 1971. Statoil was not involved in the original group but has since been given a 5 per cent share in the net output after the accumulated costs have been reimbursed. The best example of development activities, however, is undoubtedly the Statfjord field, the largest oil discovery in Norwegian waters hitherto. Statfjord was first discovered in 1974 in block 33/9; appraisal drilling since then has confirmed that the field extends into block 33/12 and into the U.K. sector block 211/14. Estimated recoverable reserves are around 3 billion barrels of oil and 2.5 trillion cubic feet of gas, with about 90 per cent in the Norwegian sector. Both blocks are covered by the 1973 licence 037 with the shares Mobil (the operator) 15 per cent, Statoil 50 per cent, Conoco 10 per cent, Shell 10 per cent, Esso 10 per cent and the Saga-Amoco group 5 per cent. Nine companies in all are involved. The original field development programme was in three phases, with an estimated cost of 20 billion kroner and with production beginning in 1977. At the time of writing it looks as if Phase 3 has been abandoned and Phase 2 modified substantially; estimated costs have risen to nearly 50 billion kroner and production is not expected until late 1979. The project history has been one

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of delays, mishaps, arguments and rapidly rising costs. Criticism in Norway has really only occurred since 1978, although it is now very widespread. There have even been official complaints from the U.K. Government in respect of those involved in the U.K. share of the field — to the extent that it has been suggested that the U.K. partners may go ahead with their own separate development programme In December 1978 the Norwegian Government announced an official but independent inquiry into the reasons for the steeply rising costs, with Statoil being required to produce a detailed report on their experiences with the field. Three main aspects are of interest here: the development delays, particularly the changes in the number and type of production platforms; the transportation plans; the rising costs; and the overall management of the project. Regarding the first, Phase 1 consists of one integrated (development drilling/production/accommodation) platform with a capacity of approximately 300,000 barrels per day and a single buoy mooring system for offshore loading into tankers. The concrete platform was built to a Condeep design at their Stavanger yard; the steel desk built by Aker at Stord; and the platform was installed in 1977. Phase 2 was to have consisted of two similar production platforms, but in 1976 the Norwegian Petroleum Directorate (NPD) rejected this plan largely on the basis that a separate accommodation platform was required on safety grounds. After a two-year delay during which various alternative designs and plans were discussed, the Statfjord field group placed an order for an integrated B platform, albeit with a lower capacity (150,000 bpd.). Even with hindsight, and taking account of the repercussions of the Ekofisk blow-out, it is difficult to understand the reasoning of the NPD, particularly given the fact that all the U.K. oil production platforms include accommodation and the U.K. safety record has been much better than Norway's. Secondly, it is similarly difficult to understand the thinking behind the transportation plans. A tanker-loading system is sensible for Phase 1, but the estimated peak production of 1 million bpd. could not be achieved with such a system, and the obvious solution is a permanent pipeline. In fact an extensive study of the possibility of piping oil to Sotra near Bergen is in progress, but the problems of crossing the Norwegian Trench probably means that this is either technically or financially impossible. One figure that has been mentioned is the cost of 2 billion kroner — about twice the average cost in the North Sea. The crucial point is that a pipeline to Sotra would be about 160 miles long;

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a pipeline to the Dunlin or Brent fields to connect with the pipeline system to Sullom Voe in the Shetlands would be about 10 miles. The latter would probably cost around 900 million kroner (£90 million), including the shared cost of the existing pipeline system — in other words about half the cost of the Sotra alternative. In addition, the terminal costs at the Sullom Voe would be very much less than at Sotra. Why has Statoil ignored the Sullom Voe alternative and been able to impose this view on the other members of the Statfjord group? Both Ekofisk and Frigg have been developed in a similar way, and so will the Murchison field. It is true that serious prob. lems have arisen with the Ekofisk pipeline to England, and in particular there have been long delays in the construction of the terminal facilities. Sullom Voe is now producing, however, so there is no possibility of the Ekofisk saga being repeated. The answer to the question is really a nationalistic one in that Statoil wishes to demonstrate its Norwegian interests and independence by developing Statfjord field without assistance from those involved in the adjacent U.K. blocks. The difference in costs seems to be a high price to pay for that nationalism. Thirdly, there are the reasons why the costs of developing Statfjord have risen so substantially. This is difficult to assess because of the underlying political motivations, so the easiest approach is simply to set out the two conflicting views. On the one hand, we have been told by Mobil that the basic problem was that they were not allowed to take decisions on commercial criteria and that Statoil objected on a number of occasions to their proposals. On the other hand, Statoil blame poor management and lack of control of sub-contractors (particularly American) involved in the platform construction and design. It is not our wish to become involved in these arguments. The relevant point is that the arrangement of Mobil as operator with Statoil as the majority partner has not worked satisfactorily, particularly given Statoil's desire to impose certain external criteria — such as the refusal to consider a pipeline to Sullom Voe and the debate over the placing of the steel deck order for the second platform. Finally, in the context of developing activities, it is necessary to stress the national oil company's steady diversification. In addition to the involvement in the Ekofisk and Statfjord transportation systems Statoil has a 50 per cent share in the Coast Center supply base at Sotra (the main base for Statfjord) and is intending to set up a similar base for activities in North Norway.

The Role of Statoil

109

Downstream activities Two downstream activities have already been mentioned: Statoil's marketing of Ekofisk royalty oil and its involvement in the natural gas liquids from Ekofisk. Statoil has a 33 per cent share in I/S Noretyl, the joint venture responsible for the construction and management of the ethylene plant in Bamble. The other partners are Norsk Hydro (51 per cent) and Saga (16 per cent). Production began in 1977 and peak capacity utilisation is expected in 1980. Statoil's estimated expenditure in the venture is 450 million kroner. The same three partners — this time in equal shares — own I/S Norpolefin which is producing polyethylene and polypropylene; peak production should be reached in 1980; and Statoil's expenditure will be about 600 million kroner. Statoil has also taken a 30 per cent share in Rafinor A/S, which owns and operates the Mongstad refinery which began production in 1975. Originally the refinery was owned jointly by Norsk Hydro and Norol. Statoil is now responsible for providing 70 per cent of the refinery's crude oil requirement (its own and Norol's) and is currently doing that with royalty oil. An 80 million kroner expansion was recently announced to provide butane and propane facilities, with in this instance Norol agreeing to market 70 per cent of the output. More detail about the exact operation of all these facilities is given in Chapter 3. Table 6.1 STATOIL'S ESTIMATED CAPITAL EXPENDITURE (millions of kroner) Statoil's Before After Area of activity share 1977 1977 1978 1979 1980 1981 1981 Exploration, production and transportation 20,940 1,908 1,407 1,539 3,813 4,067 4,638 3,568 Refining and marketing 1,122 505 428 122 6 56 5 Service companies 43 — 3 6 4 2 9 19 Administration and development 504 10 93 186 72 54 — 89 Totals

22,609 2,423 1,931 1,853 3,960 4,154 4,716 3,572

All these activities are summarised in Table 6.1, which sets out capital expenditure estimates for the period until 1981 (the `after 1981' column refers to expenditure on projects in progress during the plan period to 1981), as presented by Statoil in the annual

110

Norwegian Oil Policies

report for 1976.10 Almost all the expenditure in the first category (an estimated 19,593 million kroner) is for the development of Statfjord, which highlights the great importance of this field in Statoil's operations. After 1978 the only major capital expenditure in the plan is for exploration, including exploration north of 62°N. Regarding the investment in refining and marketing, Noretyl accounts for 48 per cent of the planned expenditure, Norpolefin 50 per cent and Rafinor the remaining 2 per cent. Regarding the investment in supply bases and service companies, the Coast Center Base accounts for 26 per cent and Norbase 74 per cent. Regarding the administrative and development projects, this includes the purchase of equipment for pollution control. Financial implications These can be dealt with briefly — from two points of view, first that of Statoil and secondly that of the other oil companies. Table 6.1 sets out Statoil's estimated capital expenditure over the period to 1981. If new fields are discovered, for example, Statoil's development expenditure will continue at a high level, and certainly the trend in the table is a rising one, although downstream investment will have been largely completed by 1979. The table does not include current (operational) expenditure, which is at a much lower level. Table 6.2 OPERATIONAL AND FINANCIAL INCOME (millions of kroner) 1977 1978 1979 1980 1981 604 1,365 2,152 — — Crude oil 566 1,106 1,543 2,097 2,227 Royalty oil 16 74 140 164 172 Gas 690 824 Refined products 651 732 777 184 432 Petrochemical products 38 301 399 55 43 Other operational income 23 52 59 Total operational income Return on Norpipe shares

1,294 2,109 3,372 4,861 5,850 41 54 74 75 9

Total income

1,303 2,150 3,426 4,935 5,925

Revenue aspects for the same period are covered by Table 6.2. At the time of writing Statoil is borrowing heavily, but by 1980 there should be a significant surplus, arising mainly from receipts from royalty oil which until the mid 1980s will continue to be

The Role of Statoil

111

Statoil's main source of revenue. Thereafter Statoil's own crude oil revenue will be more important. From the point of view of private companies, Statoil's participation can be seen as a kind of additional tax. The detailed tax policies are discussed in the next chapter, and this brief section should be seen as part of the overall fiscal regime. Statoil's participation in fields is on a sliding scale related to expected peak output, with the rates ranging from 50 per cent to 75 per cent. As described earlier, Statoil pays its share of development and operating costs but not exploration costs. A recent article by Kemp and Crichton11 has looked at the effects of these increased participation rates on the returns to the other companies involved in the fields. In the case of Statfjord (Phases 1 and 2), for example, the estimated internal rates of return (real values) are the same for no participation and 70 per cent participation, because Statoil is paying its share of development costs, but the net present values of the private companies' share of the field (using a 10 per cent discount rate) is three times as high in the former case. In this light there may be some advantage to an operator in altering the shape of the field's production profile so that peak production is less and Statoil's participation is lower. This would also lower royalty and tax payments but delay revenue. If private companies could benefit from such changes, however, it means that Statoil must suffer, and it may well be that the Ministry of Petroleum and Energy would disapprove of company requests to produce at lower peak rates. Nevertheless, it does seem that the financial conditions concerning Statoil's participation in commercial discoveries are fair to the other companies, leaving them with an acceptable rate of return on investment (excluding exploration costs). Objections to state participation are made on other grounds, of course. Comparisons with BNOC Many countries now have state oil companies. In the present context the best comparisons are with the British National Oil Corporation (BNOC), not least because the latter was modelled on Statoil when it was first seriously proposed in 1974 at the time when the Labour government came into power in the U.K. It started operations in January 1976, and thus its 3-year life is considerably shorter than that of Statoil, although already it is much bigger. This rapid rate of growth, when compared with Statoil, is largely attributable to the fact that in 1976 BNOC took over most of the existing North Sea operations of Burmah

112

Norwegian Oil Policies

(the British oil company which was rescued from severe financial difficulties — probably liquidation — by the government) and the National Coal Board, and thus inherited stakes in a number of fields as well as Burmah's qualified and experienced staff, At present BNOC's staff numbers about 1,000 and is expected to increase to over 2,000 by the early 1980s; Statoil currently employs about 600. As with Statoil the terms of reference given to the U.K. state oil company are surprisingly vague. It was set up as part of the series of legislative changes made in the Petroleum and Submarine Pipelines Acts (1975), which included major changes in taxation and depletion policies. As set out in its first annual report" BNOC's main priorities are: (1) the efficient and commercial management of its equity interests in exploration, development and production; (2) the effective disposition of petroleum available to the Corporation both from its equity interests and through participation arrangements with other offshore petroleum production licensees, with due regard both to commercial considerations and to national and international interests and obligations; (3) the development of expertise in and knowledge of all aspects of the oil business, but particularly those relating to the development and use of resources under the U.K. continental shelf; (4) the development of its capability to give informed and expert advice on oil matters to the Secretary of State as a contribution to the development of national policy. One of Britain's leading financial journalists, Adrian Hamilton, has described the situation thus:13 `The creation of BNOC was viewed with some suspicion by both the Department of Energy, because it might diminish its powers of control, and the Treasury, which was worried about cost. It raised fears in the industry that it could distort prices and returns by competing in the market place on a non-commercial basis, and it aroused the traditional parliamentary conflicts over state intervention. The solution, as in the other cases, was found in a compromise form of unusual qualifications and an unusual lack of definition.... The question of refining and marketing was left open with a vague statement that it would not occur for some years anyway.' Under Part 1 of the 1975 Act, BNOC is charged with carrying out the normal functions of an integrated oil company, including exploration, production, refining, distribution and petrochemical production throughout the world. In addition it has the duty to advise and

The Role of Statoil

113

inform the Secretary of State for Energy on oil matters and `to perform services on behalf of the Crown'. Policies and operations are decided by the Corporation's members (equivalent to a private company's board of directors but appointed by the government), two of whom are civil servants, and the Secretary of State has the power to direct the activities of the Corporation. In 1976 BNOC inherited the National Coal Board's offshore oil and gas interests, which included gas production from the Viking field and equity interests in four oil fields under development: Thistle, Dunlin, and the U.K. parts of Murchison and Statfjord. Through Burmah it acquired a share in the Ninian field and an additional stake in Thistle, and in fact became the operation for the Thistle field. Participation agreements were also reached with a few companies and in the 3 years prior to the time of writing these have been extended to include all companies in the U.K. sector. For licences issued during the first four U.K. rounds, all these agreements have been voluntary and on the basis of a `no gain, no loss' principle from the point of view of the companies involved. Originally it had been intended that this would mean BNOC contributing its full share of past costs, but some companies were unwilling to accept this; the normal procedure now is not for BNOC to have an equity stake but to have guaranteed access to 51 per cent of production, to be purchased at market prices if BNOC wishes to do so. In the fifth licence round this condition was included automatically, and in the sixth round offer documents (applications for which were made in November 1978) potential licensees were invited to offer BNOC more than a 51 per cent share and to carry all or part of the Corporation's exploration costs. In addition to these equity and participation interests, BNOC was given exclusive licences for some blocks, although recently it has been obliged to offer shares in some of these to Burmah. Its first discovery as an operator was made in June 1978 on block 30/17 b; this may prove to be a small field with around 200 million barrels recoverable reserves. At present BNOC is disposing of around 150,000 barrels a day and this should increase to around 1 million bpd. by 1981 — probably over 40 per cent of U.K. oil production by then. Of this approximately 15 per cent will come from BNOC equity shares, 30 per cent as royalty oil and 55 per cent from participation agreements. This is not necessarily a profitable aspect of operations, particularly if prices are static or falling — but it reflects a major concern of the U.K. government to have control over oil supplies,

114

Norwegian Oil Policies

in case restrictions on Middle East supplies ever reappear. Thus although a large part of British production is at present exported, BNOC could ensure that it was diverted to the domestic market if the need arose. This is in marked contrast to Norway, where domestic consumption is of course, very small and security of supply is not a major issue. Another important difference between Statoil and BNOC is the former's greater involvement in downstream activities. Again, this largely reflects differences in economic structures: the U.K. has a substantial domestic refining industry in which British companies such as BP and Shell have major shares, and there is no obvious gap which BNOC could usefully fill. As pointed out in Chapter 4, the Norwegian position was and is very different. There are also contrasts in information and regulatory aspects although in both countries the full significance of these will not be clear for some years. The U.K. government has always been able to get information and advice from BP, and Shell to a lesser extent, so BNOC has a lesser role to play than Statoil. This is probably true of regulation as well, although the 1975 Act suggests otherwise. BNOC itself has spoken out strongly against its having regulatory powers — because of the danger of conflict of interests — and maintains that this is the proper role of the Department of Energy, in the same way that the Oil Directorate in Norway is responsible within the Ministry of Petroleum and Energy. An example of this conflict has already arisen with the 30/176 discovery mentioned above. It had been claimed that this structure had been identified by Shell-Esso from seismic surveys in late 1975 and that the block had been their top priority in applications for 5th round licences, but that BNOC had been given the major share in the block. The implication was made that BNOC only `discovered' the field because it had had access to the seismic data which Shell-Esso were obliged to pass on to the Department of Energy — data which they regarded as confidential. A letter written under a nom de plume appeared in The Times" claiming that `one cannot give much credit to a person having the privilege of viewing all the hands in a poker game, then declaring himself a partner of who ever holds the best hand and finally, after settling down to play the hand, telling everyone what a good player he is as he rakes in the chips.' This particular allegation was refuted but it led to the Minister of State for Energy stating publicly that the Corporation had to recognise the importance of `compartmentalising' its operations —

The Role of Statoil

115

of keeping its monitoring of confidential information separate from its commercial operations. This conflict — or potential conflict — has been worrying oil companies which are concerned about BNOC using information gained through participation agreements to enhance its own commercial operations. In some cases special clauses have been written in to state participation agreements in order to safeguard companies against the possible misuse of information. Another example of conflict arose in discussions about the use of the Ninian pipeline through which the group developing the Heather field wished to pass their oil. BNOC was involved in two ways — with an equity interest in the Ninian field and an option to participate in Heather. In this instance BNOC withdrew from the negotiations. No conflicts of this nature have risen with Statoil but this presumably is a matter of time, and as Statoil's offshore operations expand to a size and complexity comparable with those of BNOC it is almost inevitable that they will occur. The differences which have emerged have mainly been between Statoil and the government or Statoil and other government departments. Hamilton's interpretation of these differences is:15 `Despite Norway's reputation as a hard-nosed and decisive negotiator of national interest with the oil companies, at least part of its actions have resulted from political uncertainty and changing pressures rather than considered policy. . . . The creation of an ambitious state oil company in Statoil has to some extent further intensified these internal conflicts in the Norwegian government as differences have grown between the Ministry of Industry and Statoil over gas pipeline investments, landing points, downstream investment in refining and petrochemicals, and the degree of monopoly that Statoil should enjoy north of the 62nd parallel.' Nevertheless, it appears that government`or parliamentary control of Statoil is greater than that of BNOC. Both are responsible to government ministers, who make the appointments to the respective boards. Annual reports are submitted to the Storting and Parliament, in the former case along with the views of the Ministry of Petroleum and Energy (previously the Ministry of Industry), and there are similar legislative clauses setting out the procedures for settling differences between government and the semi-autonomous corporations. Thus in law control may be almost identical, but in practice Norwegian ministers have exercised more control, and Statoil has been less willing to `step out of line'. On the other hand BNOC has involved itself in a series of disagreements, for example by borrowing from overseas rather

116

Norwegian Oil Policies

than from the government, and by selling oil to the German company Deminex which had been refused permission by the Department of Energy to export more than 50 per cent of its Thistle field production. Many of the functions which BNOC performs in the U.K. are the responsibility of the Oil Directorate in Norway. The Directorate has probably a greater influence on policy making than Statoil, but is clearly less independent of government control. It is the main regulatory body in Norway, and the division is sufficiently clear to avoid most of the conflicts which have arisen regarding BNOC. As was mentioned in Chapter 3, however, this does not apply to all aspects of the industry, because pollution matters are handled by several bodies, including two separate ministries. Finally, another difference which may have implications for Statoil's future operations concerns overseas activities. Hitherto Statoil has confined its operations to the Norwegian continental shelf. BNOC has had a series of discussions on co-operation with other state oil companies, such as Petroven (Venezuela) and Petronos (Mexico), and has agreed to exchange personnel with these companies in order to give its staff overseas experience. There is little doubt that a similar arrangement would be attractive to Statoil and in the long run it could well lead to more active operations overseas, particularly as activities in the North Sea decline. NOTES 1. J. M. Blair, The Control of Oil, and K. W. Dam, Oil resources. 2. See, e.g., A. Sampson, The Seven Sisters, and C. Tugendhat and A. Hamilton, Oil: the biggest business. 3. Dam, op. cit., pp.19-20. 4. MFPR no. 25 (1973-4), p.9. 5. Ibid. 6. MIRS no. 30 (1973-4). 7. Storting Proposition no. 78 (1972-3). 8. MIRS no. 30 (1973-4). 9. Royal Ministry of Petroleum and Energy, Invitation to apply for petroleum production licence ... fourth round, 1978. 10. Parliamentary Report no. 33 (1977-8). 11. A. G. Kemp and D. Crichton, North Sea oil taxation in Norway. 12. The British National Oil Corporation, Report and accounts, 1976. 13. A. Hamilton, North Sea impact, p.39. 14. Referred to in the Financial Times, 7 July 1978. 15. Hamilton, op. cit., pp.103-4.

7 USE OF OIL REVENUES Money is like muck, not good except it be spread. (Francis Bacon, Essays)

It has been stressed throughout this book that the direct benefits of the North Sea developments are small in comparison with the indirect benefits to the national economy, the latter principally being the increases in government revenues and company profits, and the improvements in the balance of payments. At this stage, therefore, it is necessary to try to present in an understandable form the main macroeconomic implications. Because of the complexities and mystique of international finance, some simplification of the issues is essential; hence those with a greater interest or knowledge of the particular economic policies involved should pay more attention to the sources and references on which we have relied. This applies particularly to the evaluation of the balance of payments improvement. The size of the revenues The production estimates given in Chapter 2 form a good startingpoint. Again it should be remembered that these estimates are subject to quite a number of qualifications, and that they should be seen as broad estimates of magnitude rather than precise forecasts. If this is borne in mind and attention is concentrated on the main policy implications, then small changes or errors in the production forecasts and the revenue estimates here will not affect the arguments put forward. Multiplying the production estimates by the price of oil and gas gives the gross values. This is the second line of Table 7.1. Hence some view needs to be taken of future oil prices. In part this was discussed in Chapter 2 in the context of relationship between the price of oil and the oil companies' willingness to invest in exploration and production. It was stated that, although there has been a great deal of argument over future oil prices, particularly over whether they could fall to their original 1973 117

118

Norwegian Oil Policies

levels, the most likely outcome is that oil prices will stay constant in real terms or, at most, rise slightly. The assumption of a constant real price — i.e. one that simply rises in line with the rate of inflation — is the one used in this chapter. It is true that 1979 prices will rise in accordance with the OPEC decisions of December 1978, but if they are seen in the light of the virtually static prices which have prevailed since 1974, this assumption is not invalid on recent evidence. Similarly, there may be periods when prices rise temporarily — e.g. during the Iranian crisis — but these are unlikely to have a long-term effect on prices. It is necessary, however, to give some brief thought to the implications of a rising or falling oil price. Very simply, a rising price will increase the value of Norwegian oil, and therefore revenue to both government and oil companies; and a falling price will do the opposite. But there are one or two surprising complications which need to be examined. The first is that the oil price of which we are talking is the U.S. dollar price, which is accepted — at least at the present time — as the international currency for the payment of oil transactions. Thus the `reference', `marker' and other prices used by the OPEC countries are all in U.S. dollars. Because of the fall in the value of the dollar since early 1977, there have been some moves to replace it as the common currency. This did indeed happen with the pound sterling, which was also widely used in the oil industry, but there is still little real sign that the dollar will be replaced. One related point is that much of the OPEC pressure for higher oil prices in the last two years results from the effect of declining dollar prices on the cost of their own manufactured imports from countries other than the U.S. In terms of the krone, therefore, the value of Norwegian oil and gas is the price in U.S. dollars converted by the dollar-krone exchange rate. This means that any change in this exchange rate will affect the value of Norwegian oil, a point which is often either ignored or forgotten. If the value of the krone increases, relative to the value of the dollar (or indeed of any currency which might replace it for oil transactions), then the value of Norwegian oil will fall; and vice versa. This is discussed in more detail below. There is also the problem of defining the appropriate rate of inflation. The rate which enters into the calculations of OPEC countries in setting the world price of oil is not the same as that which is the concern of Norway, leaving aside the problem, which exists in any case, of estimating a Norwegian inflation rate. Any significant differences between these rates would affect the value

Use of Oil Revenues

119

of Norwegian oil, but in the present context this aspect has been ignored on the assumption that it is unlikely to be of major significance. Thirdly, there is a complication concerning the price of gas. Under perfectly competitive market conditions, the price of oil and gas would be very similar, given that to a large extent they are alternatives. Gas can be measured in terms of its oil equivalent, and therefore the price of 1 tonne of gas (oil equivalent) should be approximately the same as 1 tonne of crude oil. The market for natural gas in Norway, however, is not perfectly competitive because it hardly exists, and gas cannot be regarded as a reasonable substitute for oil (or coal or hydro-electricity). Thus gas from Ekofisk is being piped to Emden in West Germany and gas from Frigg to St. Fergus in Scotland. Regarding Ekofisk gas, the price paid to the Phillips group is comparable with that of crude oil, because the natural gas market in West Germany is a reasonable approximation to a competitive market. This is not the case in Britain, where the state-owned British Gas Corporation is, to all intents and purposes, both a monopoly purchaser and a monopoly supplier of natural gas. Using this monopoly power, the price which the British Gas Corporation is willing to pay for natural gas is much lower than the crude oil price. Operators of gas fields in the U.K. sector have no option but to sell the gas to the British Gas Corporation, because of the terms and conditions of their licences. In theory, the Norwegian share (about 60 per cent) of Frigg could have been sold elsewhere, but the cost of piping gas to Emden, for example, or of liquefying it to increase its transportability was prohibitive. The relatively low price offered to Elf-Aquitaine, the Frigg operators, was the most profitable alternative, and thus all the Frigg gas is being piped to Scotland. The price paid for Norwegian Frigg gas is significantly higher than that paid for U.K. Frigg gas, but it is still only about 75 per cent of the oil equivalent price, which is being paid for Ekofisk gas. There are further differences arising from the escalation clauses in the Ekofisk and Frigg contracts, but these can be ignored in the present context. Regarding possible future gas fields produced in the period covered by Table 7.1, the only major possibilities discussed in Chapter 2 were the tying-in of the Hod/Valhall reserves with the Ekofisk-Emden pipeline and the piping of Statfjord and Heimdal gas through the Frigg pipeline to St. Fergus. For the former, 100 per cent of the oil price has been used and for the latter 75 per cent. This disparity in the price and value of gas is taken account of

120

Norwegian Oil Policies

in Table 7.1. Theoretically, the value of Norwegian gas is the same for all fields; in the case of Frigg gas the value to Norway is less, the difference accruing to the customers of British Gas Corporation who are paying a lower price for their gas than they would in a competitive situation. The table shows that the gross value of hydrocarbon production from the Norwegian Continental Shelf (in constant 1977 prices) is likely to increase from its 1977 level of 9 billion kroner to a peak of over 45 billion kroner by 1985, and continue at the latter level for some years. The gross revenue accruing to the oil companies is the gross value minus operating costs. These have been calculated separately for the various fields and aggregated in Table 7.1 Capital costs do not enter directly into this calculation; they are reflected in the rate of return on investment to the companies, which, as shown below, is high in comparison with other Norwegian industries. The only point to be made about the operating costs shown in the Table is that they are very high in comparison with other North Sea sectors — about 250 kroner per tonne on average compared with 170 kroner in the U.K. sector and 130 kroner in the Dutch sector. The reasons for the very high level of cost have been outlined earlier. The gross revenue can be divided between the oil companies and the government. The main determinant of the relative shares is the tax system, which is rather different for the oil sector from what it is in other industries. Exploration and production licences were first granted in 1965 and for these the companies have to pay relatively small fees — a non-recurrent sum of 500 kroner per square km., which covered the first six years, and then an annual payment of 500 kroner per square km. increasing each year thereafter to a maximum of 5,000 kroner per square km. A royalty had also to be paid on any production at the rate of 10 per cent of the well-head value of the oil or gas. At the same time, the legislation was formulated in such a way as to bring oil and gas production securely inside the national corporate tax system. A provision was introduced stating that in general capital assets connected with and income derived from offshore activities would be assessed for tax purposes in the same way as activities on the mainland of Norway. However, a few concessions were made: e.g. the rate of Municipal Income Tax was set at 15 per cent for enterprises engaged in offshore activities compared with rates of between 16 per cent and 19 per cent for other enterprises, and the offshore industry was exempted from making contributions to the Tax Equalisation Fund.

Use of Oil Revenues

121

In the early 1970s the tax and royalty system was tightened up, and state participation was introduced in the form of Statoil, which was discussed in detail in the preceding chapter. In 1972 licence fees were increased and a progressive schedule of royalty rates was introduced. This ranged from 8 per cent for small oilfields (under 40,000 bpd.) to 16 per cent for large fields (350,000 bpd. and above). A separate rate of 121 per cent was set for gas production, the value being letermined at the production area shipment point. The changes in the tax system meant that the companies involved had to pay taxes such as those for the Tax Equalisation Fund, and overall this meant a combined rate of 24.3 per cent of taxable income compared with 15 per cent previously, in addition to the normal corporation tax. Even greater changes were made in 1975 in the light of the massive increases in oil (and gas) prices resulting from the decisions of OPEC in the winter of 1973/4. The licensing, participation and royalty systems remained much the same but the income tax system was altered radically. The 1975 Act introduced new allowances but also a Special Tax to be levied at 25 per cent on a base equal to that for the general income tax. The intention was to transfer the windfall gains arising from the OPEC price rises to the government. In practice the tax system is highly complicated, and those interested in its detailed operation are advised to read the recent report by Kemp and Crichton.1 Our main concern here is with its impact on the gross revenue received by the oil companies. Kemp and Crichton's report takes five fields — Statfjord, Ekofisk, the Norwegian part of Murchison and two hypothetical fields — and calculates in detail the tax liabilities of each field. Similar estimates have been made by the Edinburgh firm of stockbrokers Wood, Mackenzie and Co.2 The two sets of calculations have been combined to produce the estimates of government revenue in Table 7.1. In a normal year (i.e. from 1980 onwards) about 55 per cent of government revenue will come from the normal corporation tax, 25 per cent from the Special Oil Tax and 20 per cent from royalties. The revenue estimates do not include any profits of Statoil, which were discussed earlier. Table 7.1 shows that it is estimated that government revenue would increase rapidly from about 8 billion kroner in 1979 to over 20 billion kroner per year from 1983 onwards. The low figures in the early years are mainly attributable to the depreciation and other allowances which the oil companies are able to claim. As it is usual practice for many of these to be claimed during the first few years

Table 7.1 THE DISTRIBUTION OF REVENUE (billion kroner) 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984

1985 1986 1987

1988 1989

1990

Gross Value

4.7

7.1

Operating Costs

1.8

2.6

Gross Revenue Government Revenue

2.9

4.5

39.8 42.3 44.4 46.0 47.5 46.6 46.0 46.0 46.0 3.1 6.2 9.2 11.4 12.0 13.1 13.7 14.0 14.5 14.7 14.6 14.5 14.5 14.5 5.9 12.0 18.2 22.2 25.1 26.7 28.6 30.4 31.5 32.8 32.0 31.5 31.5 31.5

0.5

1.1

1.4

9.0 18.2 27.4 33.6 37.1

8.1 13.5 17.7 19.8 21.1 22.4 232 24.0 23.9 23.7 23.8 23.8 9.6 10.1 8.7 7.4 6.9 7.5 8.0 8.3 8.8 8.1 7.8 7.7 7.7 2.4

Company Revenue 2.4 3.4 4.5 Government Share (%) 17.2 24.4 23.7 20.0 44.5 60.9 70.5 74.2 73.8 73.7 73.7 73.2 74.7 75.2 75.6 75.6

salollod no uvr8anuoN

tJ N

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of production, the government's receipts increase all the time. The bottom line of the table shows the government share of gross revenue increasing from 17.2 per cent in 1973 to 75.6 per cent in 1990. From 1981 onwards it is expected to be over 70 per cent. Another point to be made about the table is that the figures for company revenue are not company profits; they take no account of capital expenditure. Given existing data, it is not possible to estimate accurately the level of company profits arising from North Sea activities, but Kemp and Crichton estimate that the internal rate of return for the Ekofisk field was over 40 per cent and for the other fields being considered in the range 15-20 per cent. Since the average rate of return for Norwegian manufacturing industry in the 1970s has been about 9 per cent, the evidence suggests that activities so far have been relatively profitable, although it has to be remembered that the capital investment required and the risks involved in the North Sea activities are considerably higher than in most manufacturing industries, which suggests that a higher level of profit is acceptable. It is impossible to reach any firm conclusions on these issues at the present time because, as Table 7.1 suggests, the present position is uncertain and it will be some years yet before a stable pattern of tax receipts emerges. As a rough guide, the tax system is now comparable with that of the U.K. and the average level of government receipts is about the same, bearing in mind that capital and operating costs are now much higher in the Norwegian sector. The main drawback to the Norwegian tax system, as pointed out by Kemp and Crichton, appears to be that it is too inflexible to deal with the problems of smaller and marginal fields. This conclusion seems to have been accepted officially, because a government committee has been set up to consider the possibility of giving special concessions for small fields such as Hod/Valhall. Finally, it should be stressed that the figures in Table 7.1 are only broad estimates and should not be taken as precise calculations of government revenue for particular years. They are based on a number of assumptions which may change, but it is believed that the broad orders of magnitude are reasonable forecasts. In any case, it is hoped that our forecasts are better than official forecasts have been in the last few years! The use of revenues There can be no doubt that the sums we are discussing are vast, and will bring a tremendous improvement in the Norwegian economy. Since the remainder of this chapter takes a critical look

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at expenditure plans, the scale of the benefits should not be forgotten and the arguments should be seen in their proper context. This cautionary note is necessary because many people may find it difficult to believe that such a large increase in income can bring problems as well as benefits. Problems do occur, however, mainly because Norway is a small country incapable of absorbing large oil revenues over a short period. Similar situations have arisen with some of the smaller Middle East countries whose oil revenues have increased sharply in recent years, and it is not erroneous to argue that there are similarities in this respect between Abu Dhabi, for example, and Norway. Another introductory point to remember is that Norway has already spent a significant part of the revenues. This is discussed in more detail below, but — to state the situation briefly — Norway, at the outset of the international economic recession in 1974, decided that her main priority was to maintain full employment in the country. Despite being heavily dependent on exporting, she has been very successful in this objective, almost alone of all industrialised countries throughout the world. In 1975, for example, unemployment in Norway averaged only 1.3 per cent, compared with 3.9 per cent in the U.K., 4.9 per cent in West Germany and 8.5 per cent in the United States. The position is much the same at the time of writing. The low level of unemployment has been maintained by a very active counter-cyclical policy which has drawn heavily on public funds in the form of subsidies and liquidity loans to certain industries (particularly shipping, shipbuilding and textiles) and other similar assistance. The result has been a large increase in the public sector debt, mainly in the form of loans from overseas. This counter-cyclical policy has only been possible because of the future prospects of oil revenues; without it unemployment would have been much higher. Another aspect of this advance expenditure has been a sharp deterioration in the balance of payments, because the high level of domestic demand has meant a high level of imports and extensive foreign borrowing by both private and public sectors. Following a period of small surpluses or deficits on the current account in the late 1960s and early 1970s, foreign borrowing has been very high in the three years directly prior to the time of writing, when the net foreign debt is about 100 billion kroner. Much of this is attributable directly to the financing of the Ekofisk, Frigg and Statfjord fields, but the shipping and manufacturing sectors also account for large parts. Assuming that this debt will increase steadily until 1979, it will then take four or five

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years of the expected oil revenues to repay it — i.e. it may be that not till 1985 will there be any apparent positive benefits, although that is a rather misleading way of looking at it, given the nature of the foreign debts. International competitiveness Before turning to the expenditure of the remaining future revenues, it is necessary to pay particular attention to the implications for the external value of the krone. As mentioned previously, for policy purposes the Norwegian Government makes a distinction between sheltered and exposed industries. Exposed industries are those which are exposed to strong competition from abroad, either because they export most of their output or because in domestic markets they are subject to strong foreign competition through imports. Sheltered industries, on the other hand, are those whose products are marketed at home relatively free from foreign competition. Because of its open nature, the Norwegian economy has a relatively large exposed sector, accounting for about 30 per cent of total output. Furthermore, it is reckoned to be the dominant sector because of the influence it exerts on the rest of the economy, e.g. through price and wage formation .s Clearly the fortunes of the export industries and other industries in the exposed sector are of great importance. The 1977 National Budget set out this concern:' `The government is therefore of the view that a guideline for economic policy, also in the longer run, should be to ensure an acceptable development in Norwegian industry's external cost competitiveness. This is important, particularly because a significant decline in employment in industries exposed to foreign competition could create major social problems, but also because Norway's balance of payments position might otherwise develop in an unfavourable direction.' In this regard, the external value of the krone is extremely important. In simple terms an appreciation (revaluation) of the krone would increase the export prices of Norwegian goods and make them less competitive; a devaluation would do the opposite. Given the large balance of payments surplus which North Sea oil and gas will bring, a steadily appreciating krone is much more likely, which therefore has implications for the competitiveness of the exposed sector. Similar fears have been expressed in the U.K. On the other hand, an appreciation of the krone would have some beneficial effects, not least by reducing import prices and hence the level of consumer prices — or at least the rates of increase of these prices. Given the government's views about the

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transmission of wage increases from the exposed sector to the rest of the economy, and the effects of wage increases on inflationary pressures, some people see the appreciation of the krone as desirable. Thus, the government's long-term programme (LTP) for the period 1978-815 states: `A lower rate for the krone might improve the competitive position in the short run, but at the same time it would result in a sharper rise in prices. Inflation has so many negative effects in itself that in the long run it must be considered advantageous to allow the rates for the Norwegian krone to rise. If this results in less inflation, the same growth in real wages may be achieved through a smaller increase in nominal wages.' This appears to be the dominant view in government circles, and in any case an appreciation of the krone may well be forced on Norway by its trading competitors, if only by a series of competitive devaluations. Furthermore, there is evidence to suggest that the case for protecting export industries can be easily overstated. Here there are two main factors. First, the nominal value of the krone, with which the above discussion has been concerned, is much less important than its real value, taking into account unit labour costs and consumer prices among Norway's trading competitors. The recent performance of West German exports is adequate testimony. A report from the IFO Economic Institute in Munich shows that although the external value of the Deutschmark increased by an average of 59 per cent over the period 1969-77 in real terms, it only increased by 20 per cent (taking account of differences in units labour costs) or 18 per cent (taking account of differences in consumer prices). These averages themselves disguise some salient points. In some cases, the external value of the Deutschmark in real terms has declined. Thus with Japan, although the nominal value increased by 19 per cent it had fallen in real terms by 14 per cent, after allowance for unit labour costs, or 17 per cent, after allowance for consumer prices; and with the Netherlands the nominal increase was 14 per cent but in real terms there was a decline of 3 per cent or 5 per cent respectively. It is important to remember that the price competitiveness of Norwegian exports is not only a function of the real movement of the krone against the currency of the importing country, but it is also affected by the real movements of the currencies of Norway's trading rivals. This has been accepted in a recent joint study by the Norwegian Federation of Industry and the Ministry of Finance .° Secondly, export prices are not the only factor and may not

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even be the most important one. Quality, delivery performance and other non-price aspects all have to be taken into account. This is not to say that the exchange rate is unimportant, or that there is no case for protecting exposed industries. It is simply a question of placing the importance of price competitiveness in its proper perspective and of weighing the benefits of protecting export industries against those of an appreciating krone. In our view the case for protection as a long-term policy is not a good one. Of more relevance to the debate about the external value of the krone is the capacity of the Norwegian economy to absorb the oil revenues. A government report published in 1974' set out in some detail the nature of the problem, which is essentially the effects of domestic demand on prices, wages and employment Since the concern about rising prices and wages is similar to the external competitiveness argument summarised above, attention here can be concentrated on employment. Briefly, if the oil revenues are spent domestically, they represent an addition to demand which would in part be met by increased exports and in part by increased domestic production of goods and services. To achieve the latter, employment would have to rise. It was estimated that the natural growth in the Iabour supply would be insufficient to meet the increased labour demand, and that therefore there would have to be shifts from some industries to other. In any expanding economy such shifts are both inevitable and desirable. In Norway in recent years, however, there has been increased opposition to economic growth for its own sake, based largely on the view that the benefits from structural change have been less than the costs. The report estimated that government oil revenues would be about 10 billion kroner per year by 1980 (i.e. at 1974 prices), which is less than the estimates given above but acceptable as an illustration. Distinguishing between the sheltered and exposed industries, the report estimated that the domestic spending of 10 billion kroner of oil revenues would require a growth in employment of about 165,000 in the sheltered industries by 1980, which in turn would require a reduction in employment in the exposed sector of about 100,000. Since the exposed industries — mainly manufacturing — employed about 330,000 people in 1974, this represents a very sharp decline in Norway's key exporting sector. If none of the oil revenues were spent domestically, the employment decline in exposed industries was estimated at 30,000; if 3 billion 50,000; and if 6 billion 70,000. Furthermore, it was expected that the declines would be concentrated in a few industries and in a few geographical areas, which would exacerbate

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the adjustment problems!' It was concluded that, at best, the economy could absorb about 6 billion kroner per year by 1980, if certain new measures were introduced to help exposed industries and to alleviate the problems of adjustment. This represents about 60 per cent of government revenues from North Sea operations. Although the various calculations could be refined now in the light of additional information and the current state of the economy, the rough magnitudes — or, at least, the directions of change — are probably still applicable. In other words, the best policy would be to try to absorb up to 60 per cent of revenues domestically, while investing the remainder abroad with a view to strengthening the position of the Norwegian economy when oil production and revenue begin to decline. Domestic absorption above this level is likely to result in very serious problems for certain industries in geographical areas, and increase significantly the rate of inflation throughout the economy. This is not to say that the policies for the exposed sector implied above — e.g. special grants, liquidity loans and assistance for stockpiling — are the correct ones, and clearly a great deal more thought needs to be given to the composition of the additional expenditure. Some of the suggested policies should really only be seen as short-term adjustment measures because they could have serious structural implications if they were adopted as permanent policies. Domestic plans In terms of the domestic use of the revenues, it has not been the intention in Norway to establish a separate fund or account and earmark them for specific projects. Rather, they represent an increase in the overall government revenue, which can be used for general purposes on a greater scale or for new projects which otherwise would not have proceeded. Thus it is impossible to say precisely for what purposes the oil revenues have been used or will be used, although various government documents give some indications. General guidelines are laid down by the long-term programme (LTP), the current one being for the period 1978-81. The detailed government expenditure plans are set out in the annual budgets, but given that we are really concerned with proposals for the expenditure of future income, the LTP is the best source of information on official thinking. The 1974 parliamentary report suggested a distribution of increases for 1980 of 2.5 billion kroner private consumption, 1.25 billion kroner public consumption and gross investment in consumer capital, 1.25 billion kroner

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in housing, 0.95 billion in private investment and 1 billion to meet the social objectives of the LTP - making a total of 7 billion kroner. Since that report, objectives have become firmer and more detailed. The main objectives, as set out in the LTP, are: the maintenance of full employment; the maintenance of the external competitiveness of Norwegian industries; increased state involvement in the North Sea, largely through Statoil; reduced taxation, particularly direct income taxes; increased pensions, social security payments and other assistance for marginal groups, and a programme for a `qualitatively better society'. Given that some of these are interrelated, there is little point in taking each objective separately. The first two are closely linked and were mentioned in the introduction to this chapter. They have been major aims of economic policy throughout the last decade, and the significance of the North Sea revenues is that they have made it easier to achieve these aims in a period of international economic recession which has defeated the same aims in most other countries. Taking the level of unemployment as a simple measure of success, Table 7.2 shows how well Norway has fared in recent years compared with other industrialised countries. This has been achieved by an expansionary monetary policy with high levels of public expenditure, consumer expenditure and capital investment. Gross domestic product (GDP) grew by 6.0 per cent in 1975, 4.3 per cent in 1976 and 6.8 per cent in 1977. Deflationary measures were introduced in 1978, mainly to combat the growing external deficits, and the GDP growth in Table 7.2 INTERNATIONAL UNEMPLOYMENT TRENDS (annual percentages)* West United United States Canada France Germany Italy Kingdom Norway 0.6 3.4 3.1 1.3 2.5 1970 4.8 5.8 0.8 3.4 3.8 1.2 6.3 2.9 1971 5.7 0.8 3.9 4.1 1.5 6.3 2.9 1972 5.4 2.8 1.3 0.9 3.7 1973 4.7 5.6 2.6 1.5 3.1 2.9 1.1 1974 5.4 5.5 2.7 4.1 3.6 6.4 5.1 1.9 1975 8.3 7.0 1.8 4.6 3.6 6.4 6.9 7.1 1976 7.5 3.5 1.8 7.5 7.6 8.1 5.2 1977 6.9 * Standardised according to international definitions. Sources: Norway: OECD annual economic surveys. All other countries: National Institute Economic Review (U.K.).

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1978 was estimated at about 2.5 per cent, still higher than most European countries. The LTP lists a number of special measures which were introduced during this period and financed by the Government: liquidity loans to the manufacturing industry; interest support for the extraordinary accumulation of stocks; grants for operating expenses for certain industries; investment support for certain industries; vocational training for adults; internal company training; grants for extraordinary building and construction projects; and grants for exports to developing countries. The programme goes on to say:9 `The measures in use will be reviewed to evaluate which types of instruments may be expedient based on more longterm objectives. It is important that they are utilised as part of a suitable process of renewal in industry. Structural changes will be necessary to achieve competitiveness and a growth in productivity. Nonetheless, in many cases it will be desirable from the point of view of the society to provide support measures to industries and enterprises experiencing difficulties. The market mechanisms do not take account of the social costs of company closures and major structural changes. There will often be a need as well to prolong the period when activities are being scaled down to reduce the negative effects on the local communities.' Of greater long-term significance is the contribution which oil revenues have made to a national incomes policy. This has not only great significance for Norway but is being closely watched by OECD and most other countries in Western Europe which have experimented with incomes policies in recent years. It is not necessary here to give an account of the incomes policy,10 but its main feature is tripartite bargaining between the government, labour representatives and employer representatives. In the autumn of 1975 agreement was reached on a system of wage indexation, with moderate increases being accepted in return for temporary tax reductions, increases in subsidies and a three-months price freeze. Following a similar agreement in 1976 the revised national budget included an adjustment in tax schedules, a reduction in employers' social security contributions, an extension of the increase in food subsidies and a general increase in pensions and family allowances. The 1976 measures were aimed at, and succeeded in, raising average real disposable wage incomes by about 3 per cent. A similar agreement was reached in 1977 through another coordinated incomes settlement. The prospect of oil revenues certainly appears to have been important in reaching these agreements, but it is impossible to

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say how important. Thus the 1977 OECD survey of the Norwegian economy concluded:11 `The comprehensive incomes policy approach adopted and pursued by the authorities has been greatly facilitated, if not encouraged, by the prospect of rising oil sector external surpluses and the related boost to government revenue. Neither the sharp increase in the current foreign deficit in 1975 and its continuation in 1976, nor the weakening of public sector financial balances were considered as constraints on the freedom of choice in economic policy-making.' It is necessary to point out, however, that there have been more recent signs of the incomes policy co-operation breaking down, partly because of competing claims from different groups — e.g. the fishermen and the farmers — but this does not necessarily invalidate the contribution of oil revenues to policies to date. The oil revenues have had a similar effect on other major economic policies in the LTP, particularly regional policy. Regional policies often have non-economic aims and probably the most impressive and distinctive feature of the LTP, at least to the outsider, is its emphasis on non-economic objectives, broadly referred to as `a qualitatively better society'. Here again, the significance of the oil revenues is that they have made it easier to try out such policies. The strong impression given is that, the country having reached a high level of income and economic development and future prospects looking good, the government is determined to pay much greater attention over the next few years to social objectives and in particular to trying to reduce disparities in social and economic opportunities. Thus the main objectives of the LTP are seen as: — security and good living conditions; — greater solidarity and equality; — strengthening the family and the local community; — employment for everyone; — a better working environment; — sound management of natural resources and the environment; — freedom, democracy and legal protection; — international solidarity. This involves increased expenditure on social and community facilities, education, environmental improvements, etc. Particular emphasis is placed on measures for economically inactive groups — pensions, sickness payments, maternity benefits, expenditure on institutional care — and for reducing income differences between different groups and different parts of the country. Agriculture and fishing are singled out for special preferential treatment; as

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are women, young people, the elderly and the occupationally handicapped. A summary such as this cannot do justice to the LTP, but the intention here is only to present a guide to the policies involved. The detailed expenditure proposals over the period 1978-81 are shown in Table 7.3 in the concluding section of this chapter. Overseas spending It was suggested earlier as a rough guide that over the next decade or so the economy would only be capable of absorbing about 60 per cent of the expected oil revenues, with the remainder being spent outside Norway. This section looks at the latter possibility in more detail. These are three main components: debt repayments, overseas investment and foreign aid. We will discuss debt repayments first. Since the mid-1960s, Norway traditionally has had very small deficits on the current balance of payments. In 1970 the deficit was 1.7 billion kroner, in 1971 3.7 billion, in 1972 0.4 billion and in 1973 2.0 billion. Thereafter the deficit increased rapidly: in 1974 it was 6.8 billion, in 1975 13.2 billion, in 1976 20.0 billion, in 1977 26.5 billion and in 1978 an estimated 20 billion. In 1974 and 1975 almost all the deficit was attributable to imports for the North Sea developments, but of the 1977 deficit the oil sector (including Statoil) accounted for only 40 per cent, the shipping industry for 30 per cent, central and local government for about 20 per cent and the rest of the economy for the remaining 10 per cent. By 1979 the oil sector was not expected to have a net borrowing requirement, so the greater part of any deficit would then be attributable to other activities. At the end of 1977 the total foreign debt was about 80 billion kroner, which is likely to have risen to 100 billion by the end of 1978. It could well rise to 150 billion before it could be amortised with the help of oil revenues; and by that time (say 1981) the central government's share will be around 60 billion. This is the sum which needs to be set against the estimates of government revenue in Table 7.1. If the rate of interest is running at 10 per cent per year, annual interest payments would be 6 billion kroner, assuming no repayment of the net debt. Table 7.1 shows that this would account for about 25 per cent of average annual revenues in the 1980s. On the other hand, the total debt of 60 billion would be equal to about 30 months' receipts over that period, so repayment would not be difficult if the government wished to do so. Another contrast is that 60 billion equals the total government oil revenues over the period 1975-82, which shows how important is the build-

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up of production. The main point is that the foreign trade deficit is giving increasing concern, and its rate of growth must be checked before it becomes too great a burden. It is essentially a short-term problem, however, and it should be clear from Table 7.1 and from the discussion above that the expected level of government oil revenues in the 1980s is such that there should be no long-term problems. The second possibility mentioned was direct investment overseas, which is the strategy that many OPEC countries are currently following. Norway could build up income-earning assets overseas which will subsequently bring in considerable foreign earnings in the period when oil production, exports and government revenues are all declining. The assets could then be realised at an appropriate time. Not surprisingly, little detailed thought has so far been given to such opportunities. The LTP is suitably vague:12 `The net debt for Norway, excluding shipping and oil activities, will decline. However, even before this net debt has been repaid, state surpluses in excess of amortisation payments abroad may be used for capital exports. This will depend, among other things, on the development of petroleum prices. The composition of future capital exports will be determined by foreign policy considerations, credit and industrial policy goals, administrative considerations in connection with the practical implementation, and not least the size of such capital exports.' Nevertheless, mention can be made of some of the suggestions which have been put forward. An obvious category is energyrelated projects: the involvement of Norwegian companies in the developments at Emden and Teesside for the processing of Ekofisk gas and oil already fall into this category. The Government has had lengthy discussions with its counterparts in Sweden and Denmark on co-operation in energy projects, and if these come to fruition there would appear to be good opportunities for Norwegian investment overseas. The Volvo proposal mentioned in Chapter 2 is another example. Some more tentative discussions have taken place about Norwegian forestry interests investing in new forests in Scotland, thus securing timber supplies in the event of domestic supplies being insufficient. This would be a form of backward linkage which is a common economic strategy for a wide range of raw materials. Thirdly, there is the question of foreign aid. The LTP is much clearer on this:12 `Norway's improved economic situation in the years ahead will impose special obligations on us to contribute to the poor countries.... The govern-

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ment's goal for public assistance to the developing countries implies that the appropriations in 1978 will amount to 1 per cent of the gross national product. In Report to the Storting no. 94 for 1974-5 on Norway's economic transactions with the developing countries, the Government stated that it advocates further increases after 1978 in view of, among other things, the income the country will acquire from the oil production. The Government intends to increase the grants for development assistance by 0.1 per cent of the gross national product each year in the period from 1978, so that it will reach 1.3 per cent of the gross national product in 1981.' This is a major commitment which has been enthusiastically received by the multilateral agencies involved in developing countries. It should be stressed that Norway's assistance is already at a high level and puts to shame most other European countries. As a proportion of GNP, Norway's official commitments to development aid amounted to 0.77 per cent in 1977, compared with 0.44 per cent in the U.K., 0.33 per cent in the U.S., 0.50 per cent in West Germany and 0.22 per cent in Switzerland. The only OECD countries to exceed Norway's contribution were Sweden (1.27 per cent) and the Netherlands (1.15 per cent); the average over all the OECD countries was 0.44 per cent in 1977. Traditionally, Norway's aid has been concentrated in a few `main partner' countries — India, Pakistan, Bangladesh, Zambia, Botswana, Tanzania and Kenya — and the LTP implies a continuation of this policy, with increased assistance for a few other countries in Africa and the Far East, and increased donations to the multilateral agencies such as the United Nations Development Programme Some conclusions There can be little doubt that North Sea oil and gas will bring substantial indirect benefits to the Norwegian economy. The government has established a tax system which will ensure that the great majority of the revenues arising will accrue to the State. In some respects these can be regarded as unexpected gains because they are largely attributable to the success of the OPEC cartel in the forcing up of the world's price of oil. If the Norwegian fields had been developed on the basis of pre-1974 prices, profits and government revenues would have been very small. Despite criticisms from the oil companies, the available evidence suggests that the Norwegian tax system is no stricter than that of most countries, with the average government receipts of 70 per cent being similar with that of the U.K. Government, for

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example. The only qualification which we would make concerns the treatment of small, marginal fields, but the Norwegian Government appears to have accepted that the tax system at present discourages their development, because methods of helping such fields are being investigated. The question of how to spend these revenues is in part an unreal one because the Government has not transferred them to a separate fund; thus it is difficult to separate the expenditure of oil revenues from other government income. Nevertheless, current and planned government expenditure differs markedly from that of the past, and to a great extent the changes can be attributed to North Sea oil and gas. Also, much information is available from official government publications, the detail increasing through the earlier parliamentary reports on the North Sea opportunities, the Long-Term Programme for the period 1978-81 and the annual national budgets. In the first instance, a significant proportion of the revenues has already been spent in advance by way of the Government's counter-cyclical policy which has been in operation since the onset of the international economic recession in 1974. Although this policy has been successful in maintaining the high level of demand in the economy and in keeping unemployment down to the lowest level in Western Europe, the Government has been criticised by some people for this policy. We believe such criticism to be unjustified, that the counter-cyclical policy was the best course of action to take in the circumstances prevailing, and that it has had the general support of the country. The policy changes which have occurred in 1978, and which will probably continue in the form of deflationary measures until 1980, should be seen as short-term corrections and not a major reversal in policy. Corrections are necessary because of the deterioration in the balance of payments and because of the breakdown in the tripartite incomes policy negotiations. Where the government did go wrong was in relying on over-optimistic forecasts of exports, both oil and manufactured goods, and to fail to exercise sufficient control over certain North Sea activities (such as costs). In the context of the use of oil revenues, these should not be taken as major criticisms, and it should be accepted that throughout the 1980s the level of government oil revenues is likely to average over 20 billion kroner (£2,000 million) each year — which is over 10 per cent of GNP. Before decisions can be taken on the use of these revenues, a crucial decision has to be taken on the proportion that can be

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spent domestically without creating major problems of inflation and the decline of exposed industries. As a rough indication a 60 per cent domestic/40 per cent foreign split for the 1980s seems reasonable. The latter will take three forms - debt repayments, direct investment overseas and foreign aid. This was discussed in more detail above. Table 7.3 LONG-TERM FISCAL BUDGET, 1978-81 (million kroner, 1977 prices) Programme Area

1 General administration, etc.

Actual 1977 1,731 226 1,668 5,678 153

2 Foreign affairs 3 Development assistance 4 Military defence 5 Civil defence 6 Justice, police and prison administration 1,366 7 Education and research 6,372 8 Church, cultural purposes and sports 678 9 Social purposes 5,260 10 Health services 1,090 11 Consumer protection and price regulation 1,699 12 Environmental protection and regional planning 361 13 Employment and regional development 2,148 14 Housing 1,377 15 Agriculture and forestry 4,796 16 Fishing and whaling 389 17 Manufacturing and mining 3,064 18 Electricity and watercourses 2,083 19 Trade and shipping 257 20 Harbour, lighthouse and pilot services 303 21 Domestic transport 5,766 22 Telecommunications and postal services 2,022 23 Miscellaneous expenditure 3,828 24 Interest and repayment of central government debt 5,359 25 Loans to State banks 6,022 Total expenditure 63,696

1978 1,770 223 2,099 6,292 164

1979 1,792 189 2,466 6,456 161

1980 1,797 190 2,874 6,623 162

Annual % Change 1981 1977-81 1,849 1.7 191 3,325 18.8 6,784 4.4 162 1.4

1,453 1,388 1,386 1,388 6,591 6,752 6,867 7,024

0.4 2.5

748 803 824 879 5,330 5,438 5,523 5,619 1,088 1,095 1,091 1,110

6.7 1.7 0.5

1,710 1,721 1,733 1,748

0.7

430

433

398

2,262 1,399 4,710 351 599 1,905 249

2,392 1,463 4,730 351 608 2,037 249

2,450 1,475 4,743 340 600 2,079 249

409

3.2

2,475 3.6 1,486 1.9 4,760 340 603 2,163 0.9 249 -0.8

271 270 272 272 -2.7 6,111 6,291 6,451 6,600 3.4 2,054 2,130 2,109 2,115 1.1 4,020 5,070 6,040 6,915 15.9 5,075 6,045 11,218 10,193 17.4 5,938 6,074 6,331 6,532 2.1 62,841 66,405 73,825 75,191 42

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Detailed plans for domestic spending will take some time to emerge, but the LTP gives some indications. Again these were discussed in more detail in the main body of the chapter but, by way of a conclusion, Table 7.3 summarises the long-term fiscal budget for 1978-81.14 It shows planned increased expenditure over a whole range of areas, but significantly large increases in foreign aid (development assistance), defence (particularly on coastguard vessels), environmental protection, employment and regional development, domestic transport and 'miscellaneous expenditure' (which covers possible tax relief and other measures arising from combined incomes settlements). It is clear from the LTP that the Government sees oil revenues as enabling it to move away from a programme of rapid economic growth to one for a `qualitatively better society' which gives greater importance to social and environmental factors. This is the aspect of policy which is likely to attract considerable attention outside Norway. It also raises the fear of dissipating revenues on unproductive projects. This is the so-called `Dutch disease' which has been diagnosed recently, with the current Dutch economic problems being attributed to their choice in the late 1960s and early 1970s of using the revenues from their natural gas fields for social programmes rather than capital investment. In the Netherlands the social security system is now probably the best in Western Europe, but the level of capital investment is very low and exports are being hindered by the strength of the Dutch Guilder. Will Norway fall into the same trap? Only time can tell. NOTES A. G. Kemp and D. Crichton, Taxation of Oil in Norway. Wood, Mackenzie & Co., North Sea Report. O. Aukrust, Inflation in the Open Economy. Ministry of Finance, The National Budget of Norway 1977, p.4. 5. MFPR no. 75, p.109. 6. See Norges Industri, 7, 1978. 7. Royal Norwegian Ministry of Finance, Petroleum Industry in

1. 2. 3. 4.

Norwegian Society.

8. For more detail see K. Stenstadvold, Regional and Structural Effects of North Sea Oil in Norway. 9. Long-Term Programme, p.111.

10. For more detail see J. T. Addison and G. A. Mackay, The recent Norwegian Experience with Incomes Policies.

11. OECD, `Economic Survey: Norway' (1977), p.6. 12. Long-Term Programme, p.115. 13. Ibid., pp.95 and 98. 14. Ibid., p.176.

8 CONCLUSIONS 'But the Emperor has nothing on at all!' said a little child. (Hans Christian Andersen, The Emperor's New Clothes)

Our conclusions will be brief because many of them have been dealt with in the individual chapters. There appear to be two main questions to be answered. From the Norwegian point of view the crucial question is: are the oil policies which have evolved in the best interests of the Norwegian economy and society? From the non-Norwegian point of view the question is: are there significant differences between Norwegian policies and those of other countries? In the latter case the presumption is that the differences would be of such a kind that consideration might be given in other countries to adopting some Norwegian policies. It is possible, however, that the differences could be negative, but even then there could be the benefit of learning from Norwegian mistakes. By way of comparison, we have concentrated almost exclusively on the oil policies adopted for the United Kingdom sector of the North Sea. To a large extent this was because of our personal interests, but we do believe that the U.K. provides an excellent contrast with Norway, in the light of the differences in size, economic structure and performance, oil consumption, and so on. In these respects, the U.K.-Norway comparisons should have some applicability to other large countries with substantial offshore oil and gas resources, such as the United States and Canada. Furthermore, in the popular press Norwegians are often referred to as 'the Arabs of the north'. Without ignoring the substantial differences between the Middle East oil-producing countries and Norway, particularly in terms of economic structure and absorptive capacity, there are certainly some useful comparisons to be made — because, for example, many of the issues facing Norway's use of oil revenues are the same as those confronting countries such as the United Arab Emirates and Kuwait. Thus the best way of providing a set of conclusions would probably be to examine the main oil policies first from a Norwegian viewpoint and secondly from the viewpoint of the outsider. Before doing this, however, 138

Conclusions

139

there are three other aspects which require clarification. The first is the importance of oil policies within the overall political framework and national economic policies. There can be little doubt that the discoveries of oil and gas in the North Sea have had and will continue to have a major effect on Norway. In Chapter 7 we showed that the expected gross value of Norwegian oil and gas production in the 1980s will average 45 billion kroner (£4,500 million) per year, by then equivalent to nearly 25 per cent of gross national production. Even in 1978, with only Ekofisk and Frigg in production, oil and gas accounted for 15 per cent of gross national production. Given the short period in which the offshore industry has grown, this represents a major boost to national economic activity. It is admittedly less than in the Middle East countries, where hydrocarbon production often accounts for more than 90 per cent of national income, but it is a significantly higher share than in the U.K. for example, where even by the 1980s oil and gas will not account for more than 10 per cent of gross national production. Because of the tax policies adopted, the great bulk of this new income accrues to the state: in Chapter 7 we estimated that this share will rise from about 20 per cent in 1978 to 75 per cent by 1990. Thus the main effect on the national economy is the increase in government revenue and the opportunities provided for its spending. Chapter 7 sets out in detail the Government's current plans for the use of the additional revenue, but they are discussed briefly later in this chapter. There will also be substantial direct increases in company profits (both Norwegian and foreign), industrial output and personal incomes. The only qualification we would stress is that the direct effect on employment will be surprisingly small. The level of employment is often taken as the prime indicator of economic activity, not least in high-unemployment countries like the U.K. In Norway, employment creation and maintenance have always been major objectives of economic policy, and it is therefore necessary to point out, as we try to do in Chapter 5, that the direct contribution of North Sea oil and gas is small: at peak, about 32,000 jobs. The total Norwegian labour force is around 1,700,000, so direct oilrelated employment represents only about 1.5 per cent, compared with 15-25 per cent of national output. Given also that there are a number of associated problems — cyclical fluctuations as activity moves from exploration to development and then production, the regional concentration on the west coast and the high proportion of foreign labour — the direct employment contribution is small.

140

Norwegian Oil Policies

The two main reasons are, first, that the offshore industry is very capital-intensive, and secondly, that there is a very high `surplus value'. In other words the selling price of Norwegian oil is substantially in excess of its cost of production. The body to thank for this is the Organisation of Petroleum Exporting Countries (OPEC) who in practice have a near-monopoly of oil production and have been able to impose their prices on the world market. Norway is not a member of OPEC, but it is clearly in her interests as an oil exporter (either actual or potential) to follow OPEC prices. The result is that in comparison with production and revenue figures, the number of jobs is tiny. In this context, the only other point to be stressed is that North Sea oil appears to have had a major indirect effect on the Norwegian labour market. During the 1970s Norway has experimented with a tripartite incomes policy bringing together employers, the trade unions and the Government. This has attracted much interest outside the country and has been described by many commentators as a good model for other Western European countries.1 This tripartite system appears to have collapsed recently and it could be that this demise will mark the beginning of a difficult period in industrial relations, not least because of the relatively austere fiscal policies adopted by the Government in late 1978. Although it is difficult to disentangle the various factors involved, oil has been a major cause of the lack of success in holding down wage and inflation rates. There has certainly been a spillover effect with the high wages available in the offshore industry moving into mainland industries. The second of the three aspects mentioned earlier is the issue of who makes Norwegian oil policies. The answer is fairly simple because there has been a considerable degree of unanimity among the population as a whole and the political parties. It is true that there have been radical changes in policies since 1974 under the auspices of the Labour Government. It could be argued that the pre-1974 and current policies show a marked divergence of opinion between the conservative and labour parties, or at least between the right-wing and left-wing groupings of the various parties. That, however, would be a misrepresentation. Despite what may be claimed to the contrary, the reason for the change in policies was not political differences but major changes in the industrial environment. The OPEC price rises substantially improved Norwegian prospects, in some cases turning discoveries from marginal possibilities into very profitable developments. They virtually

Conclusions

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guaranteed continuing interest in the North Sea — at least as long as prices remained high. Similarly, the discovery of Statfjord and the U.K. fields to the west confirmed that the East Shetland basin was a major province and that the North Sea oil and gas fields were not solely in the area between 56° and 59°N. These factors were impossible to predict. It is essential to remember therefore that the policies in operation in the 1960s and early 1970s were intended for an industry markedly different from that which exists in the late 1970s. Throughout the North Sea. with the possible exception of the Dutch sector, the main objective had to be to stimulate exploration activity and create a climate in which the private oil companies would be willing to invest in development and production. In the main the Norwegian and U.K. policies were sensible and successful. It is an invalid criticism that they then proved inappropriate from 1974 onwards, because the factors which so markedly changed the offshore industry could not have been foreseen. Despite the protestations of the oil companies and a few other bodies, it was necessary then to revise policies, and major changes rather than minor modifications had to be introduced. The taxation changes discussed in Chapter 7 were the main target for criticism, but as the chapter shows, they still leave private companies with a good return on investment. It may well be that with the experience of the four or five years prior to the time of writing, some modifications are now necessary — e.g. to help the development of smaller, marginal fields — but these need only be the fine-tuning of a basically healthy engine. It is difficult to avoid the conclusion, therefore, that the changes in policy would have been very much the same whichever party or parties are forming the government. This is particularly true of the taxation policies. Looking to the future, it may be less true of production and exploration policies, because there is a growing divergence between those wishing to increase offshore activity and those who believe that the current rate of activity is as high as is desirable. This was discussed in Chapter 2, and the issue demonstrates the roles of certain pressure groups. There is clearly an industry lobby favouring more exploration and development activity, the lobby including most of the oil companies and other companies indirectly involved through the provision of equipment and materials. From time to time, support is forthcoming from the labour unions, in response to rising unemployment, but this has been sporadic and there are disagreements between various labour groups. For example, the fishing industry has consistently provided a

142

Norwegian Oil Policies

strong front against the oil industry, not by way of total opposition but by insisting that the interests of the fishing industry should be well protected. Regarding exploration activity, particularly that north of 62°N., it is obvious that the fishing industry has been the main influence on the government's `go slow' policy. The interests of other environmental groups, such as the farmers, have generally been close to those of the fishermen. In drawing comparisons with the U.K., the influence of the fishing industry is possibly the best example of differing attitudes. In the U.K. the fishing industry and related interests have been almost ignored in oil and gas policy-making. In Scotland at least the fishing industry is no less important than the domestic fishing industry is to Norway, so it is clear that the Norwegian pressure groups have been able to mobilise their arguments much better than their U.K. counterparts. There are many reasons for this, and the present context is not the appropriate one in which to discuss them, because they are mainly functions of the different political processes. However, one point worth stressing is that it has been much easier in Norway for the various groups to express their views on alternative policies. It may be argued that the process of consultation and debate has led to lengthy delays, but it has permitted extensive discussion of the issues and alternatives, and has ensured that many of the mistakes made in the U.K. were not repeated. The latter arose mainly from ignorance and inadequate discussion. The best example of such a mistake concerns the over-provision of concrete platform sites; a small group of senior civil servants was strongly of the view that more sites were needed, and managed to convince the appropriate government ministers. There was no public discussion of the policy: if there had been, the demand forecasts used by the civil servants would have been shown to be excessively optimistic, and it is likely that ministers would have accepted lower forecasts. In the event, two sites were built with considerable government money and have been empty ever since, having received no orders. It is difficult to imagine such mistakes occurring in Norway. The system of regular parliamentary reports on the oil industry has worked very well and has kept the general public well informed of the various issues. In the U.K., discussion has been stifled because of the lack of information; such reports are very rare, and when they do appear they tend to be factual and descriptive, avoiding the mention of policy issues. This is not to say that the Norwegian system is perfect, because we have doubts about

Conclusions

143

the content of some of the reports, but even with such examples the public debate which has followed has usually identified any errors and omissions. The third issue mentioned at the beginning is the relationship between the formulation and the implementation of policies. In many cases the identification of a problem will lead to the identification of a few alternative policies, from which one needs to be chosen. There are then major qualifications: implementation requires action and action requires policy instruments; but there is no advance guarantee that the use of these instruments will necessarily lead to the achievement of the policy objectives. Often external factors intervene to prevent the realisation of objectives, and some of these factors may only emerge after the original decisions have been taken. For example, the Ekofisk blow-out could be described as an external factor of this type. Also, in the areas where there is very little historical experience, the outcome of actions must be less certain: without doubt, the offshore oil industry falls into that category. This aspect is very important in the Norwegian context because, we believe, there are some inconsistencies. Probably the best example is the depletion policy discussed in Chapter 2. The objective set — which can be taken as the target of 90 million tonnes per year — is probably in excess of what could have been achieved even if there had been a rapid exploration policy along the lines of that in the U.K. sector. Could this objective then be regarded as the real objective? If not, to what purpose has been the use of policy instruments such as the issue of licences? Is licensing policy a suitable instrument for controlling the level of production? Some answers to these questions are given below, and they suggest that there is inconsistency between the stated objectives and the stated policy measures. The impression obtained from an analysis of the exploration debate is that it has been too vague and too reliant on opinions rather than facts. A close study of the relevant parliamentary reports would reveal a surprising absence of factual information — and the information exists or could be obtained, which suggests that it has been a deliberate policy to conduct the debate in general terms rather than in detail. Thus it is very difficult to assess how effective certain policies have been because the vagueness of their formulation (and implementation) precludes empirical measurement and evaluation. In some cases, of course, empirical analysis of a statistical nature is impossible, but we do believe that in a few important examples, such as licensing policy and the estab-

144

Norwegian Oil Policies

lishment of Statoil, more detailed information should have been provided. In the event the policies which emerged may have been identical, but at least their future evaluation would have been easier. Let us turn now to specific policies and their evaluation, from both Norwegian and outside viewpoints. Five main policies can be identified: licensing policy, depletion policy, taxation (fiscal) policy, the use of revenues and the activities of Statoil. To a large extent these were the subject of separate chapters, and only brief summaries of the conclusions are necessary here. Licensing policy is the one with which we are least happy, partly because of the lack of specificity and partly because of a lingering suspicion that if the policy has been successful it is due more to luck than to good judgment. In other words, if OPEC had not forced up oil prices in 1973 and 1974, and if Statfjord had not been discovered, the policy would have had to be changed and that would have been difficult for a number of reasons. First, there are the time lags between exploration drilling, development decisions and production: normally five years at least before production begins, and often longer. Thus licensing is a policy instrument not amenable to quick changes — and probably not to small changes either — and could have been very inappropriate in the mid-1970s. If it is to be used, it would be much easier if there were regular rounds of licences — e.g each year, as has recently been the case in the U.K. If the rounds were small, the necessary adjustments in scale and area could be made from year to year. U.K. policy has been criticised on this score, but this was because some of the earlier licence rounds were too extensive and beyond the capabilities of even the major international oil companies. The U.K. has now come back to the system of regular but small licence rounds, and we think that Norway would benefit from such a change. Also, we see some merit in making a clear distinction between licensing and depletion policies. This again has not been the case in Norway: licensing policy has often been seen as a policy instrument for controlling the level of production, and this confusion of instruments and policies has created many problems. Once again, the U.K. depletion controls described in Chapter 2 appear to us a better means of achieving objectives. We have no disagreement with Norwegian objectives, but believe that as production increases in the 1980s, existing policy instruments will prove inadequate. In any case, direct controls over production levels for individual fields would be rarely used, and are really

Conclusions

145

more a reserve power than an active measure. Despite these criticisms, the Norwegian policies do represent to the outsider a very different approach because they are less concerned with maximising oil revenue and production and more concerned with maximising the benefit to Norway. Given that the benefit is not exclusively economic, the great attraction is the attention paid to fishing, environmental and social interests. For similar groups in other countries, the ability to point to what Norway has done is extremely valuable and there is no doubt in our minds that others will try to follow suit — such as the U.K. fishing industry. With taxation policies the differences are small, as Kemp and Crichton have shown.2 To a large extent the Norwegian tax system has copied the earlier system evolved in the U.K., and differences such as variable royalty rates are of more interest to the academic and the accountant than to the policy-maker. There is little cause to regard Norway as having a tough regime, because the overall government share is very similar to that of all other Western European countries with offshore oil and gas. Differences which do exist are largely attributable to Norway's higher production and operating costs. They are a matter of increasing concern but are unlikely to affect future taxation policies, inasmuch as their effect is to reduce the government share rather than company profits. The government response could not be to tighten policies to reduce the latter because of the need to maintain oil company interest, at least until such time as Statoil has expanded substantially. Policies for the expenditure of revenues, on the other hand, must be of considerable interest outside Norway. As Chapter 7 showed, Norway has taken a unique approach and provides a model lesson for most industrialised countries. The only comparable oil surplus country in the Middle East is the United Arab Emirates, where a substantial proportion of revenues is also earmarked for foreign aid and overseas investment. There seems little chance in Norway of revenues being dissipated in the ways alleged in the Netherlands in the late 1960s and feared in the U.K. at the present time. Finally, there is the role of Statoil. As Chapter 6 mentioned, state oil companies are now common throughout the world, and neither Norway nor the U.K. is unique in that respect. Furthermore, the differences in activities are straightforward and understandable. There is no activity of Statoil which appears surprising. Statoil is more involved in downstream activities than is the British National Oil Company, for example, but then the U.K.

146

Norwegian Oil Policies

already had a substantial refining and petrochemical industry which needed no government stimulation. We have raised a few criticisms of Statoil, but do not regard them as major. It is easy to make points from the sidelines without appreciating the operating difficulties, and in the light of the rapid expansion since Statoil's establishment — in terms of both size and scope of activity — very few mistakes appear to have been made. Even if many of the Statfjord problems are laid at the door of Statoil, we are sure that by now they themselves are well aware of them and that they will try to ensure that they do not recur when future fields are developed. Parliamentary control of Statoil is certainly greater than that of its U.K. equivalent, and there is no reason to expect that control to diminish In contrast, it is likely that BNOC's activities will be reduced in the near future. Mistakes have been made and improvements could be made, but in the words of Ibsen,e `Life would be tolerable enough, even so, if we could only get rid of these infernal duns who come to us poor people's doors with their claim of the ideal.' We hope that we have not portrayed ourselves as duns. NOTES 1. J. T. Addison and G. A. Mackay, The recent Norwegian experi-

ence with incomes policies. 2. A. G. Kemp and D. Crichton, Taxation of oil in Norway. 3. H. Ibsen, A doll's house.

BIBLIOGRAPHY Note: The Parliamentary Reports of the Ministry of Finance and Reports to the Storting of the Ministry of Industry listed below are in English.

Adelman, M. A., The world petroleum market (Baltimore, 1972). Addison, J. T., and G. A. Mackay, The recent Norwegian experience with incomes policies (Aberdeen, 1979). Aukrust, 0., Inflation in the open economy (Oslo, 1976). Blair, J. M., The control of oil (New York, 1977). Bonham, G. M., et al., 'A cognitive model of decision-making: application to Norwegian oil policy", Co-operation and Conflict, 2, 1978. British National Oil Corporation, Annual report and accounts (London, annual). Chapman. K., North Sea oil and gas (Newton Abbot, 1976). Dam, K. W., Oil resources (Chicago, 1976). Distriktenes Utbyggingsfond, Instruments of regional development policy (Oslo, 1976). Donovan, D. R., (ed.), The geology of the shelf seas (Edinburgh,

1968). Hamilton, A., North Sea impact (London, 1978). Hepple, P. (ed.), The exploration for petroleum in Europe and North Africa (London, 1969). Hinde, P., Fortune in the North Sea (London, 1966). Kemp. A. G. and D. Crichton, Taxation of oil in Norway (Aberdeen, 1979). Khouja, M. W., and P. G. Sadler, The economy of Kuwait (London, 1979). Lind, T., North Norway and the petroleum activity (Aberdeen, 1976). Mackay, G. A., The revised demand for production platforms, 1977-82 (Aberdeen, 1977). Mackay, G. A., et al., The economic impact of North Sea oil on Scotland (Edinburgh, 1978). Mackay, G. A., and D. I. Mackay, The political economy of North Sea oil (London, 1975). Mackay, G. A., A. C. Moir and P. G. Sadler, The conflict between oil and fishing in the North Sea (Aberdeen, 1979). Ministry of Finance, The national budget of Norway (Oslo, annual). — Natural resources and economic development (Parliamentary Report no. 50, 1974-5) (Oslo, 1975). — Norwegian long-term programme, 1978-81 (Parliamentary Report no. 75, 1976-7) (Oslo, 1977). 147

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Bibliography

Petroleum industry in Norwegian society (Parliamentary Report no. 25, 1973-4) (Oslo, 1974). — Supplement to the long-term programme, 1978-81 (Report no. 76 to the Storting, 1977-8) (Oslo, 1978). Ministry of Industry, Operations on the Norwegian Continental Shelf (Report no. 30 to the Storting, 1973-4) (Oslo, 1974). — Petroleum exploration north of 62°N. (Report no. 91 to the Storting, 1975-76) (Oslo, 1976). Nicolson, J. R., Shetland and oil (London, 1975). NIBR-SINTEF, Foredlingsmuligheter og regionale konsekvenser ved petroleumsfunn nord for 62°N. (Oslo, 1978). Norges Bank, Economic bulletin (Oslo, quarterly). Norges Offentlige Utredninger (NOU), Bravorapporten (Nov. 1977, no. 47) (Oslo, 1977). Bravoutbldsningen aksjonsledelsens rapport (Nov. 1977 no. 57) (Oslo, 1977). — Olje og fiskerinaeringen (Nov. 1978 no. 24) (Oslo, 1978). Odell, P. R., Oil and world power (London, 1970). —and K. E. Rosing, Optimal development of the North Sea's oil fields (London, 1976). Organisation for Economic Co-operation and Development (OECD), Economic outlook (Paris, quarterly). OECD, Economic survey: Norway (Paris, annual). Pearce, D. W. (ed.), The economics of natural resource depletion (London, 1977). Public Accounts Committee (U.K.), North Sea oil and gas (London, 1973). Robinson, C. and J. Morgan, North Sea oil in the future (London, 1978). Sampson, A., The seven sisters (London, 1975). SINTEF, Foredlingsmuligheter av ilandfort olje og gass nord for 62°N—tekniske forstudier (Trondheim, 1978). Statistisk Sentralbyrå, Flytte-statistikk 1975 (Oslo, 1976). — Oljevirksomheten på Norsk kintinentalsokkel fram til 1977 (Oslo, 1978). Stenstadvold, K., Recruitment to oil-related activities in Norway (Bergen, 1977). — Regional and structural effects of North Sea oil in Norway (Bergen, 1977). Tugendhat, C., and A. Hamilton : Oil: the biggest business (London, 1975). Wood, Mackenzie & Co., North Sea oil report (Edinburgh, monthly). Wyller, K. B., and T. C. Wyller (eds.), Norsk olje-politikk (Oslo, 1975). —

INDEX Addison, J. T., 26n, 137n, 146n Adelman, W. A., 26n Aker, 42, 86, 95, 107 Aukrust, 0., 137n

incomes policy, 25, 135 Institute of Industrial Economics, (IØI), 87 International Energy Agency (IBA), 45

balance of payments, 22-4, 125, 132-5 Blair, J. M., 99, 116n Bonham, C. M., 61n British National Oil Company (BNOC), 30, 111-16, 145-6 British Petroleum (BP), 4, 26n, 99

Kemp, A. G., 49n, 111, 116, 121, 123, 137, 145 Khouja, M. W., 33-4, 48n Labour Directorate, 41, 81-9 licences, 13, 29-30, 37-8, 51, 1025, 144-5

Chapman, K., 77n Crichton, D., 49n, 111, 116n, 121, Mackay, D. I., 26n, 48n, 96n Mackay, G. A., 26n, 48n, 61n, 123, 137n, 145 96n, 97n, 137n, 146n Ministry of Finance, 30, 48n, 49n, Dam, K. W., 99, 116n 97n, 116n, 126, 137n Deminex, 44, 116 Ministry of Industry, 29, 48n, Donovan, D. R., 26n 49n, 52, 54, 56, 61n, 116n Ekofisk, 14, 24, 39, 40, 51, 55, 57, Ministry of Petroleum and Energy, 29, 70, 73, 105, 115, 65-7, 72, 79, 84, 96, 100, 105-8, 116n 119, 121, 123, 124, 133, 139 Mobil, 106-8 employment, 20-21, 41, 78-97, 139 Morgan, J., 34, 46, 48n 49n exchange rate, 22-3, 125-8 exploration, 13, 50-61, 102-5, 144-5

Nicolson, J. R., 61n, 96n Norges Bank, 22, 24, 26n Norol, 100, 109 fishing, 10, 58-60, 141-2 Norsk Hydro, 64, 67, 68, 100, foreign aid, 132-4, 145 102, 109 Frigg, 15, 40, 47, 65, 67, 84, 102- north of 62° N., 15, 31, 52-5, 3, 106, 119, 121, 123, 124, 139 56-7, 59, 62-77 Norwegian Institute of Urban gas, 6, 10, 15, 62-77, 119-20 and Regional Research (NIBR), Geneva Convention, 10-12 73 geological factors, 2-3, 54 Norwegian Trench, 11, 51, 68, gross domestic product, 17-19, 25 107 Hamilton, A., 116n Hepple, P., 26n Hinde, P., 26n

Odell, P., 45, 49n Oil Directorate, 29, 37, 39, 56, 57, 96 149

150

Index

Organisation of Arab Petroleum Exporting Countries (OAPEC), 9 Organisation for Economic Cooperation and Development (OECD), 19-23, 26n, 36, 45, 129-131, 134, 137n Organisation of Petroleum Exporting Countries (OPEC), 6-10, 31, 33, 35, 54, 78-9, 100, 121, 133, 134, 140 Orkney, 12, 51, 60, 69 Pearce, D. W., 48n petrochemicals, 6, 43, 62-77, 91-3, 106, 109-10 Phillips, 14, 39, 105 pollution, 55-60 prices, 8, 35, 78-9, 117 production, 5-6, 26-49

Sampson, A., 26n, 116n `Seven Sisters', the, 6-10 Shetland, 12, 51, 60, 69, 87, 108 Society for Industrial and Technical Research (Norwegian) (SINTEF), 70-3, 77n Sotra, 68, 107-8 Statfjord, 14, 40, 51, 65, 67-9, 84, 106-8, 121, 124 Statoil, 39, 45, 46, 57, 64, 68, 98116, 121, 132, 145-6 Stenstadvold, 86, 96n, 97n, 137n Storting, 38, 54, 56, 101, 115 taxation, 111, 120-37, 139, 145 Tugendhat, C., 116n unemployment, 19-20, 124, 12930 United Kingdom, 10-13, 21-3, 30, 37-8, 42, 46-8, 50, 58, 67, 85, 95-6, 111-16

refining, 43, 62-77, 91-3, 106, 109-10 regional policy, 38, 73-7, 131 Valhall, 14, 16, 40, 119 Veba, 43 reserves, 15-16, 37 revenues, 24, 33, 117-37, 139, 145 Volvo, 43-4, 133 Robinson, C., 34, 46, 48n, 49n Wood, Mackenzie & Co., 121, 137 Sadler, P. G., 33-4, 48n Saga Petrokjemi, A. S., 68, 109

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